Version 4.1
Documentation Report
September 2005
Prepared for:
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
Prepared by:
E.H. Pechan & Associates, Inc.
5528-B Hempstead Way
Springfield, VA 22151
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CONTENTS
Page
GLOSSARY 	v
CHAPTER! INTRODUCTION 	 LI
CHAPTER II. SUMMARY 	114
CHAPTER III. CONTROL DOCUMENTATION	IIL1
CHAPTER IV. REFERENCES 	IV4
APPENDIX A: CONTROL MEASURE SUMMARY LIST - BY SOURCE	 A-l
APPENDIX B: CONTROL MEASURE SUMMARY LIST - BY POLLUTANT 	B-l
APPENDIX C: SCC / SIC / NAICS CROSSWALK	C-l
TABLES
Page
Table 1-1 List of Related Publications Prepared by Pechan and EPA that Contain Useful
Control Measure Information 	 1-2
Table II-1 Number of Control Measures in AirControlNET, by Sector and Pollutant .... II-1
Table II-2 Control Measures Included in AirControlNET	II-4
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GLOSSARY
Add-On Control Device: An air pollution control device such as carbon absorber or incinerator
that reduces the pollution in exhaust gas. The control device usually does not affect the process
being controlled and thus is "add-on" technology, as opposed to a scheme to control pollution
through altering the basic process itself.
Best Available Control Technology (BACT): An emission limitation based on the maximum
degree of reduction of each pollutant subject to regulation under the Clean Air Act emitted from
or which results from any major emitting facility, which the permitting authority, on a
case-by-case basis, taking into account energy, environmental, and economic impacts and other
costs, determines is achievable for such facility through application of production processes and
available methods, systems, and techniques, including fuel cleaning, clean fuels, or treatment or
innovative fuel combustion techniques for control of each such pollutant.
Best Available Retrofit Control Technology (BARCT): An air emission limitation that applies
to existing sources and is based on the maximum degree of reduction achievable, taking into
account environmental, energy, and economic impacts by each class or category of source.
Case: For a given source category in AirControlNET, if there are more than one control measure
for controlling a given pollutant, then each control measure is assigned a case number and is
treated as a separate case from the others in the model.
Capital Recovery Factor (CRF): A function of the economic life of the equipment and the
interest rate charged to the total capital investment.
Capital to Annual Ratio: Ratio of Capital costs to annual costs.
Cost-Effectiveness (C-E): The cost of an emission control measure assessed in terms of dollars-
per-pound, or dollars-per-ton, of air emissions reduced.
Control Efficiency: The percent of pollutant mass reduced from the application of a control
measure.
Control Technique Guidelines (CTGs): An EPA guidance document which triggers a
responsibility under section 182(b)(2) for States to submit reasonably available control
technology (RACT) rules for stationary sources of VOC as part of their State Implementation
Plans.
Control Technology; Control Measures: Equipment, processes or actions used to reduce air
pollution. The extent of pollution reduction varies among technologies and measures.
Criteria Air Pollutant: A pollutant designated by the Administrator, using the latest scientific
knowledge, to have effects on public health or welfare which may be expected from the
presence of such pollutant in the ambient air, in varying quantities. The types of air pollutants
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which, when present in the atmosphere, may interact with such pollutant to produce an adverse
effect on public health or welfare; and any known or anticipated adverse effects on welfare.
Cyclone boiler: means a boiler with one or more water-cooled horizontal cylindrical chambers
in which coal combustion takes place. The horizontal cylindrical chamber(s) is (are) attached to
the bottom of the furnace. One or more cylindrical chambers are arranged either on one furnace
wall or on two opposed furnace walls. Gaseous combustion products exiting from the
chamber(s) turn 90 degrees to go up through the boiler while coal ash exits the bottom of the
boiler as a molten slag.
Dry bottom: means the boiler has a furnace bottom temperature below the ash melting point and
the bottom ash is removed as a solid.
Emission inventory: means a listing of the quantity of pollutants being emitted from sources
within a geographic boundary (i.e., country, State, nation). The listing can be broken down into
point (individual facilities), area (other stationary sources), mobile (on-road and non-road), and
biogenic emissions. Ancillary information such as stack parameters, activity data, and vehicle
type are also considered part of an emission inventory.
Emission Rate: The weight of a pollutant emitted per unit of time (e.g., tons/year).
Federal Implementation Plan (FIP): In the absence of an approved State Implementation Plan
(SIP), a plan prepared by EPA which provides measures that nonattainment areas must take to
meet the requirements of the Federal Clean Air Act.
Inspection and Maintenance Program (I/M program): A periodic automobile inspection,
usually done once a year or once every two years to check whether a car is being maintained to
keep pollution down and whether emission control systems are working properly. Vehicles
which do not pass inspection must be repaired.
Lifetime: The estimated years add-on control equipment will operated before it must be
replaced.
Maximum Achievable Control Technology (MACT): Federal emissions limitations based on
the best demonstrated control technology or practices in similar sources to be applied to major
sources emitting one or more federal HAP.
MEAS Code: An alphanumeric code assigned to each individual control measure in the
AirControlNET Model. These are unique and used internally by Pechan.
New Source Performance Standards (NSPS): Uniform national EPA air emission standards
that limit the amount of pollution allowed from new sources or from modified existing sources.
Operating and Maintenance Costs (O&M): The costs associated with work and materials
needed to preserve asset components to allow their continued use. This definition encompasses
any actions intended to prevent failure or inefficient operation, and includes housekeeping and
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custodial work. Operating Maintenance does not necessarily prolong the design service life of
the property of equipment, nor does it add to the asset's value. However, lack of maintenance can
reduce an asset's value by leading to equipment breakdown, premature failure of a building's
subsystems and shortening of the asset's useful service lifetime.
Reasonably Available Control Technology (RACT): Defined as the lowest emission limitation
that a particular source is capable of meeting by the application of control technology that is
reasonably available, considering technological and economic feasibility.
Rule Effectiveness: a generic term for identifying and estimating the uncertainties in emission
estimates caused by failures and uncertainties in emission control programs. Literally, it is the
extent to which a rule achieves the desired emission reductions.
Source Category: Categories of places or objects from which air pollutants are released.
Sources that are fixed in space are stationary sources and sources that move or are capable of
moving are mobile sources. See Area, Mobile and Stationary.
•	Area sources—means stationary and non-road sources that are too numerous or whose
emissions are too small to be individually included in a stationary source emissions
inventory.
•	Mobile sources—means on-road (highway) vehicles (e.g., automobiles, trucks and
motorcycles) and non-road vehicles and engines (e.g., trains, airplanes, agricultural
equipment, industrial equipment, construction vehicles, off-road motorcycles, and marine
vessels).
•	Point Sources: Specific points of origin where pollutants are emitted into the atmosphere
from stationary sources such as factory smokestacks.
•	Stationary Sources: Non-mobile sources such as power plants, refineries, and
manufacturing facilities which emit air pollutants.
State Implementation Plan (SIP): A plan prepared by States and submitted to EPA describing
how each area will attain and maintain national ambient air quality standards. SIPs include the
technical foundation for understanding the air quality (e.g. emission inventories and air quality
monitoring), control measures and strategies, and enforcement mechanisms.
Stoker boiler: means a boiler that burns solid fuel in a bed, on a stationary or moving grate, that
is located at the bottom of the furnace.
Tangentially fired boiler: means a boiler that has coal and air nozzles mounted in each corner
of the furnace where the vertical furnace walls meet. Both pulverized coal and air are directed
from the furnace corners along a line tangential to a circle lying in a horizontal plane of the
furnace.
Transportation Control Measure (TCM): Any control measure to reduce vehicle trips, vehicle
use, vehicle miles traveled, vehicle idling, or traffic congestion for the purpose of reducing on-
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road motor vehicle emissions. TCMs can include encouraging the use of carpools and mass
transit.
Wall-fired boiler: means a boiler that has pulverized coal burners arranged on the walls of the
furnace. The burners have discrete, individual flames that extend perpendicularly into the
furnace area.
Wet bottom: means that the ash is removed from the furnace in a molten state. The term "wet
bottom boiler" shall include: wet bottom wall-fired boilers, including wet bottom turbo-fired
boilers; and wet bottom boilers otherwise meeting the definition of vertically fired boilers,
including wet bottom arch-fired boilers, wet bottom roof-fired boilers, and wet bottom top-fired
boilers. The term "wet bottom boiler" shall exclude cyclone boilers and tangentially fired
boilers.
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CHAPTER I. INTRODUCTION
AirControlNET is a control technology analysis tool developed by E.H. Pechan & Associates,
Inc. (Pechan) to support the U.S. Environmental Protection Agency (EPA) in its analyses of air
pollution policies and regulations. The tool provides data on emission sources, potential
pollution control measures and emission reductions, and the costs of implementing those
controls.
The core of AirControlNET is a relational database system in which control technologies are
linked to sources within EPA emissions inventories. The system contains a database of control
measure applicability, efficiency, and cost information for reducing the emissions contributing to
ambient concentrations of ozone, PM10, PM2 5, S02, N02, as well as visibility impairment
(regional haze) from point, area, and mobile sources. PM10 and PM2 5 as included in
AirControlNET represent primary emissions of PM. The control measure data file in
AirControlNET includes not only the technology's control efficiency, and calculated emission
reductions for that source, but also estimates the costs (annual and capital) for application of the
control measure.
This document describes the control technology and cost information that is used to create the
control measure database. The AirControlNET User's Guide and Development Report provide
details of the installation, system requirements, use of the AirControlNET interface, and control
measure database development (Pechan, 2005a and Pechan, 2005b).
AirControlNET relies on the control efficiency, throughput, fuel use, and emission factor data
provided in the NEI to perform cost related analysis. But AirControlNET also requires
information about individual control measures. This information is obtained by examining the
technical and economic data available on the control measures. AirControlNET currently
contains information on several hundred different control measure/source combinations.
Pechan has collected information on control measure and reported it to the EPA through several
technical reports. Important aspects of each control measure, such as application, functionality,
cost and control efficiencies were reported at the time of analysis. The purpose of this document
is to compile and summarize this information for the control measures presently available in
AirControlNET to provide a central location of the information.
Individual control measures are discussed in this report under the Control Measure
Documentation chapter (Chapter III). Some of the important aspects of analysis used for these
control measures are summarized in the Summary section of this report. Table 1-1 provides a list
of AirControlNET related publications prepared by Pechan. The References section contains
complete citations.
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Table 1-1. List of Related Publications Prepared by Pechan and EPA that Contain
Useful Control Measure Information
Publication Name
Publication
Date
Comments
AirControlNET User's Guide
03/2005
Learn how to install and use
AirControlNET
AirControlNET Tool Development Kit
03/2005
Learn how the AirControlNET
application and control measure
databases were developed
VOC and NOx Control Measures Adopted by
States and Nonattainment Areas for 1999 NEI
Base Case Emissions Projection Calculations,
Pechan Report No. 02.09.002/9010.122
09/2002
Contains information on local
controls adopted through ozone
SIPs
Revisions to AirControlNET and Particulate
Matter Control Strategies and Cost Analysis,
Pechan Report No. 01.09.9010.007
09/2001
Control measure research and
evaluations
Control Measure Development Support Analysis
of Ozone Transport Commission Model Rules,
Pechan Report No. 01.02.001/9408.000
02/2001
Control measure research and
evaluations
EPA Air Pollution Control Cost Manual," 6th ed.,
EPA/452/B-02-001, Research Triangle Park, NC.
01/2002
Control measure research and
evaluations
Control Measure Evaluations: The Control
Measure Data Base for the National Emissions
Trends Inventory (AirControlNET), by E.H.
Pechan & Associates, Pechan Report No.
99.09.001/9004.112
09/1999
Control measure research and
evaluations
Control Measure Evaluations Prepared for South
Central and Reading-Lehigh Valley Pennsylvania
Ozone Stakeholders Groups - Report," prepared
for Pennsylvania Department of Environmental
Protection, Bureau of Air Quality, Harrisburg, PA,
by E.H. Pechan & Associates
12/1999
Control measure research and
evaluations
Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S.
Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative
Strategies and Economics Group, Research
Triangle Park, NC, prepared by E.H. Pechan &
Associates, Inc., September 1998
09/1998
Control measure research and
evaluations
Control Measure Evaluation for the Integrated
Implementation of the Ozone and particulate
Matter National Ambient Air Quality Standards
and Regional Haze Program, Pechan Report No.
97.03.001/1800 (Rev.)
04/1997
Control measure research and
evaluations
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Table 1-1 (continued)
Publication Name
Publication
Date
Comments
Additional Control Measure Evaluation for The
Integrated Implementation of the Ozone and
Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program, Pechan
Report No. 97.03.001/1800 (Rev.)
03/1997
Control measure research and
evaluations
Regional Particulate Strategies, Pechan Report
No. 95.09.0005/1754
09/1995
Control measure research and
evaluations
Analysis of Incremental Emission Reductions and
Costs of VOC and NOx Control Measures,
prepared for U.S. Environmental Protection
Agency, Ambient Standards Branch, Research
Triangle Park, NC, prepared by E.H. Pechan &
Associates, Inc., September 1994.
09/1994
Control measure research and
evaluations
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Additionally, three appendices are included to provide helpful summary information. Appendix
A provides a control measure summary list sorted by source category. Appendix B provides a
control measure summary list sorted by pollutant. Appendix C provides a SCC-SIC-NAICS
Crosswalk.
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CHAPTER II. SUMMARY
The control measure data needed to generate the costs and emission reductions for measures in
AirControlNET include throughput, fuel use, and emission factor data provided in EPA emission
inventories such as the National Emissions Inventory (NEI).
AirControlNET's database system links control measures to pollution sources identified in EPA
point, area, and mobile source emissions inventories. The resulting database of control measures
contains information on each measure, including emission reduction, control efficiency, and cost
information. Control measures are included for emissions contributing to ambient
concentrations of ozone, PM2 5, PM10, S02, and N02, as well as visibility impairment (regional
haze). The control measure data in AirControlNET includes not only the measure's control
efficiency and calculated emission reduction for that source, but also estimates the costs (annual
and capital, and sometimes O&M) for application of the control measure.
In determining the costs for each control measure, AirControlNET links basic cost information
from EPA and other studies to input parameters contained in the emission inventory. Currently,
AirControlNET contains several hundred source category and pollutant-specific control
measures. Table II-l provides a summary of the number of control measures that are presently
in AirControlNET.
Table 11-1. Number of Control Measures in AirControlNET,
by Sector and Pollutant


Non-




Major Pollutant
Utility
Utilitv
Area
On road
Nonroad
Total
NH,
0
0
3
0
0
3
NOv
26
417
15
15
8
481
PM
24
165
12
13
0
214
SO,
6
37
0
0
0
43
VOC
0
7
65
5
12
89
Ha
5
0
0
0
0
5
The control measures in AirControlNET have been developed through a series of studies
prepared to support rulemakings or research. Important elements that are identified for each
control measure. These elements are discussed below and summarized for each measure in the
at-a-glance tables in Chapter III of this report. Some of the important factors that have been
studied are:
Pollutants: AirControlNET contains a database of control measures and cost information for
emissions contributing to ambient concentrations of ozone, PM2 5, PM10, S02, and N02, as well
as visibility impairment (regional haze). Presently this system includes controls for NOx, S02,
VOC, PM10, PM2 5 Hg and NH3. PM10 and PM2 5 as included in AirControlNET represent
primary emissions of PM.
Sector: AirControlNET relies heavily upon EPA emission inventory data as a source of
emissions. The control measures from utility, point, area, and mobile source sector emissions
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Sector: AirControlNET relies heavily upon EPA emission inventory data as a source of
emissions. The control measures from utility, point, area, and mobile source sector emissions
inventories are supplied in EPA's National Emission Inventory (NEI) can be used in creating
overall emission reduction scenarios in which the associated costs can be estimated.
Control Efficiencies: The control measure data file in AirControlNET includes the technology's
control efficiency. The control measure's control efficiency sometimes reflects a set of baseline
conditions that are elaborated upon in the at-a-glance tables in Chapter III of the report, where
appropriate.
Cost Information: The cost information in AirControlNET may have many components
including annual, capital, and operation & maintenance costs for application of the control
measure. The individual control measure reference documents discuss the source of the cost
information. Other components include capital recovery factor and dollar year of cost estimate
(i.e., SI997).
Base Year of Cost: The cost information for the control measures have been compiled through a
series of analyses performed by EPA and others over several years. In every case, the costs for
control measure is estimated in the base year provided by the original study. AirControlNET
converts to consistent year dollars.
POD: The cost POD is an internal field which groups together similar source types. We can
think of them as a group of sources similar enough that a specific control measure can be applied
to all SCCs in the group.
Affected SCC: The Source Classification Code, or the SCC, in combination with the POD are
what link the control measure information to the NEI data. This linkage is essential for
AirControlNET functions which allow the user to create various cost related scenarios based on
the selected control measures applied to specific sources of emission.
Rule Effectiveness: Rule effectiveness is the assumption of how effective a rule containing a
control measure would be. Rule effectiveness is generally 80 to 100 percent for point source
rules and potentially less for area source or mobile source rules.
Rule Penetration: Rule Penetration is the assumed fraction of the targeted SCC which are
affected by the control measure. It is generally assumed 100 percent for point sources, but can be
less for area or mobile sources.
Measure Code: The control measures codes are unique codes assigned by E.H. Pechan &
Associates that specify control measure and source type combination. Each measure in Chapter
III of this report is identified by an alphanumeric measure code or a "meas code". The first
character of the code is a letter that corresponds to the major pollutant controlled.
Typical Value: The typical value often referred to in this report is the value used in
AirControlNET. The value has been determined to be the "best" value for a measure of interest
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(e.g. control efficiency). The typical value can be, but is not necessarily, a statistical measure of
central tendency.
Table II-2 provides a list of the control measures and sources documented in this report.
To obtain further information on AirControlNET, please contact:
EPA Contact:	Larry Sorrels at sorrels.larry@epamail.epa.gov
E.H. Pechan Contact:	Frank Divita at fdivita@pechan.com
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Table 11-2. Control Measures Included in AirControlNET
Measure
Code
Source Category
Major
Pollutant
Control Measure
A00101
Cattle Feedlots
NH3
Chemical Additives to Waste
A00201
Poultry Operations
NH3
Chemical Additives to Waste
A00301
Hog Operations
NH3
Chemical Additives to Waste
AT2010
Off-Highway Vehicles: All Terrain
Vehicles (ATVs)
VOC
2010 Implementation of Recreational Gasoline
ATV Standards
AT2015
Off-Highway Vehicles: All Terrain
Vehicles (ATVs)
VOC
2015 Implementation of Recreational Gasoline
ATV Standards
AT2020
Off-Highway Vehicles: All Terrain
Vehicles (ATVs)
VOC
2020 Implementation of Recreational Gasoline
ATV Standards
AT2030
Off-Highway Vehicles: All Terrain
Vehicles (ATVs)
VOC
2030 Implementation of Recreational Gasoline
ATV Standards
CI2010
Off-Highway Diesel Vehicles
NOX
2010 Implementation of Final Compression-
Ignition (C-l) Engine Standards
CI2015
Off-Highway Diesel Vehicles
NOX
2015 Implementation of Final Compression-
Ignition (C-l) Engine Standards
CI2020
Off-Highway Diesel Vehicles
NOX
2020 Implementation of Final Compression-
Ignition (C-l) Engine Standards
CI2030
Off-Highway Diesel Vehicles
NOX
2030 Implementation of Final Compression-
Ignition (C-l) Engine Standards
HDD10
Highway Vehicles - Heavy Duty and
Diesel-Fueled Vehicles
NOX
2010 Implementation of Heavy Duty Engine and
Vehicle Standards and Highway Diesel Fuel
Sulfur C
HDD15
Highway Vehicles - Heavy Duty and
Diesel-Fueled Vehicles
NOX
2015 Implementation of Heavy Duty Engine and
Vehicle Standards and Highway Diesel Fuel
Sulfur C
HDD20
Highway Vehicles - Heavy Duty and
Diesel-Fueled Vehicles
NOX
2020 Implementation of Heavy Duty Engine and
Vehicle Standards and Highway Diesel Fuel
Sulfur C
HDD30
Highway Vehicles - Heavy Duty and
Diesel-Fueled Vehicles
NOX
2030 Implementation of Heavy Duty Engine and
Vehicle Standards and Highway Diesel Fuel
Sulfur C
HDR101
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Diesel
Particulate Filter - 2001
HDR110
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Diesel
Particulate Filter - 2010
HDR115
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Diesel
Particulate Filter - 2015
HDR199
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Diesel
Particulate Filter -1999
HDR201
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Diesel
Oxidation Catalyst - 2001
HDR210
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Diesel
Oxidation Catalyst - 2010
HDR215
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Diesel
Oxidation Catalyst - 2015
HDR299
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Diesel
Oxidation Catalyst -1999
HDR301
Highway Vehicles - Heavy Duty Diesel
Engines
NOX
Voluntary Diesel Retrofit Program: Selective
Catalytic Reduction - 2001
HDR310
Highway Vehicles - Heavy Duty Diesel
Engines
NOX
Voluntary Diesel Retrofit Program: Selective
Catalytic Reduction - 2010
HDR315
Highway Vehicles - Heavy Duty Diesel
Engines
NOX
Voluntary Diesel Retrofit Program: Selective
Catalytic Reduction - 2015
HDR399
Highway Vehicles - Heavy Duty Diesel
Engines
NOX
Voluntary Diesel Retrofit Program: Selective
Catalytic Reduction -1999
HDR401
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Biodiesel
Fuel - 2001
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Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
HDR410
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Biodiesel
Fuel-2010
HDR415
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Biodiesel
Fuel-2015
HDR499
Highway Vehicles - Heavy Duty Diesel
Engines
PM
Voluntary Diesel Retrofit Program: Biodiesel
Fuel - 1999
MC2010
Off-Highway Vehicles: Motorcycles
VOC
2010 Implementation of Recreational Gasoline
Off-Highway Motorcycle Standards
MC2015
Off-Highway Vehicles: Motorcycles
voc
2015 Implementation of Off-Highway Motorcycle
Standards
MC2020
Off-Highway Vehicles: Motorcycles
VOC
2020 Implementation of Off-Highway Motorcycle
Standards
MC2030
Off-Highway Vehicles: Motorcycles
voc
2030 Implementation of Off-Highway Motorcycle
Standards
N00101
Utility Boiler - Coal/Wall
NOX
Selective Non-Catalytic Reduction (SNCR)
N00102
Utility Boiler - Coal/Wall
NOX
Natural Gas Reburn (NGR)
N00103
Utility Boiler - Coal/Wall
NOX
Selective Catalytic Reduction (SCR)
N00201
Utility Boiler - Coal/Tangential
NOX
Selective Non-Catalytic Reduction (SNCR)
N00202
Utility Boiler - Coal/Tangential
NOX
Natural Gas Reburn (NGR)
N00203
Utility Boiler - Coal/Tangential
NOX
Selective Catalytic Reduction (SCR)
N00501
Utility Boiler - Oil-Gas/Wall
NOX
Selective Non-Catalytic Reduction (SNCR)
N00502
Utility Boiler - Oil-Gas/Wall
NOX
Natural Gas Reburn (NGR)
N00503
Utility Boiler - Oil-Gas/Wall
NOX
Selective Catalytic Reduction (SCR)
N00601
Utility Boiler - Oil-Gas/Tangential
NOX
Selective Non-Catalytic Reduction (SNCR)
N00602
Utility Boiler - Oil-Gas/Tangential
NOX
Natural Gas Reburn (NGR)
N00603
Utility Boiler - Oil-Gas/Tangential
NOX
Selective Catalytic Reduction (SCR)
N00701
Utility Boiler - Cyclone
NOX
Selective Non-Catalytic Reduction (SNCR)
N00702
Utility Boiler - Cyclone
NOX
Natural Gas Reburn (NGR)
N00703
Utility Boiler - Cyclone
NOX
Selective Catalytic Reduction (SCR)
N00801
Coal-fired Plants with Production
Capacities>100MW
NOX
Combustion Optimization
N00901
Utility Boiler - Coal/Wall
NOX
Low NOx Burner
N00902
Utility Boiler - Coal/Wall
NOX
Low NOx Burner with Overfire Air
N00903
Utility Boiler - Coal/Tangential
NOX
Low NOx Coal-and-Air Nozzles with Close-
Coupled Overfire Air
N00904
Utility Boiler - Coal/Tangential
NOX
Low NOx Coal-and-Air Nozzles with Separated
Overfire Air
N00905
Utility Boiler - Coal/Tangential
NOX
Low NOx Coal-and-Air Nozzles with Close-
Coupled and Separated Overfire Air
N00906
Utility Boiler - Coal/Wall
NOX
Low NOx Burner
N00907
Utility Boiler - Coal/Wall
NOX
Low NOx Burner with Overfire Air
N00908
Utility Boiler - Coal/Tangential
NOX
Low NOx Coal-and-Air Nozzles with Close-
Coupled Overfire Air
N00909
Utility Boiler - Coal/Tangential
NOX
Low NOx Coal-and-Air Nozzles with Separated
Overfire Air
N00910
Utility Boiler - Coal/Tangential
NOX
Low NOx Coal-and-Air Nozzles with Close-
Coupled and Separated Overfire Air
N01101
ICI Boilers - Coal/Wall
NOX
Selective Non-Catalytic Reduction (SNCR)
N01103
ICI Boilers - Coal/Wall
NOX
Low NOx Burner
N01104
ICI Boilers - Coal/Wall
NOX
Selective Catalytic Reduction (SCR)
N0111L
ICI Boilers - Coal/Wall - Large
NOX
Selective Non-Catalytic Reduction (SNCR)
N0111S
ICI Boilers - Coal/Wall
NOX
Selective Non-Catalytic Reduction (SNCR)
N0113L
ICI Boilers - Coal/Wall - Large
NOX
Low NOx Burner
N0113S
ICI Boilers - Coal/Wall
NOX
Low NOx Burner
N0114L
ICI Boilers - Coal/Wall - Large
NOX
Selective Catalytic Reduction (SCR)
N0114S
ICI Boilers - Coal/Wall
NOX
Selective Catalytic Reduction (SCR)
Document No. 05.09.009/9010.463
II-5
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
N01201
ICI Boilers - Coal/FBC
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N0121L
ICI Boilers - Coal/FBC - Large Sources
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N0121S
ICI Boilers - Coal/FBC
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N01301
ICI Boilers - Coal/Stoker
NOX
Selective Non-Catalytic Reduction (SNCR)
N0131L
ICI Boilers - Coal/Stoker - Large
NOX
Selective Non-Catalytic Reduction (SNCR)
N0131S
ICI Boilers - Coal/Stoker
NOX
Selective Non-Catalytic Reduction (SNCR)
N01401
ICI Boilers - Coal/Cyclone
NOX
Selective Non-Catalytic Reduction (SNCR)
N01402
ICI Boilers - Coal/Cyclone
NOX
Coal Reburn
N01403
ICI Boilers - Coal/Cyclone
NOX
Selective Catalytic Reduction (SCR)
N01404
ICI Boilers - Coal/Cyclone
NOX
Natural Gas Reburn (NGR)
N0141S
ICI Boilers - Coal/Cyclone
NOX
Selective Non-Catalytic Reduction (SNCR)
N0142L
ICI Boilers - Coal/Cyclone - Large
Sources
NOX
Coal Reburn
N0142S
ICI Boilers - Coal/Cyclone
NOX
Coal Reburn
N0143S
ICI Boilers - Coal/Cyclone
NOX
Selective Catalytic Reduction (SCR)
N0144S
ICI Boilers - Coal/Cyclone
NOX
Natural Gas Reburn (NGR)
N01501
ICI Boilers - Residual Oil
NOX
Low NOx Burner
N01502
ICI Boilers - Residual Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N01503
ICI Boilers - Residual Oil
NOX
Selective Catalytic Reduction (SCR)
N01504
ICI Boilers - Residual Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N0151S
ICI Boilers - Residual Oil
NOX
Low NOx Burner
N0152S
ICI Boilers - Residual Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N0153S
ICI Boilers - Residual Oil
NOX
Selective Catalytic Reduction (SCR)
N0154L
ICI Boilers - Residual Oil - Large Sources
NOX
Selective Non-Catalytic Reduction (SNCR)
N0154S
ICI Boilers - Residual Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N01601
ICI Boilers - Distillate Oil
NOX
Low NOx Burner
N01602
ICI Boilers - Distillate Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N01603
ICI Boilers - Distillate Oil
NOX
Selective Catalytic Reduction (SCR)
N01604
ICI Boilers - Distillate Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N0161S
ICI Boilers - Distillate Oil
NOX
Low NOx Burner
N0162S
ICI Boilers - Distillate Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N0163S
ICI Boilers - Distillate Oil
NOX
Selective Catalytic Reduction (SCR)
N0164S
ICI Boilers - Distillate Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N01701
ICI Boilers - Natural Gas
NOX
Low NOx Burner
N01702
ICI Boilers - Natural Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N01703
ICI Boilers - Natural Gas
NOX
Oxygen Trim + Water Injection
N01704
ICI Boilers - Natural Gas
NOX
Selective Catalytic Reduction (SCR)
N01705
ICI Boilers - Natural Gas
NOX
Selective Non-Catalytic Reduction (SNCR)
N0171S
ICI Boilers - Natural Gas
NOX
Low NOx Burner
N0172S
ICI Boilers - Natural Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N0173S
ICI Boilers - Natural Gas
NOX
Oxygen Trim + Water Injection
N0174S
ICI Boilers - Natural Gas
NOX
Selective Catalytic Reduction (SCR)
N0175L
ICI Boilers - Natural Gas - Large Sources
NOX
Selective Non-Catalytic Reduction (SNCR)
N0175S
ICI Boilers - Natural Gas
NOX
Selective Non-Catalytic Reduction (SNCR)
N01801
ICI Boilers - Wood/Bark/Stoker
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N0181L
ICI Boilers - Wood/Bark/Stoker - Large
Sources
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N0181S
ICI Boilers - Wood/Bark/Stoker
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N02001
ICI Boilers - MSW/Stoker
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N0201S
ICI Boilers - MSW/Stoker
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
Document No. 05.09.009/9010.463
II-6
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
N02101
Internal Combustion Engines - Oil
NOX
Ignition Retard
N02104
Internal Combustion Engines - Oil
NOX
Selective Catalytic Reduction (SCR)
N02105
Rich Burn Internal Combustion Engines -
Oil
NOX
Non-Selective Catalytic Reduction (NSCR)
N0211S
Internal Combustion Engines - Oil
NOX
Ignition Retard
N0214S
Internal Combustion Engines - Oil
NOX
Selective Catalytic Reduction (SCR)
N0215S
Rich Burn Internal Combustion Engines -
Oil
NOX
Non-Selective Catalytic Reduction (NSCR)
N02201
Internal Combustion Engines - Gas
NOX
L-E (Medium Speed)
N02204
Internal Combustion Engines - Gas
NOX
Air/Fuel Ratio Adjustment
N02207
Internal Combustion Engines - Gas
NOX
Air/Fuel + Ignition Retard
N02210
Internal Combustion Engines - Gas
NOX
L-E (Medium Speed)
N02211
IC Engines - Gas
NOX
L-E (Low Speed)
N02212
IC Engines - Gas
NOX
Selective Catalytic Reduction (SCR)
N02213
Rich Burn IC Engines - Gas
NOX
Non-Selective Catalytic Reduction (NSCR)
N0221L
Internal Combustion Engines - Gas
NOX
Ignition Retard
N0221S
Internal Combustion Engines - Gas
NOX
Ignition Retard
N0224L
Internal Combustion Engines - Gas -
Large
NOX
Air/Fuel Ratio Adjustment
N0224S
Internal Combustion Engines - Gas
NOX
Air/Fuel Ratio Adjustment
N0227L
Internal Combustion Engines - Gas -
Large
NOX
Air/Fuel + Ignition Retard
N0227S
Internal Combustion Engines - Gas
NOX
Air/Fuel + Ignition Retard
N02301
Combustion Turbines - Oil
NOX
Water Injection
N02302
Combustion Turbines - Oil
NOX
Selective Catalytic Reduction (SCR) + Water
Injection
N0231S
Combustion Turbines - Oil
NOX
Water Injection
N0232S
Combustion Turbines - Oil
NOX
Selective Catalytic Reduction (SCR) + Water
Injection
N02401
Combustion Turbines - Natural Gas
NOX
Water Injection
N02402
Combustion Turbines - Natural Gas
NOX
Steam Injection
N02403
Combustion Turbines - Natural Gas
NOX
Dry Low NOx Combustor
N02404
Combustion Turbines - Natural Gas
NOX
Selective Catalytic Reduction (SCR) + Low NOx
Burner (LNB)
N02405
Combustion Turbines - Natural Gas
NOX
Selective Catalytic Reduction (SCR) + Steam
Injection
N02406
Combustion Turbines - Natural Gas
NOX
Selective Catalytic Reduction (SCR) + Water
Injection
N0241S
Combustion Turbines - Natural Gas
NOX
Water Injection
N0242S
Combustion Turbines - Natural Gas
NOX
Steam Injection
N0243L
Combustion Turbines - Natural Gas -
Large Sources
NOX
Dry Low NOx Combustors
N0243S
Combustion Turbines - Natural Gas
NOX
Dry Low NOx Combustors
N0244S
Combustion Turbines - Natural Gas
NOX
Selective Catalytic Reduction (SCR) + Low NOx
Burner (LNB)
N0245S
Combustion Turbines - Natural Gas
NOX
Selective Catalytic Reduction (SCR) + Steam
Injection
N0246S
Combustion Turbines - Natural Gas
NOX
Selective Catalytic Reduction (SCR) + Water
Injection
N02501
Process Heaters - Distillate Oil
NOX
Low NOx Burner
N02502
Process Heaters - Distillate Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N02503
Process Heaters - Distillate Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N02504
Process Heaters - Distillate Oil
NOX
Ultra Low NOx Burner
N02505
Process Heaters - Distillate Oil
NOX
Selective Catalytic Reduction (SCR)
N02506
Process Heaters - Distillate Oil
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
Document No. 05.09.009/9010.463
II-7
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure

Major

Code
Source Category
Pollutant
Control Measure
N02507
Process Heaters - Distillate Oil
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N0251S
Process Heaters - Distillate Oil
NOX
Low NOx Burner
N0252S
Process Heaters - Distillate Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N0253S
Process Heaters - Distillate Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N0254S
Process Heaters - Distillate Oil
NOX
Ultra Low NOx Burner
N0255S
Process Heaters - Distillate Oil
NOX
Selective Catalytic Reduction (SCR)
N0256S
Process Heaters - Distillate Oil
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N0257S
Process Heaters - Distillate Oil
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N02601
Process Heaters - Residual Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N02602
Process Heaters - Residual Oil
NOX
Low NOx Burner
N02603
Process Heaters - Residual Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N02604
Process Heaters - Residual Oil
NOX
Ultra Low NOx Burner
N02605
Process Heaters - Residual Oil
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N02606
Process Heaters - Residual Oil
NOX
Selective Catalytic Reduction (SCR)
N02607
Process Heaters - Residual Oil
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N0261S
Process Heaters - Residual Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N0262S
Process Heaters - Residual Oil
NOX
Low NOx Burner
N0263S
Process Heaters - Residual Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N0264S
Process Heaters - Residual Oil
NOX
Ultra Low NOx Burner
N0265S
Process Heaters - Residual Oil
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N0266S
Process Heaters - Residual Oil
NOX
Selective Catalytic Reduction (SCR)
N0267S
Process Heaters - Residual Oil
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N02701
Process Heaters - Natural Gas
NOX
Low NOx Burner
N02702
Process Heaters - Natural Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N02703
Process Heaters - Natural Gas
NOX
Selective Non-Catalytic Reduction (SNCR)
N02704
Process Heaters - Natural Gas
NOX
Ultra Low NOx Burner
N02705
Process Heaters - Natural Gas
NOX
Selective Catalytic Reduction (SCR)
N02706
Process Heaters - Natural Gas
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N02707
Process Heaters - Natural Gas
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N0271S
Process Heaters - Natural Gas
NOX
Low NOx Burner
N0272S
Process Heaters - Natural Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N0273S
Process Heaters - Natural Gas
NOX
Selective Non-Catalytic Reduction (SNCR)
N0274S
Process Heaters - Natural Gas
NOX
Ultra Low NOx Burner
N0275S
Process Heaters - Natural Gas
NOX
Selective Catalytic Reduction (SCR)
N0276S
Process Heaters - Natural Gas
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N0277S
Process Heaters - Natural Gas
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N02901
Nitric Acid Manufacturing
NOX
Extended Absorption
N02902
Nitric Acid Manufacturing
NOX
Selective Catalytic Reduction (SCR)
N02903
Nitric Acid Manufacturing
NOX
Selective Non-Catalytic Reduction (SNCR)
N0291S
Nitric Acid Manufacturing
NOX
Extended Absorption
N0292S
Nitric Acid Manufacturing
NOX
Selective Catalytic Reduction (SCR)
N0293S
Nitric Acid Manufacturing
NOX
Selective Non-Catalytic Reduction (SNCR)
N03001
Glass Manufacturing - Containers
NOX
Electric Boost
N03002
Glass Manufacturing - Containers
NOX
Cullet Preheat
N03003
Glass Manufacturing - Containers
NOX
Low NOx Burner
N03004
Glass Manufacturing - Containers
NOX
Selective Non-Catalytic Reduction (SNCR)
Document No. 05.09.009/9010.463
II-8
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
N03005
Glass Manufactur
ng - Containers
NOX
Selective Catalytic Reduction (SCR)
N03006
Glass Manufactur
ng - Containers
NOX
OXY-Firing
N0301S
Glass Manufactur
ng - Containers
NOX
Electric Boost
N0302S
Glass Manufactur
ng - Containers
NOX
Cullet Preheat
N0303S
Glass Manufactur
ng - Containers
NOX
Low NOx Burner
N0304S
Glass Manufactur
ng - Containers
NOX
Selective Non-Catalytic Reduction (SNCR)
N0305S
Glass Manufactur
ng - Containers
NOX
Selective Catalytic Reduction (SCR)
N0306S
Glass Manufactur
ng - Containers
NOX
OXY-Firing
N03101
Glass Manufactur
ng - Flat
NOX
Electric Boost
N03102
Glass Manufactur
ng - Flat
NOX
Low NOx Burner
N03103
Glass Manufactur
ng - Flat
NOX
Selective Non-Catalytic Reduction (SNCR)
N03104
Glass Manufactur
ng - Flat
NOX
Selective Catalytic Reduction (SCR)
N03105
Glass Manufactur
ng - Flat
NOX
OXY-Firing
N0311L
Glass Manufactur
ng - Flat - Large
NOX
Electric Boost
N0311S
Glass Manufactur
ng - Flat
NOX
Electric Boost
N0312L
Glass Manufactur
ng - Flat
NOX
Low NOx Burner
N0312S
Glass Manufactur
ng - Flat
NOX
Low NOx Burner
N0313L
Glass Manufactur
ng - Flat
NOX
Selective Non-Catalytic Reduction (SNCR)
N0313S
Glass Manufactur
ng - Flat
NOX
Selective Non-Catalytic Reduction (SNCR)
N0314L
Glass Manufactur
ng - Flat
NOX
Selective Catalytic Reduction (SCR)
N0314S
Glass Manufactur
ng - Flat
NOX
Selective Catalytic Reduction (SCR)
N0315L
Glass Manufactur
ng - Flat - Large
NOX
OXY-Firing
N0315S
Glass Manufactur
ng - Flat
NOX
OXY-Firing
N03201
Glass Manufactur
ng - Pressed
NOX
Electric Boost
N03202
Glass Manufactur
ng - Pressed
NOX
Cullet Preheat
N03203
Glass Manufactur
ng - Pressed
NOX
Low NOx Burner
N03204
Glass Manufactur
ng - Pressed
NOX
Selective Non-Catalytic Reduction (SNCR)
N03205
Glass Manufactur
ng - Pressed
NOX
Selective Catalytic Reduction (SCR)
N03206
Glass Manufactur
ng - Pressed
NOX
OXY-Firing
N0321S
Glass Manufactur
ng - Pressed
NOX
Electric Boost
N0322S
Glass Manufactur
ng - Pressed
NOX
Cullet Preheat
N0323S
Glass Manufactur
ng - Pressed
NOX
Low NOx Burner
N0324S
Glass Manufactur
ng - Pressed
NOX
Selective Non-Catalytic Reduction (SNCR)
N0325S
Glass Manufactur
ng - Pressed
NOX
Selective Catalytic Reduction (SCR)
N0326S
Glass Manufactur
ng - Pressed
NOX
OXY-Firing
N03301
Cement Manufacturing - Dry
NOX
Mid-Kiln Firing
N03302
Cement Manufacturing - Dry
NOX
Low NOx Burner
N03303
Cement Manufacturing - Dry
NOX
Selective Non-Catalytic Reduction (SNCR)
Ammonia Based
N03304
Cement Manufacturing - Dry
NOX
Selective Non-Catalytic Reduction (SNCR)
Ammonia Based
N03305
Cement Manufacturing - Dry
NOX
Selective Catalytic Reduction (SCR)
N0331L
Cement Manufacturing - Dry
NOX
Mid-Kiln Firing
N0331S
Cement Manufacturing - Dry
NOX
Mid-Kiln Firing
N0332S
Cement Manufacturing - Dry
NOX
Low NOx Burner
N0333S
Cement Manufacturing - Dry
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N0334S
Cement Manufacturing - Dry
NOX
Selective Non-Catalytic Reduction (SNCR)
Ammonia Based
N0335S
Cement Manufacturing - Dry
NOX
Selective Catalytic Reduction (SCR)
N03401
Cement Manufacturing - Wet
NOX
Mid-Kiln Firing
N03402
Cement Manufacturing - Wet
NOX
Low NOx Burner
N03403
Cement Manufacturing - Wet
NOX
Selective Catalytic Reduction (SCR)
N0341L
Cement Manufacturing - Wet
NOX
Mid-Kiln Firing
N0341S
Cement Manufacturing - Wet
NOX
Mid-Kiln Firing
N0342L
Cement Manufacturing - Wet
NOX
Low NOx Burner
N0342S
Cement Manufacturing - Wet
NOX
Low NOx Burner
Document No. 05.09.009/9010.463
II-9
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
N0343L
Cement Manufacturing - Wet
NOX
Selective Catalytic Reduction (SCR)
N0343S
Cement Manufacturing - Wet
NOX
Selective Catalytic Reduction (SCR)
N03501
Iron & Steel M
lis - Reheating
NOX
Low Excess Air (LEA)
N03502
Iron & Steel M
lis - Reheating
NOX
Low NOx Burner
N03503
Iron & Steel M
lis - Reheating
NOX
Low NOx Burner + Flue Gas Recirculation
N0351S
Iron & Steel M
lis - Reheating
NOX
Low Excess Air (LEA)
N0352S
Iron & Steel M
lis - Reheating
NOX
Low NOx Burner
N0353S
Iron & Steel M
lis - Reheating
NOX
Low NOx Burner + Flue Gas Recirculation
N03601
Iron & Steel M
lis - Annealing
NOX
Low NOx Burner
N03602
Iron & Steel M
lis - Annealing
NOX
Low NOx Burner + Flue Gas Recirculation
N03603
Iron & Steel M
lis - Annealing
NOX
Selective Non-Catalytic Reduction (SNCR)
N03604
Iron & Steel M
lis - Annealing
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N03605
Iron & Steel Mills - Annealing
NOX
Selective Catalytic Reduction (SCR)
N03606
Iron & Steel Mills - Annealing
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N0361S
Iron & Steel M
lis - Annealing
NOX
Low NOx Burner
N0362S
Iron & Steel M
lis - Annealing
NOX
Low NOx Burner + Flue Gas Recirculation
N0363S
Iron & Steel M
lis - Annealing
NOX
Selective Non-Catalytic Reduction (SNCR)
N0364S
Iron & Steel M
lis - Annealing
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N0365S
Iron & Steel Mills - Annealing
NOX
Selective Catalytic Reduction (SCR)
N0366S
Iron & Steel Mills - Annealing
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N03701
Iron & Steel M
lis - Galvanizing
NOX
Low NOx Burner
N03702
Iron & Steel M
lis - Galvanizing
NOX
Low NOx Burner + Flue Gas Recirculation
N0371S
Iron & Steel M
lis - Galvanizing
NOX
Low NOx Burner
N0372S
Iron & Steel M
lis - Galvanizing
NOX
Low NOx Burner + Flue Gas Recirculation
N03801
Municipal Waste Combustors
NOX
Selective Non-Catalytic Reduction (SNCR)
N0381S
Municipal Waste Combustors
NOX
Selective Non-Catalytic Reduction (SNCR)
N03901
Medical Waste Incinerators
NOX
Selective Non-Catalytic Reduction (SNCR)
N0391S
Medical Waste Incinerators
NOX
Selective Non-Catalytic Reduction (SNCR)
N04101
I CI Boilers - Process Gas
NOX
Low NOx Burner
N04102
I CI Boilers - Process Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N04103
I CI Boilers - Process Gas
NOX
Oxygen Trim + Water Injection
N04104
ICI Boilers - Process Gas
NOX
Selective Catalytic Reduction (SCR)
N0411S
I CI Boilers - Process Gas
NOX
Low NOx Burner
N0412S
ICI Boilers - Process Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N0413S
ICI Boilers - Process Gas
NOX
Oxygen Trim + Water Injection
N0414S
ICI Boilers - Process Gas
NOX
Selective Catalytic Reduction (SCR)
N04201
ICI Boilers - Coke
NOX
Selective Non-Catalytic Reduction (SNCR)
N04203
ICI Boilers - Coke
NOX
Low NOx Burner
N04204
ICI Boilers - Coke
NOX
Selective Catalytic Reduction (SCR)
N0421S
ICI Boilers - Coke
NOX
Selective Non-Catalytic Reduction (SNCR)
N0423S
ICI Boilers - Coke
NOX
Low NOx Burner
N0424S
ICI Boilers - Coke
NOX
Selective Catalytic Reduction (SCR)
N04301
ICI Boilers - LPG
NOX
Low NOx Burner
N04302
ICI Boilers - LPG
NOX
Low NOx Burner + Flue Gas Recirculation
N04303
ICI Boilers - LPG
NOX
Selective Catalytic Reduction (SCR)
N04304
ICI Boilers - LPG
NOX
Selective Non-Catalytic Reduction (SNCR)
N0431S
ICI Boilers - LPG
NOX
Low NOx Burner
N0432S
ICI Boilers - LPG
NOX
Low NOx Burner + Flue Gas Recirculation
N0433S
ICI Boilers - LPG
NOX
Selective Catalytic Reduction (SCR)
N0434S
ICI Boilers - LPG
NOX
Selective Non-Catalytic Reduction (SNCR)
N04501
ICI Boilers - Liquid Waste
NOX
Low NOx Burner
N04502
ICI Boilers - Liquid Waste
NOX
Low NOx Burner + Flue Gas Recirculation
N04503
ICI Boilers - Liquid Waste
NOX
Selective Catalytic Reduction (SCR)
Document No. 05.09.009/9010.463
11-10
Report

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PECHAN
September 2005
Table 11-2 (continued)
Measure

Major

Code
Source Category
Pollutant
Control Measure
N04504
ICI Boilers - Liquid Waste
NOX
Selective Non-Catalytic Reduction (SNCR)
N0451S
ICI Boilers - Liquid Waste
NOX
Low NOx Burner
N0452S
ICI Boilers - Liquid Waste
NOX
Low NOx Burner + Flue Gas Recirculation
N0453S
ICI Boilers - Liquid Waste
NOX
Selective Catalytic Reduction (SCR)
N0454L
ICI Boilers - Distillate Oil - Large Sources
NOX
Selective Non-Catalytic Reduction (SNCR)
N0454S
ICI Boilers - Liquid Waste
NOX
Selective Non-Catalytic Reduction (SNCR)
N04601
IC Engines - Gas, Diesel, LPG
NOX
Ignition Retard
N04604
IC Engines - Gas, Diesel, LPG
NOX
Selective Catalytic Reduction (SCR)
N04605
Rich Burn IC Engines - Gas, Diesel, LPG
NOX
Non-Selective Catalytic Reduction (NSCR)
N0461S
IC Engines - Gas, Diesel, LPG
NOX
Ignition Retard
N0464S
IC Engines - Gas, Diesel, LPG
NOX
Selective Catalytic Reduction (SCR)
N0465S
Rich Burn IC Engines - Gas, Diesel, LPG
NOX
Non-Selective Catalytic Reduction (NSCR)
N04701
Process Heaters - Process Gas
NOX
Low NOx Burner
N04702
Process Heaters - Process Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N04703
Process Heaters - Process Gas
NOX
Selective Non-Catalytic Reduction (SNCR)
N04704
Process Heaters - Process Gas
NOX
Ultra Low NOx Burner
N04705
Process Heaters - Process Gas
NOX
Selective Catalytic Reduction (SCR)
N04706
Process Heaters - Process Gas
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N04707
Process Heaters - Process Gas
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N0471S
Process Heaters - Process Gas
NOX
Low NOx Burner
N0472S
Process Heaters - Process Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N0473S
Process Heaters - Process Gas
NOX
Selective Non-Catalytic Reduction (SNCR)
N0474S
Process Heaters - Process Gas
NOX
Ultra Low NOx Burner
N0475S
Process Heaters - Process Gas
NOX
Selective Catalytic Reduction (SCR)
N0476S
Process Heaters - Process Gas
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N0477S
Process Heaters - Process Gas
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N04801
Process Heaters - LPG
NOX
Low NOx Burner
N04802
Process Heaters - LPG
NOX
Low NOx Burner + Flue Gas Recirculation
N04803
Process Heaters - LPG
NOX
Selective Non-Catalytic Reduction (SNCR)
N04804
Process Heaters - LPG
NOX
Ultra Low NOx Burner
N04805
Process Heaters - LPG
NOX
Selective Catalytic Reduction (SCR)
N04806
Process Heaters - LPG
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N04807
Process Heaters - LPG
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N0481S
Process Heaters - LPG
NOX
Low NOx Burner
N0482S
Process Heaters - LPG
NOX
Low NOx Burner + Flue Gas Recirculation
N0483S
Process Heaters - LPG
NOX
Selective Non-Catalytic Reduction (SNCR)
N0484S
Process Heaters - LPG
NOX
Ultra Low NOx Burner
N0485S
Process Heaters - LPG
NOX
Selective Catalytic Reduction (SCR)
N0486S
Process Heaters - LPG
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N0487S
Process Heaters - LPG
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N04901
Process Heaters - Other Fuel
NOX
Low NOx Burner + Flue Gas Recirculation
N04902
Process Heaters - Other Fuel
NOX
Low NOx Burner
N04903
Process Heaters - Other Fuel
NOX
Selective Non-Catalytic Reduction (SNCR)
N04904
Process Heaters - Other Fuel
NOX
Ultra Low NOx Burner
N04905
Process Heaters - Other Fuel
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N04906
Process Heaters - Other Fuel
NOX
Selective Catalytic Reduction (SCR)
N04907
Process Heaters - Other Fuel
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
Document No. 05.09.009/9010.463
11-11
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure

Major

Code
Source Category
Pollutant
Control Measure
N0491S
Process Heaters - Other Fuel
NOX
Low NOx Burner + Flue Gas Recirculation
N0492S
Process Heaters - Other Fuel
NOX
Low NOx Burner
N0493S
Process Heaters - Other Fuel
NOX
Selective Non-Catalytic Reduction (SNCR)
N0494S
Process Heaters - Other Fuel
NOX
Ultra Low NOx Burner
N0495S
Process Heaters - Other Fuel
NOX
Low NOx Burner - Selective Non-Catalytic
Reduction (SNCR)
N0496S
Process Heaters - Other Fuel
NOX
Selective Catalytic Reduction (SCR)
N0497S
Process Heaters - Other Fuel
NOX
Low NOx Burner (LNB) + Selective Catalytic
Reduction (SCR)
N05001
Combustion Turbines - Jet Fuel
NOX
Water Injection
N05002
Combustion Turbines - Jet Fuel
NOX
Selective Catalytic Reduction (SCR) + Water
Injection
N0501S
Combustion Turbines - Jet Fuel
NOX
Water Injection
N0502S
Combustion Turbines - Jet Fuel
NOX
Selective Catalytic Reduction (SCR) + Water
Injection
N05401
Space Heaters - Distillate Oil
NOX
Low NOx Burner
N05402
Space Heaters - Distillate Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N05403
Space Heaters - Distillate Oil
NOX
Selective Catalytic Reduction (SCR)
N05404
Space Heaters - Distillate Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N0541S
Space Heaters - Distillate Oil
NOX
Low NOx Burner
N0542S
Space Heaters - Distillate Oil
NOX
Low NOx Burner + Flue Gas Recirculation
N0543S
Space Heaters - Distillate Oil
NOX
Selective Catalytic Reduction (SCR)
N0544S
Space Heaters - Distillate Oil
NOX
Selective Non-Catalytic Reduction (SNCR)
N05501
Space Heaters - Natural Gas
NOX
Low NOx Burner
N05502
Space Heaters - Natural Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N05503
Space Heaters - Natural Gas
NOX
Oxygen Trim + Water Injection
N05504
Space Heaters - Natural Gas
NOX
Selective Catalytic Reduction (SCR)
N05505
Space Heaters - Natural Gas
NOX
Selective Non-Catalytic Reduction (SNCR)
N0551S
Space Heaters - Natural Gas
NOX
Low NOx Burner
N0552S
Space Heaters - Natural Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N0553S
Space Heaters - Natural Gas
NOX
Oxygen Trim + Water Injection
N0554S
Space Heaters - Natural Gas
NOX
Selective Catalytic Reduction (SCR)
N0555S
Space Heaters - Natural Gas
NOX
Selective Non-Catalytic Reduction (SNCR)
N05601
Ammonia - NG-Fired Reformers
NOX
Low NOx Burner
N05602
Ammonia - NG-Fired Reformers
NOX
Low NOx Burner + Flue Gas Recirculation
N05603
Ammonia - NG-Fired Reformers
NOX
Oxygen Trim + Water Injection
N05604
Ammonia - NG-Fired Reformers
NOX
Selective Catalytic Reduction (SCR)
N05605
Ammonia - NG-Fired Reformers
NOX
Selective Non-Catalytic Reduction (SNCR)
N0561S
Ammonia - NG-Fired Reformers
NOX
Low NOx Burner
N0562S
Ammonia - NG-Fired Reformers
NOX
Low NOx Burner (LNB) + Flue Gas Recirculation
(FGR)
N0563S
Ammonia - NG-Fired Reformers
NOX
Oxygen Trim + Water Injection
N0564S
Ammonia - NG-Fired Reformers
NOX
Selective Catalytic Reduction (SCR)
N0565S
Ammonia - NG-Fired Reformers
NOX
Selective Non-Catalytic Reduction (SNCR)
N05801
Lime Kilns
NOX
Mid-Kiln Firing
N05802
Lime Kilns
NOX
Low NOx Burner
N05803
Lime Kilns
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N05804
Lime Kilns
NOX
Selective Non-Catalytic Reduction (SNCR)
Ammonia Based
N05805
Lime Kilns
NOX
Selective Catalytic Reduction (SCR)
N0581L
Lime Kilns
NOX
Mid-Kiln Firing
N0581S
Lime Kilns
NOX
Mid-Kiln Firing
N0582S
Lime Kilns
NOX
Low NOx Burner
N0583S
Lime Kilns
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
Document No. 05.09.009/9010.463
11-12
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
N0584S
Lime Kilns
NOX
Selective Non-Catalytic Reduction (SNCR)
Ammonia Based
N0585S
Lime Kilns
NOX
Selective Catalytic Reduction (SCR)
N05901
Comm./lnst. Incinerators
NOX
Selective Non-Catalytic Reduction (SNCR)
N0591S
Comm./lnst. Incinerators
NOX
Selective Non-Catalytic Reduction (SNCR)
N06001
Indust. Incinerators
NOX
Selective Non-Catalytic Reduction (SNCR)
N0601S
Indust. Incinerators
NOX
Selective Non-Catalytic Reduction (SNCR)
N06101
Sulfate Pulping - Recovery Furnaces
NOX
Low NOx Burner
N06102
Sulfate Pulping - Recovery Furnaces
NOX
Low NOx Burner + Flue Gas Recirculation
N06103
Sulfate Pulping - Recovery Furnaces
NOX
Oxygen Trim + Water Injection
N06104
Sulfate Pulping - Recovery Furnaces
NOX
Selective Catalytic Reduction (SCR)
N06105
Sulfate Pulping - Recovery Furnaces
NOX
Selective Non-Catalytic Reduction (SNCR)
N0611S
Sulfate Pulping - Recovery Furnaces
NOX
Low NOx Burner
N0612S
Sulfate Pulping - Recovery Furnaces
NOX
Low NOx Burner + Flue Gas Recirculation
N0613S
Sulfate Pulping - Recovery Furnaces
NOX
Oxygen Trim + Water Injection
N0614S
Sulfate Pulping - Recovery Furnaces
NOX
Selective Catalytic Reduction (SCR)
N0615S
Sulfate Pulping - Recovery Furnaces
NOX
Selective Non-Catalytic Reduction (SNCR)
N06202
Ammonia Prod; Feedstock
Desulfurization
NOX
Low NOx Burner + Flue Gas Recirculation
N0622S
Ammonia Prod; Feedstock
Desulfurization
NOX
Low NOx Burner + Flue Gas Recirculation
N06302
Plastics Prod-Specific; (ABS)
NOX
Low NOx Burner + Flue Gas Recirculation
N0632S
Plastics Prod-Specific; (ABS)
NOX
Low NOx Burner + Flue Gas Recirculation
N06402
Starch Mfg; Combined Operation
NOX
Low NOx Burner + Flue Gas Recirculation
N0642S
Starch Mfg; Combined Operation
NOX
Low NOx Burner + Flue Gas Recirculation
N06503
By-Product Coke Mfg; Oven Underfiring
NOX
Selective Non-Catalytic Reduction (SNCR)
N0653S
By-Product Coke Mfg; Oven Underfiring
NOX
Selective Non-Catalytic Reduction (SNCR)
N06703
Iron Prod; Blast Furn; Blast Htg Stoves
NOX
Low NOx Burner + Flue Gas Recirculation
N0673S
Iron Prod; Blast Furn; Blast Htg Stoves
NOX
Low NOx Burner + Flue Gas Recirculation
N06802
Steel Prod; Soaking Pits
NOX
Low NOx Burner + Flue Gas Recirculation
N0682S
Steel Prod; Soaking Pits
NOX
Low NOx Burner + Flue Gas Recirculation
N06902
Fuel Fired Equip; Process Htrs; Process
Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N0692S
Fuel Fired Equip; Process Htrs; Process
Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N07001
Sec Alum Prod; Smelting Furn
NOX
Low NOx Burner
N0701S
Sec Alum Prod; Smelting Furn
NOX
Low NOx Burner
N07101
Steel Foundries; Heat Treating
NOX
Low NOx Burner
N0711S
Steel Foundries; Heat Treating
NOX
Low NOx Burner
N07201
Fuel Fired Equip; Furnaces; Natural Gas
NOX
Low NOx Burner
N0721L
Fuel Fired Equip; Furnaces; Natural Gas
NOX
Low NOx Burner
N0721S
Fuel Fired Equip; Furnaces; Natural Gas
NOX
Low NOx Burner
N07301
Asphaltic Cone; Rotary Dryer; Conv Plant
NOX
Low NOx Burner
N0731S
Asphaltic Cone; Rotary Dryer; Conv Plant
NOX
Low NOx Burner
N07401
Ceramic Clay Mfg; Drying
NOX
Low NOx Burner
N0741S
Ceramic Clay Mfg; Drying
NOX
Low NOx Burner
N07503
Coal Cleaning-Thrml Dryer; Fluidized
Bed
NOX
Low NOx Burner
N0753S
Coal Cleaning-Thrml Dryer; Fluidized
Bed
NOX
Low NOx Burner
N07603
Fiberglass Mfg; Textile -Type Fbr; Recup
Furn
NOX
Low NOx Burner
N0763S
Fiberglass Mfg; Textile -Type Fbr; Recup
Furn
NOX
Low NOx Burner
N07702
Sand/Gravel; Dryer
NOX
Low NOx Burner + Flue Gas Recirculation
N0772S
Sand/Gravel; Dryer
NOX
Low NOx Burner + Flue Gas Recirculation
N07802
Fluid Cat Cracking Units
NOX
Low NOx Burner + Flue Gas Recirculation
Document No. 05.09.009/9010.463
11-13
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
N0782S
Fluid Cat Cracking Units
NOX
Low NOx Burner + Flue Gas Recirculation
N07901
Conv Coating of Prod; Acid Cleaning
Bath
NOX
Low NOx Burner
N0791S
Conv Coating of Prod; Acid Cleaning
Bath
NOX
Low NOx Burner
N08012
Natural Gas Prod; Compressors
NOX
Selective Catalytic Reduction (SCR)
N08103
In-Process; Bituminous Coal; Cement
Kilns
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N0813S
In-Process; Bituminous Coal; Cement
Kilns
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N08203
In-Process; Bituminous Coal; Lime Kilns
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N0823S
In-Process; Bituminous Coal; Lime Kilns
NOX
Selective Non-Catalytic Reduction (SNCR) Urea
Based
N08301
In-Process Fuel Use; Bituminous Coal
NOX
Selective Non-Catalytic Reduction (SNCR)
N0831S
In-Process Fuel Use; Bituminous Coal
NOX
Selective Non-Catalytic Reduction (SNCR)
N08402
In-Process Fuel Use; Residual Oil
NOX
Low NOx Burner
N0842S
In-Process Fuel Use; Residual Oil
NOX
Low NOx Burner
N08501
In-Process Fuel Use; Natural Gas
NOX
Low NOx Burner
N0851S
In-Process Fuel Use; Natural Gas
NOX
Low NOx Burner
N08602
In-Process; Process Gas; Coke Oven
Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N0862S
In-Process; Process Gas; Coke Oven
Gas
NOX
Low NOx Burner + Flue Gas Recirculation
N08701
In-Process; Process Gas; Coke Oven
Gas
NOX
Low NOx Burner
N0871S
In-Process; Process Gas; Coke Oven
Gas
NOX
Low NOx Burner
N08801
Surf Coat Oper; Coating Oven Htr; Nat
Gas
NOX
Low NOx Burner
N0881S
Surf Coat Oper; Coating Oven Htr; Nat
Gas
NOX
Low NOx Burner
N08901
Solid Waste Disp; Gov; Other Inc
NOX
Selective Non-Catalytic Reduction (SNCR)
N0891S
Solid Waste Disp; Gov; Other Inc
NOX
Selective Non-Catalytic Reduction (SNCR)
N10001
Industrial Coal Combustion
NOX
RACT to 50 tpy (LNB)
N10002
Industrial Coal Combustion
NOX
RACT to 25 tpy (LNB)
N10101
Industrial Oil Combustion
NOX
RACT to 50 tpy (LNB)
N10102
Industrial Oil Combustion
NOX
RACT to 25 tpy (LNB)
N10201
Industrial NG Combustion
NOX
RACT to 50 tpy (LNB)
N10202
Industrial NG Combustion
NOX
RACT to 25 tpy (LNB)
N10601
Commercial/Institutional - NG
NOX
Water Heater Replacement
N10603
Commercial/Institutional - NG
NOX
Water Heaters + LNB Space Heaters
N10901
Residential NG
NOX
Water Heater Replacement
N10903
Residential NG
NOX
Water Heater + LNB Space Heaters
N12201
Open Burning
NOX
Episodic Ban (Daily Only)
N13201
Agricultural Burning
NOX
Seasonal Ban (Ozone Season Daily)
N13701
Diesel Locomotives
NOX
Selective Catalytic Reduction (SCR)
NCEMK
Cement Kilns
NOX
Biosolid Injection Technology
P2011
Industrial Boilers - Coal
PM
Fabric Filter (Pulse Jet Type)
P2012
Industrial Boilers - Coal
PM
Dry ESP-Wire Plate Type
P2013
Industrial Boilers - Coal
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2014
Industrial Boilers - Coal
PM
Venturi Scrubber
P2021
Industrial Boilers - Wood
PM
Fabric Filter (Pulse Jet Type)
P2022
Industrial Boilers - Wood
PM
Dry ESP-Wire Plate Type
P2023
Industrial Boilers - Wood
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2024
Industrial Boilers - Wood
PM
Venturi Scrubber
P2031
Industrial Boilers - Oil
PM
Dry ESP-Wire Plate Type
Document No. 05.09.009/9010.463
11-14
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
P2032
Industrial Boilers - Oil
PM
Venturi Scrubber
P2041
Industrial Boilers - Liquid Waste
PM
Dry ESP-Wire Plate Type
P2051
Commercial Institutional Boilers
PM
Fabric Filter (Pulse Jet Type)
P2052
Commercial Institutional Boilers
PM
Dry ESP-Wire Plate Type
P2053
Commercial Institutional Boilers
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2061
Commercial Institutional Boilers
PM
Fabric Filter (Pulse Jet Type)
P2062
Commercial Institutional Boilers
PM
Dry ESP-Wire Plate Type
P2063
Commercial Institutional Boilers
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2071
Commercial Institutional Boilers
PM
Dry ESP-Wire Plate Type
P2081
Non-Ferrous Metals Processing
PM
Fabric Filter (Mech. Shaker Type)
P2082
Non-Ferrous Metals Processing
PM
Dry ESP-Wire Plate Type
P2083
Non-Ferrous Metals Processing
PM
Wet ESP - Wire Plate Type
P2084
Non-Ferrous Metals Processing
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2091
Non-Ferrous Metals Processing
PM
Fabric Filter (Mech. Shaker Type)
P2092
Non-Ferrous Metals Processing
PM
Dry ESP-Wire Plate Type
P2093
Non-Ferrous Metals Processing
PM
Wet ESP - Wire Plate Type
P2094
Non-Ferrous Metals Processing
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2101
Non-Ferrous Metals Processing
PM
Fabric Filter (Mech. Shaker Type)
P2102
Non-Ferrous Metals Processing
PM
Dry ESP-Wire Plate Type
P2103
Non-Ferrous Metals Processing
PM
Wet ESP - Wire Plate Type
P2104
Non-Ferrous Metals Processing
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2111
Non-Ferrous Metals Processing
PM
Fabric Filter (Mech. Shaker Type)
P2112
Non-Ferrous Metals Processing
PM
Dry ESP-Wire Plate Type
P2113
Non-Ferrous Metals Processing
PM
Wet ESP - Wire Plate Type
P2114
Non-Ferrous Metals Processing
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2121
Non-Ferrous Metals Processing
PM
Fabric Filter (Mech. Shaker Type)
P2122
Non-Ferrous Metals Processing
PM
Dry ESP-Wire Plate Type
P2123
Non-Ferrous Metals Processing
PM
Wet ESP - Wire Plate Type
P2124
Non-Ferrous Metals Processing
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2131
Ferrous Metals Processing - Coke
PM
Fabric Filter (Mech. Shaker Type)
P2132
Ferrous Metals Processing - Coke
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2133
Ferrous Metals Processing - Coke
PM
Venturi Scrubber
P2141
Ferrous Metals Processing - Ferroalloy
Production
PM
Fabric Filter (Mech. Shaker Type)
P2142
Ferrous Metals Processing - Ferroalloy
Production
PM
Dry ESP-Wire Plate Type
P2143
Ferrous Metals Processing - Ferroalloy
Production
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2151
Ferrous Metals Processing - Iron and
Steel Production
PM
Fabric Filter (Pulse Jet Type)
P2152
Ferrous Metals Processing - Iron and
Steel Production
PM
Fabric Filter (Mech. Shaker Type)
P2153
Ferrous Metals Processing - Iron and
Steel Production
PM
Dry ESP-Wire Plate Type
P2154
Ferrous Metals Processing - Iron and
Steel Production
PM
Wet ESP - Wire Plate Type
P2155
Ferrous Metals Processing - Iron and
Steel Production
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2156
Ferrous Metals Processing - Iron and
Steel Production
PM
Venturi Scrubber
P2161
Ferrous Metals Processing - Gray Iron
Foundries
PM
Fabric Filter (Mech. Shaker Type)
P2162
Ferrous Metals Processing - Gray Iron
Foundries
PM
Dry ESP-Wire Plate Type
P2163
Ferrous Metals Processing - Gray Iron
Foundries
PM
Fabric Filter (Reverse-Air Cleaned Type)
Document No. 05.09.009/9010.463
11-15
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
P2164
Ferrous Metals Processing - Gray Iron
Foundries
PM
Impingement-Plate Scrubber
P2165
Ferrous Metals Processing - Gray Iron
Foundries
PM
Venturi Scrubber
P2171
Ferrous Metals Processing - Steel
Foundries
PM
Fabric Filter (Pulse Jet Type)
P2172
Ferrous Metals Processing - Steel
Foundries
PM
Fabric Filter (Mech. Shaker Type)
P2173
Ferrous Metals Processing - Steel
Foundries
PM
Dry ESP-Wire Plate Type
P2174
Ferrous Metals Processing - Steel
Foundries
PM
Wet ESP - Wire Plate Type
P2175
Ferrous Metals Processing - Steel
Foundries
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2176
Ferrous Metals Processing - Steel
Foundries
PM
Venturi Scrubber
P2181
Mineral Products - Cement Manufacture
PM
Fabric Filter (Pulse Jet Type)
P2182
Mineral Products - Cement Manufacture
PM
Fabric Filter (Mech. Shaker Type)
P2183
Mineral Products - Cement Manufacture
PM
Dry ESP-Wire Plate Type
P2184
Mineral Products - Cement Manufacture
PM
Paper/Nonwoven Filters - Cartridge Collector
Type
P2185
Mineral Products - Cement Manufacture
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2191
Mineral Products - Coal Cleaning
PM
Fabric Filter (Pulse Jet Type)
P2192
Mineral Products - Coal Cleaning
PM
Fabric Filter (Mech. Shaker Type)
P2193
Mineral Products - Coal Cleaning
PM
Paper/Nonwoven Filters - Cartridge Collector
Type
P2194
Mineral Products - Coal Cleaning
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2195
Mineral Products - Coal Cleaning
PM
Venturi Scrubber
P2201
Mineral Products - Stone Quarrying and
Processing
PM
Fabric Filter (Pulse Jet Type)
P2202
Mineral Products - Stone Quarrying and
Processing
PM
Fabric Filter (Mech. Shaker Type)
P2203
Mineral Products - Stone Quarrying and
Processing
PM
Dry ESP-Wire Plate Type
P2204
Mineral Products - Stone Quarrying and
Processing
PM
Wet ESP - Wire Plate Type
P2205
Mineral Products - Stone Quarrying and
Processing
PM
Paper/Nonwoven Filters - Cartridge Collector
Type
P2206
Mineral Products - Stone Quarrying and
Processing
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2207
Mineral Products - Stone Quarrying and
Processing
PM
Venturi Scrubber
P2211
Mineral Products - Other
PM
Fabric Filter (Pulse Jet Type)
P2212
Mineral Products - Other
PM
Fabric Filter (Mech. Shaker Type)
P2213
Mineral Products - Other
PM
Dry ESP-Wire Plate Type
P2214
Mineral Products - Other
PM
Wet ESP - Wire Plate Type
P2215
Mineral Products - Other
PM
Paper/Nonwoven Filters - Cartridge Collector
Type
P2216
Mineral Products - Other
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2221
Asphalt Manufacture
PM
Fabric Filter (Pulse Jet Type)
P2222
Asphalt Manufacture
PM
Fabric Filter (Mech. Shaker Type)
P2223
Asphalt Manufacture
PM
Paper/Nonwoven Filters - Cartridge Collector
Type
P2224
Asphalt Manufacture
PM
Fabric Filter (Reverse-Air Cleaned Type)
P2231
Grain Milling
PM
Fabric Filter (Pulse Jet Type)
P2232
Grain Milling
PM
Paper/Nonwoven Filters - Cartridge Collector
Type
P2233
Grain Millinq
PM
Fabric Filter (Reverse-Air Cleaned Type)
Document No. 05.09.009/9010.463
11-16
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
P2241
Wood Pulp & Paper
PM
Dry ESP-Wire Plate Type
P2242
Wood Pulp & Paper
PM
Wet ESP - Wire Plate Type
P2251
Chemical Manufacture
PM
Wet ESP - Wire Plate Type
P2261
Municipal Waste Incineration
PM
Dry ESP-Wire Plate Type
P2271
Fabricated Metal Products - Abrasive
Blasting
PM
Paper/Nonwoven Filters - Cartridge Collector
Type
P2291
Fabricated Metal Products - Welding
PM
Paper/Nonwoven Filters - Cartridge Collector
Type
P3201
Industrial Boilers - Coal
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3202
Industrial Boilers - Wood
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3203
Industrial Boilers - Oil
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3204
Industrial Boilers - Liquid Waste
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3205
Commercial Institutional Boilers - Coal
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3206
Commercial Institutional Boilers - Wood
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3207
Commercial Institutional Boilers - Oil
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3208
Non-Ferrous Metals Processing - Copper
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3209
Non-Ferrous Metals Processing - Lead
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3210
Non-Ferrous Metals Processing - Zinc
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3211
Non-Ferrous Metals Processing -
Aluminum
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3212
Non-Ferrous Metals Processing - Other
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3213
Ferrous Metals Processing - Coke
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3214
Ferrous Metals Processing - Ferroalloy
Production
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3215
Ferrous Metals Processing - Iron & Steel
Production
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3216
Ferrous Metals Processing - Gray Iron
Foundries
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3217
Ferrous Metals Processing - Steel
Foundries
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3218
Mineral Products - Cement Manufacture
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3219
Mineral Products - Coal Cleaning
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3220
Mineral Products - Stone Quarrying &
Processing
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3221
Mineral Products - Other
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3222
Asphalt Manufacture
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3225
Chemical Manufacture
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3226
Electric Generation - Coal
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3227
Commercial Institutional Boilers - LPG
PM
Increased Monitoring Frequency (IMF) of PM
Control
Document No. 05.09.009/9010.463
11-17
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
P3228
Commercial Institutional Boilers - Liquid
Waste
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3229
Commercial Institutional Boilers - Natural
Gas
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3230
Commercial Institutional Boilers -
Process Gas
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3231
Commercial Institutional Boilers - Solid
Waste
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3232
Electric Generation - Coke
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3233
Electric Generation - Bagasse
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3234
Electric Generation - LPG
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3235
Electric Generation - Liquid Waste
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3236
Electric Generation - Natural Gas
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3237
Electric Generation - Oil
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3238
Electric Generation - Solid Waste
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3239
Electric Generation - Wood
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3240
Ferrous Metals Processing - Other
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3241
Industrial Boilers - Coke
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3242
Industrial Boilers - LPG
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3243
Industrial Boilers - Natural Gas
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3244
Industrial Boilers - Process Gas
PM
Increased Monitoring Frequency (IMF) of PM
Control
P3245
Industrial Boilers - Solid Waste
PM
Increased Monitoring Frequency (IMF) of PM
Control
P4201
Industrial Boilers - Coal
PM
Increased Monitoring Frequency (IMF) of PM
Control
P4202
Industrial Boilers - Wood
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4203
Industrial Boilers - Oil
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4204
Industrial Boilers - Liquid Waste
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4205
Commercial Institutional Boilers - Coal
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4206
Commercial Institutional Boilers - Wood
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4207
Commercial Institutional Boilers - Oil
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4208
Non-Ferrous Metals Processing - Copper
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4209
Non-Ferrous Metals Processing - Lead
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4210
Non-Ferrous Metals Processing - Zinc
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4211
Non-Ferrous Metals Processing -
Aluminum
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
Document No. 05.09.009/9010.463
11-18
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
P4212
Non-Ferrous Metals Processing - Other
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4213
Ferrous Metals Processing - Coke
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4214
Ferrous Metals Processing - Ferroalloy
Production
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4215
Ferrous Metals Processing - Iron & Steel
Production
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4216
Ferrous Metals Processing - Gray Iron
Foundries
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4217
Ferrous Metals Processing - Steel
Foundries
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4218
Mineral Products - Cement Manufacture
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4219
Mineral Products - Coal Cleaning
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4220
Mineral Products - Stone Quarrying &
Processing
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4221
Mineral Products - Other
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4222
Asphalt Manufacture
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4225
Chemical Manufacture
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4226
Electric Generation - Coal
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4227
Commercial Institutional Boilers - LPG
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4228
Commercial Institutional Boilers - Liquid
Waste
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4229
Commercial Institutional Boilers - Natural
Gas
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4230
Commercial Institutional Boilers -
Process Gas
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4231
Commercial Institutional Boilers - Solid
Waste
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4232
Electric Generation - Coke
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4233
Electric Generation - Bagasse
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4234
Electric Generation - LPG
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4235
Electric Generation - Liquid Waste
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4236
Electric Generation - Natural Gas
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4237
Electric Generation - Oil
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4238
Electric Generation - Solid Waste
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4239
Electric Generation - Wood
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4240
Ferrous Metals Processing - Other
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4241
Industrial Boilers - Coke
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4242
Industrial Boilers - LPG
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
Document No. 05.09.009/9010.463
11-19
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
P4243
Industrial Boilers - Natural Gas
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4244
Industrial Boilers - Process Gas
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
P4245
Industrial Boilers - Solid Waste
PM
CEM Upgrade and Increased Monitoring
Frequency of PM Controls
PHDRET
Nonroad Diesel Engines
PM
Heavy Duty Retrofit Program
PPVAC
Paved Road
PM
Vacuum Sweeping
PUCHS
Unpaved Road
PM
Chemical Stabilization
PUDESP
Utility Boilers - Coal
PM
Dry ESP-Wire Plate Type
PUHAP
Unpaved Rd
PM
Hot Asphalt Paving
PUMECH
Utility Boilers - Coal
PM
Fabric Filter (Mech. Shaker Type)
PUPUJT
Utility Boilers - Coal
PM
Fabric Filter (Pulse Jet Type)
PUREVA
Utility Boilers - Coal
PM
Fabric Filter (Reverse-Air Cleaned Type)
PUTILC
Utility Boilers - Coal
PM
Fabric Filter
PUTILG
Utility Boilers - Gas/Oil
PM
Fabric Filter
Pagbu
Agricultural Burning
PM
Bale Stack/Propane Burning
Pagtl
Agricultural Tilling
PM
Soil Conservation Plans
Pcatf
Beef Cattle Feedlots
PM
Watering
Pcharb
Conveyorized Charbroilers
PM
Catalytic Oxidizer
Pcnst
Construction Activities
PM
Dust Control Plan
Ppreb
Prescribed Burning
PM
Increase Fuel Moisture
Presw
Residential Wood Combustion
PM
Education and Advisory Program
Pwdstv
Residential Wood Stoves
PM
NSPS compliant Wood Stoves
S0201
Sulfuric Acid Plants - Contact Absorber
(99% Conversion)
S02
Increase % Conversion ro Meet NSPS (99.7)
S0301
Sulfuric Acid Plants - Contact Absorber
S02
Increase % Conversion ro Meet NSPS (99.7)

(98% Conversion)

S0401
Sulfuric Acid Plants - Contact Absorber
(97% Conversion)
S02
Increase % Conversion ro Meet NSPS (99.7)
S0501
Sulfuric Acid Plants - Contact Absorber
S02
Increase % Conversion ro Meet NSPS (99.7)

(93% Conversion)

S0601
Sulfur Recovery Plants - Elemental Sulfur
(Claus: 2 Stage w/o control (92-95%
removal))
S02
Amine Scrubbing
S0602
Sulfur Recovery Plants - Elemental Sulfur
(Claus: 2 Stage w/o control (92-95%
removal))
S02
Sulfur Recovery and/or Tail Gas treatment
S0701
Sulfur Recovery Plants - Elemental Sulfur
(Claus: 3 Stage w/o control (95-96%
removal))
S02
Amine Scrubbing
S0702
Sulfur Recovery Plants - Elemental Sulfur
(Claus: 3 Stage w/o control (95-96%
removal))
S02
Sulfur Recovery and/or Tail Gas treatment
S0801
Sulfur Recovery Plants - Elemental Sulfur
(Claus: 4 Stage w/o control (96-97%
removal))
S02
Amine Scrubbing
S0802
Sulfur Recovery Plants - Elemental Sulfur
(Claus: 3 Stage w/o control (96-97%
removal))
S02
Sulfur Recovery and/or Tail Gas treatment
S0901
Sulfur Recovery Plants - Sulfur Removal
Process (99.9% removal)
S02
Sulfur Recovery and/or Tail Gas treatment
S1001
Sulfur Recovery Plants - Elemental Sulfur
Production (Not Classified)
S02
Sulfur Recovery and/or Tail Gas treatment
S1101
Inorganic Chemical Manufacture
S02
Flue Gas Desulfurization (FGD)
S1201
By-Product Coke Manufacturing (Coke
Oven Plants)
S02
Vacuum Carbonate Plus Sulfur Recovery Plant
Document No. 05.09.009/9010.463
11-20
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
S1301
Process Heaters (Oil and Gas Production
Industry)
S02
Flue Gas Desulfurization (FGD)
S1401
Primary Metals Industry
S02
Sulfuric Acid Plant
S1501
Secondary Metal Production
S02
Flue Gas Desulfurization (FGD)
S1601
Mineral Products Industry
S02
Flue Gas Desulfurization (FGD)
S1701
Pulp and Paper Industry (Sulfate Pulping)
S02
Flue Gas Desulfurization (FGD)
S1801
Petroleum Industry
S02
Flue Gas Desulfurization (FGD)
S1901
Bituminous/Subbituminous Coal
(Industrial Boilers)
S02
Flue Gas Desulfurization (FGD)
S2001
Residual Oil (Industrial Boilers)
S02
Flue Gas Desulfurization (FGD)
S2101
Bituminous/Subbituminous Coal
(Commercial/Institutional Boilers)
S02
Flue Gas Desulfurization (FGD)
S2201
In-process Fuel Use -
Bituminous/Subbituminous Coal
S02
Flue Gas Desulfurization (FGD)
S2301
Lignite (Industrial Boilers)
S02
Flue Gas Desulfurization (FGD)
S2401
Residual Oil (Commercial/Institutional
Boilers)
S02
Flue Gas Desulfurization (FGD)
S2601
Steam Generating Unit-Coal/Oil
S02
Flue Gas Desulfurization (FGD)
S2801
Primary Zinc Smelters - Sintering
S02
Dual absorption
S2901
Primary Zinc Smelters - Sintering
S02
Dual absorption
S3000
Bituminous/Subbituminous Coal
(Industrial Boilers)
S02
In-duct Dry Sorbent Injection
S3001
Bituminous/Subbituminous Coal
(Industrial Boilers)
S02
Spray Dryer Absorber
S3002
Bituminous/Subbituminous Coal
(Industrial Boilers)
S02
Wet Flue Gas Desulfurization
S3003
Lignite (Industrial Boilers)
S02
In-duct Dry Sorbent Injection
S3004
Lignite (Industrial Boilers)
S02
Spray Dryer Absorber
S3005
Lignite (Industrial Boilers)
S02
Wet Flue Gas Desulfurization
S3006
Residual Oil (Industrial Boilers)
S02
Wet Flue Gas Desulfurization
S3007
Distillate Oil (Industrial Boiler)
S02
Wet Flue Gas Desulfurization
SI2010
Off-Highway Gasoline Vehicles
NOX
2010 Implementation of Large Spark-Ignition (S-
I) Engine Standards
SI2015
Off-Highway Gasoline Vehicles
NOX
2015 Implementation of Large Spark-Ignition (S-
I) Engine Standards
SI2020
Off-Highway Gasoline Vehicles
NOX
2020 Implementation of Large Spark-Ignition (S-
I) Engine Standards
SI2030
Off-Highway Gasoline Vehicles
NOX
2030 Implementation of Large Spark-Ignition (S-
I) Engine Standards
SM2010
Off-Highway Vehicles
Snowmobiles
VOC
Recreational Gasoline Snowmobile Standards
SM2015
Off-Highway Vehicles
Snowmobiles
VOC
Recreational Gasoline Snowmobile Standards
SM2020
Off-Highway Vehicles
Snowmobiles
VOC
Recreational Gasoline Snowmobile Standards
SM2030
Off-Highway Vehicles
Snowmobiles
VOC
Recreational Gasoline Snowmobile Standards
SUT-H
Utility Boilers - High Sulfur Content
S02
Flue Gas Desulfurization (Wet Scrubber Type)
SUT-M
Utility Boilers - Medium Sulfur Content
S02
Flue Gas Desulfurization (Wet Scrubber Type)
SUT-R
Utility Boilers - Coal-Fired
S02
Repowering to IGCC
SUT-S
Utility Boilers - Coal-Fired
S02
Fuel Switching - High-Sulfur Coal to Low-Sulfur
Coal
SUT-VH
Utility Boilers - Very High Sulfur Content
S02
Flue Gas Desulfurization (Wet Scrubber Type)
SUT-W
Utility Boilers - Coal-Fired
S02
Coal Washing
T210
Highway Vehicles - Light Duty and
Gasoline-Fueled Vehicles
NOX
2010 Implementation of Tier 2 Motor Vehicle
Emissions and Gasoline Sulfur Controls
T215
Highway Vehicles - Light Duty and
Gasoline-Fueled Vehicles
NOX
2015 Implementation of Tier 2 Motor Vehicle
Emissions and Gasoline Sulfur Controls
T220
Highway Vehicles - Light Duty and
Gasoline-Fueled Vehicles
NOX
2020 Implementation of Tier 2 Motor Vehicle
Emissions and Gasoline Sulfur Controls
Document No. 05.09.009/9010.463
11-21
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
T230
Highway Vehicles - Light Duty and
Gasoline-Fueled Vehicles
NOX
2030 Implementation of Tier 2 Motor Vehicle
Emissions and Gasoline Sulfur Controls
V22001
Architectural Coatings
VOC
AIM Coating Federal Rule
V22002
Architectural Coatings
VOC
South Coast Phase I
V22003
Architectural Coatings
VOC
South Coast Phase II
V22004
Architectural Coatings
VOC
South Coast Phase III
V22101
Traffic Markings
VOC
AIM Coating Federal Rule
V22102
Traffic Markings
VOC
South Coast Phase I
V22103
Traffic Markings
VOC
South Coast Phase II
V22104
Traffic Markings
VOC
South Coast Phase III
V22201
Industrial Maintenance Coating
VOC
AIM Coating Federal Rule
V22202
Industrial Maintenance Coating
VOC
South Coast Phase I
V22203
Industrial Maintenance Coating
VOC
South Coast Phase II
V22204
Industrial Maintenance Coating
VOC
South Coast Phase III
V22301
Metal Coil & Can Coating
VOC
MACT Standard
V22302
Metal Coil & Can Coating
VOC
BAAQMD Rule 11 Amended
V22303
Metal Coil & Can Coating
VOC
Incineration
V22401
Wood Product Surface Coating
VOC
MACT Standard
V22402
Wood Product Surface Coating
VOC
SCAQMD Rule 1104
V22403
Wood Product Surface Coating
VOC
Incineration
V22501
Wood Furniture Surface Coating
VOC
MACT Standard
V22502
Wood Furniture Surface Coating
VOC
New CTG
V22503
Wood Furniture Surface Coating
VOC
Add-On Controls
V22601
Adhesives - Industrial
VOC
SCAQMD Rule 1168
V23201
Open Top Degreasing
VOC
Title III MACT Standard
V23202
Open Top Degreasing
VOC
SCAQMD 1122 (VOC content limit)
V23203
Open Top Degreasing
VOC
Airtight Degreasing System
V24001
Paper Surface Coating
VOC
Incineration
V24401
Rubber and Plastics Mfg
VOC
SCAQMD - Low VOC
V24501
Metal Furniture, Appliances, Parts
VOC
MACT Standard
V24502
Metal Furniture, Appliances, Parts
VOC
SCAQMD Limits
V24601
Automobile Refinishing
VOC
Federal Rule
V24602
Automobile Refinishing
VOC
CARB BARCT Limits
V24603
Automobile Refinishing
VOC
California FIP Rule (VOC content & TE)
V24604
Cold Cleaning
VOC
OTC Solvent Cleaning Operations Rule
V24605
Portable Gasoline Containers
VOC
OTC Portable Gas Container Rule
V24606
Architectural Coatings
VOC
OTC AIM Coating Rule
V24607
Consumer Solvents
VOC
OTC Consumer Products Rule
V24608
Marine Surface Coating
VOC
OTC Mobile Equipment Repair and Refinishing
Rule
V24701
Machn, Electric, Railroad Ctng
VOC
MACT Standard
V24702
Machn, Electric, Railroad Ctng
VOC
SCAQMD Limits
V24703
Machn, Electric, Railroad Ctng
VOC
OTC Mobile Equipment Repair and Refinishing
Rule
V24901
Consumer Solvents
VOC
Federal Consumer Solvents Rule
V24902
Consumer Solvents
VOC
CARB Mid-Term Limits
V24903
Consumer Solvents
VOC
CARB Long-Term Limits
V25001
Aircraft Surface Coating
VOC
MACT Standard
V25002
Aircraft Surface Coating
VOC
OTC Mobile Equipment Repair and Refinishing
Rule
V25101
Marine Surface Coating
VOC
MACT Standard
V25102
Marine Surface Coating
VOC
Add-On Controls
V25301
Electrical/Electronic Coating
VOC
MACT Standard
V25302
Electrical/Electronic Coating
VOC
SCAQMD Rule
V25401
Motor Vehicle Coating
VOC
MACT Standard
V25402
Motor Vehicle Coatinq
VOC
Incineration
Document No. 05.09.009/9010.463
11-22
Report

-------
PECHAN
September 2005
Table 11-2 (continued)
Measure
Code
Source Category
Major
Pollutant
Control Measure
V25403
Automobile Refinishing
voc
OTC Mobile Equipment Repair and Refinishing
Rule
V26901
Commercial Adhesives
voc
Federal Consumer Solvents Rule
V26902
Commercial Adhesives
voc
CARB Mid-Term Limits
V26903
Commercial Adhesives
voc
CARB Long-Term Limits
V26904
Consumer Adhesives
voc
OTC Consumer Products Rule
V27102
Bakery Products
voc
Incineration >100,000 lbs bread
V27201
Cutback Asphalt
voc
Switch to Emulsified Asphalts
V27901
Oil and Natural Gas Production
voc
Equipment and Maintenance
V28402
Municipal Solid Waste Landfill
voc
Gas Collection (SCAQMD/BAAQMD)
V29502
Pesticide Application
voc
Reformulation - FIP Rule
V30101
Stage II Service Stations
voc
Low Pressure/Vacuum Relief Valve
V30201
Stage II Service Stations - Underground
Tanks
voc
Low Pressure/Vacuum Relief Valve
V30301
Graphic Arts
voc
Use of Low or No VOC Materials
V40201
Flexographic Printing
voc
Permanent Total Enclosure (PTE)
V40202
Fabric Printing, Coating and Dyeing
voc
Permanent Total Enclosure (PTE)
V40203
Metal Can Surface Coating
voc
Permanent Total Enclosure (PTE)
V40204
Metal Furniture Surface Coating
voc
Permanent Total Enclosure (PTE)
V40205
Paper and Other Web Coating
voc
Permanent Total Enclosure (PTE)
V40206
Product and Package Roto and Screen
Prin
voc
Permanent Total Enclosure (PTE)
V40207
Publication Rotogravure Printing
voc
Permanent Total Enclosure (PTE)
VNRFG
Nonroad Gasoline Engines
voc
Federal Reformulated Gasoline
mOT1
Highway Veh - LD Gas Trucks
voc
Tier 2 Standards for 1996
mOT2
Highway Vehicles - Gasoline
voc
Federal Reformulated Gasoline (RFG)
mOT3
Highway Vehicles - Gasoline
NOX
High Enhanced Inspection and Maintenance
Program
mOT4
Highway Veh - LD Gasoline
voc
Fleet I LEV
mOT5
Highway Veh - HD Diesels
PM
HDDV Retrofit Program
mOT6
Highway Vehicles - Gasoline
NOX
Transportation Control Package for 1996
mOT7
Highway Vehicles - Gasoline
NOX
RFG and High Enhanced l/M Program
mOT8
Highway Vehicles - Gasoline
voc
Low Reid Vapor Pressure (RVP) Limit in Ozone
Season
mOT9
Highway Vehicles - Gasoline
voc
Basic Inspection and Maintenance Program
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PECHAN	September 2005
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PECHAN
September 2005
CHAPTER III. CONTROL DOCUMENTATION
Each control measure in AirControlNET is documented in this section. Control measures are
introduced with a standard table that provides an at-a-glance summary of the key control measure
data elements. Each summary table is followed by detailed sections that provide additional
information concerning the control measure. References also are provided to the documents that
were used to develop the analysis on each of the control measures.
This section is organized by primary pollutant (e.g., Ammonia, Nitrogen Oxides, Particulate
Matter, etc.) and source category. The following pages provide a pollutant introduction, a list of
source categories contained within each pollutant section.
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PECHAN	September 2005
POLLUTANT INTRODUCTION
AMMONIA (NH3)
Source Category	Page
Cattle Feedlots	III-ll
Hog Operations 	Ill-12
Poultry Operations	Ill-13
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PECHAN
September 2005
NITROGEN OXIDES (NOx)
Source Category	Page
Agricultural Burning 	Ill-15
Ammonia - Natural Gas - Fired Reformers - Small Sources	Ill-17
Ammonia Products; Feedstock Desulfurization - Small Sources 	111-28
Asphaltic Cone; Rotary Dryer; Conv Plant - Small Sources	111-30
By-Product Coke Manufacturing; Oven Underfiring	111-32
Cement Kilns	111-34
Cement Manufacturing - Dry	111-35
Cement Manufacturing - Wet 	111-46
Cement Manufacturing - Wet - Large Sources 	111-50
Cement Manufacturing - Wet - Small Sources 	111-53
Ceramic Clay Manufacturing; Drying - Small Sources	111-56
Coal Cleaning-Thrml Dryer; Fluidized Bed - Small Sources 	111-58
Coal-fired Plants with Production Capacities>100MW 	111-60
Combustion Turbines - Jet Fuel - Small Sources	111-62
Combustion Turbines - Natural Gas - Large Sources 	111-67
Combustion Turbines - Natural Gas - Small Sources 	111-69
Combustion Turbines - Oil - Small Sources 	111-84
Commercial/Institutional - Natural Gas	111-89
Commercial/Institutional Incinerators	111-93
Conv Coating of Prod; Acid Cleaning Bath - Small Sources 	111-96
Diesel Locomotives	111-98
Fiberglass Manufacture; Textile-Type; Recuperative Furnaces 	111-99
Fluid Catalytic Cracking Units - Small Sources 	Ill-101
Fuel Fired Equipment - Process Heaters 	Ill-103
Fuel Fired Equipment; Furnaces; Natural Gas	Ill-105
Glass Manufacturing - Containers	Ill-107
Glass Manufacturing - Flat 	Ill-120
Glass Manufacturing - Flat - Large Sources 	Ill-126
Glass Manufacturing - Flat - Small Sources 	Ill-131
Glass Manufacturing - Pressed 	Ill-137
Highway Vehicles - Gasoline Engine 	Ill-151
Highway Vehicles - Heavy Duty and Diesel-Fueled Vehicles	III-152
Highway Vehicles - Heavy Duty Diesel Engines	Ill-160
Highway Vehicles - Light Duty and Gasoline-Fueled Vehicles 	Ill-162
Highway Vehicles - Light Duty Gasoline Engines 	Ill-170
IC Engines - Gas 	Ill-171
IC Engines - Gas - Small Sources 	Ill-173
IC Engines - Gas, Diesel, LPG - Small Sources 	III-175
ICI Boilers - Coal/Cyclone - Large Sources	III-180
ICI Boilers - Coal/Cyclone - Small Sources 	III-182
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PECHAN
September 2005
NITROGEN OXIDES (NOx) (continued)
Source Category	Page
ICI Boilers - Coal/FBC - Large Sources 	Ill-191
ICI Boilers - Coal/FBC - Small Sources 	Ill-194
ICI Boilers - Coal/Stoker- Small Sources 	Ill-196
ICI Boilers - Coal/Wall - Large Sources 	III-202
ICI Boilers - Coal/Wall - Small Sources 	III-210
ICI Boilers - Coke - Small Sources 	III-218
ICI Boilers - Distillate Oil - Large Sources	III-226
ICI Boilers - Distillate Oil - Small Sources	III-229
ICI Boilers - Liquid Waste	III-239
ICI Boilers - Liquid Waste - Small Sources	III-242
ICI Boilers - LPG - Small Sources	III-249
ICI Boilers - MSW/Stoker - Small Sources	III-259
ICI Boilers - Natural Gas - Large Sources	III-261
ICI Boilers - Natural Gas - Small Sources	III-264
ICI Boilers - Process Gas - Small Sources	III-276
ICI Boilers - Residual Oil - Large Sources 	III-285
ICI Boilers - Residual Oil - Small Sources 	III-288
ICI Boilers - Wood/Bark/Stoker- Large Sources	III-298
ICI Boilers - Wood/Bark/Stoker - Small Sources 	III-301
Industrial Coal Combustion	III-304
Industrial Incinerators 	III-306
Industrial Natural Gas Combustion	III-309
Industrial Oil Combustion	III-311
In-Proc; Process Gas; Coke Oven/Blast Ovens	III-313
In-Process Fuel Use - Bituminous Coal - Small Sources	III-315
In-Process Fuel Use; Natural Gas - Small Sources 	III-317
In-Process Fuel Use; Residual Oil - Small Sources	III-319
In-Process; Bituminous Coal; Cement Kilns	III-321
In-Process; Bituminous Coal; Lime Kilns	III-323
In-Process; Process Gas; Coke Oven Gas 	III-325
Internal Combustion Engines - Gas	III-327
Internal Combustion Engines - Gas - Large Sources	III-329
Internal Combustion Engines - Gas - Small Sources	III-335
Internal Combustion Engines - Oil - Small Sources 	III-341
Iron & Steel Mills - Annealing 	III-345
Iron & Steel Mills - Annealing - Small Sources 	III-355
Iron & Steel Mills - Galvanizing	III-361
Iron & Steel Mills - Reheating	III-365
Iron Production; Blast Furnaces; Blast Heating Stoves	III-371
Lime Kilns	III-373
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PECHAN
September 2005
NITROGEN OXIDES (NOx) (continued)
Source Category	Page
Medical Waste Incinerators	III-385
Municipal Waste Combustors 	III-387
Natural Gas Production; Compressors - Small Sources 	III-389
Nitric Acid Manufacturing - Small Sources 	III-391
Off-Highway Diesel Vehicles 	III-398
Off-Highway Gasoline Vehicles 	III-406
Open Burning	III-414
Plastics Prod-Specific; (ABS)-Small Sources 	III-416
Process Heaters - Distillate Oil - Small Sources 	III-418
Process Heaters - LPG - Small Sources	III-436
Process Heaters - Natural Gas - Small Sources	III-454
Process Heaters - Other Fuel - Small Sources	III-472
Process Heaters - Process Gas - Small Sources	III-490
Process Heaters - Residual Oil - Small Sources 	III-508
Residential Natural Gas	III-526
Rich-Burn Stationary Reciprocating Internal Combustion Engines 	III-530
Sand/Gravel; Dryer - Small Sources 	III-536
Secondary Aluminum Production; Smelting Furnaces 	III-538
Solid Waste Disposal; Government; Other	III-540
Space Heaters - Distillate Oil - Small Sources 	III-542
Space Heaters - Natural Gas - Small Sources 	III-550
Starch Manufacturing; Combined Operation - Small Sources	III-560
Steel Foundries; Heat Treating 	III-562
Steel Production; Soaking Pits	III-564
Sulfate Pulping - Recovery Furnaces - Small Sources	III-566
Surface Coat Oper; Coating Oven Htr; Nat Gas - Small Sources 	III-576
Utility Boiler - Coal/Tangential	III-578
Utility Boiler - Coal/Wall 	III-597
Utility Boiler - Cyclone	III-612
Utility Boiler - Oil-Gas/Tangential 	III-619
Utility Boiler - Oil-Gas/Wall	III-625
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PECHAN
September 2005
PARTICULATE MATTER (PM)
Source Category	Page
Agricultural Burning 	111-631
Agricultural Tilling 	III-633
Asphalt Manufacture	III-635
Beef Cattle Feedlots	III-655
Chemical Manufacture	III-656
Commercial Institutional Boilers - Coal 	III-669
Commercial Institutional Boilers - Liquid Waste 	III-683
Commercial Institutional Boilers - LPG 	III-687
Commercial Institutional Boilers - Natural Gas 	III-691
Commercial Institutional Boilers - Oil	III-695
Commercial Institutional Boilers - Process Gas 	III-702
Commercial Institutional Boilers - Solid Waste 	III-706
Commercial Institutional Boilers - Wood 	III-710
Commercial Institutional Boilers - Wood/Bark	III-714
Construction Activities 	III-724
Conveyorized Charbroilers 	III-726
Electric Generation - Coke	III-727
Electric Generation - Bagasse 	III-731
Electric Generation - Coal	III-735
Electric Generation - Liquid Waste	III-739
Electric Generation - LPG	III-743
Electric Generation - Natural Gas 	III-747
Electric Generation - Oil 	III-751
Electric Generation - Solid Waste	III-755
Electric Generation - Wood	III-759
Fabricated Metal Products - Abrasive Blasting	III-763
Fabricated Metal Products - Welding 	III-766
Ferrous Metals Processing - Coke	III-769
Ferrous Metals Processing - Ferroalloy Production	III-784
Ferrous Metals Processing - Gray Iron Foundries	III-799
Ferrous Metals Processing - Iron and Steel Production	III-822
Ferrous Metals Processing - Other	III-851
Ferrous Metals Processing - Steel Foundries	III-855
Grain Milling	III-880
Highway Vehicles - Gasoline Engine 	III-892
Highway Vehicles - Heavy Duty Diesel Engines	III-894
Industrial Boilers - Coal	III-899
Industrial Boilers - Coke 	III-919
Industrial Boilers - Liquid Waste	III-923
Industrial Boilers - LPG	III-930
Industrial Boilers - Natural Gas	III-934
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PECHAN
September 2005
PARTICULATE MATTER (PM) (continued)
Source Category	Page
Industrial Boilers - Oil	III-938
Industrial Boilers - Process Gas	III-948
Industrial Boilers - Solid Waste	III-952
Industrial Boilers - Wood	III-956
Mineral Products - Cement Manufacture	III-975
Mineral Products - Coal Cleaning	III-999
Mineral Products - Other	Ill-1023
Mineral Products - Stone Quarrying and Processing	Ill-1076
Municipal Waste Incineration 	Ill-1108
Non-Ferrous Metals Processing - Aluminum 	III-l 111
Non-Ferrous Metals Processing - Copper 	III-l 128
Non-Ferrous Metals Processing - Lead	III-l 147
Non-Ferrous Metals Processing - Other	III-l 165
Non-Ferrous Metals Processing - Zinc 	III-l 184
Nonroad Diesel Engines	III-1201
Paved Roads	Ill-1203
Prescribed Burning	Ill-1205
Residential Wood Combustion 	Ill-1207
Residential Wood Stoves	III-1208
Unpaved Roads 	Ill-1209
Utility Boilers - Coal 	Ill-1212
Utility Boilers - Gas/Oil	III-1227
Wood Pulp & Paper	Ill-1229
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PECHAN
September 2005
SULFUR DIOXIDE (S02)
Source Category	Page
Bituminous/Subbituminous Coal 	III-1236
Bituminous/Subbituminous Coal (Industrial Boilers)	Ill-1242
By-Product Coke Manufacturing	Ill-1248
Distillate Oil (Industrial Boiler)	Ill-1250
Inorganic Chemical Manufacture	Ill-1252
In-process Fuel Use - Bituminous Coal	Ill-1254
Lignite (Industrial Boilers)	Ill-1256
Mineral Products Industry	Ill-1264
Petroleum Industry	Ill-1267
Primary Lead Smelters - Sintering	Ill-1270
Primary Metals Industry	Ill-1272
Primary Zinc Smelters - Sintering	Ill-1274
Process Heaters (Oil and Gas Production)	Ill-1276
Pulp and Paper Industry (Sulfate Pulping)	Ill-1278
Residual Oil (Commercial/Institutional Boilers)	Ill-1280
Residual Oil (Industrial Boilers) 	Ill-1284
Secondary Metal Production 	Ill-1286
Steam Generating Unit-Coal/Oil	III-1288
Sulfur Recovery Plants - Elemental Sulfur 	Ill-1290
Sulfur Recovery Plants - Sulfur Removal 	Ill-13 04
Sulfuric Acid Plants - Contact Absorbers 	Ill-13 06
Utility Boilers - Coal-Fired 	III-l 328
Utility Boilers - High Sulfur Content	Ill-1335
Utility Boilers - Medium Sulfur Content	Ill-1338
Utility Boilers - Very High Sulfur Content 	III-l341
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PECHAN
September 2005
VOLATILE ORGANIC COMPOUNDS (VOC)
Source Category	Page
Adhesives - Industrial 	Ill-1344
Aircraft Surface Coating 	Ill-1346
Architectural Coatings	Ill-1347
AREA	Ill-1356
Automobile Refinishing	Ill-13 64
Bakery Products	Ill-13 70
Commercial Adhesives 	III-1372
Consumer Solvents 	Ill-1377
Cutback Asphalt	Ill-13 82
Electrical/Electronic Coating	Ill-1383
Fabric Printing, Coating and Dyeing	III-1386
Flexographic Printing	Ill-1389
Graphic Arts	Ill-1391
Highway Vehicles - Gasoline Engine 	Ill-13 92
Industrial Maintenance Coating	Ill-13 94
Machinery, Equipment, and Railroad Coating	Ill-1402
Marine Surface Coating (Shipbuilding)	Ill-1404
Metal Can Surface Coating Operations	Ill-1406
Metal Coil & Can Coating	Ill-1408
Metal Furniture Surface Coating Operations	Ill-1411
Metal Furniture, Appliances, Parts 	Ill-1413
Miscellaneous Metal Products Coatings 	Ill-1416
Motor Vehicle Coating 	Ill-1417
Municipal Solid Waste Landfill	III-1420
Nonroad Gasoline Engines	Ill-1421
Off-Highway Vehicles: All Terrain Vehicles (ATVs)	III-1424
Off-Highway Vehicles: Motorcycles	III-1428
Off-Highway Vehicles: Snowmobiles	III-1436
Open Top Degreasing 	Ill-1444
Paper and other Web Coating Operations 	Ill-1450
Paper Surface Coating	Ill-1452
Pesticide Application	III-1453
Portable Gasoline Containers	Ill-1455
Product and Packaging Rotogravure and Screen Printing	III-1456
Publication Rotogravure Printing 	Ill-145 8
Rubber and Plastics Manufacturing	Ill-1460
Stage II Service Stations 	Ill-1462
Stage II Service Stations - Underground Tanks	Ill-1464
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PECHAN	September 2005
VOLATILE ORGANIC COMPOUNDS (VOC) (continued)
Source Category	Page
Traffic Markings 	Ill-1466
Wood Furniture Surface Coating	Ill-1474
Wood Product Surface Coating	Ill-1479
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Cattle Feedlots
Control Measure Name: Chemical Additives to Waste
Rule Name: Not Applicable
Pechan Measure Code: A00101	POD: 01
Application: This control is the adding of chemicals to cattle waste to reduce ammonia emissions
from cattle feedlots.
The control applies to all cattle and calve operations classified under SCC 280503000.
Affected SCC:
2805020000 Cattle and Calves Composite, Total
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg







V*


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Pechan contacted the manufacturer of the chemical inhibitor, N-(n-butyl)
thiophosphoric triamide (NBPT; trade name Conserve-Nr). According to the
manufacturer, the control effectiveness at cattle feedlots is 50 percent and the cost
per head-day is $0.0062 ($2.26/head-yr; Axe, 1999). The manufacturer also reports
that field tests are ongoing at dairies and that the product should perform the same
(50 percent control), but cost slightly more $0.0094/head-day ($3.43/head-yr; Axe,
1999). It was not clear why the costs would be higher at dairies.
To estimate costs, an average per head cost between dairy cattle and feedlot cattle
would be $2.85/head-yr (from the above estimates). The emission factor for cattle is
about 23 kg/head-yr (0.025 ton/head-yr). A 50 percent control efficiency yields
0.0125 ton/head-yr reduced). Hence, the cost factor would be $2.85/0.0125 ton or
$228/ton of NH3 reduced.
Cost Effectiveness: The cost effectiveness is $228 per ton HN3 reduced. (1999$)
Comments:
Status: Demonstrated
Last Reviewed: 2000
Additional Information:
References:
Axe, 1999: D. Axe, IMC Agrico Feed Ingredients, personal communication with S. Roe, E.H.
Pechan & Associates, Inc., June 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Hog Operations
Control Measure Name: Chemical Additives to Waste
Rule Name: Not Applicable
Pechan Measure Code: A00301
POD: 03
Application: This control is the adding of chemicals to hog waste to reduce ammonia emissions
from hog feedlots. Assessment of control measures applicable to ammonia emissions
for hog operations is based on procedures used for cattle operations.
The control applies to all hog and pig operations classified under SCC 2805025000.
Affected SCC:
2805025000 Hogs and Pigs Composite, Total
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg







V*


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Pechan contacted the manufacturer of the chemical inhibitor, N-(n-butyl)
thiophosphoric triamide (NBPT; trade name Conserve-Nr). According to the
manufacturer, the control effectiveness at cattle feedlots is 50 percent and the cost
per head-day is $0.0062 ($2.26/head-yr; Axe, 1999).
According to the manufacturer, the same 50 percent control efficiency derived for
cattle can be assumed for hogs (Axe, 1999). The emission factor for hogs is 20.3
Ib/head-yr. With the 50 percent control efficiency, this equates to 10.15 Ib/head-yr
reduced (5.08 x 10-3 ton/head-yr reduced). Therefore, the cost parameter would be
$0.37/5.08E-3 ton or $73/ton NH3 reduced.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $73 per ton NH3 reduced.
(1999$)
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
There is assumed to be 100 percent penetration; however, the modeling parameters are probably
most applicable to large hog farming operations. Hence, it may be more reasonable to apply the
control in counties with large hog raising operations (i.e., using COA data).
References:
Axe, 1999: D. Axe, IMC Agrico Feed Ingredients, personal communication with S. Roe, E.H.
Pechan & Associates, Inc., June 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Poultry Operations
Control Measure Name: Chemical Additives to Waste
Rule Name: Not Applicable
Pechan Measure Code: A00201
POD: 02
Application: This control is the chemical addition of alum to poultry litter. Alum is used to stabilize
poultry litter to reduce ammonia emissions. Alum, an acid-forming compounds, keeps
the pH of the poultry litter below 7, which inhibits ammonia volatilization.
The control applies to all poultry and chicken operations classified under SCC
280503000.
Affected SCC:
2805030000 Poultry and Chickens Composite, Total
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg







V*


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Treatment costs are estimated to be about $0.025/head (Moore, 1999). These costs
do not factor in some benefits to the grower (e.g., reduced heating/ventilation costs
due to lower ammonia levels; higher value for fertilizer due to higher nitrogen levels).
Assuming six grow-outs per year, the costs would be $0.15/head-yr. The emission
factor used for all poultry is 0.394 Ib/head-yr (1.97 x 10-4 ton/head-yr). Assuming a
75 percent control efficiency for alum treatment, the emission reduction would be 1.48
x 10-4 ton/head-yr reduced. Hence, the cost parameter would be $0.15/1.48E-04 ton
reduced or $1,014/ton NH3 reduced.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,014 per ton NH3 reduced.
(1999$)
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
The control effectiveness for alum treatment is estimated to be 75 percent (Moore, 1999). The
control effectiveness is highest during the early part of the growing cycle (i.e., >95 percent), when
the young chickens are most susceptible to health problems from high ammonia levels. The control
effectiveness drops off during the grow-out (about two months). Alum is then reapplied to the litter
before the next grow-out begins (typically, there are 5 or 6 grow-outs per year). There is assumed to
be 100 percent penetration.
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Axe, 1999: D. Axe, IMC Agrico Feed Ingredients, personal communication with S. Roe, E.H.
Pechan & Associates, Inc., June 1999
Moore, 1999: P.A. Moore, Jr., University of Arkansas, personal communication with S. Roe, E.H.
Pechan & Associates, Inc., June 1999
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Agricultural Burning
Control Measure Name: Seasonal Ban (Ozone Season Daily)
Rule Name: Not Applicable
Pechan Measure Code: N13201	POD: 132
Application: An ozone season ban of burning is a ban of burning on an ozone season day where
ozone exceedances are predicted. Ozone season daily ban of agricultural burning to
reduce NOx emissions during the ban.
This control is applicable to field burning where the entire field would be set on fire,
and can be applied to all crop types. These sources are classified under 2801500000.
Affected SCC:
2801500000 Agricultural Burning
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: Daily control efficiency is 100% from uncontrolled; Annual control efficiency is
0% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 80%
Penetration: 100%
Cost Basis: Since burning can simply be shifted to other acceptable periods, emission control
costs are assumed to be zero for regulations that schedule the burning days where
ozone exceedances are not predicted (Pechan, 1997).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $0 per ton NOx reduced
(1990$).
Note: Since this is a daily control, no annual emission reductions are expected.
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
Costs may be incurred if personnel scheduled to participate in the agricultural burning cannot be
used elsewhere or if fire personnel or other professionals have been scheduled to participate.
Assuming full compliance with the regulation, ozone season daily emission reductions from such a
regulation would be 100 percent. However, annual emission reductions would not be expected,
because there would likely be a shift in the timing of the emissions, not a reduction in the total
amount of annual NOx emitted. A compliance rate of 80 percent is used in estimating daily
reductions (Pechan, 1997).
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Pechan, 1997: E.H. Pechan & Associates, "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ammonia - Natural Gas - Fired Reformers - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0561S, N05601	POD: 56
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) ammonia production
operations with natural gas-fired reformers (SCC 30100306) and uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30100306 Ammonia Production, Primary Reformer: Natural Gas Fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 5.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $820 per ton NOx reduced
from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ammonia - Natural Gas - Fired Reformers - Small Sources
Control Measure Name: Low NOx Burner (LNB) + Flue Gas Recirculation (FGR)
Rule Name: Not Applicable
Pechan Measure Code: N0562S, N05602	POD: 56
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) ammonia production
operations with natural gas-fired reformers (SCC 30100306) and uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30100306 Ammonia Production, Primary Reformer: Natural Gas Fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1993). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
5.9. An equipment life of 10 years is assumed (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $2,560 per ton NOx reduced from
uncontrolled and $2,470 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ammonia - Natural Gas - Fired Reformers - Small Sources
Control Measure Name: Oxygen Trim + Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0563S, N05603	POD: 56
Application: This control is the use of OT + Wl to reduce NOx emissions.
This control is applicable to small (<1 ton NOx per OSD) ammonia production
operations with natural gas-fired reformers (SCC 30100306) and uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30100306 Ammonia Production, Primary Reformer: Natural Gas Fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 65% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 2.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $680 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The
water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ammonia - Natural Gas - Fired Reformers - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0564S, N05604	POD: 56
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) natural-gas fired reformers involved in the
production of ammonia (SCC 30100306) with uncontrolled NOx emissions greater than
10 tons per year..
Affected SCC:
30100306 Ammonia Production, Primary Reformer: Natural Gas Fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,230 per ton NOx
reduced from uncontrolled and $2,860 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent
reacts selectively with the flue gas NOx within a specific temperature range and in the presence of
the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Document No. 05.09.009/9010.463
111-24
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ammonia - Natural Gas - Fired Reformers - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0565S, N05605	POD: 56
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx per OSD) ammonia production natural gas
fired reformers (SCC 30100306) with uncontrolled NOx emissions greater than 10 tons
per year.
Affected SCC:
30100306 Ammonia Production, Primary Reformer: Natural Gas Fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $3,780 per ton NOx
reduced from uncontrolled and $2,900 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ammonia Products; Feedstock Desulfurization - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0622S, N06202	POD: 62
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) feedstock desulfurization
processes in ammonia products operations with uncontrolled NOx emissions greater
than 10 tons per year.
Affected SCC:
30100305 Ammonia Production, Feedstock Desulfurization
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.9. An equipment life of 10 years is assumed (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $2,560 per ton NOx reduced from
uncontrolled and $2,470 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
It is assumed that the superheated steam needed to regenerate the activated carbon bed used in
the desulfurization process is the NOx source.
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Asphaltic Cone; Rotary Dryer; Conv Plant - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0731S, N07301	POD: 73
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) construction operations with
rotary driers and uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30502508 Construction Sand & Gravel, Dryer (See 3-05-027-20 thru -24 Industrial Sand Dryers)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1993).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,200 per ton NOx reduced
from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: By-Product Coke Manufacturing; Oven Underfiring
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0653S, N06503	POD: 65
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to all by-product coke manufacturing operations with oven
underfiring (SCC 30300306) and uncontrolled NOx emissions greater than 10 tons per
year.
Affected SCC:
30300306 By-product Coke Manufacturing, Oven Underfiring
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$1,640 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September, 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Kilns
Control Measure Name: Biosolid Injection
Rule Name: Not Applicable
Pechan Measure Code: NCEMK
Application: This control applies to cement kilns
POD: 90
Affected SCC:
30102306 Sulfuric Acid (Contact Process), Absorber/@99.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 23% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital cost to annual ratio is 7.3
Cost Effectiveness: The cost effectiveness is $310 per ton of Nox reduction (1997$).
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Manufacturing - Dry
Control Measure Name: Mid-Kiln Firing
Rule Name: Not Applicable
Pechan Measure Code: N0331L, N0331S, N03301	POD: 33
Application: This control is the use of mid- kiln firing to reduce NOx emissions.
This control applies to dry-process cement manufacturing (SCC 30500606) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30500606 Mineral Products, Cement Manufacturing (Dry Process), Kilns
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost equations for cement plants NOx control are based on an analysis of EPA's NOx
State Implementation Plan (SIP) Call (Pechan, 1998). Capital and annual cost
information was obtained from a NOx control technologies for the cement industry
report (EC/R, 2000). Cost for low-NOx burners were developed using model plants.
A discount rate of 10% and an equipment life of 15 years was assumed.
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in the EC/R report, Tables 6-3, 6-9 and 6-10. Per the EC/R report,
electricity costs are negligible. The breakdown was obtained using the average O&M
costs for furnaces having capacities of 113 and 180 MMBTU per hour. A capacity
factor of is used in estimating the O&M cost breakdown.
Maintenance labor: $24.33 per hour times 0.5 hour per 8-hour shift
Fuel (tires): -$42.50 per ton
Cost Effectiveness: The default cost effectiveness value is $55 per ton NOx reduced from both
uncontrolled and RACT baselines (1997$). The cost effectiveness range is
from a savings of $460 to a cost of $720 per ton NOx reduced.
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EC/R, 2000: EC/R Incorporated, "NOx Control Technologies for the Cement Industry," prepared for
U.S. Environmental Protection Agency, Research Triangle Park, NC, September 2000.
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Manufacturing - Dry
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0332S, N03302	POD: 33
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to dry-process cement manufacturing operations with indirect-fired
kilns (SCC 30500606) with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30500606 Mineral Products, Cement Manufacturing (Dry Process), Kilns
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). Capital and annual cost information
was obtained from a NOx control technologies for the cement industry report (EC/R,
2000). Cost for low-NOx burners were developed using model plants. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1994).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Tables 6-5, 6-6, 6-7 and 6-8 of the ACT document. The breakdown
was developed using the average costs for 2 direct-fired and 2 indirect-fired model
furnaces. A capacity factor of 0.91 is used in estimating the O&M cost breakdown.
Operating Labor: $22.12/hr
Maintenance Labor: $24.33/hr
Cost Effectiveness: The cost effectiveness used in AirControlNET is $440 per ton NOx reduced
from both uncontrolled and RACT (1997$). The cost effectiveness range is
$300 to $620 per ton NOx reduced.
Comments:
Status: Demonstrated
Last Reviewed: 1998
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EC/R, 2000: EC/R Incorporated, "NOx Control Technologies for the Cement Industry," prepared for
U.S. Environmental Protection Agency, Research Triangle Park, NC, September 2000.
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Manufacturing - Dry
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Urea Based
Rule Name: Not Applicable
Pechan Measure Code: N0333S, N03303	POD: 33
Application: This control is the reduction of NOx emission through urea based selective non-
catalytic reduction add-on controls. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20).
This control applies to dry-process cement manufacturing (SCC 30500606) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30500606 Mineral Products, Cement Manufacturing (Dry Process), Kilns
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1994).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in the ACT document Table 6-11. The breakdown was obtained using the
average O&M costs for furnaces having capacities of 152, 266, 330 and 495 MMBTU
per hour. A capacity factor of 0.913 is used in estimating the O&M cost breakdown.
Operating labor: $28.22 per hour
Maintenance labor: $24.33 per hour times 0.5 hours per 8 hour shift
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$770 per ton NOx reduced (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Manufacturing - Dry
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Ammonia Based
Rule Name: Not Applicable
Pechan Measure Code: N0334S, N03304	POD: 33
Application: This control is the reduction of NOx emission through ammonia based selective non-
catalytic reduction add-on controls. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20).
This control applies to dry-process cement manufacturing operations (SCC 30500606)
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30500606 Mineral Products, Cement Manufacturing (Dry Process), Kilns
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1994).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in . The breakdown was obtained using the average O&M costs for
having capacities of per hour. A capacity factor of is used in estimating the O&M
cost breakdown.
Operating labor: $28.22 per hour
Fuel (natural gas): $5.00 per MMBTU
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$850 per ton NOx reduced (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Manufacturing - Dry
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0335S, N03305	POD: 33
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control applies to dry-process cement manufacturing (SCC 30500606) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30500606 Mineral Products, Cement Manufacturing (Dry Process), Kilns
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in the EC/R report, Tables 6-13 and 6-14. The breakdown was obtained
using the average O&M costs for furnaces having capacities of 113 and 180 MMBTU
per hour. A capacity factor of 0.913 is used in estimating the O&M cost breakdown.
Operating labor: $22.12 per hour
Maintenance labor: $24.33 per hour
Cost Effectiveness: The cost effectiveness values (for both small and large sources) used in
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AT-A-GLANCE TABLE FOR POINT SOURCES
AirControlNET are $3,370 per ton NOx reduced from both uncontrolled and
RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent
reacts selectively with the flue gas NOx within a specific temperature range and in the presence of
the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EC/R, 2000: EC/R Incorporated, "NOx Control Technologies for the Cement Industry," prepared for
U.S. Environmental Protection Agency, Research Triangle Park, NC, September 2000.
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Manufacturing - Wet
Control Measure Name: Mid-Kiln Firing
Rule Name: Not Applicable
Pechan Measure Code: N0341L, N0341S, N03401	POD: 34
Application: This control is the use of mid- kiln firing to reduce NOx emissions.
This control applies to wet-process cement manufacturing (SCC 30500706) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30500706 Mineral Products, Cement Manufacturing (Wet Process), Kilns
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost equations for cement plants NOx control are based on an analysis of EPA's NOx
State Implementation Plan (SIP) Call (Pechan, 1998). Capital and annual cost
information was obtained from a NOx control technologies for the cement industry
report (EC/R, 2000). Cost for low-NOx burners were developed using model plants.
A discount rate of 10% and an equipment life of 15 years was assumed.
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in the EC/R report, Tables 6-3, 6-9 and 6-10. The breakdown was
obtained using the average costs for furnaces having capacities of 113 and 180
MMBTU per hour. A capacity factor of 0.913 is used in estimating the O&M cost
breakdown.
Maintenance labor: $24.33 per hour
Fuel (tires): -$42.50 per ton
Cost Effectiveness: The default cost effectiveness value is $55 per ton NOx reduced from both
uncontrolled and RACT baselines (1997$). The cost effectiveness range is
from a savings of $460 to a cost of $720 per ton NOx reduced.
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EC/R, 2000: EC/R Incorporated, "NOx Control Technologies for the Cement Industry," prepared for
U.S. Environmental Protection Agency, Research Triangle Park, NC, September 2000.
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Manufacturing - Wet
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0342S, N0342L, N03402	POD: 34
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wet-process cement manufacturing operations with indirect-fired
kilns (SCC 30500706) with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30500706 Mineral Products, Cement Manufacturing (Wet Process), Kilns
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). Capital and annual cost information
was obtained from a NOx control technologies for the cement industry report (EC/R,
2000). A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 15 years (EPA, 1994).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in the EC/R report, Tables 6-5, 6-6, 6-7 and 6-8. The breakdown was
obtained using the average costs for two direct and two indirect-fired furnaces having
capacities (1 direct and 1 indirect) of 180 and 300 MMBTU per hour. A capacity
factor of 0.913 is used in estimating the O&M cost breakdown.
Operating labor: $22.12/hr
Maintenance labor: $24.33 per hour times 0.5 hours per 8 hour shift
Cost Effectiveness: The cost effectiveness used in AirControlNET is $440 per ton NOx reduced
from both uncontrolled and RACT (1997$). The cost effectiveness range is
$300 to $620 per ton NOx reduced.
Comments:
Status: Demonstrated
Last Reviewed: 1998
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EC/R, 2000: EC/R Incorporated, "NOx Control Technologies for the Cement Industry," prepared for
U.S. Environmental Protection Agency, Research Triangle Park, NC, September 2000.
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Manufacturing - Wet - Large Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0343L, N03403	POD: 34
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control applies to large(>1 ton NOx per OSD) wet-process cement manufacturing
(SCC 30500706) with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30500706 Mineral Products, Cement Manufacturing (Wet Process), Kilns
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in the EC/R report Tables 6-3, 6-13 and 6-14. The breakdown was
obtained using the average costs for furnaces having capacities of 113 and 180
MMBTU per hour. A capacity factor of 0.913 is used in estimating the O&M cost
breakdown.
Operating labor: $22.12/hr
Maintenance labor: $24.33/hr
Fuel (natural gas): $3.42/MMBTU
Cost Effectiveness: The cost effectiveness values (for both small and large sources) used in
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AT-A-GLANCE TABLE FOR POINT SOURCES
AirControlNET are $2,880 per ton NOx reduced from both uncontrolled and
RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent
reacts selectively with the flue gas NOx within a specific temperature range and in the presence of
the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EC/R, 2000: EC/R Incorporated, "NOx Control Technologies for the Cement Industry," prepared for
U.S. Environmental Protection Agency, Research Triangle Park, NC, September 2000.
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Cement Manufacturing - Wet - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0343S	POD: 34
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control applies to small (<1 ton NOx per OSD) wet-process cement manufacturing
(SCC 30500706) with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30500706 Mineral Products, Cement Manufacturing (Wet Process), Kilns
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in the EC/R report Tables 6-3, 6-13 and 6-14. The breakdown was
obtained using the average costs for furnaces having capacities of 113 and 180
MMBTU per hour. A capacity factor of 0.913 is used in estimating the O&M cost
breakdown.
Operating labor: $22.12/hr
Maintenance labor: $24.33/hr
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,880 per ton NOx
reduced from both uncontrolled and RACT baselines (1990$).
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AT-A-GLANCE TABLE FOR POINT SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ceramic Clay Manufacturing; Drying - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0741S, N07401	POD: 74
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) drying processes at ceramic
clay manufacturing operations with uncontrolled NOx emissions greater than 10 tons
per year.
Affected SCC:
30500801 Ceramic Clay/Tile Manufacture, Drying ** (use SCC 3-05-008-13)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). Capital and annual cost information
was obtained from the Alternative Control Techniques Document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 7.3. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,200 per ton NOx reduced
from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
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AT-A-GLANCE TABLE FOR POINT SOURCES
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993c: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Coal Cleaning-Thrml Dryer; Fluidized Bed - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0753S, N07503	POD: 75
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) thermal drying processes at
coal cleaning operations with uncontrolled NOx emissions greater than 10 tons per
year.
Affected SCC:
30502508 Construction Sand & Gravel, Dryer (See 3-05-027-20 thru -24 Industrial Sand Dryers)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 4.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,460 per ton NOx reduced
from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
Thermal dryers are a direct-heat device.
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
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AT-A-GLANCE TABLE FOR POINT SOURCES
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Coal-fired Plants with Production Capacities>100MW
Control Measure Name: Combustion Optimization
Rule Name: Not Applicable
Pechan Measure Code: N00801	POD: 11
Application: Combustion optimization is a method that can improve combustion efficiency and
decrease NOx emissions from the electric utility boilers by using active control of the
combustion process. By using commercially available technology enhancements,
combustion optimization is an effective and broadly applicable option for most types of
boilers (e.g. gas, oil and coal) with greater than 100 MW production capacities.
This control is applicable to SCCs 10100202, 10100203, 10100212, and 10100217..
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Based on literature surveys and discussions with vendors and other experts familiar
with combustion optimization software, EPA's Integrated Planning Model (IPM)
performed a cost and performance analysis for process optimization of coal plants
with production capacities greater than 100 MW. According to this analysis, the
capital needed for making the required modifications to the boilers and adding the
required sensors, software and control devices was estimated to be $250,000 per
unit. The annual operating and maintenance costs for the control systems were
estimated to be $40,000 per boiler. This analysis, however does not take into
account the projected energy savings.
Wisconsin Department of Natural Resources estimated the costs associated with
three government-owned facilities in 2000 and estimated the initial expenditure for the
boilers to be approximately $100,000 each. Including expected fuel savings, the
Wisconsin Department of Natural Resources estimated an annualized net savings of
$50,000 per year for each unit (WDNR, 2000).
All costs are in 1999 dollars.
Cost Effectiveness: The cost analysis is based on the 2000 Wisconsin SIP which estimated the
cost effectiveness of the NOx combustion optimization to range from a cost
savings of $100 to a cost of $50 per ton NOx reduced (1999$). The average
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
value used in AirControlNET is a cost of $50 per ton NOx reduced. The
analysis includes projected energy savings from thermal efficiency
improvements for units that utilize combustion optimization (WDNR, 2000). All
costs are in $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
In coal-fired plants it is estimated that thermal efficiency can be improved by 0.5%. The improved
heat rate from the units that utilize combustion optimization translates into further pollution
prevention, in addition to the reduced NOx emissions (EPA, 2002).
All combustion processes require a mixture of fuel and air. Improper fuel to air ratio can result in
thermal inefficiencies and/or excessive emissions from the boilers. Combustion optimization
measures seek to find and maintain optimum combustion conditions by applying better controls on
the air and fuel injection mechanisms of the boilers. One approach used in process optimization
utilizes a neural network computer program to find the optimum control points. For example,
advanced controls, such as furnace sensors and coal flow measuring devices, can be used to
optimize the boiler combustion by controlling the flow of fuel and air into the boiler (EPA, 1999).
Combustion must be optimized for the conditions that are encountered and often requires
customized designs for individual boilers. For example, when boiler tubes are far enough away from
the burner, computer controls from some vendors are designed to decrease the amount of air that is
pre-mixed with fuel from the stoichiometric ratio to lengthen the flame at the burner and reduce the
rate of heat release per unit volume (EPA, 1999).
References:
EPA, 1999: U.S. Environmental Protection Agenc, Clean Air Technology Center (MD-12)
Information Transfer and Program Integration Division Office of Air Quality Planning and Standard,
"Nitrogen Oxides (NOx), Why and How They Are Controlled," EPA-456/F-99-006R, Research
Triangle Park, NC, November 1999.
EPA, 2002: U.S. Environmental Protection Agency, "Documentation of EPA Modeling Applications
(v.2.1) Using The Integrated Planning Model," EPA 430/R-02-004, March 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Jet Fuel - Small Sources
Control Measure Name: Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0501S, N05001	POD: 50
Application: This control is the use of water injection to reduce NOx emissions.
This control applies to small (3.3 MW to 34.4MW) jet fuel-fired turbines with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200901 Kerosene/Naphtha (Jet Fuel), Turbine
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 68% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by the following (Pechan, 1998).
Small source = 3.3 MWto 34.4 MW
The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1993). Capital and annual cost information was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.9
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent are
assumed, along with an equipment lifetime of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information for an example small turbine in Table 6-5 of the ACT document for
stationary gas turbines. The model plant is a 26.8 megawatt MS5001P turbine.
Continuous operation 8,000 hours per year is used to estimate operating costs.
Electricity cost: 0.06 $/kW-hr
Natural gas cost: $4.13/MMBtu
Cost Effectiveness: The default cost effectiveness value is $1,290 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
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Status: Demonstrated
Last Reviewed: 2001
Additional Information:

Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The
water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).

References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Jet Fuel - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR) + Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0502S, N05002	POD: 50
Application: This control is the selective catalytic reduction of NOx through add-on controls in
combination with water injection. SCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx
removal efficiency, which allows the process to occur at lower temperatures.
This control applies to small (3.3 MW to 34.4MW) jet fuel-fired turbines with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200901 Kerosene/Naphtha (Jet Fuel), Turbine
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by the following (Pechan, 1998).
Small source = 3.3 MWto 34.4 MW
The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1993). Capital and annual cost information was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.8
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent are
assumed, along with an equipment lifetime of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information for an example small turbine in Table 6-9 of the ACT document for
stationary gas turbines. The model plant is a 26.8 megawatt MS5001P turbine.
Continuous operation 8,000 hours per year is used to estimate operating costs.
Electricity cost: 0.06 $/kW-hr
Natural gas cost: $4.13/MMBtu
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The default cost effectiveness value is $2,30 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Natural Gas - Large Sources
Control Measure Name: Dry Low NOx Combustors
Rule Name: Not Applicable
Pechan Measure Code: N0243L, N02403	POD: 24
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to large (83.3 MWto 161 MW) natural gas fired turbines with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200201 Natural Gas, Turbine
20200203 Natural Gas, Turbine: Cogeneration
20300202	Natural Gas, Turbine
20300203	Natural Gas, Turbine: Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 84% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by the following (Pechan, 1998).
Large source = greater than 83.3 MW and less than 161 MW
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1993), capacity-based equations are used to calculate costs. A
discount rate of 10 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 76% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
Capital Cost = 71,281.1 * Capacity (MMBtu/hr)A0.505
Annual Cost = 7,826.3 * Capacity (MMBtu/hr)A0.505
From RACT Baseline:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Capital Cost = 71,281.1 * Capacity (MMBtu/hr)A0.505
Annual Cost = 7,826.3 * Capacity (MMBtu/hr)A0.505
Note: All costs are in 1990 dollars.
O&M Cost Components: There are no O&M costs associated with dry low NOx
combustors.
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness value, used when capacity information is not
available, is $100 per ton NOx reduced from uncontrolled and $140 per ton
NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Natural Gas - Small Sources
Control Measure Name: Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0241S, N02401	POD: 24
Application: This control is the use of water injection to reduce NOx emissions.
This control applies to small (3.3 MWto 34.4MW) natural gas-fired gas turbines with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200201 Natural Gas, Turbine
20200203 Natural Gas, Turbine: Cogeneration
20300202	Natural Gas, Turbine
20300203	Natural Gas, Turbine: Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 76% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by the following (Pechan, 1998).
Small source = 3.3 MWto 34.4 MW
The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1993). Capital and annual cost information was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 3.
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent are
assumed, along with an equipment lifetime of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 76% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information for an example small turbine in Table 6-5 of the ACT document for
stationary gas turbines. The model plant is a 26.8 megawatt MS5001P turbine.
Continuous operation 8,000 hours per year is used to estimate operating costs.
Electricity cost: 0.06 $/kW-hr
Natural gas cost: $4.13/MMBtu
Cost Effectiveness: The default cost effectiveness value is $1,510 per ton NOx reduced from both
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AT-A-GLANCE TABLE FOR POINT SOURCES
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:

Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The
water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).

References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Natural Gas - Small Sources
Control Measure Name: Steam Injection
Rule Name: Not Applicable
Pechan Measure Code: N0242S, N02402	POD: 24
Application: This control is the use of steam injection to reduce NOx emissions.
This control applies to small (3.3 MWto 34.4MW) natural gas-fired gas turbines with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200201 Natural Gas, Turbine
20200203 Natural Gas, Turbine: Cogeneration
20300202	Natural Gas, Turbine
20300203	Natural Gas, Turbine: Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by the following (Pechan, 1998).
Small source = 3.3 MWto 34.4 MW
The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1993). Capital and annual cost information was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 3.7
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent are
assumed, along with an equipment lifetime of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 76% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information for an example small turbine in Table 6-5 of the ACT document for
stationary gas turbines. The model plant is a 26.8 megawatt MS5001P turbine.
Continuous operation 8,000 hours per year is used to estimate operating costs.
Electricity cost: 0.06 $/kW-hr
Natural gas cost: $4.13/MMBtu
Cost Effectiveness: The default cost effectiveness value is $1,040 per ton NOx reduced from both
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AT-A-GLANCE TABLE FOR POINT SOURCES
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:

Steam is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The
steam can be injected into the fuel, the combustion air or directly into the combustion chamber
(ERG, 2000).

References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Natural Gas - Small Sources
Control Measure Name: Dry Low NOx Combustors
Rule Name: Not Applicable
Pechan Measure Code: N0243S	POD: 24
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to small (3.3 MWto 34.4 MW) natural gas fired turbines with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200201 Natural Gas, Turbine
20200203 Natural Gas, Turbine: Cogeneration
20300202	Natural Gas, Turbine
20300203	Natural Gas, Turbine: Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 84% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by the following (Pechan, 1998).
Small source = 3.3 MWto 34.4 MW
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). Capital and annual cost information
was obtained from the Alternative Control Techniques Document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 9.1. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 76% (Pechan, 2001).
O&M Cost Components: There are no O&M costs associated with dry low NOx
combustors.
Cost Effectiveness: The default cost effectiveness values are $490 per ton NOx reduced from
uncontrolled and $540 per ton NOx reduced from RACT (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Natural Gas - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR) + Low NOx Burner (LNB)
Rule Name: Not Applicable
Pechan Measure Code: N0244S, N02404	POD: 24
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control applies to small (<1 ton NOx per OSD) natural gas fired turbines with NOx
emissions greater than 10 tons per year.
Affected SCC:
20200201 Natural Gas, Turbine
20200203 Natural Gas, Turbine: Cogeneration
20300202	Natural Gas, Turbine
20300203	Natural Gas, Turbine: Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 94% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 76% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information for an example small turbine in Table 6-10 of the ACT document for
stationary gas turbines. The model plant is a 26.8 megawatt MS5001P turbine.
Continuous operation 8,000 hours per year is used to estimate operating costs.
Electricity cost: 0.06 $/kW-hr
Natural gas cost: $4.13/MMBtu
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,570 per ton NOx
reduced from uncontrolled and $19,120 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Natural Gas - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR) + Steam Injection
Rule Name: Not Applicable
Pechan Measure Code: N0245S, N02405	POD: 24
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control applies to small (<1 ton NOx per OSD) natural gas fired turbines with NOx
emissions greater than 10 tons per year.
Affected SCC:
20200201 Natural Gas, Turbine
20200203 Natural Gas, Turbine: Cogeneration
20300202	Natural Gas, Turbine
20300203	Natural Gas, Turbine: Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 76% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information for an example small turbine in Table 6-9 of the ACT document for
stationary gas turbines. The model plant is a 26.8 megawatt MS5001P turbine.
Continuous operation 8,000 hours per year is used to estimate operating costs.
Electricity cost: 0.06 $/kW-hr
Natural gas cost: $4.13/MMBtu
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,010 per ton NOx
reduced from uncontrolled and $8,960 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Natural Gas - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR) + Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0246S, N02406	POD: 24
Application: This control is the selective catalytic reduction of NOx through add-on controls in
combination with water injection. SCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx
removal efficiency, which allows the process to occur at lower temperatures.
This control applies to small (3.3 MWto 34.4MW) natural gas-fired gas turbines with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200201 Natural Gas, Turbine
20200203 Natural Gas, Turbine: Cogeneration
20300202	Natural Gas, Turbine
20300203	Natural Gas, Turbine: Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by the following (Pechan, 1998).
Small source = 3.3 MWto 34.4 MW
The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1993). Capital and annual cost information was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.8
(Pechan, 1998). A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment lifetime of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 76% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information for an example small turbine in Table 6-9 of the ACT document for
stationary gas turbines. The model plant is a 26.8 megawatt MS5001P turbine.
Continuous operation 8,000 hours per year is used to estimate operating costs.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity cost: 0.06 $/kW-hr
Natural gas cost: $4.13/MMBtu
Cost Effectiveness: The default cost effectiveness value is $2,730 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Oil - Small Sources
Control Measure Name: Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0231S, N02301	POD: 23
Application: This control is the use of water injection to reduce NOx emissions.
This control applies to small (3.3 MWto 34.4MW) oil-fired turbines with uncontrolled
NOx emissions greater than 10 tons per year.
Affected SCC:
20200101 Distillate Oil (Diesel), Turbine
20200103 Distillate Oil (Diesel), Turbine: Cogeneration
20300102 Commercial/Institutional, Distillate Oil (Diesel), Turbine
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 68% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by the following (Pechan, 1998).
Small source = 3.3 MWto 34.4 MW
The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1993). Capital and annual cost information was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.9
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent are
assumed, along with an equipment lifetime of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information for an example small turbine in Table 6-5 of the ACT document for
stationary gas turbines. The model plant is a 26.8 megawatt MS5001P turbine.
Continuous operation 8,000 hours per year is used to estimate operating costs.
Electricity cost: 0.06 $/kW-hr
Natural gas cost: $4.13/MMBtu
Cost Effectiveness: The default cost effectiveness value is $1,290 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
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AT-A-GLANCE TABLE FOR POINT SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:

Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The
water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).

References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Combustion Turbines - Oil - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR) + Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0232S, N02302	POD: 23
Application: This control is the selective catalytic reduction of NOx through add-on controls in
combination with water injection. SCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx
removal efficiency, which allows the process to occur at lower temperatures.
This control applies to small (3.3 MWto 34.4MW) oil-fired turbines with uncontrolled
NOx emissions greater than 10 tons per year.
Affected SCC:
20200101 Distillate Oil (Diesel), Turbine
20200103 Distillate Oil (Diesel), Turbine: Cogeneration
20300102 Commercial/Institutional, Distillate Oil (Diesel), Turbine
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by the following (Pechan, 1998).
Small source = 3.3 MWto 34.4 MW
The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1993). Capital and annual cost information was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.9
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent are
assumed, along with an equipment lifetime of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information for an example small turbine in Table 6-9 of the ACT document for
stationary gas turbines. The model plant is a 26.8 megawatt MS5001P turbine.
Continuous operation 8,000 hours per year is used to estimate operating costs.
Electricity cost: 0.06 $/kW-hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Natural gas cost: $4.13/MMBtu
Cost Effectiveness: The default cost effectiveness value is $2,300 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Gas Turbines," EPA,-453/R-93-007, Research Triangle Park, NC, January 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Commercial/Institutional - Natural Gas
Control Measure Name: Water Heater Replacement
Rule Name: Not Applicable
Pechan Measure Code: N10601	POD: 106
Application: This control would replace existing water heaters with new water heaters. New water
heaters would be required to emit less than or equal to 40 ng NOx per Joule heat
output.
This control applies to all natural gas burning water heaters classified under SCC
2103006000.
Affected SCC:
2103006000 Natural Gas, Total: Boilers and IC Engines
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7% from uncontrolled
Equipment Life: 13 years
Rule Effectiveness: 100%
Penetration: 23%
Cost Basis: In 1994, EPA conducted an analysis of the emission reductions and costs for a
Federal Implementation Plan residential water heater rule for the Sacramento,
California ozone nonattainment area (EPA, 1995). This analysis found that a rule
based on an emission limit of 40 nanograms per joule (ng/j) of heat output for natural
gas heaters with a heat input rating less than 75,000 Btu/hr would not result in an
increase in the cost of natural gas water heaters. The cost-effectiveness of NOx
reductions resulting from low-NOx residential water heaters is, therefore, zero dollar-
per-ton of NOx removed. It is assumed that the technology for residential water and
space heaters can be transferred to commercial installation at a similar cost to
achieve the same percentage reduction (Pechan, 1997).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $0 per ton NOx reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
EPA (1995) noted a life expectancy of both conventional and low-NOx units ranging from 10 to 15
years. Thus, rule penetration is based on an average water heater equipment life of 13 years
(Pechan, 1996).
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Costs for the California Federal Implementation Plans for Attainment of
the Ozone National Ambient Air Quality Standard," Final Draft, February 1995.
Pechan, 1996: E.H. Pechan & Associates, "The Emission Reduction and Cost Analysis Model for
NOx (ECRAM-NOx)," Revised Documentation, prepared for U.S. Environmental Protection Agency,
Ozone Policy and Strategies Group, Research Triangle Park, NC, September 1996.
Pechan, 1997: E.H. Pechan & Associates, "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Commercial/Institutional - Natural Gas
Control Measure Name: Water Heaters + LNB Space Heaters
Rule Name: South Coast and Bay Area AQMD Limits
Pechan Measure Code: N10603	POD: 106
Application: The South Coast and Bay Area AQMDs set emission limits for water heaters and
space heaters. This control is based on the installation of low-NOx space heaters and
water heaters in commercial and institutional sources for the reduction of NOx
emissions.
The control applies to natural gas burning sources classified under SCC 2103006000.
Affected SCC:
2103006000 Natural Gas, Total: Boilers and IC Engines
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7% from uncontrolled
Equipment Life: 20 years (space heaters)
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The 1997 South Coast AQMP estimates a cost savings for new commercial and
residential water heaters meeting a low-NOx standard. The cost savings is based on
capital costs associated with installation of energy efficient equipment existing
demand-side management programs, energy savings, associated emission
reductions, and the prevailing emission credit price (SCAQMD, 1996).
Costs for the space heaters are based on the low-NOx limits established for the
South Coast and Bay Area Air Quality Management Districts for space heaters of
0.009 lbs NOx per million Btu. The cost effectiveness estimate for the low-NOx
space heater regulation is $1,600 per ton NOx (STAPPA/ALAPCO, 1994). For this
analysis a 75% reduction in commercial space heater NOx emissions is assumed,
based on a 20-year equipment life (Pechan, 1997).
The water heater savings and LNB space heater costs are combined to achieve an
overall cost effectiveness of $1,230 per ton NOx reduced.
Cost Effectiveness: The cost effectiveness is $1,230 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 1997.
SCAQMD, 1996: South Coast Air Quality Management District, "1997 Air Quality Management Plan,
Appendix IV-A: Stationary and Mobile Source Control Measures," August 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial/Institutional Incinerators
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0591S, N05901	POD: 59
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to commercial/institutional incinerators with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
50200101	Solid Waste Disposal - Commercial/Institutional, Incineration, Multiple Chamber
50200102	Solid Waste Disposal - Commercial/Institutional, Incineration, Single Chamber
50200103	Solid Waste Disposal - Commercial/Institutional, Incineration, Controlled Air
50200506 Solid Waste Disposal - Commercial/Institutional, Incineration: Special Purpose, Sludge
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 45% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information in Chapter and Appendix A of the MWC ACT document. The cost
outputs for conventional SNCR applied to the 400 ton per day model combustor
(Table 3-3) are used to estimate the O&M cost breakdown. The tipping fee ($1.47
per ton) is included as a waste disposal cost (direct annual cost).
Electricity Cost: 0.046 $/kW-hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$1,130 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Radian Corporation, "Alternative Control
Techniques Document- NOx Emissions from Municipal Waste Combustion," EPA-600/R-94-208,
Research Triangle Park, NC, December 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Conv Coating of Prod; Acid Cleaning Bath - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0791S, N07901	POD: 79
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) acid cleaning bath/conversion
coating processes at metal product fabricating operations with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30901102 Fabricated Metal Products, Conversion Coating, Acid Cleaning Bath (Pickling)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). Capital and annual cost information
was obtained from the Alternative Control Techniques Document (EPA, 1993). The
data provided for LNB applied to process heaters firing natural gas are assumed to
be representative of the costs and emission reductions for this source. From this
analysis, default cost per ton values are assigned along with a capital to annual costs
ratio of 7.3. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,200 per ton NOx reduced
from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
The source of emissions for acid cleaning baths come from heating of the baths.
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA-453/R-93-034, Research Triangle Park, NC, September, 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Diesel Locomotives
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N13701	POD: 137
Application: This control is the selective catalytic reduction of Nox through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (Nox) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the Nox removal efficiency, which allows the process to
occur at lower temperatures.
Applies to line and yard diesel locomotive engines
Affected SCC:
2285002006	- Railroad Equipment, Diesel, Line Haul Locomotives: Class I Operations
2285002007	- Railroad Equipment, Diesel, Line Haul Locomotives: Class II / III Operations
2285002008- Railroad Equipment, Diesel, Line Haul Locomotives: Passenger Trains (Amtrak)
2285002009	- Railroad Equipment, Diesel, Line Haul Locomotives: Commuter Lines
2285002010	- Railroad Equipment, Diesel, Yard Locomotives
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 72% from uncontrolled (CARB, 1995)
Equipment Life: NA
Rule Effectiveness: NA
Penetration: NA
Cost Basis: A 1995 report prepared for the California Resources Board (CARB) contains
information for retrofit emission control techniques available for line-haul, local, and
yard locomotives. These retrofit controls include Selective Catalytic Reduction and
conversion to dual fuel (including liquified natural gas) capability (EFEE, 1995).
Pechan developed ControlNET inputs for these controls using the reported emission
reduction percentages and cost-effectiveness values developed for CARB.
Cost Effectiveness: The cost effectiveness is $1,400 per ton of Nox reduction (1995$).
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
EFEE, 1995. Engine, Fuel, and Emissions Engineering, Inc., "Controlling Locomotive Emissions in
California, Technology, Cost-Effectiveness, and Regulatory Strategy," Final report prepared for the
California Air Resources Board, Sacramento, CA. March 1995.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Fiberglass Manufacture; Textile-Type; Recuperative Furnaces
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0763S, N07603	POD: 76
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to textile-type fiberglass manufacturing operations with
recuperative furnaces and uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501212 Fiberglass Manufacturing, Recuperative Furnace (Textile-type Fiber)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 3 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). Capital and annual cost information
was obtained from the Alternative Control Techniques Document (EPA, 1994). The
data provided for LNB applied to process heaters firing natural gas are assumed to
be representative of the costs and emission reductions for this source. From this
analysis, default cost per ton values are assigned along with a capital to annual costs
ratio of 2.2. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 3 years (EPA, 1994).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,690 per ton NOx reduced
from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
Recuperative furnaces may be gas- or oil-fired.
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
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AT-A-GLANCE TABLE FOR POINT SOURCES
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Fluid Catalytic Cracking Units - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0782S, N07802	POD: 78
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) fluid catalytic cracking units with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600201 Petroleum Industry, Catalytic Cracking Units, Fluid Catalytic Cracking Unit
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.9. An equipment life of 15 years is assumed (EPA, 1993).
Cost Effectiveness: The default cost effectiveness values are $3,190 per ton NOx reduced from
uncontrolled and $1,430 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The source of emissions for fluidized catalytic cracking come from process heaters and catalyst
regenerators.
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
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AT-A-GLANCE TABLE FOR POINT SOURCES
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Fuel Fired Equipment - Process Heaters
Control Measure Name: Low Nox Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0692S, N06902	POD: 72
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small process heaters with uncontrolled NOx emissions
greater than 10 tons per year.
Affected SCC:
30490033 Fuel Fired Equipment, Natural Gas: Furnaces
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 7.0. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 50% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on distillate
oil and having a capacity of 69 MMBTU per hour. The cost percentage is applied to
heaters fired on LPG via technology transfer (Pechan, 1998). A capacity factor of
0.58 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The default cost effectiveness values are $570 per ton Nox reduced from
uncontrolled.
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Fuel Fired Equipment; Furnaces; Natural Gas
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0721L, N0721S, N07201	POD: 72
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to natural gas fired equipment classified under SCC 30490033
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30490033 Fuel Fired Equipment, Natural Gas: Furnaces
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). Capital and annual cost information
was obtained from the Alternative Control Techniques Document (EPA, 1993). The
data provided for LNB applied to process heaters firing natural gas are assumed to
be representative of the costs and emission reductions for this source. From this
analysis, default cost per ton values are assigned along with a capital to annual costs
ratio of 7.0. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1993
Cost Effectiveness: The cost effectiveness used in AirControlNET is $570 per ton NOx reduced
from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Containers
Control Measure Name: Electric Boost
Rule Name: Not Applicable
Pechan Measure Code: N0301S, N03001
POD: 30
Application: This control is the use of electric boost technologies to reduce NOx emissions from
glass manufacturing operations.
This control applies to container glass manufacturing operations classified under SCC
30501402.
Affected SCC:
30501402 Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 10% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital, and annual cost information that
was obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 4.5. A
discount rate of 10 percent and a capacity factor of 65 percent are assumed, along
with an equipment lifetime of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $7,150 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The 250 tons per day plant is assumed to be representative of container glass plants (Pechan,
1998).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Containers
Control Measure Name: Cullet Preheat
Rule Name: Not Applicable
Pechan Measure Code: N0302S, N03002
POD: 30
Application: This control is the use of cullet preheat technologies to reduce NOx emissions from
glass manufacturing operations.
This control is applicable to container glass manufacturing operations classified under
305010402.
Affected SCC:
30501402 Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital and annual cost information was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 4.5
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent are
assumed, along with an equipment lifetime of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $940 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
The 250 tons per day plant is assumed to be representative of container glass plants (Pechan,
1998).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Containers
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0303S, N03003	POD: 30
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to container glass manufacturing operations classified under
305010402 with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501402 Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital and annual cost information was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.2
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent are
assumed, along with an equipment lifetime of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $1,690 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
The 250 tons per day plant is assumed to be representative of container glass plants (Pechan,
1998).
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
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AT-A-GLANCE TABLE FOR POINT SOURCES
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Containers
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0304S, N03004	POD: 30
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to glass-container manufacturing operations (SCC 30501402) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501402 Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated by applying
percentages of O&M breakdown for SNCR as applied to process heaters, using
detailed information found in Table 6-3 and Chapter 6 of the Process Heater ACT
document. The breakdown was obtained using the O&M costs for a 250 ton per day
furnace.
Electricity: $0.06 per kw-hr
Fuel (nat gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$1,770 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Containers
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0305S, N03005	POD: 30
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to glass-container manufacturing processes, classified under SCC 30501402
and uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501402 Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness values (for both small and large sources) used in
AirControlNET are $2,200 per ton NOx reduced from both uncontrolled and
RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Containers
Control Measure Name: OXY-Firing
Rule Name: Not Applicable
Pechan Measure Code: N0306S, N03006	POD: 30
Application: This control is the use of OXY-firing to reduce NOx emissions.
This control applies to container-glass manufacturing operations with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30501402 Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 85% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost equations for glass manufacturing NOx control are based on an analysis of
EPA's NOx State Implementation Plan (SIP) Call (Pechan-Avanti, 1998). The basis
of the costs are model plant data contained in the Alternative Control Techniques
(ACT) document. The 50 tons per day plant was assumed to be representative of
pressed glass plants, the 250 tons per day plant was assumed to be representative of
container glass plants, and the 500 tons per day plant was assumed to be
representative of flat glass plants. Capital, and annual cost information that was
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned. A capital cost to annual cost ratio was developed
to estimate default capital and O&M costs. A discount rate of 10% was assumed for
all sources. The equipment life of varied form3 to 10 years by control.
Cost Effectiveness: The default cost effectiveness value is $4,590 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:

The 550 tons per day plant is assumed to be representative of container glass plants (Pechan,
1998).

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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Flat
Control Measure Name: Electric Boost
Rule Name: Not Applicable
Pechan Measure Code: N0311L, N0311S, N03101
POD: 31
Application: This control is the use of electric boost technologies to reduce NOx emissions from
glass manufacturing operations.
This control applies to flat glass manufacturing operations classified under SCC
30501403.
Affected SCC:
30501403 Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 10% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital and annual cost information that
was obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 4.5. A
discount rate of 10 percent and a capacity factor of 65 percent are assumed, along
with an equipment lifetime of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $2,320 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
The 500 tons per day plant is assumed to be representative of flat glass plants (Pechan, 1998).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, NC, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Flat
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0312S, N0312L, N03102	POD: 31
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to flat glass manufacturing operations classified under
305010404 with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501403 Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 3 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital and annual cost information is
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.2
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment lifetime of 3 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $700 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
The 500 tons per day plant is assumed to be representative of flat glass plants (Pechan, 1998).
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Flat
Control Measure Name: OXY-Firing
Rule Name: Not Applicable
Pechan Measure Code: N0315L, N0315S, N03105	POD: 31
Application: This control is the use of OXY-firing to reduce NOx emissions.
This control applies to flat-glass manufacturing operations with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30501403 Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 85% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital and annual cost information is
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.7
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment lifetime of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value is $1,900 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The 500 tons per day plant is assumed to be representative of flat glass plants (Pechan, 1998).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Flat - Large Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0313L, N03103	POD: 31
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to large (>1 ton NOx emissions per OSD) flat-glass manufacturing
operations (SCC 30501403) with uncontrolled NOx emissions greater than 10 tons per
year.
Affected SCC:
30501403 Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $740 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
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AT-A-GLANCE TABLE FOR POINT SOURCES
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Flat - Large Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0314L, N03104	POD: 31
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to large(>1 ton NOx per OSD) flat-glass manufacturing operations (SCC
30501403) with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501403 Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated by applying
percentages of O&M breakdown for SCR as applied to process heaters, using
detailed information found in Table 6-3 and Chapter 6 of the Process Heater ACT
document. The breakdown was obtained using the O&M costs for a 750 ton per day
furnace.
Electricity: $0.06 per kw-hr
Fuel (nat gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $710 per ton NOx
reduced from both uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Flat - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0313S	POD: 31
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) flat-glass manufacturing
operations (SCC 30501403) with uncontrolled NOx emissions greater than 10 tons per
year.
Affected SCC:
30501403 Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 10 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated by applying
percentages of O&M breakdown for SNCR as applied to process heaters, using
detailed information found in Table 6-3 and Chapter 6 of the Process Heater ACT
document. The breakdown was obtained using the O&M costs for a 750 ton per day
furnace.
Electricity: $0.06 per kw-hr
Fuel (nat gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
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AT-A-GLANCE TABLE FOR POINT SOURCES
O&M Cost Components: The O&M cost breakdown is estimated by applying
percentages of O&M breakdown for SNCR as applied to process heaters, using
detailed information found in Table 6-3 and Chapter 6 of the Process Heater ACT
document. The breakdown was obtained using the O&M costs for a 750 ton per day
furnace.
Electricity: $0.06 per kw-hr
Fuel (nat gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $740 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Flat - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0314S	POD: 31
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) flat-glass manufacturing operations (SCC
30501403) with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501403 Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated by applying
percentages of O&M breakdown for SCR as applied to process heaters, using
detailed information found in Table 6-3 and Chapter 6 of the Process Heater ACT
document. The breakdown was obtained using the O&M costs for a 750 ton per day
furnace.
Electricity: $0.06 per kw-hr
Fuel (nat gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $3,370 per ton NOx
reduced from both uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Pressed
Control Measure Name: Electric Boost
Rule Name: Not Applicable
Pechan Measure Code: N0321S, N03201
POD: 32
Application: This control is the use of electric boost technologies to reduce NOx emissions from
glass manufacturing operations.
This control applies to pressed glass manufacturing operations classified under SCC
30501403.
Affected SCC:
30501404 Glass Manufacture, Pressed and Blown Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 10% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital, and annual cost information that
was obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 4.5. A
discount rate of 10 percent and a capacity factor of 65 percent are assumed, along
with an equipment lifetime of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $8,760 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
The 50 tons per day plant is assumed to be representative of pressed glass plants (Pechan, 1998).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, NC, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Pressed
Control Measure Name: Cullet Preheat
Rule Name: Not Applicable
Pechan Measure Code: N0322S, N03202
POD: 32
Application: This control is the use of cullet preheat technologies to reduce NOx emissions from
glass manufacturing operations.
This control is applicable to pressed glass manufacturing operations classified under
305010404.
Affected SCC:
30501404 Glass Manufacture, Pressed and Blown Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital and annual cost information is
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 4.5
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment lifetime of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $810 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
The 50 tons per day plant is assumed to be representative of pressed glass plants (Pechan, 1998).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Pressed
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0323S, N03203	POD: 32
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to pressed glass manufacturing operations classified under
305010404 with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501404 Glass Manufacture, Pressed and Blown Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital and annual cost information is
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.2
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment lifetime of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $1,500 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
The 500 tons per day plant is assumed to be representative of flat glass plants (Pechan, 1998).
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Pressed
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0324S, N03204	POD: 32
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to pressed-glass manufacturing operations (SCC 30501404) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501404 Glass Manufacture, Pressed and Blown Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated by applying
percentages of O&M breakdown for SNCR as applied to process heaters, using
detailed information found in Table 6-3 and Chapter 6 of the Process Heater ACT
document. The breakdown was obtained using the O&M costs for a 50 ton per day
furnace.
Electricity: $0.06 per kw-hr
Fuel (nat gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$1,640 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip..
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994..
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
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AT-A-GLANCE TABLE FOR POINT SOURCES
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Pressed
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0325S, N03205	POD: 32
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to pressed-glass manufacturing operations, classified under SCC 30101404
and uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30501404 Glass Manufacture, Pressed and Blown Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values and a capital to annual cost ratio of 1.3 are assigned. A discount rate of 7
percent and a capacity factor of 65 percent are assumed, along with an equipment
life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated by applying
percentages of O&M breakdown for SCR as applied to process heaters, using
detailed information found in Table 6-3 and Chapter 6 of the Process Heater ACT
document. The breakdown was obtained using the O&M costs for a 50 ton per day
furnace.
Electricity: $0.06 per kw-hr
Fuel (nat gas): $2.00 per MMBTU
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AT-A-GLANCE TABLE FOR POINT SOURCES
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness value (for both small and large sources) used in
AirControlNET is $2,530 per ton NOx reduced from both uncontrolled and
RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Glass Manufacturing - Pressed
Control Measure Name: OXY-Firing
Rule Name: Not Applicable
Pechan Measure Code: N0326S, N03206	POD: 32
Application: This control is the use of OXY-firing to reduce NOx emissions.
This control applies to pressed-glass manufacturing operations with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30501404 Glass Manufacture, Pressed and Blown Glass: Melting Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 85% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital and annual cost information is
obtained from control-specific cost data based on tons of glass produced. O&M
costs were back calculated from annual costs. From these determinations, default
cost per ton values were assigned along with a capital to annual cost ratio of 2.7
(Pechan, 1998). A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment lifetime of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value is $3,900 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The 50 tons per day plant is assumed to be representative of pressed glass plants (Pechan, 1998).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Glass Manufacturing," EPA,-453/R-94-037, Research Triangle Park, NC, June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Gasoline Engine
Control Measure Name: Low Reid Vapor Pressure (RVP) Limit in Ozone Season
Rule Name: Not Applicable
Pechan Measure Code: mOT8
POD: N/A
Application: This control measure represents the use of reformulated gasoline to have a RVP limit
of 7.8 psi from May through September in counties with an ozone season RVP value
greater than 7.8 psi. Emission reduction benefits of NOx, CO, and VOC are estimated
using EPA's MOBILE6 model.
This control is applicable to all light duty gasoline vehicles, motor cycles, and trucks.
Affected SCC:
2201001000 Light Duty Gasoline Vehicles (LDGV), Total: All Road Types
2201020000 Light Duty Gasoline Trucks 1 (LDGT1), Total: All Road Types
2201040000 Light Duty Gasoline Trucks 2 (LDGT2), Total: All Road Types
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2201080000 Motorcycles (MC), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg




V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency ranged from: NOx (-1.1 to 0.6%; VOC (0.1 to 11.1%); CO
(0.0 to 6.1%)
Equipment Life: Not Applicable
Rule Effectiveness: Not applicable
Penetration: Not applicable
Cost Basis: The calculate are calculated based of the number of vehicles and amount of fuel
consumed form May through September by county and vehicle type. Costs were
estimated on a per-vehicle basis.
The number of vehicles was estimated by dividing the VMT by the average LDGV
annual mileage accumulation rate. The costs estimated at $0.0036 * 5 /12 per gallon
(Pechan 2002). All costs are $1997.
Cost Effectiveness: The cost effectiveness of a 7.8 RVP limit varies greatly by county. Cost
effectiveness for VOC ranged from $25,671 to $125 per ton. The average C-E
for VOC is $1,548 per ton of VOC reduced (median is $1,560 per ton). All
costs are $1997.
Comments: In some cases this control produces a slight NOx disbenefit.
Status: Demonstrated
Last Reviewed: 2002
Additional Information:
References:
Pechan 2002: "AirControlNET Specifications and Methods for Mobile Source Controls" Memo
prepared for Larry Sorrels of the US EPA, December 2002.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Heavy Duty and Diesel-Fueled Vehicles
Control Measure Name: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur
Controls
Rule Name: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur
Standards
Pechan Measure Code: HDD10	POD: N/A
Application: This control measure represents the application of EPA's heavy duty engine and
vehicle standards and highway diesel fuel sulfur control requirements in 1999.
Emissions reduction benefits of NOX, PM10, PM2.5, VOC, CO and S02 are estimated
using EPA's MOBILE6 model.
This control is applicable to all heavy duty diesel vehicles beginning with the 2007
model year, and all heavy duty gasoline vehicles beginning with the 2008 model year.
Light duty gasoline vehicles and motorcycles are not affected by this control.
Affected SCC:
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2230070000 Heavy Duty Diesel Vehicles (HDDV), Total: All Road Types
2230001000 Light Duty Diesel Vehicles (LDDV), Total: All Road Types
2230060000 Light Duty Diesel Trucks (LDDT), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies varies for each vehicle type:
HDG: PM2.5 (11%); PM10 (9%); NOx (19%); VOC (2%); S02 (1%); CO (5%)
HDD: PM2.5 (19%); PM10 (18%); NOx (33%); VOC (12%); S02 (97%); CO
(22%)
LDD: PM2.5 (2-4%); PM10 (2-4%); NOx (0%); VOC (0%); S02 (97%); CO (0%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the heavy duty engine and vehicle standards, an estimate was
made of the number of vehicles affected by the control. The number of vehicles was
estimated by dividing the VMT by the average annual mileage accumulation rate for
each affected vehicle type and model year. The costs for the heavy duty engine and
vehicle standards are estimated at $1,940.92 per heavy duty gasoline vehicle and
$2,712.89 per heavy duty diesel vehicle (EPA, 2000). All costs are in 1999 dollars.
The costs for the highway diesel fuel sulfur controls were applied to all gallons of
diesel fuel used by the affected vehicles (LDDV, LDDT, and HDDV). Low sulfur
diesel fuel is estimated to cost an additional $0.05 per gallon of diesel fuel (EPA,
2000). All costs are in 1999 dollars.
Cost Effectiveness: The cost effectiveness of the heavy duty engine and vehicle standards and
highway diesel fuel sulfur controls varies greatly by county and depends mostly
on the number of vehicles and the year modeled. Cost effectiveness ranged
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
from $2,414 to $22,859 per ton NOx reduced. The average value used in
AirControlNET is $9,301.05 per ton NOx reduced. All costs are $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2000: U.S. Environmental Protection Agency, "Regulatory Impact Analysis: Control of
Emissions of Air Pollution from Highway Heavy-Duty Engines." EPA420-R-00-010, July 2000.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Heavy Duty and Diesel-Fueled Vehicles
Control Measure Name: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur
Controls
Rule Name: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur
Standards
Pechan Measure Code: HDD15	POD: N/A
Application: This control measure represents the application of EPA's heavy duty engine and
vehicle standards and highway diesel fuel sulfur control requirements in 1999.
Emissions reduction benefits of NOX, PM10, PM2.5, VOC, CO and S02 are estimated
using EPA's MOBILE6 model.
This control is applicable to all heavy duty diesel vehicles beginning with the 2007
model year, and all heavy duty gasoline vehicles beginning with the 2008 model year.
Light duty gasoline vehicles and motorcycles are not affected by this control.
Affected SCC:
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2230070000 Heavy Duty Diesel Vehicles (HDDV), Total: All Road Types
2230001000 Light Duty Diesel Vehicles (LDDV), Total: All Road Types
2230060000 Light Duty Diesel Trucks (LDDT), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies varies for each vehicle type:
HDG: PM2.5 (25%); PM10 (21%); NOx (44%); VOC (11%); S02 (99%); CO
(13%)
HDD: PM2.5 (39%); PM10 (37%); NOx (68%); VOC (26%); S02 (97%); CO
(41%)
LDD: PM2.5 (2-4%); PM10 (2-4%); NOx (0%); VOC (0%); S02 (97%); CO (0%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the heavy duty engine and vehicle standards, an estimate was
made of the number of vehicles affected by the control. The number of vehicles was
estimated by dividing the VMT by the average annual mileage accumulation rate for
each affected vehicle type and model year. The costs for the heavy duty engine and
vehicle standards are estimated at $1,940.92 per heavy duty gasoline vehicle and
$2,712.89 per heavy duty diesel vehicle (EPA, 2000). All costs are in 1999 dollars.
The costs for the highway diesel fuel sulfur controls were applied to all gallons of
diesel fuel used by the affected vehicles (LDDV, LDDT, and HDDV). Low sulfur
diesel fuel is estimated to cost an additional $0.05 per gallon of diesel fuel (EPA,
2000). All costs are in 1999 dollars.
Cost Effectiveness: The cost effectiveness of the heavy duty engine and vehicle standards and
highway diesel fuel sulfur controls varies greatly by county and depends mostly
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
on the number of vehicles and the year modeled. Cost effectiveness ranged
from $1,926 to $26,499 per ton NOx reduced. The average value is
$10,560.58 per ton NOx reduced. All costs are $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2000: U.S. Environmental Protection Agency, "Regulatory Impact Analysis: Control of
Emissions of Air Pollution from Highway Heavy-Duty Engines." EPA420-R-00-010, July 2000.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Heavy Duty and Diesel-Fueled Vehicles
Control Measure Name: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur
Controls
Rule Name: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur
Standards
Pechan Measure Code: HDD20	POD: N/A
Application: This control measure represents the application of EPA's heavy duty engine and
vehicle standards and highway diesel fuel sulfur control requirements in 1999.
Emissions reduction benefits of NOX, PM10, PM2.5, VOC, CO and S02 are estimated
using EPA's MOBILE6 model.
This control is applicable to all heavy duty diesel vehicles beginning with the 2007
model year, and all heavy duty gasoline vehicles beginning with the 2008 model year.
Light duty gasoline vehicles and motorcycles are not affected by this control.
Affected SCC:
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2230070000 Heavy Duty Diesel Vehicles (HDDV), Total: All Road Types
2230001000 Light Duty Diesel Vehicles (LDDV), Total: All Road Types
2230060000 Light Duty Diesel Trucks (LDDT), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies varies for each vehicle type:
HDG: PM2.5 (32%); PM10 (28%); NOx (61%); VOC (21%); S02 (100%); CO
(19%)
HDD: PM2.5 (70%); PM10 (67%); NOx (85%); VOC (43%); S02 (97%); CO
(66%)
LDD: PM2.5 (2-4%); PM10 (2-4%); NOx (0%); VOC (0%); S02 (97%); CO (0%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the heavy duty engine and vehicle standards, an estimate was
made of the number of vehicles affected by the control. The number of vehicles was
estimated by dividing the VMT by the average annual mileage accumulation rate for
each affected vehicle type and model year. The costs for the heavy duty engine and
vehicle standards are estimated at $1,940.92 per heavy duty gasoline vehicle and
$2,712.89 per heavy duty diesel vehicle (EPA, 2000). All costs are in 1999 dollars.
The costs for the highway diesel fuel sulfur controls were applied to all gallons of
diesel fuel used by the affected vehicles (LDDV, LDDT, and HDDV). Low sulfur
diesel fuel is estimated to cost an additional $0.05 per gallon of diesel fuel (EPA,
2000). All costs are in 1999 dollars.
Cost Effectiveness: The cost effectiveness of the heavy duty engine and vehicle standards and
highway diesel fuel sulfur controls varies greatly by county and depends mostly
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
on the number of vehicles and the year modeled. Cost effectiveness ranged
from $2,131 to $29,408 per ton NOx reduced. The average value is
$11,955.65 per ton NOx reduced. All costs are $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2000: U.S. Environmental Protection Agency, "Regulatory Impact Analysis: Control of
Emissions of Air Pollution from Highway Heavy-Duty Engines." EPA420-R-00-010, July 2000.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Heavy Duty and Diesel-Fueled Vehicles
Control Measure Name: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur
Controls
Rule Name: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur
Standards
Pechan Measure Code: HDD30	POD: N/A
Application: This control measure represents the application of EPA's heavy duty engine and
vehicle standards and highway diesel fuel sulfur control requirements in 1999.
Emissions reduction benefits of NOX, PM10, PM2.5, VOC, CO and S02 are estimated
using EPA's MOBILE6 model.
This control is applicable to all heavy duty diesel vehicles beginning with the 2007
model year, and all heavy duty gasoline vehicles beginning with the 2008 model year.
Light duty gasoline vehicles and motorcycles are not affected by this control.
Affected SCC:
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2230070000 Heavy Duty Diesel Vehicles (HDDV), Total: All Road Types
2230001000 Light Duty Diesel Vehicles (LDDV), Total: All Road Types
2230060000 Light Duty Diesel Trucks (LDDT), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies varies for each vehicle type:
HDG: PM2.5 (53%); PM10 (52%); NOx (76%); VOC (61%); S02 (103%); CO
(63%)
HDD: PM2.5 (91%); PM10 (87%); NOx (95%); VOC (63%); S02 (97%); CO
(91%)
LDD: PM2.5 (2-4%); PM10 (2-4%); NOx (0%); VOC (0%); S02 (97%); CO (0%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the heavy duty engine and vehicle standards, an estimate was
made of the number of vehicles affected by the control. The number of vehicles was
estimated by dividing the VMT by the average annual mileage accumulation rate for
each affected vehicle type and model year. The costs for the heavy duty engine and
vehicle standards are estimated at $1,940.92 per heavy duty gasoline vehicle and
$2,712.89 per heavy duty diesel vehicle (EPA, 2000). All costs are in 1999 dollars.
The costs for the highway diesel fuel sulfur controls were applied to all gallons of
diesel fuel used by the affected vehicles (LDDV, LDDT, and HDDV). Low sulfur
diesel fuel is estimated to cost an additional $0.05 per gallon of diesel fuel (EPA,
2000). All costs are in 1999 dollars.
Cost Effectiveness: The cost effectiveness of the heavy duty engine and vehicle standards and
highway diesel fuel sulfur controls varies greatly by county and depends mostly
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
on the number of vehicles and the year modeled. Cost effectiveness ranged
from $2,229 to $38,254 per ton NOx reduced. The average value is
$16,108.48 per ton NOx reduced. All costs are $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2000: U.S. Environmental Protection Agency, "Regulatory Impact Analysis: Control of
Emissions of Air Pollution from Highway Heavy-Duty Engines." EPA420-R-00-010, July 2000.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Heavy Duty Diesel Engines
Control Measure Name: Voluntary Diesel Retrofit Program: Selective Catalytic Reduction
Rule Name: Not Applicable
Pechan Measure Code: HDR399	POD:
Application: This control measure represents the application of EPA's voluntary diesel retrofit
program through the use of selective catalytic reduction as a retrofit technology in
1999. Emissions reduction benefits of NOX, CO, VOC, PM10, PM2.5, and S02 are
estimated using EPA's MOBILE6 model and independent research on the percent
reductions yielded by this control measure.
This control is applicable to all heavy duty diesel vehicles. Light duty and gasoline-
fueled vehicles are not affected by this control.
Affected SCC:
2230070000 Heavy Duty Diesel Vehicles (HDDV), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by pollutant: NOx (75%); PM10 (19.26%); PM2.5
(19.8%); VOC (70%); S02 (97%); CO (70%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the use of selective catalytic reduction as a retrofit technology,
the assumption was made that all relevant vehicles would be affected by the control.
Therefore, all heavy duty diesel vehicles were assumed to employ selective catalytic
reduction as a retrofit technology through the voluntary diesel retrofit program. The
average cost of a selective catalytic reduction system ranges from $10,000 to
$20,000 per vehicle depending on the size of the engine, the sales volume, and other
factors (Pechan, 2003). For this AirControlNET analysis, the average estimated cost
of this system is $15,000 per heavy duty diesel vehicle.
Selective catalytic reduction requires the use of low sulfur diesel fuel. The costs for
the low sulfur diesel fuel were applied to all gallons of diesel fuel used by the heavy
duty diesel vehicles. Low sulfur diesel fuel is estimated to cost an additional $0.05
per gallon of diesel (EPA, 2000). All costs are in 1999 dollars.
Cost Effectiveness: The cost effectiveness of selective catalytic reduction varies greatly by county
and depends mostly on the number of vehicles. Cost effectiveness for NOX fell
within the following range: $13,499 to $56,474 per ton NOx reduced. The
average cost effectiveness used in AirControlNET is $50,441.54 per ton NOX
reduced. All costs are in $1999.
Comments:
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2000: U.S. Environmental Protection Agency, "Regulatory Impact Analysis: Control of
Emissions of Air Pollution from Highway Heavy-Duty Engines." EPA420-R-00-010, July 2000.
Pechan, 2003. E.H. Pechan & Associates, Inc., "Methodology to Implement Voluntary Diesel
Retrofit Program in AirControlNET," Memo prepared for Tyler Fox of the US EPA, July 2003.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Light Duty and Gasoline-Fueled Vehicles
Control Measure Name: Tier 2 Motor Vehicle Emissions and Gasoline Sulfur Controls
Rule Name: Tier 2 Motor Vehicle Emissions and Gasoline Sulfur Standards
Pechan Measure Code: T210	POD: N/A
Application: This control measure represents the application of EPA's Tier 2 motor vehicle
emissions and gasoline fuel sulfur control requirements in 1999. Emissions reduction
benefits of NOX, PM 10-2.5, PM2.5, VOC, CO and S02 are estimated using EPA's
MOBILE6 model.
This control is applicable to all light duty vehicles beginning with the 2004 model year,
and all gasoline vehicles beginning with the 1981 model year. Heavy duty diesel
vehicles and motorcycles are not affected by this control.
Affected SCC:
2201001000 Light Duty Gasoline Vehicles (LDGV), Total: All Road Types
2201020000 Light Duty Gasoline Trucks 1 (LDGT1), Total: All Road Types
2201040000 Light Duty Gasoline Trucks 2 (LDGT2), Total: All Road Types
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2230001000 Light Duty Diesel Vehicles (LDDV), Total: All Road Types
2230060000 Light Duty Diesel Trucks (LDDT), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies varies for each vehicle type:
LDG: PM2.5 (23-32%); PM10 (15-19%); NOx (28-40%); VOC (12-23%); S02
(90%); CO (13-25%)
HDG: PM2.5 (8%); PM10 (6%); NOx (2%); VOC (5%); S02 (90%); CO (4%)
LDD: PM2.5 (4-27%); PM10 (4-26%); NOx (7-35%); VOC (3-26%); S02 (0%);
CO (2-21%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the Tier 2 motor vehicle emissions standards, an estimate was
made of the number of vehicles affected by the control. The number of vehicles was
estimated by dividing the VMT by the average annual mileage accumulation rate for
each affected vehicle type and model year. The costs for the Tier 2 motor vehicle
emissions standards are estimated at $82.43 per light duty gasoline vehicle and light
duty diesel truck, $116.66 per light duty gasoline truck 1, $210.51 per light duty diesel
truck, and $252.90 per light duty gasoline truck 2 (EPA, 1999). All costs are in 1999
dollars.
The costs for the gasoline fuel sulfur controls were applied to all gallons of gasoline
fuel used by the affected vehicles (LDGV, LDGT1, LDGT2, HDGV). Low sulfur
gasoline fuel is estimated to cost an additional $0.0193 per gallon of gasoline (EPA,
1999). All costs are in 1999 dollars.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Cost Effectiveness: The cost effectiveness of the Tier 2 motor vehicle emissions and gasoline fuel
sulfur control requirements varies greatly by county and depends mostly on the
number of vehicles and the year modeled. Cost effectiveness ranged from
$1,108 to $11,221 per ton NOx reduced. The average value used in
AirControlNET is $6,269.63 per ton NOx reduced. All costs are $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 1999: U.S. Environmental Protection Agency, "Regulatory Impact Analysis - Control of Air
Pollution from New Motor Vehicles: Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur
Control Requirements," EPA420-R-99-023, December 1999.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Light Duty and Gasoline-Fueled Vehicles
Control Measure Name: Tier 2 Motor Vehicle Emissions and Gasoline Sulfur Controls
Rule Name: Tier 2 Motor Vehicle Emissions and Gasoline Sulfur Standards
Pechan Measure Code: T215	POD: N/A
Application: This control measure represents the application of EPA's Tier 2 motor vehicle
emissions and gasoline fuel sulfur control requirements in 1999. Emissions reduction
benefits of NOX, PM 10-2.5, PM2.5, VOC, CO and S02 are estimated using EPA's
MOBILE6 model.
This control is applicable to all light duty vehicles beginning with the 2004 model year,
and all gasoline vehicles beginning with the 1981 model year. Heavy duty diesel
vehicles and motorcycles are not affected by this control.
Affected SCC:
2201001000 Light Duty Gasoline Vehicles (LDGV), Total: All Road Types
2201020000 Light Duty Gasoline Trucks 1 (LDGT1), Total: All Road Types
2201040000 Light Duty Gasoline Trucks 2 (LDGT2), Total: All Road Types
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2230001000 Light Duty Diesel Vehicles (LDDV), Total: All Road Types
2230060000 Light Duty Diesel Trucks (LDDT), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies varies for each vehicle type:
LDG: PM2.5 (25-35%); PM10 (16-21%); NOx (43-66%); VOC (21-43%); S02
(90%); CO (20-41%)
HDG: PM2.5 (12%); PM10 (10%); NOx (9%); VOC (8%); S02 (90%); CO (6%)
LDD: PM2.5 (6-45%); PM10 (6-43%); NOx (11-49%); VOC (7-42%); S02 (0%);
CO (4-33%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the Tier 2 motor vehicle emissions standards, an estimate was
made of the number of vehicles affected by the control. The number of vehicles was
estimated by dividing the VMT by the average annual mileage accumulation rate for
each affected vehicle type and model year. The costs for the Tier 2 motor vehicle
emissions standards are estimated at $82.43 per light duty gasoline vehicle and light
duty diesel truck, $116.66 per light duty gasoline truck 1, $210.51 per light duty diesel
truck, and $252.90 per light duty gasoline truck 2 (EPA, 1999). All costs are in 1999
dollars.
The costs for the gasoline fuel sulfur controls were applied to all gallons of gasoline
fuel used by the affected vehicles (LDGV, LDGT1, LDGT2, HDGV). Low sulfur
gasoline fuel is estimated to cost an additional $0.0193 per gallon of gasoline (EPA,
1999). All costs are in 1999 dollars.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Cost Effectiveness: The cost effectiveness of the Tier 2 motor vehicle emissions and gasoline fuel
sulfur control requirements varies greatly by county and depends mostly on the
number of vehicles and the year modeled. Cost effectiveness ranged from
$1,188 to $12,609 per ton NOx reduced. The average value used in
AirControlNET is $6,135.41 per ton NOx reduced. All costs are $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 1999: U.S. Environmental Protection Agency, "Regulatory Impact Analysis - Control of Air
Pollution from New Motor Vehicles: Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur
Control Requirements," EPA420-R-99-023, December 1999.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Light Duty and Gasoline-Fueled Vehicles
Control Measure Name: Tier 2 Motor Vehicle Emissions and Gasoline Sulfur Controls
Rule Name: Tier 2 Motor Vehicle Emissions and Gasoline Sulfur Standards
Pechan Measure Code: T220	POD: N/A
Application: This control measure represents the application of EPA's Tier 2 motor vehicle
emissions and gasoline fuel sulfur control requirements in 1999. Emissions reduction
benefits of NOX, PM 10-2.5, PM2.5, VOC, CO and S02 are estimated using EPA's
MOBILE6 model.
This control is applicable to all light duty vehicles beginning with the 2004 model year,
and all gasoline vehicles beginning with the 1981 model year. Heavy duty diesel
vehicles and motorcycles are not affected by this control.
Affected SCC:
2201001000 Light Duty Gasoline Vehicles (LDGV), Total: All Road Types
2201020000 Light Duty Gasoline Trucks 1 (LDGT1), Total: All Road Types
2201040000 Light Duty Gasoline Trucks 2 (LDGT2), Total: All Road Types
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2230001000 Light Duty Diesel Vehicles (LDDV), Total: All Road Types
2230060000 Light Duty Diesel Trucks (LDDT), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies varies for each vehicle type:
LDG: PM2.5 (30-39%); PM10 (17-23%); NOx (52-77%); VOC (36-65%); S02
(90%); CO (30-56%)
HDG: PM2.5 (14%); PM10 (12%); NOx (13%); VOC (11%); S02 (90%); CO (8%)
LDD: PM2.5 (30-58%); PM10 (29-54%); NOx (40-61%); VOC (30-55%); S02 (0-
4%); CO (7-41%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the Tier 2 motor vehicle emissions standards, an estimate was
made of the number of vehicles affected by the control. The number of vehicles was
estimated by dividing the VMT by the average annual mileage accumulation rate for
each affected vehicle type and model year. The costs for the Tier 2 motor vehicle
emissions standards are estimated at $82.43 per light duty gasoline vehicle and light
duty diesel truck, $116.66 per light duty gasoline truck 1, $210.51 per light duty diesel
truck, and $252.90 per light duty gasoline truck 2 (EPA, 1999). All costs are in 1999
dollars.
The costs for the gasoline fuel sulfur controls were applied to all gallons of gasoline
fuel used by the affected vehicles (LDGV, LDGT1, LDGT2, HDGV). Low sulfur
gasoline fuel is estimated to cost an additional $0.0193 per gallon of gasoline (EPA,
1999). All costs are in 1999 dollars.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Cost Effectiveness: The cost effectiveness of the Tier 2 motor vehicle emissions and gasoline fuel
sulfur control requirements varies greatly by county and depends mostly on the
number of vehicles and the year modeled. Cost effectiveness ranged from
$1,464 to $16,235 per ton NOx reduced. The average value used in
AirControlNET is $6,933.40 per ton NOx reduced. All costs are $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 1999: U.S. Environmental Protection Agency, "Regulatory Impact Analysis - Control of Air
Pollution from New Motor Vehicles: Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur
Control Requirements," EPA420-R-99-023, December 1999.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Light Duty and Gasoline-Fueled Vehicles
Control Measure Name: Tier 2 Motor Vehicle Emissions and Gasoline Sulfur Controls
Rule Name: Tier 2 Motor Vehicle Emissions and Gasoline Sulfur Standards
Pechan Measure Code: T230	POD: N/A
Application: This control measure represents the application of EPA's Tier 2 motor vehicle
emissions and gasoline fuel sulfur control requirements in 1999. Emissions reduction
benefits of NOX, PM 10-2.5, PM2.5, VOC, CO and S02 are estimated using EPA's
MOBILE6 model.
This control is applicable to all light duty vehicles beginning with the 2004 model year,
and all gasoline vehicles beginning with the 1981 model year. Heavy duty diesel
vehicles and motorcycles are not affected by this control.
Affected SCC:
2201001000 Light Duty Gasoline Vehicles (LDGV), Total: All Road Types
2201020000 Light Duty Gasoline Trucks 1 (LDGT1), Total: All Road Types
2201040000 Light Duty Gasoline Trucks 2 (LDGT2), Total: All Road Types
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2230001000 Light Duty Diesel Vehicles (LDDV), Total: All Road Types
2230060000 Light Duty Diesel Trucks (LDDT), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies varies for each vehicle type:
LDG: PM2.5 (32-58%); PM10 (18-43%); NOx (74-92%); VOC (83-88%); S02
(90%); CO (63-73%)
HDG: PM2.5 (38%); PM10 (34%); NOx (42%); VOC (35%); S02 (94%); CO
(10%)
LDD: PM2.5 (61-93%); PM10 (58-89%); NOx (65-98%); VOC (60-90%); S02 (0-
15%); CO (45-46%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the Tier 2 motor vehicle emissions standards, an estimate was
made of the number of vehicles affected by the control. The number of vehicles was
estimated by dividing the VMT by the average annual mileage accumulation rate for
each affected vehicle type and model year. The costs for the Tier 2 motor vehicle
emissions standards are estimated at $82.43 per light duty gasoline vehicle and light
duty diesel truck, $116.66 per light duty gasoline truck 1, $210.51 per light duty diesel
truck, and $252.90 per light duty gasoline truck 2 (EPA, 1999). All costs are in 1999
dollars.
The costs for the gasoline fuel sulfur controls were applied to all gallons of gasoline
fuel used by the affected vehicles (LDGV, LDGT1, LDGT2, HDGV). Low sulfur
gasoline fuel is estimated to cost an additional $0.0193 per gallon of gasoline (EPA,
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
1999). All costs are in 1999 dollars.
Cost Effectiveness: The cost effectiveness of the Tier 2 motor vehicle emissions and gasoline fuel
sulfur control requirements varies greatly by county and depends mostly on the
number of vehicles and the year modeled. Cost effectiveness ranged from
$2,050 to $15,228 per ton NOx reduced. The average value used in
AirControlNET is $8,542.46 per ton NOx reduced. All costs are $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 1999: U.S. Environmental Protection Agency, "Regulatory Impact Analysis - Control of Air
Pollution from New Motor Vehicles: Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur
Control Requirements," EPA420-R-99-023, December 1999.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Light Duty Gasoline Engines
Control Measure Name: High Enhanced Inspection and Maintenance (l/M) Program
Rule Name: Not Applicable
Pechan Measure Code: mOT3
POD: N/A
Application: This control measure represents the application of EPA's high enhanced l/M
performance standards to light duty gasoline vehicles in counties that do not have this
requirement implemented in 1999. Emission reduction benefits of NOx, CO, and VOC
are estimated using EPA's MOBILE6 model.
This control is applicable to all light duty gasoline vehicles, motor cycles, and trucks.
Affected SCC:
2201001000 Light Duty Gasoline Vehicles (LDGV), Total: All Road Types
2201020000 Light Duty Gasoline Trucks 1 (LDGT1), Total: All Road Types
2201040000 Light Duty Gasoline Trucks 2 (LDGT2), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg




V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency ranged from: NOx (0.4 to 13.4%; VOC (1.8 to 19.8%); CO
(0.7 to 26.1%)
Equipment Life: Not Applicable
Rule Effectiveness: Not applicable
Penetration: Not applicable
Cost Basis: To calculate costs for high enhanced l/M, an estimate was made of the number of
vehicles and amount of fuel consumed by county and vehicle type. Costs were
estimated on a per-vehicle basis.
The number of vehicles was estimated by dividing the VMT by the average LDGV
annual mileage accumulation rate. The costs are for enhanced l/M is estimated at $
17.95 per vehicle inspected and $11.43 per vehicle inspected in counties with current
basic or low l/M program (Pechan 2002). All costs are $1997.
Cost Effectiveness: The cost effectiveness of an enhanced l/M program varies greatly by county
and depends mostly on the number of vehicles and the current l/M
requirements for light duty vehicles in each county. Cost effectiveness for NOx
ranged from $218,369 to $3,900 per ton. The average C-E for NOx is $7,949
per ton of NOx reduced (median is $6,721 per ton). All costs are $1997.
Comments:
Status: Demonstrated
Last Reviewed: 2002
Additional Information:
References:
Pechan 2002: "AirControlNET Specifications and Methods for Mobile Source Controls" Memo
prepared for Larry Sorrels of the US EPA, December 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: IC Engines - Gas
Control Measure Name: L-E (Low Speed)
Rule Name: Not Applicable
Pechan Measure Code: N02211	POD: 22
Application: This control is the application of L-E (Low Speed) technology to reduce NOx emissions.
This control applies to gasoline powered IC engines with uncontrolled NOx emissions
greater than 10 tons per year.
Affected SCC:
20200202 Industrial, Natural Gas, Reciprocating
20200204 Natural Gas, Reciprocating: Cogeneration
20300201 Natural Gas, Reciprocating
20300204 Natural Gas, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 87% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost equations for stationary source NOx control are based on an analysis of EPA's
NOx State Implementation Plan (SIP) Call (Pechan-Avanti, 1998). A capital cost to
annual cost ratio based upon information provided in the respective Alternative
Control Techniques (ACT) document is also assigned (EPA, 1993). In cases where
the default cost per ton value of 4.3 was applied, a default capital and operating and
maintenance cost could also be determined. A discount rate of 7% and a capacity
factor of 65% were assumed for all sources. The equipment life of 15 years is also
assumed.
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $176 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
.EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
.EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: IC Engines - Gas - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N02212	POD: 22
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<4,000 HP) gas-fired IC engines with uncontrolled NOx emissions
greater than 10 tons per year.
Affected SCC:
20200202 Industrial, Natural Gas, Reciprocating
20200204 Natural Gas, Reciprocating: Cogeneration
20300201 Natural Gas, Reciprocating
20300204 Natural Gas, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines less than 4,000 horsepower were considered small engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 1.9 is developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $2,769 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: IC Engines - Gas, Diesel, LPG - Small Sources
Control Measure Name: Ignition Retard
Rule Name: Not Applicable
Pechan Measure Code: N0461S, N04601	POD: 46
Application: This control is the use of ignition retard technologies to reduce NOx emissions.
This applies to small (<1 ton NOx per OSD) gas, diesel and LPG IC engines with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200301 Gasoline, Reciprocating
20200401	Industrial, Large Bore Engine, Diesel
20200402	Large Bore Engine, Dual Fuel (Oil/Gas)
20200403	Large Bore Engine, Cogeneration: Dual Fuel
20200902 Kerosene/Naphtha (Jet Fuel), Reciprocating
20201001 Liquefied Petroleum Gas (LPG), Propane: Reciprocating
20300301 Gasoline, Reciprocating
20301001 Liquefied Petroleum Gas (LPG), Propane: Reciprocating
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines less than 4,000 horsepower were considered small engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 1.1 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $770 per ton NOx reduced from both
uncontrolled RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: IC Engines - Gas, Diesel, LPG - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0464S, N04604	POD: 46
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control applies to small (<4,000 HP) gas, diesel and LPG-fired IC engines with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200301 Gasoline, Reciprocating
20200401	Industrial, Large Bore Engine, Diesel
20200402	Large Bore Engine, Dual Fuel (Oil/Gas)
20200403	Large Bore Engine, Cogeneration: Dual Fuel
20200902 Kerosene/Naphtha (Jet Fuel), Reciprocating
20201001 Liquefied Petroleum Gas (LPG), Propane: Reciprocating
20300301 Gasoline, Reciprocating
20301001 Liquefied Petroleum Gas (LPG), Propane: Reciprocating
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines less than 4,000 horsepower were considered small engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 1.8 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $2,340 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
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AT-A-GLANCE TABLE FOR POINT SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Cyclone - Large Sources
Control Measure Name: Coal Reburn
Rule Name: Not Applicable
Pechan Measure Code: N0142L, N01402	POD: 14
Application: This control reduces NOx emissions through coal reburn.
This control is applicable to large coal/cyclone ICI boilers classified under SCCs
10200203 and 10300223.
Affected SCC:
10200203 Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
10300223 Bituminous/Subbituminous Coal, Cyclone Furnace (Subbituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emissions level greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 2.0. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost component breakdown is estimated using
the material in Appendix B - 4.0 Cyclone-Fired boilers for coal reburning of the
Cadmus report (1995). Cost breakdowns were provided in this Group 2 boiler
analysis for 150 MW and 400 MW cyclone boilers. A capacity factor of 0.65 is used
in estimating the O&M cost breakdown.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The default cost effectiveness values is $300 per ton NOx reduced from both
uncontrolled and RACT (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Cadmus, 1995: The Cadmus Group, Inc., Investigation and Performance and Cost of NOx Controls
as Applied to Group 2 Boilers, Draft Report, prepared for U.S. Environmental Protection Agency,
Acid Rain Division, Washington, DC, August 1995.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Cyclone - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0141S, N01401	POD: 14
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) coal/cyclone IC boilers
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200203 Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
10300223 Bituminous/Subbituminous Coal, Cyclone Furnace (Subbituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 35% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $840 per ton NOx reduced (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Cyclone - Small Sources
Control Measure Name: Coal Reburn
Rule Name: Not Applicable
Pechan Measure Code: N0142S	POD: 14
Application: This control reduces NOx emissions through coal reburn.
This control is applicable to small coal/cyclone ICI boilers classified under SCCs
10200203 and 10300223.
Affected SCC:
10200203 Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
10300223 Bituminous/Subbituminous Coal, Cyclone Furnace (Subbituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 2.0. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost component breakdown is estimated using
the material in Appendix B - 4.0 Cyclone-Fired boilers for coal reburning of the
Cadmus report (1995). Cost breakdowns were provided in this Group 2 boiler
analysis for 150 MW and 400 MW cyclone boilers. A capacity factor of 0.65 is used
in estimating the O&M cost breakdown.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The default cost effectiveness values is $1,570 per ton NOx reduced from both
uncontrolled and RACT (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Cadmus, 1995: The Cadmus Group, Inc., Investigation and Performance and Cost of NOx Controls
as Applied to Group 2 Boilers, Draft Report, prepared for U.S. Environmental Protection Agency,
Acid Rain Division, Washington, DC, August 1995.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Cyclone - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0143S, N01403	POD: 14
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control applies to small (<1 ton NOx per OSD) coal/cyclone ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200203 Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
10300223 Bituminous/Subbituminous Coal, Cyclone Furnace (Subbituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values and a capital to annual cost ratio of 7.0 are assigned. A discount rate of 7
percent and a capacity factor of 65 percent are assumed, along with an equipment
life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the Chapter 4
costing algorithms in EPA, 2001. The fixed O&M cost is the sum of the annual
maintenance material and labor cost, and is estimated to be 0.66 percent of the
capital cost. This portion of the O&M cost is included in the database as maintenance
labor. The NH3 use cost equation is used to estimate chemicals costs. The annual
replacement cost equation is used to estimate replacement materials costs. The
energy requirement cost equation is used to estimate electricity costs.
Electricity cost = $0.03/kW-hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Ammonia cost = $225/ton
The above O&M component costs are in 2000 dollars. The model plant size used to
estimate ICI boiler O&M cost components is 400 MMBtu/hr.
Cost Effectiveness: The default cost effectiveness value is $820 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Document No. 05.09.009/9010.463	III-187	Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Cyclone - Small Sources
Control Measure Name: Natural Gas Reburn (NGR)
Rule Name: Not Applicable
Pechan Measure Code: N0144S, N01404	POD: 14
Application: Natural gas reburning (NGR) involves add-on controls to reduce NOx emissions. NGR
is a combustion control technology in which part of the main fuel heat input is diverted
to locations above the main burners, called the reburn zone. As flue gas passes
through the reburn zone, a portion of the NOx formed in the main combustion zone is
reduced by hydrocarbon radicals and converted to molecular nitrogen (N2).
This control applies to small (<1 ton NOx per OSD) coal/cyclone ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200203 Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
10300223 Bituminous/Subbituminous Coal, Cyclone Furnace (Subbituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 2.0. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the economic
analysis for a 200 megawatt unit provided in Appendix E: Cost Analysis of Reburning
Systems for conventional gas reburn. The example calculation with a $1.00 per
million Btu difference between the primary fuel cost and the reburn fuel cost was
used. The reference for this information is the 1998 Andover Technology Partners
report for NESCAUM/MARAMA. The fuel cost differential is the dominant operating
cost of NGR.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Coal Cost: $ 1.50/MM Btu
Natural Gas Cost: $2.50/MMBtu
Cost Effectiveness: The default cost effectiveness value is $1,570 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In a reburn boiler, fuel is injected into the upper furnace region to convert the NOx formed in the
primary combustion zone to molecular N2 and H20. In general, the overall process occurs within
three zones of the boiler; the combustion zone, the gas reburning zone, and the burnout zone (ERG,
2000). In the combustion zone the amount of fuel is reduced and the burners may be operated at
the lowest excess air level. In the gas reburning zone the fuel not used in the combustion zone is
injected to create a fuel-rich region where radicals can react with NOx to form molecular Nitrogen.
In the burnout zone a separate overfire air system redirects air from the primary combustion zone to
ensure complete combustion of unreacted fuel leaving the reburning zone.
Operational parameters that affect the performance of reburn include reburn zone stoichiometry,
residence time in the reburn zone, reburn fuel carrier gas and temperature and 02 levels in the
burnout zone (ERG, 2000).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Staudt, 1998: Staudt, James E., "Status Report on NOx Control Technologies and Cost
Effectiveness for Utility Boilers," Andover Technology Partners, North Andover, MA, prepared for
NESCAUM and MARAMA, June 1998.
Document No. 05.09.009/9010.463	III-190	Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/FBC - Large Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Urea Based
Rule Name: Not Applicable
Pechan Measure Code: N0121L, N01201	POD: 12
Application: This control is the reduction of NOx emission through urea based selective non-
catalytic reduction add-on controls. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20).
This control applies to large (>1 ton NOx emissions per OSD) coal-fired/fluidized bed
combustion IC boilers with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
10300217 Commercial/Institutional, Atm. Fluidized Bed Combustion-Bubbling (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1994), capacity-based equations are used to calculate costs. A
discount rate of 7 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 20 years (EPA, 1994).
In general, incremental cost equations (or defaults cost) are used for sources where
there are existing controls (RACT baseline), with efficiencies less than or equal to
70% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
Capital Cost = 15,972.8 * Capacity (MMBtu/hr)A0.6
Annual Cost = 4,970.5 * Capacity (MMBtu/hr)A0.6
From RACT Baseline:
Capital Cost = 15,972.8 * Capacity (MMBtu/hr)A0.6
Annual Cost = 3,059.2 * Capacity (MMBtu/hr)A0.6
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Note: All costs are in 1990 dollars.
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness values, used when capacity information is not
available, is $670 per ton NOx reduced from both uncontrolled and RACT
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Document No. 05.09.009/9010.463
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-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/FBC - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Urea Based
Rule Name: Not Applicable
Pechan Measure Code: N0121S	POD: 12
Application: This control is the reduction of NOx emission through urea based selective non-
catalytic reduction add-on controls. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) coal-fired/fluidized bed
combustion IC boilers with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
10300217 Commercial/Institutional, Atm. Fluidized Bed Combustion-Bubbling (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $900 per ton NOx reduced (1990$).
Comments:
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Stoker - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0131L, N01301	POD: 13
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls to coal/stoker IC boilers. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20).
This control applies to large (>1 ton NOx emissions per OSD) coal/stoker IC boilers
with uncontrolled NOx emissions greater than 10 tons per year, classified under SCC
10200204.
Affected SCC:
10200204 Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1994), capacity-based equations are used to calculate costs. A
discount rate of 7 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 20 years (EPA, 1994).
In general, incremental cost equations (or defaults cost) are used for sources where
there are existing controls (RACT baseline), with efficiencies less than or equal to
70% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
Capital Cost = 110,487.6 * Capacity (MMBtu/hr)A0.423
Annual Cost = 3,440.9 * Capacity (MMBtu/hr)A0.7337
From RACT Baseline:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Capital Cost = 67,093.8 * Capacity (MMBtu/hr)A0.423
Annual Cost = 7,514.2 * Capacity (MMBtu/hr)A0.4195
Note: All costs are in 1990 dollars.
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness value, used when capacity information is not
available, is $817 per ton NOx reduced from uncontrolled and $703 per ton
NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Stoker - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0131S	POD: 13
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) coal/stoker IC boilers
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200104 Anthracite Coal, Traveling Grate (Overfeed) Stoker
10200204	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
10200205	Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
10200206	Industrial, Bituminous/Subbituminous Coal, Underfeed Stoker
10200210 Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker**
10200224	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10200225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
10200306 Lignite, Spreader Stoker
10300102 Anthracite Coal, Traveling Grate (Overfeed) Stoker
10300207	Commercial/Institutional, Overfeed Stoker (Bituminous Coal)
10300208	Commercial/Institutional, Underfeed Stoker (Bituminous Coal)
10300209	Commercial/Institutional, Spreader Stoker (Bituminous Coal)
10300224	Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10300225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $1,015 per ton NOx
reduced from uncontrolled and $873 per ton NOx reduced from RACT baseline
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EEPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
Document No. 05.09.009/9010.463	III-200	Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Wall - Large Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0111L, N01101	POD: 11
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls to wall fired (coal) IC boilers. SNCR controls are post-combustion
control technologies based on the chemical reduction of nitrogen oxides (NOx) into
molecular nitrogen (N2) and water vapor (H20).
This control applies to large (>1 ton NOx emissions per OSD) coal-fired IC boilers with
uncontrolled NOx emissions greater than 10 tons per year, classified under SCCs
10200201 and 10200202.
Affected SCC:
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1994), capacity-based equations are used to calculate costs. A
discount rate of 7 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
Capital Cost = 110,487.6 * Capacity (MMBtu/hr)A0.423
Annual Cost = 3,440.9 * Capacity (MMBtu/hr)A0.7337
From RACT Baseline:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Capital Cost = 67,093.8 * Capacity (MMBtu/hr)A0.423
Annual Cost = 7,514.2 * Capacity (MMBtu/hr)A0.4195
Note: All costs are in 1990 dollars.
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness value, used when capacity information is not
available, is $840 per ton NOx reduced from uncontrolled and $260 per ton
NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Wall - Large Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0113L, N01103	POD: 11
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to large (>1 ton NOx per OSD) coal/wall fired ICI boilers
classified under SCCs 10200201 and 10200202 with uncontrolled NOx emissions
greater than 10 tons per year.
Affected SCC:
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1994), capacity-based equations are used to calculate costs. A
discount rate of 7 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
Capital Cost = 53,868.7 * Capacity (MMBtu/hr)A0.6
Annual Cost= 11,861.1 * Capacity (MMBtu/hr)A0.6
From RACT Baseline:
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Capital Cost = 53,868.7 * Capacity (MMBtu/hr)A0.6
Annual Cost= 11,861.1 * Capacity (MMBtu/hr)A0.6
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Appendix F of the ACT document (see page F-4). The model boiler
size used to develop O&M cost components is 766 MMBtu/hr. A capacity factor of
0.58 is used in estimating the O&M cost breakdown.
Electricity cost: $0.05/kW-hr
Note: All costs are in 1990 dollars.
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness value, used when capacity information is not
available, is $1,090 per ton NOx reduced from both uncontrolled and RACT
baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Wall - Large Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0114L, N01104	POD: 11
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control applies to large (>1 ton NOx emissions per OSD) coal/wall IC boilers with
uncontrolled NOx emissions greater than 10 tons per year, classified under SCCs
10200201 and 10200202.
Affected SCC:
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 70% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1994), capacity-based equations are used to calculate costs. A
discount rate of 7 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
Capital Cost = 82,400.9 * Capacity (MMBtu/hr)A0.65
Annual Cost = 5,555.6 * Capacity (MMBtu/hr)A0.7885
From RACT Baseline:
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Capital Cost = 79,002.2 * Capacity (MMBtu/hr)A0.65
Annual Cost = 8,701.5 * Capacity (MMBtu/hr)A0.6493
Note: All costs are in 1990 dollars.
O&M Cost Components: The O&M cost breakdown is estimated using the Chapter 4
costing algorithms in EPA, 2001. The fixed O&M cost is the sum of the annual
maintenance material and labor cost, and is estimated to be 0.66 percent of the
capital cost. This portion of the O&M cost is included in the database as maintenance
labor. The NH3 use cost equation is used to estimate chemicals costs. The annual
replacement cost equation is used to estimate replacement materials costs. The
energy requirement cost equation is used to estimate electricity costs.
Electricity cost = $0.03/kW-hr
Ammonia cost = $225/ton
The above O&M component costs are in 2000 dollars. The model plant size used to
estimate ICI boiler O&M cost components is 400 MMBtu/hr.
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness values, used when capacity information is not
available, are $1,070 per ton NOx reduced from uncontrolled and $700 per ton
NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Wall - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0111S	POD: 11
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls to wall fired (coal) IC boilers. SNCR controls are post-combustion
control technologies based on the chemical reduction of nitrogen oxides (NOx) into
molecular nitrogen (N2) and water vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) coal-fired IC boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200101 Anthracite Coal, Pulverized Coal
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
10200212 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
10200219 Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
10200222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
10200301 Lignite, Pulverized Coal: Dry Bottom, Wall Fired
10300101 Anthracite Coal, Pulverized Coal
10300205	Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Bituminous Coal)
10300206	Commercial/Institutional, Pulverized Coal-Dry Bottom (Bituminous Coal)
10300222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
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AT-A-GLANCE TABLE FOR POINT SOURCES
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $1,040 per ton NOx
reduced from uncontrolled and $400 per ton NOx reduced from RACT baseline
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
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AT-A-GLANCE TABLE FOR POINT SOURCES
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Wall - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0113S	POD: 11
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) coal/wall fired ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200101 Anthracite Coal, Pulverized Coal
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
10200212 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
10200219 Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
10200222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
10200301 Lignite, Pulverized Coal: Dry Bottom, Wall Fired
10300101 Anthracite Coal, Pulverized Coal
10300205	Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Bituminous Coal)
10300206	Commercial/Institutional, Pulverized Coal-Dry Bottom (Bituminous Coal)
10300222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 4.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
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AT-A-GLANCE TABLE FOR POINT SOURCES
information in Appendix F of the ACT document (see page F-4). The model boiler
size used to develop O&M cost components is 766 MMBtu/hr. A capacity factor of
0.58 is used in estimating the O&M cost breakdown.
Electricity cost: $0.05/kW-hr
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $1,460 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coal/Wall - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0114S	POD: 11
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control applies to small (<1 ton NOx per OSD) coal/wall-fired ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200101 Anthracite Coal, Pulverized Coal
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
10200212 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
10200219 Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
10200222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
10200301 Lignite, Pulverized Coal: Dry Bottom, Wall Fired
10300101 Anthracite Coal, Pulverized Coal
10300205	Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Bituminous Coal)
10300206	Commercial/Institutional, Pulverized Coal-Dry Bottom (Bituminous Coal)
10300222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 70% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values and a capital to annual cost ratio of 7.1 are assigned. A discount rate of 7
percent and a capacity factor of 65 percent are assumed, along with an equipment
life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
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Cost Effectiveness: The default cost effectiveness value is $1,260 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coke - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0421S, N04201	POD: 42
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) coke IC boilers with
uncontrolled NOx emissions greater than 10 tons per year, classified under SCCs
10200801, 10200802, and 10200804.
Affected SCC:
10200801	Industrial, Coke
10200802	Coke, All Boiler Sizes
10200804 Coke, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $1,040 per ton NOx
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AT-A-GLANCE TABLE FOR POINT SOURCES
reduced from uncontrolled and $400 per ton NOx reduced from RACT baseline
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coke - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0423S, N04203	POD: 42
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) coke ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200801	Industrial, Coke
10200802	Coke, All Boiler Sizes
10200804 Coke, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 4.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $1,460 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Coke - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0424S, N04204	POD: 42
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) coke ICI boilers with NOx emissions greater
than 10 tons per year.
Affected SCC:
10200801	Industrial, Coke
10200802	Coke, All Boiler Sizes
10200804 Coke, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 70% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the Chapter 4
costing algorithms in EPA, 2001. The fixed O&M cost is the sum of the annual
maintenance material and labor cost, and is estimated to be 0.66 percent of the
capital cost. This portion of the O&M cost is included in the database as maintenance
labor. The NH3 use cost equation is used to estimate chemicals costs. The annual
replacement cost equation is used to estimate replacement materials costs. The
energy requirement cost equation is used to estimate electricity costs.
Electricity cost = $0.03/kW-hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Ammonia cost = $225/ton
The above O&M component costs are in 2000 dollars. The model plant size used to
estimate ICI boiler O&M cost components is 400 MMBtu/hr.
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $1,260 per ton NOx
reduced from uncontrolled and $910 per ton NOx reduced from RACT baseline
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Distillate Oil - Large Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0454L, N04504	POD: 16
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to large (>1 ton NOx emissions per OSD) distillate oil IC boilers
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200501	Industrial, Distillate Oil, Grades 1 and 2 Oil
10200502	Distillate Oil, 10-100 Million Btu/hr**
10200503	Distillate Oil, < 10 Million Btu/hr**
10200504	Industrial, Distillate Oil, Grade 4 Oil
10300501	Commercial/Institutional, Distillate Oil, Grades 1 and 2 Oil
10300502	Commercial/Institutional, Distillate Oil, 10-100 Million Btu/hr**
10300503	Commercial/Institutional, Distillate Oil, < 10 Million Btu/hr**
10300504	Commercial/Institutional, Distillate Oil, Grade 4 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1994), capacity-based equations are used to calculate costs. A
discount rate of 7 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Capital Cost = 62,148.8 * Capacity (MMBtu/hr)A0.423
Annual Cost = 2,012.4 * Capacity (MMBtu/hr)A0.7229
From RACT Baseline:
Capital Cost = 48,002.6 * Capacity (MMBtu/hr)A0.423
Annual Cost = 5,244.4 * Capacity (MMBtu/hr)A0.4238
Note: All costs are in 1990 dollars.
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness value, used when capacity information is not
available, is $1,890 per ton NOx reduced from uncontrolled and $1,010 per ton
NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
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AT-A-GLANCE TABLE FOR POINT SOURCES
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Distillate Oil - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0161S, N01601	POD: 16
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to distillate oil-fired ICI boilers with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
10200501	Industrial, Distillate Oil, Grades 1 and 2 Oil
10200502	Distillate Oil, 10-100 Million Btu/hr**
10200503	Distillate Oil, < 10 Million Btu/hr**
10200504	Industrial, Distillate Oil, Grade 4 Oil
10300501	Commercial/Institutional, Distillate Oil, Grades 1 and 2 Oil
10300502	Commercial/Institutional, Distillate Oil, 10-100 Million Btu/hr**
10300503	Commercial/Institutional, Distillate Oil, < 10 Million Btu/hr**
10300504	Commercial/Institutional, Distillate Oil, Grade 4 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 5.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information in the appendix to the 1994 ICI Boiler ACT document. The only O&M cost
for LNBs is for administrative, property tax, and insurance, and these are estimated
(in total) as 4 percent of the capital investment cost.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $1,180 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Distillate Oil - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0162S, N01602	POD: 16
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) distillate oil-fired ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200501	Industrial, Distillate Oil, Grades 1 and 2 Oil
10200502	Distillate Oil, 10-100 Million Btu/hr**
10200503	Distillate Oil, < 10 Million Btu/hr**
10200504	Industrial, Distillate Oil, Grade 4 Oil
10300501	Commercial/Institutional, Distillate Oil, Grades 1 and 2 Oil
10300502	Commercial/Institutional, Distillate Oil, 10-100 Million Btu/hr**
10300503	Commercial/Institutional, Distillate Oil, < 10 Million Btu/hr**
10300504	Commercial/Institutional, Distillate Oil, Grade 4 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Appendix E of ICI boiler ACT document (see pages E-27 and E-28). A
capacity factor of 0.58 is used in estimating the O&M cost breakdown. The model
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AT-A-GLANCE TABLE FOR POINT SOURCES
boiler size used to develop cost estimates is 45 MMBtu/hr.
Electricity cost: $0.05/kW-hr
Natural gas cost: $3.63/MMBtu
Cost Effectiveness: The default cost effectiveness values are $2,490 per ton NOx reduced from
uncontrolled and $1,090 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Distillate Oil - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0163S, N01603	POD: 16
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) distillate oil-fired ICI boilers with NOx emissions
greater than 10 tons per year.
Affected SCC:
10200501	Industrial, Distillate Oil, Grades 1 and 2 Oil
10200502	Distillate Oil, 10-100 Million Btu/hr**
10200503	Distillate Oil, < 10 Million Btu/hr**
10200504	Industrial, Distillate Oil, Grade 4 Oil
10300501	Commercial/Institutional, Distillate Oil, Grades 1 and 2 Oil
10300502	Commercial/Institutional, Distillate Oil, 10-100 Million Btu/hr**
10300503	Commercial/Institutional, Distillate Oil, < 10 Million Btu/hr**
10300504	Commercial/Institutional, Distillate Oil, Grade 4 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown for SCR is estimated using
information from Appendix E of the ACT document (pages E-53 to E-60). This
appendix provides O&M costs for 100, 150, 200, and 250 MMBtu/hour natural gas-
fired boilers. The costs by category were averaged for the four boiler sizes to
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AT-A-GLANCE TABLE FOR POINT SOURCES
establish a representative O&M cost breakdown for this source category/control
measure combination. A capacity factor of 0.5 was used in this evaluation.
Electricity cost: $0.05/kW-hr
Ammonia cost: $250/ton
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $2,780 per ton NOx
reduced from uncontrolled and $3,570 per ton NOx from RACT baselines
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Distillate Oil - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0164S, N01604	POD: 16
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) distillate oil IC boilers
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200501	Industrial, Distillate Oil, Grades 1 and 2 Oil
10200502	Distillate Oil, 10-100 Million Btu/hr**
10200503	Distillate Oil, < 10 Million Btu/hr**
10200504	Industrial, Distillate Oil, Grade 4 Oil
10300501	Commercial/Institutional, Distillate Oil, Grades 1 and 2 Oil
10300502	Commercial/Institutional, Distillate Oil, 10-100 Million Btu/hr**
10300503	Commercial/Institutional, Distillate Oil, < 10 Million Btu/hr**
10300504	Commercial/Institutional, Distillate Oil, Grade 4 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $4,640 per ton NOx
reduced from uncontrolled and $3,470 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Liquid Waste
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0453S, N04503	POD: 45
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) liquid waste ICI boilers with NOx emissions
greater than 10 tons per year.
Affected SCC:
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown for SCR is estimated using
information from Appendix E of the ACT document (pages E-53 to E-60). This
appendix provides O&M costs for 100, 150, 200, and 250 MMBtu/hour natural gas-
fired boilers. The costs by category were averaged for the four boiler sizes to
establish a representative O&M cost breakdown for this source category/control
measure combination. A capacity factor of 0.5 was used in this evaluation.
Electricity cost: $0.05/kW-hr
Ammonia cost: $250/ton
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $1,480 per ton NOx
reduced from uncontrolled and $ 1,910 per ton NOx reduced from RACT
baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Liquid Waste - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0451S, N04501	POD: 45
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) liquid waste ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10201301	Industrial, Liquid Waste, Specify Waste Material in Comments
10201302	Industrial, Liquid Waste, Waste Oil
10301301	Liquid Waste, Specify Waste Material in Comments
10301302	Liquid Waste, Waste Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 5.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information in the appendix to the 1994 ICI Boiler ACT document. The only O&M cost
for LNBs is for administrative, property tax, and insurance, and these are estimated
(in total) as 4 percent of the capital investment cost.
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $400 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Liquid Waste - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0452S, N04502	POD: 45
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) liquid waste-fired ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10201301	Industrial, Liquid Waste, Specify Waste Material in Comments
10201302	Industrial, Liquid Waste, Waste Oil
10301301	Liquid Waste, Specify Waste Material in Comments
10301302	Liquid Waste, Waste Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Appendix E of ICI boiler ACT document (see pages E-27 and E-28). A
capacity factor of 0.58 is used in estimating the O&M cost breakdown. The model
boiler size used to develop cost estimates is 45 MMBtu/hr.
Electricity cost: $0.05/kW-hr
Natural gas cost: $3.63/MMBtu
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The default cost effectiveness values are $1,120 per ton NOx reduced from
uncontrolled and $1,080 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Liquid Waste - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0454S	POD: 45
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) liquid waste-fired IC
boilers with uncontrolled NOx emissions greater than 10 tons per year, classified under
the following SCCs: 10201301, 10201302, 10301301, and 10301302.
Affected SCC:
10201301	Industrial, Liquid Waste, Specify Waste Material in Comments
10201302	Industrial, Liquid Waste, Waste Oil
10301301	Liquid Waste, Specify Waste Material in Comments
10301302	Liquid Waste, Waste Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,580 per ton NOx
reduced from uncontrolled and $1,940 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - LPG - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0431S, N04301	POD: 43
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) LPG ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10201001	Liquefied Petroleum Gas (LPG), Butane
10201002	Industrial, Liquefied Petroleum Gas (LPG), Propane
10301002 Commercial/Institutional, Liquefied Petroleum Gas (LPG), Propane
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 5.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information in the appendix to the 1994 ICI Boiler ACT document. The only O&M cost
for LNBs is for administrative, property tax, and insurance, and these are estimated
(in total) as 4 percent of the capital investment cost.
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $1,180 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - LPG - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0432S, N04302	POD: 43
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) LPG-fired ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10201001	Liquefied Petroleum Gas (LPG), Butane
10201002	Industrial, Liquefied Petroleum Gas (LPG), Propane
10301002 Commercial/Institutional, Liquefied Petroleum Gas (LPG), Propane
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Appendix E of ICI boiler ACT document (see pages E-27 and E-28). A
capacity factor of 0.58 is used in estimating the O&M cost breakdown. The model
boiler size used to develop cost estimates is 45 MMBtu/hr.
Electricity cost: $0.05/kW-hr
Natural gas cost: $3.63/MMBtu
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The default cost effectiveness values are $2,490 per ton NOx reduced from
uncontrolled and $1,090 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - LPG - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0433S, N04303	POD: 43
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) LPG ICI boilers with NOx emissions greater
than 10 tons per year.
Affected SCC:
10201001	Liquefied Petroleum Gas (LPG), Butane
10201002	Industrial, Liquefied Petroleum Gas (LPG), Propane
10301002 Commercial/Institutional, Liquefied Petroleum Gas (LPG), Propane
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown for SCR is estimated using
information from Appendix E of the ACT document (pages E-53 to E-60). This
appendix provides O&M costs for 100, 150, 200, and 250 MMBtu/hour natural gas-
fired boilers. The costs by category were averaged for the four boiler sizes to
establish a representative O&M cost breakdown for this source category/control
measure combination. A capacity factor of 0.5 was used in this evaluation.
Electricity cost: $0.05/kW-hr
Ammonia cost: $250/ton
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $2,780 per ton NOx
reduced from uncontrolled and $3,570 per ton NOx reduced from RACT
baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - LPG - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0434S, N04304	POD: 43
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) liquid petroleum gas-
fired IC boilers with uncontrolled NOx emissions greater than 10 tons per year,
classified under SCCs 10201001, 10201002, and 10301002.
Affected SCC:
10201001	Liquefied Petroleum Gas (LPG), Butane
10201002	Industrial, Liquefied Petroleum Gas (LPG), Propane
10301002 Commercial/Institutional, Liquefied Petroleum Gas (LPG), Propane
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $4,640 per ton NOx
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AT-A-GLANCE TABLE FOR POINT SOURCES
reduced from uncontrolled and $ 3,470 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - MSW/Stoker - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Urea Based
Rule Name: Not Applicable
Pechan Measure Code: N0201S, N02001	POD: 20
Application: This control is the reduction of NOx emission through urea based selective non-
catalytic reduction add-on controls. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) solid waste/stoker IC
boilers with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10201201 Industrial, Solid Waste, Specify Waste Material in Comments
10301201	Solid Waste, Specify Waste Material in Comments
10301202	Solid Waste, Refuse Derived Fuel
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $1,690 per ton NOx reduced (1990$).
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Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Natural Gas - Large Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0175L, N01705	POD: 17
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to large (>1 ton NOx emissions per OSD) natural gas fired IC
boilers with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200601	Industrial, Natural Gas, > 100 Million Btu/hr
10200602	Industrial, Natural Gas, 10-100 Million Btu/hr
10200603	Industrial, Natural Gas, < 10 Million Btu/hr
10200604	Natural Gas, Cogeneration
10201401 CO Boiler, Natural Gas
10300601	Commercial/Institutional, Natural Gas, > 100 Million Btu/hr
10300602	Commercial/Institutional, Natural Gas, 10-100 Million Btu/hr
10300603	Commercial/Institutional, Natural Gas, < 10 Million Btu/hr
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1994), capacity-based equations are used to calculate costs. A
discount rate of 7 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
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Capital Cost = 62,148.8 * Capacity (MMBtu/hr)A0.423
Annual Cost = 2,012.4 * Capacity (MMBtu/hr)A0.7229
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
From RACT Baseline:
Capital Cost = 48,002.6 * Capacity (MMBtu/hr)A0.423
Annual Cost = 5,244.4 * Capacity (MMBtu/hr)A0.4238
Note: All costs are in 1990 dollars.
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness value, used when capacity information is not
available, is $1,570 per ton NOx reduced from uncontrolled and $840 per ton
NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
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Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Natural Gas - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0171S, N01701	POD: 17
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) natural gas fired ICI boilers
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200601	Industrial, Natural Gas, > 100 Million Btu/hr
10200602	Industrial, Natural Gas, 10-100 Million Btu/hr
10200603	Industrial, Natural Gas, < 10 Million Btu/hr
10200604	Natural Gas, Cogeneration
10201401 CO Boiler, Natural Gas
10300601	Commercial/Institutional, Natural Gas, > 100 Million Btu/hr
10300602	Commercial/Institutional, Natural Gas, 10-100 Million Btu/hr
10300603	Commercial/Institutional, Natural Gas, < 10 Million Btu/hr
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 5.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information in the appendix to the 1994 ICI Boiler ACT document. The only O&M cost
for LNBs is for administrative, property tax, and insurance, and these are estimated
(in total) as 4 percent of the capital investment cost.
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Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $820 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Natural Gas - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0172S, N01702	POD: 17
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) natural gas-fired ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200601	Industrial, Natural Gas, > 100 Million Btu/hr
10200602	Industrial, Natural Gas, 10-100 Million Btu/hr
10200603	Industrial, Natural Gas, < 10 Million Btu/hr
10200604	Natural Gas, Cogeneration
10201401 CO Boiler, Natural Gas
10300601	Commercial/Institutional, Natural Gas, > 100 Million Btu/hr
10300602	Commercial/Institutional, Natural Gas, 10-100 Million Btu/hr
10300603	Commercial/Institutional, Natural Gas, < 10 Million Btu/hr
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Appendix E of ICI boiler ACT document (see pages E-27 and E-28). A
capacity factor of 0.58 is used in estimating the O&M cost breakdown. The model
boiler size used to develop cost estimates is 45 MMBtu/hr.
Electricity cost: $0.05/kW-hr
Natural gas cost: $3.63/MMBtu
Cost Effectiveness: The default cost effectiveness values are $2,560 per ton NOx reduced from
uncontrolled and $2,470 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Natural Gas - Small Sources
Control Measure Name: Oxygen Trim + Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0173S, N01703	POD: 17
Application: This control is the use of OT + Wl to reduce NOx emissions.
This control applies to small (<1 ton NOx per OSD) natural gas-fired ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200601	Industrial, Natural Gas, > 100 Million Btu/hr
10200602	Industrial, Natural Gas, 10-100 Million Btu/hr
10200603	Industrial, Natural Gas, < 10 Million Btu/hr
10200604	Natural Gas, Cogeneration
10201401 CO Boiler, Natural Gas
10300601	Commercial/Institutional, Natural Gas, > 100 Million Btu/hr
10300602	Commercial/Institutional, Natural Gas, 10-100 Million Btu/hr
10300603	Commercial/Institutional, Natural Gas, < 10 Million Btu/hr
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 65% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). The
model boiler size used to develop cost estimates is 45 MMBtu/hr. From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
2.9. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 10 years (EPA, 1994). The 7 percent discount rate
used as a baseline in AirControlNET is changed from the 10 percent rate used in the
ACT document.
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Appendix E of the ACT document. (See pages E-3 and E-4.) A
capacity factor of 0.58 is used in estimating the O&M cost breakdown.
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Electricity Cost: $0.05/kW-hr
Natural Gas Cost: $3.63/MMBtu
Cost Effectiveness: The default cost effectiveness value is $680 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The
water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Natural Gas - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0174S, N01704	POD: 17
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) natural gas fired ICI boilers with NOx emissions
greater than 10 tons per year.
Affected SCC:
10200601	Industrial, Natural Gas, > 100 Million Btu/hr
10200602	Industrial, Natural Gas, 10-100 Million Btu/hr
10200603	Industrial, Natural Gas, < 10 Million Btu/hr
10200604	Natural Gas, Cogeneration
10201401 CO Boiler, Natural Gas
10300601	Commercial/Institutional, Natural Gas, > 100 Million Btu/hr
10300602	Commercial/Institutional, Natural Gas, 10-100 Million Btu/hr
10300603	Commercial/Institutional, Natural Gas, < 10 Million Btu/hr
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown for SCR is estimated using
information from Appendix E of the ACT document (pages E-53 to E-60). This
appendix provides O&M costs for 100, 150, 200, and 250 MMBtu/hour natural gas-
fired boilers. The costs by category were averaged for the four boiler sizes to
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establish a representative O&M cost breakdown for this source category/control
measure combination. A capacity factor of 0.5 was used in this evaluation.
Electricity cost: $0.05/kW-hr
Ammonia cost: $250/ton
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,230 per ton NOx
reduced from uncontrolled and $2,860 per ton NOx reduced from RACT
baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
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EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Natural Gas - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0175S	POD: 17
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) natural gas-fired IC
boilers with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200601	Industrial, Natural Gas, > 100 Million Btu/hr
10200602	Industrial, Natural Gas, 10-100 Million Btu/hr
10200603	Industrial, Natural Gas, < 10 Million Btu/hr
10200604	Natural Gas, Cogeneration
10201401 CO Boiler, Natural Gas
10300601	Commercial/Institutional, Natural Gas, > 100 Million Btu/hr
10300602	Commercial/Institutional, Natural Gas, 10-100 Million Btu/hr
10300603	Commercial/Institutional, Natural Gas, < 10 Million Btu/hr
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
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Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $3,870 per ton NOx
reduced from uncontrolled and $2,900 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
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Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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Source Category: ICI Boilers - Process Gas - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0411S, N04101	POD: 41
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) process gas fired ICI boilers
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200701	Industrial, Process Gas, Petroleum Refinery Gas
10200702	Industrial, Process Gas
10200704 Process Gas, Blast Furnace Gas
10200707 Industrial, Process Gas, Coke Oven Gas
10200710 Process Gas, Cogeneration
10200799 Process Gas, Other: Specify in Comments
10201402 CO Boiler, Process Gas
10300701 Commercial/Institutional, Process Gas, POTW Digester Gas-fired Boiler
10300799 Commercial/Institutional, Process Gas, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 5.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information in the appendix to the 1994 ICI Boiler ACT document. The only O&M cost
for LNBs is for administrative, property tax, and insurance, and these are estimated
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(in total) as 4 percent of the capital investment cost.
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $820 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Process Gas - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0412S, N04102	POD: 41
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) process gas-fired ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200701	Industrial, Process Gas, Petroleum Refinery Gas
10200702	Industrial, Process Gas
10200704 Process Gas, Blast Furnace Gas
10200707 Industrial, Process Gas, Coke Oven Gas
10200710 Process Gas, Cogeneration
10200799 Process Gas, Other: Specify in Comments
10201402 CO Boiler, Process Gas
10300701 Commercial/Institutional, Process Gas, POTW Digester Gas-fired Boiler
10300799 Commercial/Institutional, Process Gas, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Appendix E of ICI boiler ACT document (see pages E-27 and E-28). A
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AT-A-GLANCE TABLE FOR POINT SOURCES
capacity factor of 0.58 is used in estimating the O&M cost breakdown. The model
boiler size used to develop cost estimates is 45 MMBtu/hr.
Electricity cost: $0.05/kW-hr
Natural gas cost: $3.63/MMBtu
Cost Effectiveness: The default cost effectiveness values are $2,560 per ton NOx reduced from
uncontrolled and $2,470 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Process Gas - Small Sources
Control Measure Name: Oxygen Trim + Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0413S, N04103	POD: 41
Application: This control is the use of OT + Wl to reduce NOx emissions.
This control applies to small (<1 ton NOx per OSD) process gas-fired reformers
involved in ammonia production with uncontrolled NOx emissions greater than 10 tons
per year.
Affected SCC:
10200701	Industrial, Process Gas, Petroleum Refinery Gas
10200702	Industrial, Process Gas
10200704 Process Gas, Blast Furnace Gas
10200707 Industrial, Process Gas, Coke Oven Gas
10200710 Process Gas, Cogeneration
10200799 Process Gas, Other: Specify in Comments
10201402 CO Boiler, Process Gas
10300701 Commercial/Institutional, Process Gas, POTW Digester Gas-fired Boiler
10300799 Commercial/Institutional, Process Gas, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 65% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 2.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Appendix E of the ACT document. (See pages E-3 and E-4.) A
capacity factor of 0.58 is used in estimating the O&M cost breakdown.
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Electricity Cost: $0.05/kW-hr
Natural Gas Cost: $3.63/MMBtu
Cost Effectiveness: The default cost effectiveness value is $680 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The
water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Process Gas - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0414S, N04104	POD: 41
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) process gas fired ICI boilers with NOx
emissions greater than 10 tons per year.
Affected SCC:
10200701	Industrial, Process Gas, Petroleum Refinery Gas
10200702	Industrial, Process Gas
10200704 Process Gas, Blast Furnace Gas
10200707 Industrial, Process Gas, Coke Oven Gas
10200710 Process Gas, Cogeneration
10200799 Process Gas, Other: Specify in Comments
10201402 CO Boiler, Process Gas
10300701 Commercial/Institutional, Process Gas, POTW Digester Gas-fired Boiler
10300799 Commercial/Institutional, Process Gas, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown for SCR is estimated using
information from Appendix E of the ACT document (pages E-53 to E-60). This
appendix provides O&M costs for 100, 150, 200, and 250 MMBtu/hour natural gas-
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fired boilers. The costs by category were averaged for the four boiler sizes to
establish a representative O&M cost breakdown for this source category/control
measure combination. A capacity factor of 0.5 was used in this evaluation.
Electricity cost: $0.05/kW-hr
Ammonia cost: $250/ton
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,230 per ton NOx
reduced from uncontrolled and $2,860 per ton NOx reduced from RACT
baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
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June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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Source Category: ICI Boilers - Residual Oil - Large Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0154L, N01504	POD: 15
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to large (>1 ton NOx emissions per OSD) residual oil IC boilers
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200401	Industrial, Residual Oil, Grade 6 Oil
10200402	Residual Oil, 10-100 Million Btu/hr**
10200403	Residual Oil, < 10 Million Btu/hr**
10200404	Industrial, Residual Oil, Grade 5 Oil
10200405	Residual Oil, Cogeneration
10201404 CO Boiler, Residual Oil
10300401	Commercial/Institutional, Residual Oil, Grade 6 Oil
10300402	Commercial/Institutional, Residual Oil, 10-100 Million Btu/hr**
10300404 Commercial/Institutional, Residual Oil, Grade 5 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1994), capacity-based equations are used to calculate costs. A
discount rate of 7 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
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Capital Cost = 62,148.8 * Capacity (MMBtu/hr)A0.423
Annual Cost = 2,012.4 * Capacity (MMBtu/hr)A0.7229
From RACT Baseline:
Capital Cost = 48,002.6 * Capacity (MMBtu/hr)A0.423
Annual Cost = 5,244.4 * Capacity (MMBtu/hr)A0.4238
Note: All costs are in 1990 dollars.
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness value, used when capacity information is not
available, is $1,050 per ton NOx reduced from uncontrolled and $560 per ton
NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
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AT-A-GLANCE TABLE FOR POINT SOURCES
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Residual Oil - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0151S, N01501	POD: 15
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) residual oil-fired ICI boilers
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200401	Industrial, Residual Oil, Grade 6 Oil
10200402	Residual Oil, 10-100 Million Btu/hr**
10200403	Residual Oil, < 10 Million Btu/hr**
10200404	Industrial, Residual Oil, Grade 5 Oil
10200405	Residual Oil, Cogeneration
10201404 CO Boiler, Residual Oil
10300401	Commercial/Institutional, Residual Oil, Grade 6 Oil
10300402	Commercial/Institutional, Residual Oil, 10-100 Million Btu/hr**
10300404 Commercial/Institutional, Residual Oil, Grade 5 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 5.5. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information in the appendix to the 1994 ICI Boiler ACT document. The only O&M cost
for LNBs is for administrative, property tax, and insurance, and these are estimated
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AT-A-GLANCE TABLE FOR POINT SOURCES
(in total) as 4 percent of the capital investment cost.
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $400 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Residual Oil - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0152S, N01502	POD: 15
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) residual oil-fired ICI boilers with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200401	Industrial, Residual Oil, Grade 6 Oil
10200402	Residual Oil, 10-100 Million Btu/hr**
10200403	Residual Oil, < 10 Million Btu/hr**
10200404	Industrial, Residual Oil, Grade 5 Oil
10200405	Residual Oil, Cogeneration
10201404 CO Boiler, Residual Oil
10300401	Commercial/Institutional, Residual Oil, Grade 6 Oil
10300402	Commercial/Institutional, Residual Oil, 10-100 Million Btu/hr**
10300404 Commercial/Institutional, Residual Oil, Grade 5 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Appendix E of ICI boiler ACT document (see pages E-27 and E-28). A
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AT-A-GLANCE TABLE FOR POINT SOURCES
capacity factor of 0.58 is used in estimating the O&M cost breakdown. The model
boiler size used to develop cost estimates is 45 MMBtu/hr.
Electricity cost: $0.05/kW-hr
Natural gas cost: $3.63/MMBtu
Cost Effectiveness: The default cost effectiveness values are $1,120 per ton NOx reduced from
uncontrolled and $1,080 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Residual Oil - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0153S, N01503	POD: 15
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) residual oil-fired ICI boilers with NOx emissions
greater than 10 tons per year.
Affected SCC:
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown for SCR is estimated using
information from Appendix E of the ACT document (pages E-53 to E-60). This
appendix provides O&M costs for 100, 150, 200, and 250 MMBtu/hour natural gas-
fired boilers. The costs by category were averaged for the four boiler sizes to
establish a representative O&M cost breakdown for this source category/control
measure combination. A capacity factor of 0.5 was used in this evaluation.
Electricity cost: $0.05/kW-hr
Ammonia cost: $250/ton
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $1,480 per ton NOx
reduced from uncontrolled and $1,910 per ton NOx reduced from RACT
baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Residual Oil - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0154S	POD: 15
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) residual oil-fired IC
boilers with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200401	Industrial, Residual Oil, Grade 6 Oil
10200402	Residual Oil, 10-100 Million Btu/hr**
10200403	Residual Oil, < 10 Million Btu/hr**
10200404	Industrial, Residual Oil, Grade 5 Oil
10200405	Residual Oil, Cogeneration
10201404 CO Boiler, Residual Oil
10300401	Commercial/Institutional, Residual Oil, Grade 6 Oil
10300402	Commercial/Institutional, Residual Oil, 10-100 Million Btu/hr**
10300404 Commercial/Institutional, Residual Oil, Grade 5 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
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Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,580 per ton NOx
reduced from uncontrolled and $ 1,940 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Wood/Bark/Stoker - Large Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Urea Based
Rule Name: Not Applicable
Pechan Measure Code: N0181L, N01801	POD: 18
Application: This control is the reduction of NOx emission through urea based selective non-
catalytic reduction add-on controls. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20).
This control applies to large(>1 ton NOx emissions per OSD) wood/bark fired IC boilers
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200901	Industrial, Wood/Bark Waste, Bark-fired Boiler (> 50,000 Lb Steam)
10200902	Industrial, Wood/Bark Waste, Wood/Bark-fired Boiler (> 50,000 Lb Steam)
10200903	Industrial, Wood/Bark Waste, Wood-fired Boiler (> 50,000 Lb Steam)
10200904	Wood/Bark Waste, Bark-fired Boiler (< 50,000 Lb Steam)
10200905	Wood/Bark Waste, Wood/Bark-fired Boiler (< 50,000 Lb Steam)
10200906	Industrial, Wood/Bark Waste, Wood-fired Boiler (< 50,000 Lb Steam)
10200907	Wood/Bark Waste, Wood Cogeneration
10300902	Wood/Bark Waste, Wood/Bark-fired Boiler
10300903	Commercial/Institutional, Wood/Bark Waste, Wood-fired Boiler
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Large source = emission levels greater than 1 ton per ozone season day
Where information was available in the Alternative Control Techniques (ACT)
document (EPA, 1994), capacity-based equations are used to calculate costs. A
discount rate of 7 percent and a capacity factor of 65 percent are assumed, along
with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
The following equations, based primarily on information in the Air Pollution Cost
Manual (EPA, 2002), are used for large NOx sources as defined above:
From Uncontrolled:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Capital Cost = 65,820.1 * Capacity (MMBtu/hr)A0.3607
Annual Cost= 17,777.1 * Capacity (MMBtu/hr)A0.3462
From RACT Baseline:
Capital Cost = 65,820.1 * Capacity (MMBtu/hr)A0.361
Annual Cost= 17,777.1 * Capacity (MMBtu/hr)A0.3462
Note: All costs are in 1990 dollars.
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: When capacity is available and within the applicable range of 0 to 2,000
MMBTU/hr the cost equations are used to calculate cost effectiveness. The
default cost effectiveness values, used when capacity information is not
available, is $1,190 per ton NOx reduced from both uncontrolled and RACT
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: ICI Boilers - Wood/Bark/Stoker - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Urea Based
Rule Name: Not Applicable
Pechan Measure Code: N0181S	POD: 18
Application: This control is the reduction of NOx emission through urea based selective non-
catalytic reduction add-on controls. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) wood/bark fired IC
boilers with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10200901	Industrial, Wood/Bark Waste, Bark-fired Boiler (> 50,000 Lb Steam)
10200902	Industrial, Wood/Bark Waste, Wood/Bark-fired Boiler (> 50,000 Lb Steam)
10200903	Industrial, Wood/Bark Waste, Wood-fired Boiler (> 50,000 Lb Steam)
10200904	Wood/Bark Waste, Bark-fired Boiler (< 50,000 Lb Steam)
10200905	Wood/Bark Waste, Wood/Bark-fired Boiler (< 50,000 Lb Steam)
10200906	Industrial, Wood/Bark Waste, Wood-fired Boiler (< 50,000 Lb Steam)
10200907	Wood/Bark Waste, Wood Cogeneration
10300902	Wood/Bark Waste, Wood/Bark-fired Boiler
10300903	Commercial/Institutional, Wood/Bark Waste, Wood-fired Boiler
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the example
problem in the OAQPS Control Cost Manual chapter on SNCR. This example was for
a 1,000 MMBtu/hr boiler burning sub-bituminous coal.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity cost: $0.05/kW-hr
Coal cost: $1.60/MMBtu
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $1,440 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Coal Combustion
Control Measure Name: RACT to 50 tpy (LNB)
Rule Name: Reasonably Available Control Technology - 50 tpy
Pechan Measure Code: N10001
POD: 100
Application: The RACT control technology used is the addition of a low NOx burner to reduce NOx
emissions.
This standard applies to sources with boilers fueled by coal that emit over 50 tpy NOx
(classified under SCCs 2102001000 and 2102002000).
Affected SCC:
2102001000 Anthracite Coal, Total: All Boiler Types
2102002000 Bituminous/Subbituminous Coal, Total: All Boiler Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 21% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 80%
Penetration: 23%
Cost Basis:
Cost per ton (CPT) values are based on applying the cost equations developed for
the point source ICI boilers to small sources. For coal, costs are based on a 50
MMBtu/hr boiler operating at 33% capacity. Costs are based on a 10-year equipment
life and a 5% discount rate (Pechan, 1998).
Annual Cost (AC) = CPT
Penetration)
Emissions *(Control Efficiency *Rule Effectiveness*Rule
Cost Effectiveness = AC / Tons NOx Reduced Per Year
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,350 per ton NOx reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1996: E.H. Pechan & Associates, "The Emission Reduction and Cost Analysis Model for
NOx (ECRAM-NOx)," Revised Documentation, prepared for U.S. Environmental Protection Agency,
Ozone Policy and Strategies Group, Research Triangle Park, NC, September 1996.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Clean Air Act Section 812 Prospective Cost
Analysis - Draft Report," prepared for Industrial Economics, Inc., Cambridge, MA, September 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Coal Combustion
Control Measure Name: RACT to 25 tpy (LNB)
Rule Name: Reasonably Available Control Technology - 25 tpy
Pechan Measure Code: N10002
POD: 100
Application: The RACT control technology used is the addition of a low NOx burner to reduce NOx
emissions.
This standard applies to sources with boilers fueled by coal that emit over 25 tpy NOx
(classified under SCCs 2102001000 and 2102002000).
Affected SCC:
2102001000 Anthracite Coal, Total: All Boiler Types
2102002000 Bituminous/Subbituminous Coal, Total: All Boiler Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 21% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 80%
Penetration: 45%
Cost Basis:
Cost per ton (CPT) values are based on applying the cost equations developed for
the point source ICI boilers to small sources. For coal, costs are based on a 50
MMBtu/hr boiler operating at 33% capacity. Costs are based on a 10-year equipment
life and a 5% discount rate (Pechan, 1998).
Annual Cost (AC) = CPT
Penetration)
Emissions *(Control Efficiency *Rule Effectiveness*Rule
Cost Effectiveness = AC / Tons NOx Reduced Per Year
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,350 per ton NOx reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1996: E.H. Pechan & Associates, "The Emission Reduction and Cost Analysis Model for
NOx (ECRAM-NOx)," Revised Documentation, prepared for U.S. Environmental Protection Agency,
Ozone Policy and Strategies Group, Research Triangle Park, NC, September 1996.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Clean Air Act Section 812 Prospective Cost
Analysis - Draft Report," prepared for Industrial Economics, Inc., Cambridge, MA, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Incinerators
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0601S, N06001	POD: 60
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to industrial incinerators IC boilers with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30190012	Fuel Fired Equipment, Residual Oil: Incinerators
30190013	Fuel Fired Equipment, Natural Gas: Incinerators
30190014	Fuel Fired Equipment, Process Gas: Incinerators
30590013 Fuel Fired Equipment, Natural Gas: Incinerators
30790013 Fuel Fired Equipment, Natural Gas: Incinerators
30890013 Fuel Fired Equipment, Natural Gas: Incinerators
39990013 Miscellaneous Manufacturing Industries, Natural Gas: Incinerators
50300101	Solid Waste Disposal - Industrial, Incineration, Multiple Chamber
50300102	Solid Waste Disposal - Industrial, Incineration, Single Chamber
50300103	Solid Waste Disposal - Industrial, Incineration, Controlled Air
50300104	Incineration, Conical Design (Tee Pee) Municipal Refuse
50300105	Solid Waste Disposal - Industrial, Incineration, Conical Design (Tee Pee) Wood Refuse
50300506 Solid Waste Disposal - Industrial, Incineration, Sludge
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 45% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
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AT-A-GLANCE TABLE FOR POINT SOURCES
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the
information in Chapter and Appendix A of the MWC ACT document. The cost
outputs for conventional SNCR applied to the 400 ton per day model combustor
(Table 3-3) are used to estimate the O&M cost breakdown. The tipping fee ($1.47
per ton) is included as a waste disposal cost (direct annual cost).
Electricity Cost: 0.046 $/kW-hr
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$1,130 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Radian Corporation, "Alternative Control
Techniques Document- NOx Emissions from Municipal Waste Combustion," EPA-600/R-94-208,
Research Triangle Park, NC, December, 1994.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Natural Gas Combustion
Control Measure Name: RACT to 50 tpy (LNB)
Rule Name: Reasonably Available Control Technology - 50 tpy
Pechan Measure Code: N10201
POD: 102
Application: The RACT control technology used is the addition of a low NOx burner to reduce NOx
emissions.
This standard applies to sources with boilers fueled by coal that emit over 50 tpy NOx
(classified under SCCs 2102001000 and 2102002000).
Affected SCC:
2102006000 Natural Gas, Total: Boilers and IC Engines
2102006002 Natural Gas, All IC Engine Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 31% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 80%
Penetration: 11%
Cost Basis: Cost per ton (CPT) values are based on applying the cost equations developed for
the point source ICI boilers to small sources. For gas and oil, costs are based on a
25 MMBtu/hour boiler operating at 33 percent of capacity, an equipment lifetime of 10
years, and a 5 percent discount rate (Pechan, 1998).
Annual Cost (AC) = CPT * Emissions *(Control Efficiency *Rule Effectiveness*Rule
Penetration)
Cost Effectiveness = AC / Tons NOx Reduced Per Year
Cost Effectiveness: The cost effectiveness used in AirControlNET is $770 per ton NOx reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1996: E.H. Pechan & Associates, "The Emission Reduction and Cost Analysis Model for
NOx (ECRAM-NOx)," Revised Documentation, prepared for U.S. Environmental Protection Agency,
Ozone Policy and Strategies Group, Research Triangle Park, NC, September 1996.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Clean Air Act Section 812 Prospective Cost
Analysis - Draft Report," prepared for Industrial Economics, Inc., Cambridge, MA, September 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Natural Gas Combustion
Control Measure Name: RACT to 25 tpy (LNB)
Rule Name: Reasonably Available Control Technology - 25 tpy
Pechan Measure Code: N10202
POD: 102
Application: The RACT control technology used is the addition of a low NOx burner to reduce NOx
emissions.
This standard applies to sources with boilers fueled by coal that emit over 50 tpy NOx
(classified under SCCs 2102001000 and 2102002000).
Affected SCC:
2102006000 Natural Gas, Total: Boilers and IC Engines
2102006002 Natural Gas, All IC Engine Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 31% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 80%
Penetration: 22%
Cost Basis: Cost per ton (CPT) values are based on applying the cost equations developed for
the point source ICI boilers to small sources. For gas and oil, costs are based on a
25 MMBtu/hour boiler operating at 33 percent of capacity, an equipment lifetime of 10
years, and a 5 percent discount rate (Pechan, 1998).
Annual Cost (AC) = CPT * Emissions *(Control Efficiency *Rule Effectiveness*Rule
Penetration)
Cost Effectiveness = AC / Tons NOx Reduced Per Year
Cost Effectiveness: The cost effectiveness used in AirControlNET is $770 per ton NOx reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1996: E.H. Pechan & Associates, "The Emission Reduction and Cost Analysis Model for
NOx (ECRAM-NOx)," Revised Documentation, prepared for U.S. Environmental Protection Agency,
Ozone Policy and Strategies Group, Research Triangle Park, NC, September 1996.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Clean Air Act Section 812 Prospective Cost
Analysis - Draft Report," prepared for Industrial Economics, Inc., Cambridge, MA, September 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Oil Combustion
Control Measure Name: RACT to 50 tpy (LNB)
Rule Name: Reasonably Available Control Technology - 50 tpy
Pechan Measure Code: N10101
POD: 101
Application: The RACT control technology used is the addition of a low NOx burner to reduce NOx
emissions.
This standard applies to sources with boilers fueled by coal that emit over 50 tpy NOx
(classified under SCCs 2102001000 and 2102002000).
Affected SCC:
2102004000 Distillate Oil, Total: Boilers and IC Engines
2102005000 Residual Oil, Total: All Boiler Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 36% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 80%
Penetration: 8%
Cost Basis: Cost per ton (CPT) values are based on applying the cost equations developed for
the point source ICI boilers to small sources. For gas and oil, costs are based on a
25 MMBtu/hour boiler operating at 33 percent of capacity, an equipment lifetime of 10
years, and a 5 percent discount rate (Pechan, 1998).
Annual Cost (AC) = CPT * Emissions *(Control Efficiency *Rule Effectiveness*Rule
Penetration)
Cost Effectiveness = AC / Tons NOx Reduced Per Year
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,180 per ton NOx reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1996: E.H. Pechan & Associates, "The Emission Reduction and Cost Analysis Model for
NOx (ECRAM-NOx)," Revised Documentation, prepared for U.S. Environmental Protection Agency,
Ozone Policy and Strategies Group, Research Triangle Park, NC, September 1996.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Clean Air Act Section 812 Prospective Cost
Analysis - Draft Report," prepared for Industrial Economics, Inc., Cambridge, MA, September 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Oil Combustion
Control Measure Name: RACT to 25 tpy (LNB)
Rule Name: Reasonably Available Control Technology - 25 tpy
Pechan Measure Code: N10102
POD: 101
Application: The RACT control technology used is the addition of a low NOx burner to reduce NOx
emissions.
This standard applies to sources with boilers fueled by coal that emit over 25 tpy NOx
(classified under SCCs 2102001000 and 2102002000).
Affected SCC:
2102004000 Distillate Oil, Total: Boilers and IC Engines
2102005000 Residual Oil, Total: All Boiler Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 36% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 80%
Penetration: 16%
Cost Basis: Cost per ton (CPT) values are based on applying the cost equations developed for
the point source ICI boilers to small sources. For gas and oil, costs are based on a
25 MMBtu/hour boiler operating at 33 percent of capacity, an equipment lifetime of 10
years, and a 5 percent discount rate (Pechan, 1998).
Annual Cost (AC) = CPT * Emissions *(Control Efficiency *Rule Effectiveness*Rule
Penetration)
Cost Effectiveness = AC / Tons NOx Reduced Per Year
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,180 per ton NOx reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1996: E.H. Pechan & Associates, "The Emission Reduction and Cost Analysis Model for
NOx (ECRAM-NOx)," Revised Documentation, prepared for U.S. Environmental Protection Agency,
Ozone Policy and Strategies Group, Research Triangle Park, NC, September 1996.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Clean Air Act Section 812 Prospective Cost
Analysis - Draft Report," prepared for Industrial Economics, Inc., Cambridge, MA, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: In-Proc; Process Gas; Coke Oven/Blast Ovens
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0862S, N08602	POD: 86
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) sources with in-process coke/blast
furnaces and uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
39000701 In-process Fuel Use, Process Gas, Coke Oven or Blast Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.9. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $3,190 per ton NOx reduced from
uncontrolled and $1,430 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: In-Process Fuel Use - Bituminous Coal - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0831S, N08301	POD: 83
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) operations with general
(in process) bituminous coal use and uncontrolled NOx emissions greater than 10 tons
per year. These sources are classified under SCC 39000289.
Affected SCC:
39000289 Bituminous Coal, General (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $1,260 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: In-Process Fuel Use; Natural Gas - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0851S, N08501	POD: 85
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) operations with in-process
natural gas usage and uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
39000689 In-process Fuel Use, Natural Gas, General
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $2,200 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: In-Process Fuel Use; Residual Oil - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0842S, N08402	POD: 84
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) operations with in-process
residual oil usage and uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
39000489 In-process Fuel Use, Residual Oil, General
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 37% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $2,250 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: In-Process; Bituminous Coal; Cement Kilns
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Urea Based
Rule Name: Not Applicable
Pechan Measure Code: N0813S, N08103	POD: 81
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to bituminous coal-fired cement kilns (SCC 39000201) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
39000201 Bituminous Coal, Cement Kiln/Dryer (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$770 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Cement Manufacturing," EPA-453/R-94-004, Research Triangle Park, NC, March, 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: In-Process; Bituminous Coal; Lime Kilns
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Urea Based
Rule Name: Not Applicable
Pechan Measure Code: N0823S, N08203	POD: 82
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to bituminous coal-fired lime kilns (SCC 39000203) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
39000203 In-process Fuel Use, Bituminous Coal, Lime Kiln (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$770 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Cement Manufacturing," EPA-453/R-94-004, Research Triangle Park, NC, March, 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: In-Process; Process Gas; Coke Oven Gas
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0871S, N08701	POD: 87
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) operations with in-process
coke oven gas usage and uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
39000789 Process Gas, Coke Oven Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50%from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emissions level less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $2,200 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Internal Combustion Engines - Gas
Control Measure Name: L-E (Medium Speed)
Rule Name: Not Applicable
Pechan Measure Code: N02210	POD: 22
Application: This control is the application of L-E (Medium Speed) technology to reduce NOx
emissions.
This control applies to gasoline powered IC engines with uncontrolled NOx emissions
greater than 10 tons per year.
Affected SCC:
20200202 Industrial, Natural Gas, Reciprocating
20200204 Natural Gas, Reciprocating: Cogeneration
20300201 Natural Gas, Reciprocating
20300204 Natural Gas, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 87% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $380 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
.EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
.EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Internal Combustion Engines - Gas - Large Sources
Control Measure Name: Ignition Retard
Rule Name: Not Applicable
Pechan Measure Code: N0221L	POD: 22
Application: This control is the use of ignition retard technologies to reduce NOx emissions.
This applies to large (>4,000 HP) gasoline powered IC engines with uncontrolled NOx
emissions greater than 10 tons per yea
Affected SCC:
20200202 Industrial, Natural Gas, Reciprocating
20300201 Natural Gas, Reciprocating
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines greater than 4,000 horsepower were considered large engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 0.7 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $550 per ton NOx reduced from both
uncontrolled RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Document No. 05.09.009/9010.463
III-329
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Internal Combustion Engines - Gas - Large Sources
Control Measure Name: Air/Fuel Ratio Adjustment
Rule Name: Not Applicable
Pechan Measure Code: N0224L, N02204	POD: 22
Application: This control is the use of air/fuel ratio adjustment to reduce NOx emissions.
This control applies to large (>4,00 HP) gasoline powered internal combustion engines
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200202 Industrial, Natural Gas, Reciprocating
20300201 Natural Gas, Reciprocating
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines less than 4,000 horsepower were considered large engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 1.5 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $380 per ton NOx reduced from both
uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Document No. 05.09.009/9010.463
III-331
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
Document No. 05.09.009/9010.463
III-332
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Internal Combustion Engines - Gas - Large Sources
Control Measure Name: Air/Fuel + Ignition Retard
Rule Name: Not Applicable
Pechan Measure Code: N0227L, N02207	POD: 22
Application: This control is the use of air/fuel and ignition retard to reduce NOx emissions.
This control applies to large (>=4,000 HP) gasoline powered internal combustion
engines with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200202 Industrial, Natural Gas, Reciprocating
20300201 Natural Gas, Reciprocating
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 30% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines less than 4,000 horsepower were considered large engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 1.2 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $460 per ton NOx reduced from
uncontrolled and $150 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Document No. 05.09.009/9010.463
III-333
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
Document No. 05.09.009/9010.463
III-334
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Internal Combustion Engines - Gas - Small Sources
Control Measure Name: Ignition Retard
Rule Name: Not Applicable
Pechan Measure Code: N0221S, N02201	POD: 22
Application: This control is the use of ignition retard technologies to reduce NOx emissions.
This applies to small (<4,000 HP) gasoline powered IC engines with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
20200202 Industrial, Natural Gas, Reciprocating
20200204 Natural Gas, Reciprocating: Cogeneration
20300201 Natural Gas, Reciprocating
20300204 Natural Gas, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines less than 4,000 horsepower were considered small engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 1.2 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $1,020 per ton NOx reduced from both
uncontrolled RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
Document No. 05.09.009/9010.463
III-336
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Internal Combustion Engines - Gas - Small Sources
Control Measure Name: Air/Fuel Ratio Adjustment
Rule Name: Not Applicable
Pechan Measure Code: N0224S	POD: 22
Application: This control is the use of air/fuel ratio adjustment to reduce NOx emissions.
This control applies to small (<4,00 HP) gasoline powered internal combustion engines
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
20200202 Industrial, Natural Gas, Reciprocating
20200204 Natural Gas, Reciprocating: Cogeneration
20300201 Natural Gas, Reciprocating
20300204 Natural Gas, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines less than 4,000 horsepower were considered small engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 2.8 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $1,570 per ton NOx reduced from both
uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Internal Combustion Engines - Gas - Small Sources
Control Measure Name: Air/Fuel + Ignition Retard
Rule Name: Not Applicable
Pechan Measure Code: N0227S	POD: 22
Application: This control is the use of air/fuel and ignition retard to reduce NOx emissions.
This control applies to small (<4,000 HP) gasoline powered internal combustion
engines with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 30% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines less than 4,000 horsepower were considered small engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 2.6 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $1,440 per ton NOx reduced from
uncontrolled and $270 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Document No. 05.09.009/9010.463
III-339
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Internal Combustion Engines - Oil - Small Sources
Control Measure Name: Ignition Retard
Rule Name: Not Applicable
Pechan Measure Code: N0211S, N02101	POD: 21
Application: This control is the use of ignition retard technologies to reduce NOx emissions.
This applies to small (<4,000 HP) oil IC engines with uncontrolled NOx emissions
greater than 10 tons per year.
Affected SCC:
20200102 Distillate Oil (Diesel), Reciprocating
20200104 Industrial, Distillate Oil (Diesel), Reciprocating: Cogeneration
20200501 Residual/Crude Oil, Reciprocating
20300101 Commercial/Institutional, Distillate Oil (Diesel), Reciprocating
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power (Pechan, 1998).
Engines less than 4,000 horsepower were considered small engines.
Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1993). A capital cost to
annual cost ratio of 1.1 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $770 per ton NOx reduced from both
uncontrolled RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
.EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
.EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Internal Combustion Engines - Oil - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0214S, N02104	POD: 21
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) internal combustion engines with NOx
emissions greater than 10 tons per year.
Affected SCC:
20200102 Distillate Oil (Diesel), Reciprocating
20200104 Industrial, Distillate Oil (Diesel), Reciprocating: Cogeneration
20200501 Residual/Crude Oil, Reciprocating
20300101 Commercial/Institutional, Distillate Oil (Diesel), Reciprocating
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 25% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness value (for both small and large sources) used in
AirControlNET is $2,340 per ton NOx reduced from both uncontrolled and
RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Annealing
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0361S, N03601	POD: 36
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to iron and steel annealing operations with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30300934 Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document for annealing, reheating and galvanizing (EPA, 1994).
Capital, and annual cost information was obtained from control-specific cost data.
Some O&M costs were included. Missing O&M costs were back calculated from
annual costs (Pechan, 1998). From these determinations, an average cost per ton
values was assigned along with a capital cost to annual cost ratio of 7.0. A discount
rate of 7% was assumed for all sources. The equipment life is 10 years.
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $570 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
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AT-A-GLANCE TABLE FOR POINT SOURCES
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Annealing
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0362S, N03602	POD: 36
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to iron and steel annealing operations with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
30300934 Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 7.0. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $750 per ton NOx reduced from
uncontrolled and $250 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Annealing
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0363S, N03603	POD: 36
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to iron and steel mill annealing operations with uncontrolled NOx
emissions greater than 10 tons per year, classified under SCC 30300934.
Affected SCC:
30300934 Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 10 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated by applying
percentages of O&M breakdown for SCR as applied to process heaters, using
detailed information found in Table 6-3 and Chapter 6 of the Process Heater ACT
document. The breakdown was obtained using the average O&M costs for 3
annealing furnaces having capacities of 100, 200 and 300 MMBTU per hour.
Electricity: $0.06 per kw-hr
Fuel (nat gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$1,640 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Document No. 05.09.009/9010.463
III-350
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Annealing
Control Measure Name: Low NOx Burner (LNB) + SCR
Rule Name: Not Applicable
Pechan Measure Code: N0364S, N03604	POD: 36
Application: This control is the use of low NOx burner (LNB) technology and selective catalytic
reduction (SCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control is applicable to iron and steel annealing operations with uncontrolled NOx
emissions greater than 10 tons per year.
Affected SCC:
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 3.7. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $1,720 per ton NOx reduced from
uncontrolled and $1,320 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Document No. 05.09.009/9010.463
III-353
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
III-354
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Annealing - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0365S, N03605	POD: 36
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) iron and steel annealing operations with NOx
emissions greater than 10 tons per year.
Affected SCC:
30300934 Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 85% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated by applying
percentages of O&M breakdown for SCR as applied to process heaters, using
detailed information found in Table 6-4 and Chapter 6 of the Process Heater ACT
document. The breakdown was obtained using the average O&M costs for 3
annealing furnaces having capacities of 100, 200 and 300 MMBTU per hour.
Electricity: $0.06 per kw-hr
Fuel (nat gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness value (for both small and large sources) used in
AirControlNET is $3,830 per ton NOx reduced from both uncontrolled and
RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
III-357
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Annealing - Small Sources
Control Measure Name: Low NOx Burner (LNB) + Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0366S, N03606	POD: 36
Application: This control is the use of low NOx burner (LNB) technology and selective catalytic
reduction (SCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control is applicable to small (<1 ton NOx per OSD) iron and steel annealing
operations with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30300934 Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emissions (Pechan, 1998).
Small source = less than 1 ton NOx emissions per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.1. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $4,080 per ton NOx reduced from
uncontrolled and $3,720 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Document No. 05.09.009/9010.463
III-359
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Galvanizing
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0371S, N03701	POD: 37
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to iron and steel galvanizing operations (SCC 30300936) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30300936 Primary Metal Production, Steel Manufacturing (See 3-03-015), Coating: Tin, Zinc, etc.
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 9 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document for annealing, reheating and galvanizing (EPA, 1994).
Capital, and annual cost information was obtained from control-specific cost data.
Some O&M costs were included. Missing O&M costs were back calculated from
annual costs (Pechan, 1998). From these determinations, an average cost per ton
values was assigned along with a capital cost to annual cost ratio of 6.5. A discount
rate of 7% was assumed for all sources. The equipment life is 9 years.
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $490 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
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AT-A-GLANCE TABLE FOR POINT SOURCES
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Galvanizing
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0372S, N03702	POD: 37
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to iron and steel galvanizing operations with uncontrolled
NOx emissions greater than 10 tons per year.
Affected SCC:
30300936 Primary Metal Production, Steel Manufacturing (See 3-03-015), Coating: Tin, Zinc, etc.
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 9 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.5. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 9 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $580 per ton NOx reduced from
uncontrolled and $190 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Reheating
Control Measure Name: Low Excess Air (LEA)
Rule Name: Not Applicable
Pechan Measure Code: N0351S, N03501	POD: 35
Application: The reduction in NOx emissions is achieved through the use of low excess air
techniques, such that there is less available oxygen convert fuel nitrogen to NOx.
This control applies to iron & steel reheating furnaces classified under SCC 30300933.
Affected SCC:
30300933 Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 13% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual cost information was obtained from model engine data in the
Alternative Control Techniques (ACT) document (EPA, 1994). A capital cost to
annual cost ratio of 3.8 was developed to estimate default capital and operating and
maintenance costs. From these determinations, default cost effectiveness values
were assigned. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 15% and less than or equal
to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $1,320 per ton NOx reduced from both
uncontrolled RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Low excess air works by reducing levels of excess air to the combustor, usually by adjustments to
air registers and/or fuel injection positions, or through control of overfire air dampers. The lower
oxygen concentration in the burner zone reduces conversion of the fuel nitrogen to NOx. Also,
under excess air conditions in the flame zone, a greater portion of fuel-bound nitrogen is converted
to N2 therefore reducing the formation of fuel NOx (ERG, 2000).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
.EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
.EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA,-453/R-93-032, Research Triangle
Park, NC, July 1993
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.8.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Reheating
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0352S, N03502	POD: 35
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to iron and steel reheating operations (SCC 30300933) with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30300933 Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 66% from uncontrolled
Equipment Life: 5 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document for annealing, reheating and galvanizing (EPA, 1994).
Capital, and annual cost information was obtained from control-specific cost data.
Some O&M costs were included. Missing O&M costs were back calculated from
annual costs (Pechan, 1998). From these determinations, an average cost per ton
values was assigned along with a capital cost to annual cost ratio of 4.1. A discount
rate of 7% was assumed for all sources. The equipment life is 5 years.
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 15% and less than or equal
to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $300 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
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AT-A-GLANCE TABLE FOR POINT SOURCES
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron & Steel Mills - Reheating
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0353S, N03503	POD: 35
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to reheating processes in iron and steel mills with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30300933 Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 77% from uncontrolled
Equipment Life: 5 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 4.1. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 5 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 15% and less than or equal
to 25% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $380 per ton NOx reduced from
uncontrolled and $150 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
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AT-A-GLANCE TABLE FOR POINT SOURCES
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Iron Production; Blast Furnaces; Blast Heating Stoves
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0673S, N06703	POD: 67
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to reheating processes in iron production operations with
blast heating stoves ant uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30300824 Iron Production (See 3-03-015), Blast Heating Stoves
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 77% from uncontrolled
Equipment Life: 5 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 4.1. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 5 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness values are $380 per ton NOx reduced from
uncontrolled and $150 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Lime Kilns
Control Measure Name: Mid-Kiln Firing
Rule Name: Not Applicable
Pechan Measure Code: N0581, N0581L, N0581S, N05801 POD: 58
Application: This control is the use of mid- kiln firing to reduce NOx emissions.
This control applies to lime kilns with uncontrolled NOx emissions greater than 10 tons
per year.
Affected SCC:
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime, Calcining-Rotary Kiln (See SCCs 305016-18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30700106 Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Lime Kiln
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 30% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost equations for cement plants NOx control are based on an analysis of EPA's NOx
State Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are
model plant data contained in the Alternative Control Techniques (ACT) document for
wet and dry kilns (EPA, 1994). Capital, and annual cost information is obtained from
control-specific cost data. O&M costs were back calculated from annual costs. From
these determinations, an average cost per ton values was assigned along with a
capital cost to annual cost ratio of 3.4. A discount rate of 10% and an equipment life
of 15 years was assumed.
O&M Cost Components: These were estimated for lime kilns using the example
applications of this control technique to the cement manufacturing. See the cement
kiln documentation for more information.
Cost Effectiveness: The default cost effectiveness value is $460 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Lime Kilns
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0582S, N05802	POD: 58
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to lime kilns with uncontrolled NOx emissions greater than 10
tons per year.
Affected SCC:
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime, Calcining-Rotary Kiln (See SCCs 305016-18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30700106 Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Lime Kiln
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 30% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1994). Capital, and annual cost information was
obtained from control-specific cost data. O&M costs were back calculated from
annual costs (Pechan, 1998). From these determinations, an average cost per ton
values was assigned along with a capital cost to annual cost ratio of 5.0. A discount
rate of 7% was assumed for all sources. The equipment life is 15 years.
O&M Cost Components: These were estimated for lime kilns using the example
applications of this control technique to the cement manufacturing. See the cement
kiln documentation for more information.
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $560 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Cement Manufacturing," EPA-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Lime Kilns
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Urea Based
Rule Name: Not Applicable
Pechan Measure Code: N0583S, N05803	POD: 58
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to lime kilns with uncontrolled NOx emissions greater than 10 tons
per year.
Affected SCC:
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime, Calcining-Rotary Kiln (See SCCs 305016-18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30700106 Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Lime Kiln
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: These were estimated for lime kilns using the example
applications of this control technique to the cement manufacturing. See the cement
kiln documentation for more information.
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
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AT-A-GLANCE TABLE FOR POINT SOURCES
$770 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Cement Manufacturing," EPA-453/R-94-004, Research Triangle Park, NC, March, 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Lime Kilns
Control Measure Name: Selective Non-Catalytic Reduction (SNCR) Ammonia Based
Rule Name: Not Applicable
Pechan Measure Code: N0584S, N05804	POD: 58
Application: This control is the reduction of NOx emission through ammonia based selective non-
catalytic reduction add-on controls. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular
nitrogen (N2) and water vapor (H20).
This control applies to lime kilns with uncontrolled NOx emissions greater than 10 tons
per year.
Affected SCC:
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime, Calcining-Rotary Kiln (See SCCs 305016-18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30700106 Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Lime Kiln
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1994).
O&M Cost Components: These were estimated for lime kilns using the example
applications of this control technique to the cement manufacturing. See the cement
kiln documentation for more information.
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$850 per ton NOx reduced (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Cement Manufacturing," EPA,-453/R-94-004, Research Triangle Park, NC, March 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Lime Kilns
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0585S, N05805	POD: 58
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This applies to lime kilns with NOx emissions greater than 10 tons per year.
Affected SCC:
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime, Calcining-Rotary Kiln (See SCCs 305016-18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30700106 Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Lime Kiln
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: These were estimated for lime kilns using the example
applications of this control technique to the cement manufacturing. See the cement
kiln documentation for more information.
Cost Effectiveness: The cost effectiveness value (for both small and large sources) used in
AirControlNET is $3,370 per ton NOx reduced from both uncontrolled and
RACT baselines (1990$).
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AT-A-GLANCE TABLE FOR POINT SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Medical Waste Incinerators
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0391S, N03901	POD: 39
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to medical waste incinerators (SCC 50200505) with uncontrolled
NOx emissions greater than 10 tons per year.
Affected SCC:
50200505 Solid Waste Disposal-Commercial/lnstitutional, Incineration-Special, Medical Infectious
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 45% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(STAPPA/ALAPCO, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$4,510 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
STAPPA/AI_APCO, 1994: State and Territorial Air Pollution Program Administrators/Association of
Local Air Pollution Officials, "Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of
Options," Washington, DC, July 1994.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Municipal Waste Combustors
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0381S, N03801	POD: 38
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to municipal waste combustors with uncontrolled NOx emissions
greater than 10 tons per year.
Affected SCC:
50100101	Solid Waste Disposal-Government, Municipal Incineration, Starved Air-Multiple Chamber
50100102	Municipal Incineration, Mass Burn: Single Chamber
50100103	Municipal Incineration, Refuse Derived Fuel
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 45% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
O&M Cost Components: The O&M cost breakdown is estimated using the
information in Chapter and Appendix A of the MWC ACT document. The cost
outputs for conventional SNCR applied to the 400 ton per day model combustor
(Table 3-3) are used to estimate the O&M cost breakdown. The tipping fee ($1.47
per ton) is included as a waste disposal cost (direct annual cost).
Electricity Cost: 0.046 $/kW-hr
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$1,130 per ton NOx reduced (1990$).
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AT-A-GLANCE TABLE FOR POINT SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Radian Corporation, "Alternative Control
Techniques Document- NOx Emissions from Municipal Waste Combustion," EPA-600/R-94-208,
Research Triangle Park, NC, December 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Natural Gas Production; Compressors - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N08012	POD: 80
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) compressors used in natural gas production
operations with NOx emissions greater than 10 tons per year.
Affected SCC:
31000203 Natural Gas Production, Compressors
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $1,651 per ton NOx
reduced from both uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
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AT-A-GLANCE TABLE FOR POINT SOURCES
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Stationary Reciprocating Internal Combustion Engines," EPA-453/R-93-032, Research Triangle
Park, NC, July, 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Nitric Acid Manufacturing - Small Sources
Control Measure Name: Extended Absorption
Rule Name: Not Applicable
Pechan Measure Code: N0291S, N02901	POD: 29
Application: This control is the use of extended absorption technologies to reduce NOx emissions.
This control applies to nitric acid manufacturing operations classified under SCCs
30101301, 30101302.
Affected SCC:
30101301	Chemical Manufacturing, Nitric Acid, Absorber Tail Gas (Pre-1970 Facilities)
30101302	Chemical Manufacturing, Nitric Acid, Absorber Tail Gas (Post-1970 Facilities)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) document (EPA, 1991). Capital and annual cost information was
obtained from control-specific cost data, allowing for the back calculation of
operating and maintenance costs. From these determinations, default cost per ton
values were assigned (Pechan, 1998). A capital cost to annual cost ratio of 8.1 was
developed to estimate default capital and operating and maintenance costs. A
discount rate of 10% was assumed for all sources. The equipment life was assumed
to be 10 years.
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Tables 6-1 and 6-2 of the Nitric and Adipic Acid Manufacturing Plant
ACT document. The breakdown was obtained using O&M costs for a 500 ton per day
plant. A capacity factor of 0.5 is used in estimating the O&M cost breakdown.
Operating labor: $22.00 per man-hr
Operating labor - supervision: 20% of operating labor
Maintenance materials and labor: 4% of capital cost
Electricity: $0.06 per kw-hr
Water: $0.74 per 1000 gallon
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $480 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
EPA, 1991: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Alternative Control Techniques Document-- Nitric and Adipic Acid Manufacturing Plants," EPA-
450/3-91-026, Research Triangle Park, NC, January 1991.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Nitric Acid Manufacturing - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0292S, N02902	POD: 29
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to nitric acid manufacturing operations with NOx emissions greater than 10
tons per year.
Affected SCC:
30101301	Chemical Manufacturing, Nitric Acid, Absorber Tail Gas (Pre-1970 Facilities)
30101302	Chemical Manufacturing, Nitric Acid, Absorber Tail Gas (Post-1970 Facilities)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 97% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 10 years (EPA, 1991).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-7 and Ch. 6 of the Nitric and Adipic Acid Manufacturing Plant
ACT document. The breakdown was obtained using the average O&M costs for
three plants having capacities of 200, 500 and 1000 tons per day.
Maintenance materials and labor: 4% of capital cost
Cost Effectiveness: The cost effectiveness value (for both small and large sources) used in
AirControlNET is $590 per ton NOx reduced from both uncontrolled and RACT
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AT-A-GLANCE TABLE FOR POINT SOURCES
baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1991: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Alternative Control Techniques Document- Nitric and Adipic Acid Manufacturing Plants," EPA-
450/3-91-026, Research Triangle Park, NC, January 1991.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Nitric Acid Manufacturing - Small Sources
Control Measure Name: Non-Selective Catalytic Reduction (NSCR)
Rule Name: Not Applicable
Pechan Measure Code: N0293S, N029036	POD: 29
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to nitric acid manufacturing operations with uncontrolled NOx
emissions greater than 10 tons per year. These sources are classified under SCCs
30101301 and 30101302.
Affected SCC:
30101301	Chemical Manufacturing, Nitric Acid, Absorber Tail Gas (Pre-1970 Facilities)
30101302	Chemical Manufacturing, Nitric Acid, Absorber Tail Gas (Post-1970 Facilities)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 98% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 10 years
(EPA, 1991).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Nitric and Adipic Acid Manufacturing Plant
ACT document. The breakdown was obtained using O&M costs for three plants
having capacities of 200, 500 and 1000 tons per day.
Maintenance materials and labor: 4% of capital cost
Operating labor - direct: $22 per hour
Operating labor - supervision: 20% of direct operating labor
Fuel (natural gas): $4.12 per MMBTU
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
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AT-A-GLANCE TABLE FOR POINT SOURCES
AirControlNET for both reductions from baseline and reductions from RACT is
$550 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1991: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Alternative Control Techniques Document-- Nitric and Adipic Acid Manufacturing Plants," EPA-
450/3-91-026, Research Triangle Park, NC, January 1991.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Diesel Vehicles
Control Measure Name: Final Compression-Ignition (C-l) Engine Standards
Rule Name: Final Compression-Ignition (C-l) Engine Standards
Pechan Measure Code: CI2010	POD: N/A
Application: This control measure represents the application of EPA's Federal Tier 1/Tier2/Tier 3 C-
I standards to diesel equipment to model implementation of these standards for 2010.
This control measure applies to non-road diesel vehicles, including railroad equipment.
Affected SCC:
2270001000 Off-highway Vehicle Diesel
2270002000 Off-highway Vehicle Diesel
2270003000 Off-highway Vehicle Diesel
2270004000 Off-highway Vehicle Diesel
2270005000 Off-highway Vehicle Diesel
2270006000 Off-highway Vehicle Diesel
2270007000 Off-highway Vehicle Diesel
2270008000 Off-highway Vehicle Diesel
2285002015 Railroad Equipment; Diesel;
Recreational Equipment
Construction and Mining Equipment
Industrial Equipment
Lawn and Garden Equipment
Agricultural Equipment
Commercial Equipment
Logging Equipment
Airport Ground Support Equipment
Railway Maintenance
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (22-50%); PM10
(22-50%); NOx (14-49%); VOC (26-60%); CO (23-53%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the final nonroad C-l standards, an estimate was made of the
number of affected engines by horsepower range and by Tier type (i.e., Tier 1, Tier 2,
or Tier 3) for each implementation year (Pechan, 2003). Near-term costs per engine
by horsepower range and Tier type, obtained from EPA 1994 and EPA 1998, were
then applied to the corresponding number of affected engines and summed to obtain
the total cost for this standard. The number of affected engines was determined by
subtracting out growth in engines, and using turnover data compiled from EPA's
NONROAD 2002 model.
All costs are in 1998 dollars.
Cost Effectiveness: The total cost of this control measure varies by equipment category and Tier
from $56 per engine for Tier 1 engines with less than 50 HP to $5,195 per
engine for Tier 3 engines with 600 to 750 HP ($1998).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Office of Mobile Sources, Certification Division,
"Regulatory Impact Analysis and Regulatory Support Document, Control of Air Pollution;
Determination of Significance for Nonroad Sources and Emission Standards for New Nonroad
Compression-Ignition Engines at or Above 37 Kilowatts (50 Horsepower)," FINAL, Ann Arbor, Ml.
May 1994.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of Mobile
Sources, "Final Regulatory Impact Analysis: Control of Emissions from Nonroad Diesel Engines,"
EPA420-R-98-016, August 1998.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-399
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Diesel Vehicles
Control Measure Name: Final Compression-Ignition (C-l) Engine Standards
Rule Name: Final Compression-Ignition (C-l) Engine Standards
Pechan Measure Code: CI2015	POD: N/A
Application: This control measure represents the application of EPA's Federal Tier 1/Tier2/Tier 3 C-
I standards to diesel equipment to model implementation of these standards for 2015.
This control measure applies to non-road diesel vehicles, including railroad equipment.
Affected SCC:
2270001000 Off-highway Vehicle Diesel
2270002000 Off-highway Vehicle Diesel
2270003000 Off-highway Vehicle Diesel
2270004000 Off-highway Vehicle Diesel
2270005000 Off-highway Vehicle Diesel
2270006000 Off-highway Vehicle Diesel
2270007000 Off-highway Vehicle Diesel
2270008000 Off-highway Vehicle Diesel
2285002015 Railroad Equipment; Diesel;
Recreational Equipment
Construction and Mining Equipment
Industrial Equipment
Lawn and Garden Equipment
Agricultural Equipment
Commercial Equipment
Logging Equipment
Airport Ground Support Equipment
Railway Maintenance
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (33-59%); PM10
(33-59%); NOx (34-57%); VOC (38-71%); CO (34-57%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the final nonroad C-l standards, an estimate was made of the
number of affected engines by horsepower range and by Tier type (i.e., Tier 1, Tier 2,
or Tier 3) for each implementation year (Pechan, 2003). Near-term costs per engine
by horsepower range and Tier type, obtained from EPA 1994 and EPA 1998, were
then applied to the corresponding number of affected engines and summed to obtain
the total cost for this standard. The number of affected engines was determined by
subtracting out growth in engines, and using turnover data compiled from EPA's
NONROAD 2002 model.
All costs are in 1998 dollars.
Cost Effectiveness: The total cost of this control measure varies by equipment category and Tier
from $56 per engine for Tier 1 engines with less than 50 HP to $5,195 per
engine for Tier 3 engines with 600 to 750 HP ($1998).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Office of Mobile Sources, Certification Division,
"Regulatory Impact Analysis and Regulatory Support Document, Control of Air Pollution;
Determination of Significance for Nonroad Sources and Emission Standards for New Nonroad
Compression-Ignition Engines at or Above 37 Kilowatts (50 Horsepower)," FINAL, Ann Arbor, Ml.
May 1994.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of Mobile
Sources, "Final Regulatory Impact Analysis: Control of Emissions from Nonroad Diesel Engines,"
EPA420-R-98-016, August 1998.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-401
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Diesel Vehicles
Control Measure Name: Final Compression-Ignition (C-l) Engine Standards
Rule Name: Final Compression-Ignition (C-l) Engine Standards
Pechan Measure Code: CI2020	POD: N/A
Application: This control measure represents the application of EPA's Federal Tier 1/Tier2/Tier 3 C-
I standards to diesel equipment to model implementation of these standards for 2020.
This control measure applies to non-road diesel vehicles, including railroad equipment.
Affected SCC:
2270001000 Off-highway Vehicle Diesel
2270002000 Off-highway Vehicle Diesel
2270003000 Off-highway Vehicle Diesel
2270004000 Off-highway Vehicle Diesel
2270005000 Off-highway Vehicle Diesel
2270006000 Off-highway Vehicle Diesel
2270007000 Off-highway Vehicle Diesel
2270008000 Off-highway Vehicle Diesel
2285002015 Railroad Equipment; Diesel;
Recreational Equipment
Construction and Mining Equipment
Industrial Equipment
Lawn and Garden Equipment
Agricultural Equipment
Commercial Equipment
Logging Equipment
Airport Ground Support Equipment
Railway Maintenance
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (37-66%); PM10
(37-66%); NOx (28-64%); VOC (49-75%); CO (28-64%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the final nonroad C-l standards, an estimate was made of the
number of affected engines by horsepower range and by Tier type (i.e., Tier 1, Tier 2,
or Tier 3) for each implementation year (Pechan, 2003). Near-term costs per engine
by horsepower range and Tier type, obtained from EPA 1994 and EPA 1998, were
then applied to the corresponding number of affected engines and summed to obtain
the total cost for this standard. The number of affected engines was determined by
subtracting out growth in engines, and using turnover data compiled from EPA's
NONROAD 2002 model.
All costs are in 1998 dollars.
Cost Effectiveness: The total cost of this control measure varies by equipment category and Tier
from $56 per engine for Tier 1 engines with less than 50 HP to $5,195 per
engine for Tier 3 engines with 600 to 750 HP ($1998).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Office of Mobile Sources, Certification Division,
"Regulatory Impact Analysis and Regulatory Support Document, Control of Air Pollution;
Determination of Significance for Nonroad Sources and Emission Standards for New Nonroad
Compression-Ignition Engines at or Above 37 Kilowatts (50 Horsepower)," FINAL, Ann Arbor, Ml.
May 1994.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of Mobile
Sources, "Final Regulatory Impact Analysis: Control of Emissions from Nonroad Diesel Engines,"
EPA420-R-98-016, August 1998.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-403
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Diesel Vehicles
Control Measure Name: Final Compression-Ignition (C-l) Engine Standards
Rule Name: Final Compression-Ignition (C-l) Engine Standards
Pechan Measure Code: CI2030	POD: N/A
Application: This control measure represents the application of EPA's Federal Tier 1/Tier2/Tier 3 C-
I standards to diesel equipment to model implementation of these standards for 2030.
This control measure applies to non-road diesel vehicles, including railroad equipment.
Affected SCC:
2270001000 Off-highway Vehicle Diesel
2270002000 Off-highway Vehicle Diesel
2270003000 Off-highway Vehicle Diesel
2270004000 Off-highway Vehicle Diesel
2270005000 Off-highway Vehicle Diesel
2270006000 Off-highway Vehicle Diesel
2270007000 Off-highway Vehicle Diesel
2270008000 Off-highway Vehicle Diesel
2285002015 Railroad Equipment; Diesel;
Recreational Equipment
Construction and Mining Equipment
Industrial Equipment
Lawn and Garden Equipment
Agricultural Equipment
Commercial Equipment
Logging Equipment
Airport Ground Support Equipment
Railway Maintenance
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (37-66%); PM10
(37-66%); NOx (41-66%); VOC (65-79%); CO (38-66%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the final nonroad C-l standards, an estimate was made of the
number of affected engines by horsepower range and by Tier type (i.e., Tier 1, Tier 2,
or Tier 3) for each implementation year (Pechan, 2003). Near-term costs per engine
by horsepower range and Tier type, obtained from EPA 1994 and EPA 1998, were
then applied to the corresponding number of affected engines and summed to obtain
the total cost for this standard. The number of affected engines was determined by
subtracting out growth in engines, and using turnover data compiled from EPA's
NONROAD 2002 model.
All costs are in 1998 dollars.
Cost Effectiveness: The total cost of this control measure varies by equipment category and Tier
from $56 per engine for Tier 1 engines with less than 50 HP to $5,195 per
engine for Tier 3 engines with 600 to 750 HP ($1998).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Office of Mobile Sources, Certification Division,
"Regulatory Impact Analysis and Regulatory Support Document, Control of Air Pollution;
Determination of Significance for Nonroad Sources and Emission Standards for New Nonroad
Compression-Ignition Engines at or Above 37 Kilowatts (50 Horsepower)," FINAL, Ann Arbor, Ml.
May 1994.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of Mobile
Sources, "Final Regulatory Impact Analysis: Control of Emissions from Nonroad Diesel Engines,"
EPA420-R-98-016, August 1998.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-405
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Gasoline Vehicles
Control Measure Name: Large Spark-Ignition (S-l) Engine Standards
Rule Name: Large Spark-Ignition (S-l) Engine Standards
Pechan Measure Code: SI2010	POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for large S-
I engines greater than 25 horsepower for implementation year 2010. These engines
include 2-stroke gasoline, 4-stroke gasoline, liquified petroleum gasoline (LPG), and
compressed natural gas (CNG).
Affected SCC:
2260001060 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Specialty
Vehicles/Carts
2260006000 Off-highway Vehicle Gasoline, 2-Stroke; Commercial Equipment
2265001060 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; Specialty
Vehicles/Carts
2265002000 Off-highway Vehicle Gasoline, 4-Stroke; Construction and Mining Equipment
2265004000 Off-highway Vehicle Gasoline, 4-Stroke; Lawn and Garden Equipment
2265005000 Off-highway Vehicle Gasoline, 4-Stroke; Agricultural Equipment
2265006000 Off-highway Vehicle Gasoline, 4-Stroke; Commercial Equipment
2265008000 Off-highway Vehicle Gasoline, 4-Stroke; Airport Ground Support Equipment
2267001060 Off-highway Vehicle LPG; Recreational Equipment; Specialty Vehicles/Carts
2267002000 Off-highway Vehicle LPG; Construction and Mining Equipment
2267003000 Off-highway Vehicle LPG; Industrial Equipment
2267004000 Off-highway Vehicle LPG; Lawn and Garden Equipment
2267005000 Off-highway Vehicle LPG; Agricultural Equipment
2267006000 Off-highway Vehicle LPG; Commercial Equipment
2267008000 Off-highway Vehicle LPG; Airport Ground Support Equipment
2268002000 Off-highway Vehicle CNG; Construction and Mining Equipment
2268005000 Off-highway Vehicle CNG; Agricultural Equipment
2268006000 Off-highway Vehicle CNG; Commercial Equipment
2285004015 Railroad Equipment; Gasoline, 4-Stroke; Railway Maintenance
2285006015 Railroad Equipment; LPG; Railway Maintenance
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (lncrease-7%);
PM10 (lncrease-7%); NOx (lncrease-77%); VOC (1-78%); CO (1-75%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad large S-l standards, an estimate was made of the
number of affected engines by Phase for each implementation year (Pechan, 2003).
Near-term costs per engine by Phase, obtained from EPA 2002, were then applied to
the corresponding number of affected engines and summed to obtain the total cost
for this standard. The number of affected engines was determined by subtracting out
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
growth in engines, and using turnover data compiled from EPA's NONROAD 2002
model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of S-l engines varies by Phase, technology type and equipment
category from $550 to $847 per engine ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Gasoline Vehicles
Control Measure Name: Large Spark-Ignition (S-l) Engine Standards
Rule Name: Large Spark-Ignition (S-l) Engine Standards
Pechan Measure Code: SI2015	POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for large S-
I engines greater than 25 horsepower for implementation year 2015. These engines
include 2-stroke gasoline, 4-stroke gasoline, liquified petroleum gasoline (LPG), and
compressed natural gas (CNG).
Affected SCC:
2260001060 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Specialty
Vehicles/Carts
2260006000 Off-highway Vehicle Gasoline, 2-Stroke; Commercial Equipment
2265001060 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; Specialty
Vehicles/Carts
2265002000 Off-highway Vehicle Gasoline, 4-Stroke; Construction and Mining Equipment
2265004000 Off-highway Vehicle Gasoline, 4-Stroke; Lawn and Garden Equipment
2265005000 Off-highway Vehicle Gasoline, 4-Stroke; Agricultural Equipment
2265006000 Off-highway Vehicle Gasoline, 4-Stroke; Commercial Equipment
2265008000 Off-highway Vehicle Gasoline, 4-Stroke; Airport Ground Support Equipment
2267001060 Off-highway Vehicle LPG; Recreational Equipment; Specialty Vehicles/Carts
2267002000 Off-highway Vehicle LPG; Construction and Mining Equipment
2267003000 Off-highway Vehicle LPG; Industrial Equipment
2267004000 Off-highway Vehicle LPG; Lawn and Garden Equipment
2267005000 Off-highway Vehicle LPG; Agricultural Equipment
2267006000 Off-highway Vehicle LPG; Commercial Equipment
2267008000 Off-highway Vehicle LPG; Airport Ground Support Equipment
2268002000 Off-highway Vehicle CNG; Construction and Mining Equipment
2268005000 Off-highway Vehicle CNG; Agricultural Equipment
2268006000 Off-highway Vehicle CNG; Commercial Equipment
2285004015 Railroad Equipment; Gasoline, 4-Stroke; Railway Maintenance
2285006015 Railroad Equipment; LPG; Railway Maintenance
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (lncrease-7%);
PM10 (lncrease-7%); NOx (lncrease-91%); VOC (1-93%); CO (1-87%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad large S-l standards, an estimate was made of the
number of affected engines by Phase for each implementation year (Pechan, 2003).
Near-term costs per engine by Phase, obtained from EPA 2002, were then applied to
the corresponding number of affected engines and summed to obtain the total cost
for this standard. The number of affected engines was determined by subtracting out
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
growth in engines, and using turnover data compiled from EPA's NONROAD 2002
model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of S-l engines varies by Phase, technology type and equipment
category from $550 to $847 per engine ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Gasoline Vehicles
Control Measure Name: Large Spark-Ignition (S-l) Engine Standards
Rule Name: Large Spark-Ignition (S-l) Engine Standards
Pechan Measure Code: SI2020	POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for large S-
I engines greater than 25 horsepower for implementation year 2020. These engines
include 2-stroke gasoline, 4-stroke gasoline, liquified petroleum gasoline (LPG), and
compressed natural gas (CNG).
Affected SCC:
2260001060 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Specialty
Vehicles/Carts
2260006000 Off-highway Vehicle Gasoline, 2-Stroke; Commercial Equipment
2265001060 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; Specialty
Vehicles/Carts
2265002000 Off-highway Vehicle Gasoline, 4-Stroke; Construction and Mining Equipment
2265004000 Off-highway Vehicle Gasoline, 4-Stroke; Lawn and Garden Equipment
2265005000 Off-highway Vehicle Gasoline, 4-Stroke; Agricultural Equipment
2265006000 Off-highway Vehicle Gasoline, 4-Stroke; Commercial Equipment
2265008000 Off-highway Vehicle Gasoline, 4-Stroke; Airport Ground Support Equipment
2267001060 Off-highway Vehicle LPG; Recreational Equipment; Specialty Vehicles/Carts
2267002000 Off-highway Vehicle LPG; Construction and Mining Equipment
2267003000 Off-highway Vehicle LPG; Industrial Equipment
2267004000 Off-highway Vehicle LPG; Lawn and Garden Equipment
2267005000 Off-highway Vehicle LPG; Agricultural Equipment
2267006000 Off-highway Vehicle LPG; Commercial Equipment
2267008000 Off-highway Vehicle LPG; Airport Ground Support Equipment
2268002000 Off-highway Vehicle CNG; Construction and Mining Equipment
2268005000 Off-highway Vehicle CNG; Agricultural Equipment
2268006000 Off-highway Vehicle CNG; Commercial Equipment
2285004015 Railroad Equipment; Gasoline, 4-Stroke; Railway Maintenance
2285006015 Railroad Equipment; LPG; Railway Maintenance
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (lncrease-6%);
PM10 (lncrease-6%); NOx (lncrease-93%); VOC (1-95%); CO (1-90%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad large S-l standards, an estimate was made of the
number of affected engines by Phase for each implementation year (Pechan, 2003).
Near-term costs per engine by Phase, obtained from EPA 2002, were then applied to
the corresponding number of affected engines and summed to obtain the total cost
for this standard. The number of affected engines was determined by subtracting out
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
growth in engines, and using turnover data compiled from EPA's NONROAD 2002
model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of S-l engines varies by Phase, technology type and equipment
category from $550 to $847 per engine ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Gasoline Vehicles
Control Measure Name: Large Spark-Ignition (S-l) Engine Standards
Rule Name: Large Spark-Ignition (S-l) Engine Standards
Pechan Measure Code: SI2030	POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for large S-
I engines greater than 25 horsepower for implementation year 2030. These engines
include 2-stroke gasoline, 4-stroke gasoline, liquified petroleum gasoline (LPG), and
compressed natural gas (CNG).
Affected SCC:
2260001060 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Specialty
Vehicles/Carts
2260006000 Off-highway Vehicle Gasoline, 2-Stroke; Commercial Equipment
2265001060 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; Specialty
Vehicles/Carts
2265002000 Off-highway Vehicle Gasoline, 4-Stroke; Construction and Mining Equipment
2265004000 Off-highway Vehicle Gasoline, 4-Stroke; Lawn and Garden Equipment
2265005000 Off-highway Vehicle Gasoline, 4-Stroke; Agricultural Equipment
2265006000 Off-highway Vehicle Gasoline, 4-Stroke; Commercial Equipment
2265008000 Off-highway Vehicle Gasoline, 4-Stroke; Airport Ground Support Equipment
2267001060 Off-highway Vehicle LPG; Recreational Equipment; Specialty Vehicles/Carts
2267002000 Off-highway Vehicle LPG; Construction and Mining Equipment
2267003000 Off-highway Vehicle LPG; Industrial Equipment
2267004000 Off-highway Vehicle LPG; Lawn and Garden Equipment
2267005000 Off-highway Vehicle LPG; Agricultural Equipment
2267006000 Off-highway Vehicle LPG; Commercial Equipment
2267008000 Off-highway Vehicle LPG; Airport Ground Support Equipment
2268002000 Off-highway Vehicle CNG; Construction and Mining Equipment
2268005000 Off-highway Vehicle CNG; Agricultural Equipment
2268006000 Off-highway Vehicle CNG; Commercial Equipment
2285004015 Railroad Equipment; Gasoline, 4-Stroke; Railway Maintenance
2285006015 Railroad Equipment; LPG; Railway Maintenance
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (0-6%); PM10 (0-
6%); NOx (lncrease-93%); VOC (1-90%); CO (0-90%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad large S-l standards, an estimate was made of the
number of affected engines by Phase for each implementation year (Pechan, 2003).
Near-term costs per engine by Phase, obtained from EPA 2002, were then applied to
the corresponding number of affected engines and summed to obtain the total cost
for this standard. The number of affected engines was determined by subtracting out
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AT-A-GLANCE TABLE FOR NONROAD SOURCES
growth in engines, and using turnover data compiled from EPA's NONROAD 2002
model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of S-l engines varies by Phase, technology type and equipment
category from $550 to $847 per engine ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Open Burning
Control Measure Name: Episodic Ban (Daily Only)
Rule Name: Not Applicable
Pechan Measure Code: N12201
POD: 122
Application: This is a generic control measure that would ban open burning on days where ozone
exceedances were predicted, reducing NOx emissions on those days. This measure
would not reduce the annual emissions.
Affected SCC:
2610000000 Open Burning
2610010000 Open Burning
2610020000 Open Burning
2610030000 Open Burning
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: Daily control efficiency is 100% from uncontrolled; Annual control efficiency is
0% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 80%
Penetration: 100%
Cost Basis: Because burning can simply be shifted to other acceptable periods, emission control
costs would be zero for regulations that shift the burning to days where ozone
exceedances are not predicted (Pechan, 1996). Although this periodic ban would
have no cost in the stationary source measures, a cost may be incurred in the area
source total due to labor shifts.
Cost Effectiveness: The cost effectiveness associated with this control is $0 per ton NOx reduced.
(1990)
Note: Since this is a daily control, no annual emission reductions are expected.
Comments:
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
Generally, the relatively low temperatures associated with open burning tend to suppress NOx
emissions. Because of the relatively low level of NOx emissions expected to result from open
burning, little attention has been paid to quantifying or controlling the NOx emissions from this
source. However, some jurisdictions control open burning by limiting the types of material that can
be burned, or, based on ambient conditions limiting the days on which materials can be burned.
Assuming full compliance with the regulation, daily NOx emission reductions from such a regulation
would be 100% (Pechan, 1996). However, annual emission reductions would not be expected
because there would likely be a shift in the timing of emissions, not a reduction in the total amount of
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AT-A-GLANCE TABLE FOR AREA SOURCES
annual NOx emitted.
References:
Pechan, 1994: E.H. Pechan & Associates, Inc., "Analysis of Incremental Emission Reductions and
Costs of VOC and NOx Control Measures," prepared for U.S. Environmental Protection Agency,
Ambient Standards Branch, Research Triangle Park, NC, September 1994.
Pechan, 1996: E.H. Pechan & Associates, "The Emission Reduction and Cost Analysis Model for
NOx (ECRAM-NOx)," Revised Documentation, prepared for U.S. Environmental Protection Agency,
Ozone Policy and Strategies Group, Research Triangle Park, NC, September 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Plastics Prod-Specific; (ABS) - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0632S, N06302	POD: 63
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to with acrylonitrile-butadiene-styrene plastic production
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30101849 Plastics Production, Acrylonitrile-Butadiene-Styrene (ABS) Resin
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.9. An equipment life of 15 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness values are $3,190 per ton NOx reduced from
uncontrolled and $1,430 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
It is assumed that the NOx source is a process heater or boiler.
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
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AT-A-GLANCE TABLE FOR POINT SOURCES
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Distillate Oil - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0251S, N02501	POD: 25
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) distillate oil-fired process
heaters and uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30600101 Process Heaters, Oil-fired **
30600103 Petroleum Industry, Process Heaters, Oil-fired
30600111 Process Heaters, Oil-fired (No. 6 Oil) >100 Million Btu Capacity
30790001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
39990001 Miscellaneous Manufacturing Industries, Distillate Oil (No. 2): Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 45% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $3,740 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Distillate Oil - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0252S, N02502	POD: 25
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) distillate-fired process heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30600101 Process Heaters, Oil-fired **
30600103 Petroleum Industry, Process Heaters, Oil-fired
30600111 Process Heaters, Oil-fired (No. 6 Oil) >100 Million Btu Capacity
30790001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
39990001 Miscellaneous Manufacturing Industries, Distillate Oil (No. 2): Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 48% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 7.1. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Cost Effectiveness: The default cost effectiveness values are $4,520 per ton NOx reduced from
uncontrolled and $19,540 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Distillate Oil - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0253S, N02503	POD: 25
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) distillate oil-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30600101 Process Heaters, Oil-fired **
30600103 Petroleum Industry, Process Heaters, Oil-fired
30600111 Process Heaters, Oil-fired (No. 6 Oil) >100 Million Btu Capacity
30790001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
39990001 Miscellaneous Manufacturing Industries, Distillate Oil (No. 2): Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
O&M cost breakdown.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity: $0.06 per kw-hr
Fuel (distillate oil): $5.54 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $3,180 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Distillate Oil - Small Sources
Control Measure Name: Ultra Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0254S, N02504	POD: 25
Application: This control is the use of ultra-low NOx burner (ULNB) add-on technologies to reduce
NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel
nitrogen and oxygen by lowering the temperature of one combustion zone and
reducing the amount of oxygen available in another. SCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) into molecular nitrogen (N2) and water vapor (H20).
This control applies to small (40 to 174 MMBtu/hr) distillate oil-fired process heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30600101 Process Heaters, Oil-fired **
30600103 Petroleum Industry, Process Heaters, Oil-fired
30600111 Process Heaters, Oil-fired (No. 6 Oil) >100 Million Btu Capacity
30790001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
39990001 Miscellaneous Manufacturing Industries, Distillate Oil (No. 2): Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 74% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 10 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $2,140 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Distillate Oil - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0255S, N02505	POD: 25
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) distillate oil-fired process heaters with NOx
emissions greater than 10 tons per year.
Affected SCC:
30190001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30600101 Process Heaters, Oil-fired **
30600103 Petroleum Industry, Process Heaters, Oil-fired
30600111 Process Heaters, Oil-fired (No. 6 Oil) >100 Million Btu Capacity
30790001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
39990001 Miscellaneous Manufacturing Industries, Distillate Oil (No. 2): Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
O&M cost breakdown.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity: $0.06 per kw-hr
Fuel (distillate oil): $5.54 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $9,230 per ton NOx
reduced from uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Distillate Oil - Small Sources
Control Measure Name: Low NOx Burner - Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0256S, N02506	POD: 25
Application: This control is the use of low NOx burner (LNB) technology and selective non catalytic
reduction (SNCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SNCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20).
This control is applicable to small (40 to 174 MMBtu/hr) distillate oil-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30600101 Process Heaters, Oil-fired **
30600103 Petroleum Industry, Process Heaters, Oil-fired
30600111 Process Heaters, Oil-fired (No. 6 Oil) >100 Million Btu Capacity
30790001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
39990001 Miscellaneous Manufacturing Industries, Distillate Oil (No. 2): Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 78% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.5. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (distillate oil): $5.54 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $3,620 per ton NOx reduced from
uncontrolled and $3,830 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Distillate Oil - Small Sources
Control Measure Name: Low NOx Burner (LNB) + Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0257S, N02507	POD: 25
Application: This control is the use of low NOx burner (LNB) technology and selective catalytic
reduction (SCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control is applicable to small (40 to 174 MMBtu/hr) distillate oil-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30600101 Process Heaters, Oil-fired **
30600103 Petroleum Industry, Process Heaters, Oil-fired
30600111 Process Heaters, Oil-fired (No. 6 Oil) >100 Million Btu Capacity
30790001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
39990001 Miscellaneous Manufacturing Industries, Distillate Oil (No. 2): Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 92% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.5. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (distillate oil): $5.54 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $9,120 per ton NOx reduced from
uncontrolled and $15,350 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
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AT-A-GLANCE TABLE FOR POINT SOURCES
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - LPG - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0481S, N04801	POD: 48
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) LPG-fired process heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600107 Process Heaters, LPG-fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 45% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 7 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $3,740 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
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AT-A-GLANCE TABLE FOR POINT SOURCES
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - LPG - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0482S, N04802	POD: 48
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) LPG-fired process heaters with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600107 Process Heaters, LPG-fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 48% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 7.1. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on distillate
oil and having a capacity of 69 MMBTU per hour. The cost percentage is applied to
heaters fired on LPG via technology transfer (Pechan, 1998). A capacity factor of
0.58 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The default cost effectiveness values are $4,250 per ton NOx reduced from
uncontrolled and $19,540 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - LPG - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0483S, N04803	POD: 48
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) LPG-fired process
heaters (SCC 30600107) with uncontrolled NOx emissions greater than 10 tons per
year.
Affected SCC:
30600107 Process Heaters, LPG-fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on distillate
oil and having a capacity of 69 MMBTU per hour. The cost percentage is applied to
heaters fired on LPG via technology transfer (Pechan, 1998). A capacity factor of
0.58 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (distillate oil): $5.54 per MMBTU
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AT-A-GLANCE TABLE FOR POINT SOURCES
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $3,180 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - LPG - Small Sources
Control Measure Name: Ultra Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0484S, N04804	POD: 48
Application: This control is the use of ultra-low NOx burner (ULNB) add-on technologies to reduce
NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel
nitrogen and oxygen by lowering the temperature of one combustion zone and
reducing the amount of oxygen available in another. SCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) into molecular nitrogen (N2) and water vapor (H20).
This control applies to small (40 to 174 MMBtu/hr) LPG-fired process heaters with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600107 Process Heaters, LPG-fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 74% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 10 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $2,140 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - LPG - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0485S, N04805	POD: 48
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) LPG process heaters with NOx emissions
greater than 10 tons per year.
Affected SCC:
30600107 Process Heaters, LPG-fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on distillate
oil and having a capacity of 69 MMBTU per hour. The cost percentage is applied to
heaters fired on LPG via technology transfer (Pechan, 1998). A capacity factor of
0.58 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (distillate oil): $5.54 per MMBTU
Ammonia: $0,125 per lb
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $9,230 per ton NOx
reduced from both uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA-453/R-93-034, Research Triangle Park, NC, September, 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - LPG - Small Sources
Control Measure Name: Low NOx Burner (LNB) + SNCR
Rule Name: Not Applicable
Pechan Measure Code: N0486S, N04806	POD: 48
Application: This control is the use of low NOx burner (LNB) technology and selective non-catalytic
reduction (SNCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SNCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20).
This control is applicable to small (40 to 174 MMBtu/hr) LPG-fired process heaters with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600107 Process Heaters, LPG-fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 78% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.5. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on distillate
oil and having a capacity of 69 MMBTU per hour. The cost percentage is applied to
heaters fired on LPG via technology transfer (Pechan, 1998). A capacity factor of
0.58 is used in estimating the O&M cost breakdown.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity: $0.06 per kw-hr
Fuel (distillate oil): $5.54 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $3,620 per ton NOx reduced from
uncontrolled and $3,830 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - LPG - Small Sources
Control Measure Name: Low NOx Burner (LNB) + Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0487S, N04807	POD: 48
Application: This control is the use of low NOx burner (LNB) technology and selective catalytic
reduction (SCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control is applicable to small (40 to 174 MMBtu/hr) LPG-fired process heaters with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600107 Process Heaters, LPG-fired
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 92% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.5. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 48% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour, and distillate oil as fuel. The cost percentage is
applied to heaters fired on LPG via technology transfer (Pechan, 1998). A capacity
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AT-A-GLANCE TABLE FOR POINT SOURCES
factor of 0.58 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (distillate oil): $5.54 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $9,120 per ton NOx reduced from
uncontrolled and $15,350 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Natural Gas - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0271S, N02701	POD: 27
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) natural gas-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190003 Fuel Fired Equipment, Natural Gas: Process Heaters
30390003 Primary Metal Production, Fuel Fired Equipment, Natural Gas: Process Heaters
30490003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30600102 Process Heaters, Gas-fired **
30600104	Petroleum Industry, Process Heaters, Gas-fired
30600105	Process Heaters, Natural Gas-fired
30790003 Pulp, Paper & Wood Products, Fuel Fired Equipment, Natural Gas-Process Heaters
30890003 Fuel Fired Equipment, Natural Gas: Process Heaters
31000404 Oil and Gas Production, Process Heaters, Natural Gas
31000414 Process Heaters, Natural Gas: Steam Generators
39990003 Miscellaneous Manufacturing Industries, Natural Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1993). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
7.3. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
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AT-A-GLANCE TABLE FOR POINT SOURCES
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
O&M Cost Components: The maintenance cost is estimated as a flat percentage
(2.75%) of the total capital costs (see pages 6-4 and 6-5 of the ACT document).
Impacts on operational costs are considered minimal, according to the ACT
document; therefore, O&M costs are a function of the maintenance cost only.
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $2,200 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Natural Gas - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0272S, N02702	POD: 27
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) natural gas-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190003 Fuel Fired Equipment, Natural Gas: Process Heaters
30390003 Primary Metal Production, Fuel Fired Equipment, Natural Gas: Process Heaters
30490003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30600102 Process Heaters, Gas-fired **
30600104	Petroleum Industry, Process Heaters, Gas-fired
30600105	Process Heaters, Natural Gas-fired
30790003 Pulp, Paper & Wood Products, Fuel Fired Equipment, Natural Gas-Process Heaters
30890003 Fuel Fired Equipment, Natural Gas: Process Heaters
31000404 Oil and Gas Production, Process Heaters, Natural Gas
31000414 Process Heaters, Natural Gas: Steam Generators
39990003 Miscellaneous Manufacturing Industries, Natural Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.9. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
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AT-A-GLANCE TABLE FOR POINT SOURCES
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-3 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 77 MMBTU per hour. A capacity factor of 0.5 is used in estimating the
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Cost Effectiveness: The default cost effectiveness values are $3,190 per ton NOx reduced from
uncontrolled and $15,580 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Natural Gas - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0273S, N02703	POD: 27
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) natural gas-fired
process heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190003 Fuel Fired Equipment, Natural Gas: Process Heaters
30390003 Primary Metal Production, Fuel Fired Equipment, Natural Gas: Process Heaters
30490003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30600102 Process Heaters, Gas-fired **
30600104	Petroleum Industry, Process Heaters, Gas-fired
30600105	Process Heaters, Natural Gas-fired
30790003 Pulp, Paper & Wood Products, Fuel Fired Equipment, Natural Gas-Process Heaters
30890003 Fuel Fired Equipment, Natural Gas: Process Heaters
31000404 Oil and Gas Production, Process Heaters, Natural Gas
31000414 Process Heaters, Natural Gas: Steam Generators
39990003 Miscellaneous Manufacturing Industries, Natural Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
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AT-A-GLANCE TABLE FOR POINT SOURCES
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-3 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 77 MMBTU per hour. A capacity factor of 0.5 is used in estimating the
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (natural gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $2,850 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
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AT-A-GLANCE TABLE FOR POINT SOURCES
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Natural Gas - Small Sources
Control Measure Name: Ultra Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0274S, N02704	POD: 27
Application: This control is the use of ultra-low NOx burner (ULNB) add-on technologies to reduce
NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel
nitrogen and oxygen by lowering the temperature of one combustion zone and
reducing the amount of oxygen available in another. SCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) into molecular nitrogen (N2) and water vapor (H20).
This control applies to small (40 to 174 MMBtu/hr) natural gas-fired process heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190003 Fuel Fired Equipment, Natural Gas: Process Heaters
30390003 Primary Metal Production, Fuel Fired Equipment, Natural Gas: Process Heaters
30490003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30600102 Process Heaters, Gas-fired **
30600104	Petroleum Industry, Process Heaters, Gas-fired
30600105	Process Heaters, Natural Gas-fired
30790003 Pulp, Paper & Wood Products, Fuel Fired Equipment, Natural Gas-Process Heaters
30890003 Fuel Fired Equipment, Natural Gas: Process Heaters
31000404 Oil and Gas Production, Process Heaters, Natural Gas
31000414 Process Heaters, Natural Gas: Steam Generators
39990003 Miscellaneous Manufacturing Industries, Natural Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 10 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
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AT-A-GLANCE TABLE FOR POINT SOURCES
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $1,500 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Natural Gas - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0275S, N02705	POD: 27
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) natural gas fired process heaters with NOx
emissions greater than 10 tons per year.
Affected SCC:
30190003 Fuel Fired Equipment, Natural Gas: Process Heaters
30390003 Primary Metal Production, Fuel Fired Equipment, Natural Gas: Process Heaters
30490003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30600102 Process Heaters, Gas-fired **
30600104	Petroleum Industry, Process Heaters, Gas-fired
30600105	Process Heaters, Natural Gas-fired
30790003 Pulp, Paper & Wood Products, Fuel Fired Equipment, Natural Gas-Process Heaters
30890003 Fuel Fired Equipment, Natural Gas: Process Heaters
31000404 Oil and Gas Production, Process Heaters, Natural Gas
31000414 Process Heaters, Natural Gas: Steam Generators
39990003 Miscellaneous Manufacturing Industries, Natural Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
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AT-A-GLANCE TABLE FOR POINT SOURCES
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-3 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 77 MMBTU per hour. A capacity factor of 0.5 is used in estimating the
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (natural gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $12,040 per ton NOx
reduced from both uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Natural Gas - Small Sources
Control Measure Name: Low NOx Burner (LNB) + SNCR
Rule Name: Not Applicable
Pechan Measure Code: N0276S, N02706	POD: 27
Application: This control is the use of low NOx burner (LNB) technology and selective non-catalytic
reduction (SNCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SNCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20).
This control is applicable to small (40 to 174 MMBtu/hr) natural gas-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190003 Fuel Fired Equipment, Natural Gas: Process Heaters
30390003 Primary Metal Production, Fuel Fired Equipment, Natural Gas: Process Heaters
30490003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30600102 Process Heaters, Gas-fired **
30600104	Petroleum Industry, Process Heaters, Gas-fired
30600105	Process Heaters, Natural Gas-fired
30790003 Pulp, Paper & Wood Products, Fuel Fired Equipment, Natural Gas-Process Heaters
30890003 Fuel Fired Equipment, Natural Gas: Process Heaters
31000404 Oil and Gas Production, Process Heaters, Natural Gas
31000414 Process Heaters, Natural Gas: Steam Generators
39990003 Miscellaneous Manufacturing Industries, Natural Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.7. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
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AT-A-GLANCE TABLE FOR POINT SOURCES
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-3 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 77 MMBTU per hour. A capacity factor of 0.5 is used in estimating the
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (natural gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $3,520 per ton NOx reduced from
uncontrolled and $6,600 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
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AT-A-GLANCE TABLE FOR POINT SOURCES
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Natural Gas - Small Sources
Control Measure Name: Low NOx Burner (LNB) + Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0277S, N02707	POD: 27
Application: This control is the use of low NOx burner (LNB) technology and selective catalytic
reduction (SCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control is applicable to small (40 to 174 MMBtu/hr) natural gas-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190003 Fuel Fired Equipment, Natural Gas: Process Heaters
30390003 Primary Metal Production, Fuel Fired Equipment, Natural Gas: Process Heaters
30490003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30600102 Process Heaters, Gas-fired **
30600104	Petroleum Industry, Process Heaters, Gas-fired
30600105	Process Heaters, Natural Gas-fired
30790003 Pulp, Paper & Wood Products, Fuel Fired Equipment, Natural Gas-Process Heaters
30890003 Fuel Fired Equipment, Natural Gas: Process Heaters
31000404 Oil and Gas Production, Process Heaters, Natural Gas
31000414 Process Heaters, Natural Gas: Steam Generators
39990003 Miscellaneous Manufacturing Industries, Natural Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 88% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.8. A discount rate of 10 percent and a capacity factor of 65 percent
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AT-A-GLANCE TABLE FOR POINT SOURCES
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-3 and Ch. 6 of the ACT for Process Heaters. The breakdown
was obtained using the O&M costs for a mechanical draft process heater having a
capacity of 77 MMBTU per hour. A capacity factor of 0.5 is used in estimating the
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (natural gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $11,560 per ton NOx reduced from
uncontrolled and $27,910 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
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AT-A-GLANCE TABLE FOR POINT SOURCES
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Other Fuel - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0491S, N04901	POD: 49
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) other (miscellaneous) fuel-fired
process heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600199 Process Heaters, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 34% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 7.1. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on residual
fuel oil and having a capacity of 69 MMBTU per hour. The cost percentage is applied
to heaters fired on other fuel via technology transfer (Pechan, 1998). A capacity
factor of 0.58 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The default cost effectiveness value is $3,490 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Other Fuel - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0492S, N04902	POD: 49
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) un-classified fuel process
heaters (SCC 30600199) with uncontrolled NOx emissions greater than 10 tons per
year.
Affected SCC:
30600199 Process Heaters, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 37% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1993). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
7.3. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $2,520 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Other Fuel - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0493S, N04903	POD: 49
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) process heaters (fired
with fuels classified as other) with uncontrolled NOx emissions greater than 10 tons
per year. These sources are classified under SCC 30600199.
Affected SCC:
30600199 Process Heaters, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on residual
fuel oil and having a capacity of 69 MMBTU per hour. The cost percentage is applied
to heaters fired on other fuel via technology transfer (Pechan, 1998). A capacity
factor of 0.58 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Fuel (residual oil): $3.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $1,930 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Other Fuel - Small Sources
Control Measure Name: Ultra Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0494S, N04904	POD: 49
Application: This control is the use of ultra-low NOx burner (ULNB) add-on technologies to reduce
NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel
nitrogen and oxygen by lowering the temperature of one combustion zone and
reducing the amount of oxygen available in another. SCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) into molecular nitrogen (N2) and water vapor (H20).
This control applies to small (40 to 174 MMBtu/hr) other (miscellaneous) fuel-fired
process heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600199 Process Heaters, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 73% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 10 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $1,290 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Other Fuel - Small Sources
Control Measure Name: Low NOx Burner (LNB) + SNCR
Rule Name: Not Applicable
Pechan Measure Code: N0495S, N04905	POD: 49
Application: This control is the use of low NOx burner (LNB) technology and selective non-catalytic
reduction (SNCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SNCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20).
This control is applicable to small (40 to 174 MMBtu/hr) other (not classified) fuel-fired
process heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600199 Process Heaters, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.4. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on residual
fuel oil and having a capacity of 69 MMBTU per hour. The cost percentage is applied
to heaters fired on other fuel via technology transfer (Pechan, 1998). A capacity
factor of 0.58 is used in estimating the O&M cost breakdown.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity: $0.06 per kw-hr
Fuel (residual oil): $3.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $2,320 per ton NOx reduced from
uncontrolled and $2,080 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Other Fuel - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0496S, N04906	POD: 49
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) process heaters (SCC 30600199) with NOx
emissions greater than 10 tons per year.
Affected SCC:
30600199 Process Heaters, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on residual
fuel oil and having a capacity of 69 MMBTU per hour. The cost percentage is applied
to heaters fired on other fuel via technology transfer (Pechan, 1998). A capacity
factor of 0.58 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (residual oil): $3.00 per MMBTU
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AT-A-GLANCE TABLE FOR POINT SOURCES
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $5,350 per ton NOx
reduced from both uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Other Fuel - Small Sources
Control Measure Name: Low NOx Burner (LNB) + Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0497S, N04907	POD: 49
Application: This control is the use of low NOx burner (LNB) technology and selective catalytic
reduction (SCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control is applicable to small (40 to 174 MMBtu/hr) other (not classified) fuel-fired
process heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30600199 Process Heaters, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 91% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.6. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on residual
fuel and having a capacity of 69 MMBTU per hour. The cost percentage is applied to
heaters fired on other fuel via technology transfer (Pechan, 1998). A capacity factor
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AT-A-GLANCE TABLE FOR POINT SOURCES
of 0.58 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (residual oil): $3.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $5,420 per ton NOx reduced from
uncontrolled and $7,680 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Cost equations for NOx control of process heaters firing other fuel are based on an analysis of
EPA's NOx State Implementation Plan (SIP) Call (Pechan-Avanti, 1998). Applicable control
technologies and costs are assumed to be similar to process heaters firing residual oil. LNBs are
designed to "stage" combustion so that two combustion zones are created, one fuel-rich combustion
and one at a lower temperature. Staging techniques are usually used by LNB to supply excess air to
cool the combustion process or to reduce available oxygen in the flame zone. Staged-air LNB's
create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone.
Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
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AT-A-GLANCE TABLE FOR POINT SOURCES
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Process Gas - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0471S, N04701	POD: 47
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) process gas-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190004 Fuel Fired Equipment, Process Gas: Process Heaters
30600106 Process Heaters, Process Gas-fired
31000405 Process Heaters, Process Gas
31000415 Process Heaters, Process Gas: Steam Generators
39990004 Miscellaneous Manufacturing Industries, Process Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1993). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
7.3. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $2,200 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Process Gas - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0472S, N04702	POD: 47
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) process gas-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190004 Fuel Fired Equipment, Process Gas: Process Heaters
30600106 Process Heaters, Process Gas-fired
31000405 Process Heaters, Process Gas
31000415 Process Heaters, Process Gas: Steam Generators
39990004 Miscellaneous Manufacturing Industries, Process Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.9. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-3 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on natural
gas and having a capacity of 77 MMBTU per hour. The cost percentage is applied to
heaters fired on process gas via technology transfer (Pechan, 1998). A capacity
factor of 0.5 is used in estimating the O&M cost breakdown.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity: $0.06 per kw-hr
Cost Effectiveness: The default cost effectiveness values are $3,190 per ton NOx reduced from
uncontrolled and $15,580 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Process Gas - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0473S, N04703	POD: 47
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) process gas fired
process heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190004 Fuel Fired Equipment, Process Gas: Process Heaters
30600106 Process Heaters, Process Gas-fired
31000405 Process Heaters, Process Gas
31000415 Process Heaters, Process Gas: Steam Generators
39990004 Miscellaneous Manufacturing Industries, Process Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-3 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on natural
gas and having a capacity of 77 MMBTU per hour. The cost percentage is applied to
heaters fired on process gas via technology transfer (Pechan, 1998). A capacity
factor of 0.5 is used in estimating the O&M cost breakdown.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity: $0.06 per kw-hr
Fuel (natural gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $2,850 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Process Gas - Small Sources
Control Measure Name: Ultra Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0474S, N04704	POD: 47
Application: This control is the use of ultra-low NOx burner (ULNB) add-on technologies to reduce
NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel
nitrogen and oxygen by lowering the temperature of one combustion zone and
reducing the amount of oxygen available in another. SCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) into molecular nitrogen (N2) and water vapor (H20).
This control applies to small (40 to 174 MMBtu/hr) process gas-fired process heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190004 Fuel Fired Equipment, Process Gas: Process Heaters
30490004 Fuel Fired Equipment, Process Gas: Process Heaters
30600106 Process Heaters, Process Gas-fired
31000405 Process Heaters, Process Gas
31000415 Process Heaters, Process Gas: Steam Generators
39990004 Miscellaneous Manufacturing Industries, Process Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 10 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $1,500 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Process Gas - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0475S, N04705	POD: 47
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) process gas process heaters with NOx
emissions greater than 10 tons per year.
Affected SCC:
30190004 Fuel Fired Equipment, Process Gas: Process Heaters
30490004 Fuel Fired Equipment, Process Gas: Process Heaters
30600106 Process Heaters, Process Gas-fired
31000405 Process Heaters, Process Gas
31000415 Process Heaters, Process Gas: Steam Generators
39990004 Miscellaneous Manufacturing Industries, Process Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-3 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on natural
gas and having a capacity of 77 MMBTU per hour. The cost percentage is applied to
heaters fired on process gas via technology transfer (Pechan, 1998). A capacity
factor of 0.5 is used in estimating the O&M cost breakdown.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity: $0.06 per kw-hr
Fuel (natural gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $12,040 per ton NOx
reduced from both uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Process Gas - Small Sources
Control Measure Name: Low NOx Burner (LNB)+Selective Reduction SNCR
Rule Name: Not Applicable
Pechan Measure Code: N0476S, N04706	POD: 47
Application: This control is the use of low NOx burner (LNB) technology and selective non-catalytic
reduction (SNCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SNCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20).
This control is applicable to small (40 to 174 MMBtu/hr) process gas-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190004 Fuel Fired Equipment, Process Gas: Process Heaters
30490004 Fuel Fired Equipment, Process Gas: Process Heaters
30600106 Process Heaters, Process Gas-fired
31000405 Process Heaters, Process Gas
31000415 Process Heaters, Process Gas: Steam Generators
39990004 Miscellaneous Manufacturing Industries, Process Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.7. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-3 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater fired on natural
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AT-A-GLANCE TABLE FOR POINT SOURCES
gas and having a capacity of 77 MMBTU per hour. The cost percentage is applied to
heaters fired on process gas via technology transfer (Pechan, 1998). A capacity
factor of 0.5 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (natural gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $3,520 per ton NOx reduced from
uncontrolled and $6,600 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Process Gas - Small Sources
Control Measure Name: Low NOx Burner (LNB) + Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0477S, N04707	POD: 47
Application: This control is the use of low NOx burner (LNB) technology and selective catalytic
reduction (SCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control is applicable to small (40 to 174 MMBtu/hr) process gas-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190004 Fuel Fired Equipment, Process Gas: Process Heaters
30490004 Fuel Fired Equipment, Process Gas: Process Heaters
30600106 Process Heaters, Process Gas-fired
31000405 Process Heaters, Process Gas
31000415 Process Heaters, Process Gas: Steam Generators
39990004 Miscellaneous Manufacturing Industries, Process Gas: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 88% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.8. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
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AT-A-GLANCE TABLE FOR POINT SOURCES
information in Table 6-3 and Ch. 6 of the ACT for Process Heaters. The breakdown
was obtained using the O&M costs for a mechanical draft process heater having a
capacity of 77 MMBTU per hour fired on natural gas. The cost percentage is applied
to heaters fired on process gas via technology transfer (Pechan, 1998). A capacity
factor of 0.5 is used in estimating the O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (natural gas): $2.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $11,560 per ton NOx reduced from
uncontrolled and $27,910 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
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AT-A-GLANCE TABLE FOR POINT SOURCES
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Residual Oil - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0261S, N02601	POD: 26
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) residual oil-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190002 Fuel Fired Equipment, Residual Oil: Process Heaters
30590002 Fuel Fired Equipment, Residual Oil: Process Heaters
30790002 Fuel Fired Equipment, Residual Oil: Process Heaters
31000403 Process Heaters, Crude Oil
39990002 Miscellaneous Manufacturing Industries, Residual Oil: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 34% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emissions (Pechan, 1998).
Small source = less than 1 ton NOx emissions per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1993). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
7.1. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 10 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
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AT-A-GLANCE TABLE FOR POINT SOURCES
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Cost Effectiveness: The default cost effectiveness value is $3,490 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Residual Oil - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0262S, N02602	POD: 26
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (40 to 174 MMBtu/hr) residual oil-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190002 Fuel Fired Equipment, Residual Oil: Process Heaters
30590002 Fuel Fired Equipment, Residual Oil: Process Heaters
30790002 Fuel Fired Equipment, Residual Oil: Process Heaters
31000403 Process Heaters, Crude Oil
39990002 Miscellaneous Manufacturing Industries, Residual Oil: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 37% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1993). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
7.3. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $2,520 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Residual Oil - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0263S, N02603	POD: 26
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) residual oil-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190002 Fuel Fired Equipment, Residual Oil: Process Heaters
30590002 Fuel Fired Equipment, Residual Oil: Process Heaters
30790002 Fuel Fired Equipment, Residual Oil: Process Heaters
31000403 Process Heaters, Crude Oil
39990002 Miscellaneous Manufacturing Industries, Residual Oil: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 15 years
(EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
O&M cost breakdown.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity: $0.06 per kw-hr
Fuel (residual oil): $3.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness used in AirControlNET for both reductions from baseline
and reductions from RACT is $1,930 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
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AT-A-GLANCE TABLE FOR POINT SOURCES
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Residual Oil - Small Sources
Control Measure Name: Ultra Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0264S, N02604	POD: 26
Application: This control is the use of ultra-low NOx burner (ULNB) add-on technologies to reduce
NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel
nitrogen and oxygen by lowering the temperature of one combustion zone and
reducing the amount of oxygen available in another. SCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) into molecular nitrogen (N2) and water vapor (H20).
This control applies to small (40 to 174 MMBtu/hr) residual oil-fired process heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190002 Fuel Fired Equipment, Residual Oil: Process Heaters
30590002 Fuel Fired Equipment, Residual Oil: Process Heaters
30790002 Fuel Fired Equipment, Residual Oil: Process Heaters
31000403 Process Heaters, Crude Oil
39990002 Miscellaneous Manufacturing Industries, Residual Oil: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 73% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned along with a capital to annual costs ratio of 7.3. A discount
rate of 10 percent and a capacity factor of 65 percent are assumed, along with an
equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $1,290 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, NC, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Residual Oil - Small Sources
Control Measure Name: Low NOx Burner (LNB) + SCR
Rule Name: Not Applicable
Pechan Measure Code: N0265S, N02605	POD: 26
Application: This control is the use of low NOx burner (LNB) technology and selective non-catalytic
reduction (SNCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SNCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20).
This control is applicable to small (40 to 174 MMBtu/hr) residual-fired process heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190002 Fuel Fired Equipment, Residual Oil: Process Heaters
30590002 Fuel Fired Equipment, Residual Oil: Process Heaters
30790002 Fuel Fired Equipment, Residual Oil: Process Heaters
31000403 Process Heaters, Crude Oil
39990002 Miscellaneous Manufacturing Industries, Residual Oil: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.4. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
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AT-A-GLANCE TABLE FOR POINT SOURCES
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (residual oil): $3.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $2,300 per ton NOx reduced from
uncontrolled and $2,080 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and ammonia slip.
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative EPA, 1993: U.S. Environmental Protection Agency,
Emissions Standard Division, Office of Air Quality Planning and Standards, "Alternative Control
Techniques Document- NOx Emissions from Process Heaters," EPA,-453/R-93-034, Research
Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Residual Oil - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0266S, N02606	POD: 26
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) residual oil-fired process heaters with NOx
emissions greater than 10 tons per year.
Affected SCC:
30190002 Fuel Fired Equipment, Residual Oil: Process Heaters
30590002 Fuel Fired Equipment, Residual Oil: Process Heaters
30790002 Fuel Fired Equipment, Residual Oil: Process Heaters
31000403 Process Heaters, Crude Oil
39990002 Miscellaneous Manufacturing Industries, Residual Oil: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 15 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
O&M cost breakdown.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity: $0.06 per kw-hr
Fuel (residual oil): $3.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The cost effectiveness value used in AirControlNET is $5,350 per ton NOx
reduced from both uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters - Residual Oil - Small Sources
Control Measure Name: Low NOx Burner (LNB) + Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0267S, N02607	POD: 26
Application: This control is the use of low NOx burner (LNB) technology and selective catalytic
reduction (SCR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
This control is applicable to small (40 to 174 MMBtu/hr) residual oil-fired process
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30190002 Fuel Fired Equipment, Residual Oil: Process Heaters
30590002 Fuel Fired Equipment, Residual Oil: Process Heaters
30790002 Fuel Fired Equipment, Residual Oil: Process Heaters
31000403 Process Heaters, Crude Oil
39990002 Miscellaneous Manufacturing Industries, Residual Oil: Process Heaters
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 91% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = 40 to 174 MMBtu/hr
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1993). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.6. A discount rate of 10 percent and a capacity factor of 65 percent
are assumed, along with an equipment life of 15 years (EPA, 1993).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies greater than 26% and less than or equal to
55% (Pechan, 2001).
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
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AT-A-GLANCE TABLE FOR POINT SOURCES
information in Table 6-4 and Ch. 6 of the Process Heaters ACT. The breakdown was
obtained using the O&M costs for a mechanical draft process heater having a
capacity of 69 MMBTU per hour. A capacity factor of 0.58 is used in estimating the
O&M cost breakdown.
Electricity: $0.06 per kw-hr
Fuel (residual oil): $3.00 per MMBTU
Ammonia: $0,125 per lb
Cost Effectiveness: The default cost effectiveness values are $5,420 per ton NOx reduced from
uncontrolled and $7,680 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNB's create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNB's create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
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AT-A-GLANCE TABLE FOR POINT SOURCES
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Residential Natural Gas
Control Measure Name: Water Heater Replacement
Rule Name: Not Applicable
Pechan Measure Code: N10901	POD: 109
Application: This control would replace existing water heaters with new water heaters. New water
heaters would be required to emit less than or equal to 40 ng NOx per Joule heat
output.
This control applies to all natural gas burning water heaters classified under SCC
2104006000.
Affected SCC:
2104006000 Natural Gas, Total: All Combustor Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7% from uncontrolled
Equipment Life: 13 years
Rule Effectiveness: 100%
Penetration: 23%
Cost Basis: In 1994, EPA conducted an analysis of the emission reductions and costs for a
Federal Implementation Plan residential water heater rule for the Sacramento,
California ozone nonattainment area (EPA, 1995). This analysis found that a rule
based on an emission limit of 40 nanograms per joule (ng/j) of heat output for natural
gas heaters with a heat input rating less than 75,000 Btu/hr would not result in an
increase in the cost of natural gas water heaters. The cost-effectiveness of NOx
reductions resulting from low-NOx residential water heaters is, therefore, zero dollar-
per-ton of NOx removed.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $0 per ton NOx reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
EPA (1995) noted a life expectancy of both conventional and low-NOx units ranging from 10 to 15
years. Thus, rule penetration is based on an average water heater equipment life of 13 years
(Pechan, 1996).
References:
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Costs for the California Federal Implementation Plans for Attainment of
the Ozone National Ambient Air Quality Standard," Final Draft, February 1995.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Pechan, 1996: E.H. Pechan & Associates, "The Emission Reduction and Cost Analysis Model for
NOx (ECRAM-NOx)," Revised Documentation, prepared for U.S. Environmental Protection Agency,
Ozone Policy and Strategies Group, Research Triangle Park, NC, September 1996.
Pechan, 1997: E.H. Pechan & Associates, "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Residential Natural Gas
Control Measure Name: Water Heater + LNB Space Heaters
Rule Name: South Coast and Bay Area AQMD Limits
Pechan Measure Code: N10903	POD: 109
Application: The South Coast and Bay Area AQMDs set emission limits for water heaters and
space heaters. This control is based on the installation of low-NOx space heaters and
water heaters in commercial and institutional sources for the reduction of NOx
emissions.
The control applies to natural gas burning sources classified under SCC 2104006000.
Affected SCC:
2104006000 Natural Gas, Total: All Combustor Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7% from uncontrolled
Equipment Life: 20 years (space heaters)
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The 1997 South Coast AQMP estimates a cost savings for new commercial and
residential water heaters meeting a low-NOx standard. The cost savings is based on
capital costs associated with installation of energy efficient equipment existing
demand-side management programs, energy savings, associated emission
reductions, and the prevailing emission credit price (SCAQMD, 1996).
Costs for the space heaters are based on the low-NOx limits established for the
South Coast and Bay Area Air Quality Management Districts for space heaters of
0.009 lbs NOx per million Btu. The cost effectiveness estimate for the low-NOx
space heater regulation is $1,600 per ton NOx (STAPPA/ALAPCO, 1994). For this
analysis a 75% reduction in commercial space heater NOx emissions is assumed,
based on a 20-year equipment life (Pechan, 1997).
The water heater savings and LNB space heater costs are combined to achieve an
overall cost effectiveness of $1,230 per ton NOx reduced.
Cost Effectiveness: The cost effectiveness is $1,230 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 1997.
SCAQMD, 1996: South Coast Air Quality Management District, "1997 Air Quality Management Plan,
Appendix IV-A: Stationary and Mobile Source Control Measures," August 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Rich-Burn Stationary Reciprocating Internal Combustion Engines
Control Measure Name: Non-selective catalytic reduction
Rule Name: Not Applicable
Pechan Measure Code: N0215S, N02105	POD:
Application: NSCR is achieved by placing a catalyst in the exhaust stream of the engine. The
exhaust passes over the catalyst, usually a noble metal (platinum, rhodium or
palladium) which reduces the reactants to N2, C02 and H20 (NJDEP, 2003). Typical
exhaust temperatures for effective removal of NOx are 800-1200 degrees Fahrenheit.
An oxidation catalyst using additional air can be installed downstream of the NSCR
catalyst for additional CO and VOC control. This includes 4-cycle naturally aspirated
engines and some 4-cycle turbocharged engines. Engines operating with NSCR
require air/fuel control to maintain high reduction effectiveness.
Affected SCC:


20100102
lean and
rich
burn
20100202
lean and
rich
burn
20100702
lean and
rich
burn
20200102
lean and
rich
burn
20200104
lean and
rich
burn
20200202
lean and
rich
burn
20200204
lean and
rich
burn
20200253
rich burn
only)
20200301
lean and
rich
burn
20200401
lean and
rich
burn
20200402
lean and
rich
burn
20200403
lean and
rich
burn
20200501
lean and
rich
burn
20200902
lean and
rich
burn
20201001
lean and
rich
burn
20300101
lean and
rich
burn
20300201
lean and
rich
burn
20300204
lean and
rich
burn
20300301
lean and
rich
burn
large bore engine
large bore engine
large bore engine
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: »NOx: 90% from uncontrolled (Pechan, 2000)
•CO: 90% from uncontrolled (NJDEP, 2003)
•VOC: 50% from uncontrolled (NJDEP, 2003)
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Control costs are estimated using an "ozone season" cost per ton. The ozone season
runs from May 1 to September 30 (5 months). The total annualized cost is calculated
using the operating cost incurred during the 5 month ozone season. An interest rate
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AT-A-GLANCE TABLE FOR AREA SOURCES
of 7% was used to determine the capital recovery factor. Maintenance and overhead
costs were estimated using recommended methods from the EPA Office of Air
Quality Planning and Standards (OAQPS) Control Cost Manual. The maintenance
cost is the maintenance labor rate times the number of expected additional
maintenance hours per year (500). The overhead cost is 60 percent of the
maintenance labor value. The fuel penalty is based on an estimated one percent
decrease in natural gas use. Taxes, insurance, and administrative costs are
estimated to be 4 percent of the capital cost. The compliance test cost is $2,440,
which is the same value that was estimated in an EPA alternative control techniques
document (EPA, 1993).
Cost Effectiveness: The cost effectiveness is $342 per ton of NOx reduction (1990$). The cost
effectiveness is based on an annualized capital cost of $16,778 and an annual
operation and maintenance (O&M) cost of $155,217 averaged over three rich-
burn natural gas-fired RICE (2.000. 4,000, and 8,000 horsepower).
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
EPA, 1993: U.S. Environmental Protection Agency, "Alternative Control Techniques Document-
NOx Emissions from Stationary Reciprocating Internal Combustion Engines", EPA-453/R-93-032,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 1993.
NJDEP, 2003: "State of the Art (SOTA) Manual for Reciprocating Internal Combustion Engines",
State of New Jersey Department of Environmental Protection, Division of Air Quality, 2003.
Pechan, 2000: E.H. Pechan & Associates, Inc., "NOx Emissions Control Costs for Stationary
Reciprocating Internal Combustion Engines in the NOx SIP Call States", Revised Final Report,
August 11, 2000
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Rich-Burn Stationary Reciprocating Internal Combustion Engines
Control Measure Name: Non-selective catalytic reduction
Rule Name: Not Applicable
Pechan Measure Code: N2213	POD:
Application: NSCR is achieved by placing a catalyst in the exhaust stream of the engine. The
exhaust passes over the catalyst, usually a noble metal (platinum, rhodium or
palladium) which reduces the reactants to N2, C02 and H20 (NJDEP, 2003). Typical
exhaust temperatures for effective removal of NOx are 800-1200 degrees Fahrenheit.
An oxidation catalyst using additional air can be installed downstream of the NSCR
catalyst for additional CO and VOC control. This includes 4-cycle naturally aspirated
engines and some 4-cycle turbocharged engines. Engines operating with NSCR
require air/fuel control to maintain high reduction effectiveness.
Affected SCC:


20100102
lean and
rich
burn
20100202
lean and
rich
burn
20100702
lean and
rich
burn
20200102
lean and
rich
burn
20200104
lean and
rich
burn
20200202
lean and
rich
burn
20200204
lean and
rich
burn
20200253
rich burn
only)
20200301
lean and
rich
burn
20200401
lean and
rich
burn
20200402
lean and
rich
burn
20200403
lean and
rich
burn
20200501
lean and
rich
burn
20200902
lean and
rich
burn
20201001
lean and
rich
burn
20300101
lean and
rich
burn
20300201
lean and
rich
burn
20300204
lean and
rich
burn
20300301
lean and
rich
burn
large bore engine
large bore engine
large bore engine
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: »NOx: 90% from uncontrolled (Pechan, 2000)
•CO: 90% from uncontrolled (NJDEP, 2003)
•VOC: 50% from uncontrolled (NJDEP, 2003)
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Control costs are estimated using an "ozone season" cost per ton. The ozone season
runs from May 1 to September 30 (5 months). The total annualized cost is calculated
using the operating cost incurred during the 5 month ozone season. An interest rate
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AT-A-GLANCE TABLE FOR AREA SOURCES
of 7% was used to determine the capital recovery factor. Maintenance and overhead
costs were estimated using recommended methods from the EPA Office of Air
Quality Planning and Standards (OAQPS) Control Cost Manual. The maintenance
cost is the maintenance labor rate times the number of expected additional
maintenance hours per year (500). The overhead cost is 60 percent of the
maintenance labor value. The fuel penalty is based on an estimated one percent
decrease in natural gas use. Taxes, insurance, and administrative costs are
estimated to be 4 percent of the capital cost. The compliance test cost is $2,440,
which is the same value that was estimated in an EPA alternative control techniques
document (EPA, 1993).
Cost Effectiveness: The cost effectiveness is $342 per ton of NOx reduction (1990$). The cost
effectiveness is based on an annualized capital cost of $16,778 and an annual
operation and maintenance (O&M) cost of $155,217 averaged over three rich-
burn natural gas-fired RICE (2.000. 4,000, and 8,000 horsepower).
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
EPA, 1993: U.S. Environmental Protection Agency, "Alternative Control Techniques Document-
NOx Emissions from Stationary Reciprocating Internal Combustion Engines", EPA-453/R-93-032,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 1993.
NJDEP, 2003: "State of the Art (SOTA) Manual for Reciprocating Internal Combustion Engines",
State of New Jersey Department of Environmental Protection, Division of Air Quality, 2003.
Pechan, 2000: E.H. Pechan & Associates, Inc., "NOx Emissions Control Costs for Stationary
Reciprocating Internal Combustion Engines in the NOx SIP Call States", Revised Final Report,
August 11, 2000
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Rich-Burn Stationary Reciprocating Internal Combustion Engines (RICE)
Control Measure Name: Non-selective catalytic reduction (NSCR)
Rule Name: Not Applicable
Pechan Measure Code: N0465S, N04605	POD:
Application: NSCR is essentially the same as the catalytic reduction systems that are used in
automobile applications (ElIP, 2000). NSCR is achieved by placing a catalyst in the
exhaust stream of the engine. The exhaust passes over the catalyst, usually a noble
metal (platinum, rhodium or palladium) which reduces the reactants to N2, C02 and
H20 (NJDEP, 2003). Typical exhaust temperatures for effective removal of NOx are
800-1200 degrees Fahrenheit. An oxidation catalyst using additional air can be
installed downstream of the NSCR catalyst for additional CO and VOC control. This
includes 4-cycle naturally aspirated engines and some 4-cycle turbocharged engines.
Engines operating with NSCR require air/fuel control to maintain high reduction
effectiveness. Extremely tight control of the air to fuel ratio operating range is
accomplished with an electronic air to fuel ratio controller. NSCR is also referred to as
three-way catalyst because it simultaneously reduces NOx, CO, and HC to water,
C02, and N2.
Affected SCC:
20200301 Gasoline, Reciprocating
20200401	Industrial, Large Bore Engine, Diesel
20200402	Large Bore Engine, Dual Fuel (Oil/Gas)
20200403	Large Bore Engine, Cogeneration: Dual Fuel
20200902 Kerosene/Naphtha (Jet Fuel), Reciprocating
20201001 Liquefied Petroleum Gas (LPG), Propane: Reciprocating
20300301 Gasoline, Reciprocating
20301001 Liquefied Petroleum Gas (LPG), Propane: Reciprocating
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg




V*
V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: NOx: 90% from uncontrolled (Pechan, 2000)
CO: 90% from uncontrolled (NJDEP, 2003)
VOC: 50% from uncontrolled (NJDEP, 2003)
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Control costs are estimated using an "ozone season" cost per ton. The ozone
season runs from May 1 to September 30 (5 months). The total annualized cost is
calculated using the operating cost incurred during the 5 month ozone season. An
interest rate of 7% was used to determine the capital recovery factor. Maintenance
and overhead costs were estimated using recommended methods from the EPA
Office of Air Quality Planning and Standards (OAQPS) Control Cost Manual. The
maintenance cost is the maintenance labor rate times the number of expected
additional maintenance hours per year (500). The overhead cost is 60 percent of the
maintenance labor value. The fuel penalty is based on an estimated one percent
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AT-A-GLANCE TABLE FOR POINT SOURCES
decrease in natural gas use. Taxes, insurance, and administrative costs are
estimated to be 4 percent of the capital cost. The compliance test cost is $2,440,
which is the same value that was estimated in an EPA alternative control techniques
document (EPA, 1993).
Cost Effectiveness: The cost effectiveness is $342 per ton of NOx reduction (1990$). The cost
effectiveness is based on an annualized capital cost of $16,778 and an annual
operation and maintenance (O&M) cost of $155,217 averaged over three rich-
burn natural gas-fired RICE (2.000. 4,000, and 8,000 horsepower).
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
EIIP, 2000: "How to Incorporate the Effects of Air Pollution Control Device Efficiencies and
Malfunctions into Emission Inventory Estimates", Volume II, Chapter 12, Emission Inventory
Improvement Program, July 2000.
EPA, 1993: U.S. Environmental Protection Agency, "Alternative Control Techniques Document-
NOx Emissions from Stationary Reciprocating Internal Combustion Engines", EPA-453/R-93-032,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 1993.
NJDEP, 2003: "State of the Art (SOTA) Manual for Reciprocating Internal Combustion Engines",
State of New Jersey Department of Environmental Protection, Division of Air Quality, 2003.
Pechan, 2000: E.H. Pechan & Associates, Inc., "NOx Emissions Control Costs for Stationary
Reciprocating Internal Combustion Engines in the NOx SIP Call States", Revised Final Report,
August 11, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sand/Gravel; Dryer - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0772S, N07702	POD: 77
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) sand and gravel drying
processes with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30502508 Construction Sand & Gravel, Dryer (See 3-05-027-20 thru -24 Industrial Sand Dryers)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emissions (Pechan, 1998).
Small source = less than 1 ton NOx emissions per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1993). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
6.9. An equipment life of 15 years is assumed (EPA, 1993).
Cost Effectiveness: The default cost effectiveness values are $3,190 per ton NOx reduced from
uncontrolled and $1,430 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
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AT-A-GLANCE TABLE FOR POINT SOURCES
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Secondary Aluminum Production; Smelting Furnaces
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0701S, N07001	POD: 70
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to secondary aluminum production operations with smelting
furnaces (SCC 30400103) and uncontrolled NOx emissions greater than 10 tons per
year.
Affected SCC:
30400103 Secondary Metal Production, Aluminum, Smelting Furnace/Reverberatory
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The basis of the costs are model plant data contained in the Alternative Control
Techniques (ACT) (EPA, 1994). Capital, and annual cost information was obtained
from control-specific cost data. Some O&M costs were included. Missing O&M costs
were back calculated from annual costs (Pechan, 1998). From these determinations,
an average cost per ton values was assigned along with a capital cost to annual cost
ratio of 7.0. A discount rate of 7% was assumed for all sources. The equipment life
is 10 years.
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $570 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Solid Waste Disposal; Government; Other
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0891S, N08901	POD: 89
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to solid waste disposal operations (classified under SCC
50100506) with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
50100506 Other Incineration, Sludge
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 45% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Large source = emission levels greater than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness (for both small and large sources) used in
AirControlNET for both reductions from baseline and reductions from RACT is
$1,130 per ton NOx reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Radian Corporation, "Alternative Control
Techniques Document- NOx Emissions from Municipal Waste Combustion," EPA-600/R-94-208,
Research Triangle Park, NC, December 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Space Heaters - Distillate Oil - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0541S, N05401	POD: 54
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) distillate oil-fired space
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10500105 Space Heaters, Industrial, Distillate Oil
10500205 Commercial/Institutional, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emissions (Pechan, 1998).
Small source = less than 1 ton NOx emissions per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1994). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
5.5. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $1,180 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Space Heaters - Distillate Oil - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0542S, N05402	POD: 54
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) residual oil-fired process heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10500105 Space Heaters, Industrial, Distillate Oil
10500205 Commercial/Institutional, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $2,490 per ton NOx reduced from
uncontrolled and $1,090 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Space Heaters - Distillate Oil - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0543S, N05403	POD: 54
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) distillate oil-fired space heaters with NOx
emissions greater than 10 tons per year.
Affected SCC:
10500105 Space Heaters, Industrial, Distillate Oil
10500205 Commercial/Institutional, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,780 per ton NOx
reduced from uncontrolled and $3,570 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Space Heaters - Distillate Oil - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0544S, N05404	POD: 54
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) distillate oil-fired space
heaters with uncontrolled NOx emissions greater than 10 tons per year, classified
under SCCs 10500105 and 10500205.
Affected SCC:
10500105 Space Heaters, Industrial, Distillate Oil
10500205 Commercial/Institutional, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $4,640 per ton NOx
reduced from uncontrolled and $3,470 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
III-549
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Space Heaters - Natural Gas - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0551S, N05501	POD: 55
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) natural gas-fired space
heaters with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10500106 Space Heaters, Industrial, Natural Gas
10500206 Commercial/Institutional, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emissions (Pechan, 1998).
Small source = less than 1 ton NOx emissions per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1994). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
5.5. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $820 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
III-551
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Space Heaters - Natural Gas - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0552S, N05502	POD: 55
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) LPG-fired process heaters with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10500106 Space Heaters, Industrial, Natural Gas
10500206 Commercial/Institutional, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $2,560 per ton NOx reduced from
uncontrolled and $2,470 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
III-553
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Space Heaters - Natural Gas - Small Sources
Control Measure Name: Oxygen Trim + Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0553S, N05503	POD: 55
Application: This control is the use of OT + Wl to reduce NOx emissions.
This control applies to small (<1 ton NOx per OSD) natural gas-fired space heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
10500106 Space Heaters, Industrial, Natural Gas
10500206 Commercial/Institutional, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 65% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $680 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The
water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
III-555
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Space Heaters - Natural Gas - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0554S, N05504	POD: 55
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) natural gas fired space heaters with NOx
emissions greater than 10 tons per year.
Affected SCC:
10500106 Space Heaters, Industrial, Natural Gas
10500206 Commercial/Institutional, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,230 per ton NOx
reduced from uncontrolled and $2,860 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
III-557
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Space Heaters - Natural Gas - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0555S, N05505	POD: 55
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) natural gas fired space
heaters with uncontrolled NOx emissions greater than 10 tons per year, classified
under SCCs 10500106 and 10500206.
Affected SCC:
10500106 Space Heaters, Industrial, Natural Gas
10500206 Commercial/Institutional, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $3,870 per ton NOx
reduced from uncontrolled and $ 2,900 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Starch Manufacturing; Combined Operation - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0642S, N06402	POD: 64
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) starch manufacturing with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30201401 Starch Manufacturing, Combined Operations
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 6.9. An equipment life of 15 years was uncontrolled (EPA, 1994).
Cost Effectiveness: The default cost effectiveness values are $3,190 per ton NOx reduced from
uncontrolled and $1,430 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The NOx source is generally a natural gas-fired dryer. Therefore, applicable control technologies
are assumed to be LNB with FGR.
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
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AT-A-GLANCE TABLE FOR POINT SOURCES
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA,-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Steel Foundries; Heat Treating
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0711S, N07101	POD: 71
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to heat treating operations at steel foundries (SCC
30400704) with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30400704 Steel Foundries, Heat Treating Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1994). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
7.0. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 10 years (EPA, 1994).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $570 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Steel Production; Soaking Pits
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0682S, N06802	POD: 68
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to soaking pits at steel production operations with
uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30300911 Steel Manufacturing (See 3-03-015), Soaking Pits
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 7.0. An equipment life of 10 years was uncontrolled (EPA, 1994).
Cost Effectiveness: The default cost effectiveness values are $750 per ton NOx reduced from
uncontrolled and $250 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Soaking pits are a combustion source which can fire natural gas, oil or coal. Emissions of NOx are
similar to boilers emissions.
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Iron and Steel Mills," EPA-453/R-94-065, Research Triangle Park, NC, September 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfate Pulping - Recovery Furnaces - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0611S, N06101	POD: 61
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) recovery furnaces at sulfate
pulping operations with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30700104 Pulp, Paper & Wood, Sulfate Pulping, Recovery Furnace/Direct Contact Evaporator
30700110 Sulfate (Kraft) Pulping, Recovery Furnace/Indirect Contact Evaporator
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emissions (Pechan, 1998).
Small source = less than 1 ton NOx emissions per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1994). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
5.5. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $820 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
Cost equations for NOx control of sulfate pulping recovery furnaces are based on an analysis of
EPA's NOx State Implementation Plan (SIP) Call (Pechan, 1998) and STAPPA/ALAPCO's
Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options. Applicable control
technologies and costs are assumed to be similar to ICI boilers firing natural gas.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfate Pulping - Recovery Furnaces - Small Sources
Control Measure Name: Low NOx Burner + Flue Gas Recirculation
Rule Name: Not Applicable
Pechan Measure Code: N0612S, N06102	POD: 61
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation
(FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created from
reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton per OSD) residual oil-fired process heaters
with uncontrolled NOx emissions greater than 10 tons per year.
Affected SCC:
30700104 Pulp, Paper & Wood, Sulfate Pulping, Recovery Furnace/Direct Contact Evaporator
30700110 Sulfate (Kraft) Pulping, Recovery Furnace/Indirect Contact Evaporator
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 5.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness values are $2,560 per ton NOx reduced from
uncontrolled and $2,470 per ton NOx reduced from RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfate Pulping - Recovery Furnaces - Small Sources
Control Measure Name: Oxygen Trim + Water Injection
Rule Name: Not Applicable
Pechan Measure Code: N0613S, N06103	POD: 61
Application: This control is the use of OT + Wl to reduce NOx emissions.
This control applies to small (<1 ton NOx per OSD) recovery furnaces involved in
sulfate pulping operations with uncontrolled NOx emissions greater than 10 tons per
year.
Affected SCC:
30700104 Pulp, Paper & Wood, Sulfate Pulping, Recovery Furnace/Direct Contact Evaporator
30700110 Sulfate (Kraft) Pulping, Recovery Furnace/Indirect Contact Evaporator
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 65% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by power output (Pechan, 1998).
Small source = less than 1 ton NOx per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data in the Alternative Control Techniques (ACT) document (EPA, 1994). From
this analysis, default cost per ton values are assigned along with a capital to annual
costs ratio of 2.9. A discount rate of 7 percent and a capacity factor of 65 percent are
assumed, along with an equipment life of 10 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The default cost effectiveness value is $680 per ton NOx reduced from both
uncontrolled and RACT baselines (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The
water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfate Pulping - Recovery Furnaces - Small Sources
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N0614S, N06104	POD: 61
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR
controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR
utilizes a catalyst to increase the NOx removal efficiency, which allows the process to
occur at lower temperatures.
Applies to small (<1 ton NOx per OSD) recovery furnaces in sulfate pulping operations
with NOx emissions greater than 10 tons per year.
Affected SCC:
30700104 Pulp, Paper & Wood, Sulfate Pulping, Recovery Furnace/Direct Contact Evaporator
30700110 Sulfate (Kraft) Pulping, Recovery Furnace/Indirect Contact Evaporator
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned. A discount rate of 7 percent and a capacity factor of 65
percent are assumed, along with an equipment life of 20 years (EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $2,230 per ton NOx
reduced from uncontrolled and $2,860 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired,
combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx
reduction efficiency and the lower and broader temperature ranges. However, the decrease in
reaction temperature and increase in efficiency is accompanied by a significant increase in capital
and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous
ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with
the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002).
Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in
water.
Today, catalyst formulations include single component, multi-component, or active phase with a
support structure. Most catalyst formulations contain additional compounds or sup-ports, providing
thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include: reaction temperature range;
residence time available in the optimum temperature range; degree of mixing between the injected
reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected
reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop
across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfate Pulping - Recovery Furnaces - Small Sources
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N0615S, N06105	POD: 61
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls. SNCR controls are post-combustion control technologies based on
the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water
vapor (H20).
This control applies to small (<1 ton NOx emissions per OSD) sulfate pulping
operations with recovery furnaces and uncontrolled NOx emissions greater than 10
tons per year.
Affected SCC:
30700104 Pulp, Paper & Wood, Sulfate Pulping, Recovery Furnace/Direct Contact Evaporator
30700110 Sulfate (Kraft) Pulping, Recovery Furnace/Indirect Contact Evaporator
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emission levels (Pechan, 1998).
Small source = emission levels less than 1 ton per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). From this analysis, default cost per
ton values are assigned for small sources. A discount rate of 7 percent and a
capacity factor of 65 percent are assumed, along with an equipment life of 20 years
(EPA, 1994).
In general, the incremental default cost is used for sources where there are existing
controls (RACT baseline), with efficiencies less than or equal to 70% (Pechan, 2001).
Cost Effectiveness: The cost effectiveness values used in AirControlNET are $3,870 per ton NOx
reduced from uncontrolled and $ 2,900 per ton NOx reduced from RACT
baseline (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic,
less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets
can penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002).
Because of these advantages, urea is more commonly used than ammonia in large boiler
applications.
The rate of reaction determines the amount of NOx removed from the flue gas. The important
design and operational factors that affect the rate of reduction include:
Reaction temperature range;
Residence time available in the optimum temperature range;
Degree of mixing between the injected reagent and the combustion gases
Uncontrolled NOx concentration level;
Molar ratio of injected reagent to uncontrolled NOx ; and
Ammonia slip.
References:
EPA, 1994: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document-- NOx Emissions from
Industrial/Commercial/lnstitutional (ICI) Boilers," EPA,-453/R-94-022, Research Triangle Park, NC,
June 1994.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
Pechan, 2001: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate Matter
Control Strategies and Cost Analysis," Revised Report, prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Research Triangle Park, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Surface Coat Oper; Coating Oven Htr; Nat Gas - Small Sources
Control Measure Name: Low NOx Burner
Rule Name: Not Applicable
Pechan Measure Code: N0881S, N08801	POD: 88
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) natural gas-fired coating oven
heater at surface coating operations with uncontrolled NOx emissions greater than 10
tons per year.
Affected SCC:
40201001 Surface Coating Operations, Coating Oven Heater, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Sources are distinguished by NOx emissions (Pechan, 1998).
Small source = less than 1 ton NOx emissions per ozone season day
Costs for stationary source NOx control are based on an analysis of EPA's NOx State
Implementation Plan (SIP) Call (Pechan, 1998). The basis of the costs are model
plant data for mechanical draft heaters firing natural gas and oil contained in the
Alternative Control Techniques (ACT) document (EPA, 1993). From this analysis,
default cost per ton values are assigned along with a capital to annual costs ratio of
7.3. A discount rate of 7 percent and a capacity factor of 65 percent are assumed,
along with an equipment life of 10 years (EPA, 1993).
Cost Effectiveness: The default cost effectiveness value used in AirControlNET is $2,200 per ton
NOx reduced from both uncontrolled and RACT (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
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AT-A-GLANCE TABLE FOR POINT SOURCES
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 1993: U.S. Environmental Protection Agency, Emissions Standard Division, Office of Air
Quality Planning and Standards, "Alternative Control Techniques Document- NOx Emissions from
Process Heaters," EPA-453/R-93-034, Research Triangle Park, NC, September 1993.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Ozone Transport Rulemaking Non-Electricity
Generating Unit Cost Analysis," prepared for U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics Group, Research Triangle
Park, September 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Tangential
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N00201	POD: 02
Application: This control is the use of selective non-catalytic reduction add-on controls to reduce
NOx emissions from tangentially coal-fired utility boilers. SNCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) with a nitrogen based reducing reagent, such as ammonia or urea, to reduce
the NOx into molecular nitrogen (N2) and water vapor (H20).
This control applies to bituminous/subbituminous coal-fired electricity generation
sources, including sources with atmospheric fluidized bed combustion.
Affected SCC:
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 35% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SNCR had capacities of 100 MW.
The equations were scaled to develop costs for smaller or larger boilers than the
model plant. The cost equations also assume a high NOx rate (>=0.5 pounds per
MMBtu) and a capacity utilization factor of 65% were assumed for the utility boilers,
as well as a 7% discount rate and 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $15.80 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (100 / MW)A0.681
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.24 per kW per year
Variable O&M: omv = $0.73 mills per kW-hr
Capacity Factor: capfac = 0.65
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $15.80 per kW; the fixed
O&M costs of $0.24 per kW per year; and variable O&M costs of $0.73 mills
per kW per year (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Tangential
Control Measure Name: Natural Gas Reburn (NGR)
Rule Name: Not Applicable
Pechan Measure Code: N00202	POD: 02
Application: Natural gas reburning (NGR) involves add-on controls to reduce NOx emissions. NGR
is a combustion control technology in which part of the main fuel heat input is diverted
to locations above the main burners, called the reburn zone. As flue gas passes
through the reburn zone, a portion of the NOx formed in the main combustion zone is
reduced by hydrocarbon radicals and converted to molecular nitrogen (N2).
This control applies to bituminous/subbituminous coal-fired electricity generation
sources, including sources with atmospheric fluidized bed combustion.
Affected SCC:
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Sub bituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying NGR had capacities of 200 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu),
a 7% discount rate, and a 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $26.90 per kW
Scaling Factor: SF= (sfn / netdc)Asfe = (200 / MW)A0.35
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.41 per kW per year
Variable O&M: omv = $0 millions per kW-hr
Capacity Utilization Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
O&M Cost Components: The O&M cost breakdown is estimated using the economic
analysis for a 200 megawatt unit provided in Appendix E: Cost Analysis of Reburning
Systems for conventional gas reburn. The example calculation with a $1.00 per
million Btu difference between the primary fuel cost and the reburn fuel cost was
used. The reference for this information is the 1998 Andover Technology Partners
report for NESCAUM/MARAMA. The fuel cost differential is the dominant operating
cost of NGR.
Coal Cost: $ 1.50/MM Btu
Natural Gas Cost: $2.50/MMBtu
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $26.90 per kW, the fixed
O&M of $0.41 per kW per year, and the variable O&M of $0 per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In a reburn boiler, fuel is injected into the upper furnace region to convert the NOx formed in the
primary combustion zone to molecular N2 and H20. In general, the overall process occurs within
three zones of the boiler; the combustion zone, the gas reburning zone, and the burnout zone (ERG,
2000). In the combustion zone the amount of fuel is reduced and the burners may be operated at
the lowest excess air level. In the gas reburning zone the fuel not used in the combustion zone is
injected to create a fuel-rich region where radicals can react with NOx to form molecular Nitrogen.
In the burnout zone a separate overfire air system redirects air from the primary combustion zone to
ensure complete combustion of unreacted fuel leaving the reburning zone.
Operational parameters that affect the performance of reburn include reburn zone stoichiometry,
residence time in the reburn zone, reburn fuel carrier gas and temperature and 02 levels in the
burnout zone (ERG, 2000).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Staudt, 1998: Staudt, James E., "Status Report on NOx Control Technologies and Cost
Effectiveness for Utility Boilers," Andover Technology Partners, North Andover, MA, prepared for
NESCAUM and MARAMA, June 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Tangential
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N00203	POD: 02
Application: This control is the use of selective catalytic reduction add-on controls to tangentially
coal-fired utility boilers for the reduction of NOx emissions. SCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) with a nitrogen based reducing reagent, such as ammonia or urea, to reduce
the NOx into molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a
catalyst to increase the NOx removal efficiency, which allows the process to occur at
lower temperatures.
This control applies to bituminous/subbituminous coal-fired electricity generation
sources, including sources with atmospheric fluidized bed combustion.
Affected SCC:
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X

V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled for NOx; 95% from uncontrolled for Hg
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SCR had capacities of 243 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu)
and a capacity utilization factor of 65% were assumed for the utility boilers, as well as
a 7% discount rate and 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $100 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (243 / MW)A0.27
CC (for netdc < 600) = TCC * netdc * 1000 * SF
CC (for netdc > 600) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.66 per kW per year
Variable O&M: omv = $0.6 mills per kW-hr
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Capacity Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: The O&M cost breakdown is estimated using the Chapter 4
costing algorithms in EPA, 2001. The fixed O&M cost is the sum of the annual
maintenance material and labor cost, and is estimated to be 0.66 percent of the
capital cost. This portion of the O&M cost is included in the database as maintenance
labor. The NH3 use cost equation is used to estimate chemicals costs. The annual
replacement cost equation is used to estimate replacement materials costs. The
energy requirement cost equation is used to estimate electricity costs.
Electricity cost = $0.03/kWhr
Ammonia cost = $225/ton
The above O&M component costs are in 2000 dollars. The model plant size used to
estimate utility boiler O&M cost components is 750 MMBtu/hour.
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $100 per kW; the fixed
O&M cost of $0.66 per kW per year; and the variable O&M cost of $0.6 mills
per KW-hr (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
Selective Catalytic Reduction (SCR) systems are among the post-combustion NOx control systems
that can be effective in controlling mercury. This is based on recent pilot-scale tests that indicate
that SNCR and SCR systems may enhance Hg capture under some conditions by oxidizing HgO
(Massachusetts, 2002).
Researches are investigating the possibility of HgO to Hg2+ conversion in SCR systems as a
possible result of ammonia on fly ash mercury reactions. In the SCR process, a catalyst (such as
vanadium, titanium, platinum, or zeolite) is used in a bed reactor, and the NOx reduction occurs at
the surface of the catalyst bed with the help of a reducing agent (diluted ammonia or urea, which
generates ammonia in the process). The ammonia mixture is injected into the flue gas upstream of
the metal catalyst bed reactor, which is located upstream of a PM or S02 control device (usually
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
between the economizer outlet and air heater inlet, where temperatures range from 230 to 400oC).
Recent pilot-scale tests indicate that SCR systems can enhance Hg capture under some conditions
by oxidizing HgO. On the plant-size scale, only one set of tests have been performed to measure
the effectiveness of SCR systems. Application of SCR system, combined with spray dryer absorber
was tested at a plant which was firing bituminous coal. The test results indicated greater than 95
percent mercury removal for the combined co-control systems (Massachusetts, 2002).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
Massachusetts, 2002: Commonwealth of Massachusetts, Department of Environmental Protection,
Executive Office of Environmental Affairs, Division of Planning and Evaluation, Bureau of Waste
Prevention, "Evaluation Of The Technological and Economic Feasibility of Controlling and
Eliminating Mercury Emissions from the Combustion of Solid Fossil Fuel, Pursuant To 310 CMR
7.29 - Emissions Standards For Power Plants," Downloaded from
http://www.state.ma.us/dep/bwp/daqc/daqcpubs.htm#other, December 2002.
EPA, 2001: U.S. Environmental Protection, Office of Research and Development, "Cost of Selective
Catalytic Reduction (SCR) Application for NOx Control on Coal-Fired Boilers," EPA-600/R-01-087,
Research Triangle Park, NC, October 2001.
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Tangential
Control Measure Name: Low Nox Coal-and-Air Nozzles with cross-Coupled Overfire Air (LNC1)
Rule Name: Not Applicable
Pechan Measure Code: N00903	POD: 02
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 33% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $9.1 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.14 per kW per year
Variable O&M: omv = $0.0 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $9.1 per kW; the fixed
O&M costs of $0.14 per kW per year; and variable O&M costs of $0.0 mills per
kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Tangential
Control Measure Name: Low Nox Coal-and-Air Nozzles with separated Overfire Air (LNC2)
Rule Name: Not Applicable
Pechan Measure Code: N00904	POD: 02
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 38% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $12.71 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.19 per kW per year
Variable O&M: omv = $0,024 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $12.71 per kW; the fixed
O&M costs of $0.19 per kW per year; and variable O&M costs of $0,024 mills
per kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Tangential
Control Measure Name: Low Nox Coal-and-Air Nozzles with Close-Coupled and Separated Overfire
Air (LNC3)
Rule Name: Not Applicable
Pechan Measure Code: N00905	POD: 02
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 53% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $14.52 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.22 per kW per year
Variable O&M: omv = $0,024 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $14.52 per kW; the fixed
O&M costs of $0.22 per kW per year; and variable O&M costs of $0,024 mills
per kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
III-590
Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Tangential
Control Measure Name: Low Nox Coal-and-Air Nozzles with cross-Coupled Overfire Air (LNC1)
Rule Name: Not Applicable
Pechan Measure Code: N00908	POD: 10
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100226 Electric Generation, Pulverized Coal: Dry Bottom Tangential (Subbituminous Coal)
10100302 Electric Generation, Pulverized Coal: Dry Bottom, Tangential Fired
10100317 Electric Generation, Atmospheric Fluidized Bed Combustion - Bubbling Bed
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 43% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $9.1 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.14 per kW per year
Variable O&M: omv = $0.0 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $9.1 per kW; the fixed
O&M costs of $0.14 per kW per year; and variable O&M costs of $0.0 mills per
kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Tangential
Control Measure Name: Low Nox Coal-and-Air Nozzles with separated Overfire Air (LNC2)
Rule Name: Not Applicable
Pechan Measure Code: N00909	POD: 10
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100226 Electric Generation, Pulverized Coal: Dry Bottom Tangential (Subbituminous Coal)
10100302 Electric Generation, Pulverized Coal: Dry Bottom, Tangential Fired
10100317 Electric Generation, Atmospheric Fluidized Bed Combustion - Bubbling Bed
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 48% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $12.71 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.19 per kW per year
Variable O&M: omv = $0,024 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $12.71 per kW; the fixed
O&M costs of $0.19 per kW per year; and variable O&M costs of $0,024 mills
per kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Tangential
Control Measure Name: Low Nox Coal-and-Air Nozzles with Close-Coupled and Separated Overfire
Air (LNC3)
Rule Name: Not Applicable
Pechan Measure Code: N00910	POD: 10
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100226 Electric Generation, Pulverized Coal: Dry Bottom Tangential (Subbituminous Coal)
10100302 Electric Generation, Pulverized Coal: Dry Bottom, Tangential Fired
10100317 Electric Generation, Atmospheric Fluidized Bed Combustion - Bubbling Bed
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 58% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $14.52 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.22 per kW per year
Variable O&M: omv = $0,024 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $14.52 per kW; the fixed
O&M costs of $0.22 per kW per year; and variable O&M costs of $0,024 mills
per kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Wall
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N00101	POD: 01
Application: This control is the reduction of NOx emission through selective non-catalytic reduction
add-on controls to wall fired (coal) utility boilers. SNCR controls are post-combustion
control technologies based on the chemical reduction of nitrogen oxides (NOx) with a
nitrogen based reducing reagent, such as ammonia or urea, to reduce the NOx into
molecular nitrogen (N2) and water vapor (H20).
This control applies to pulverized-dry bottom coal-fired electricity generation sources.
Affected SCC:
10100202 Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 35% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SNCR had capacities of 100 MW.
The equations were scaled to develop costs for smaller or larger boilers than the
model plant. The cost equations also assume a high NOx rate (>=0.5 pounds per
MMBtu) and a capacity utilization factor of 65% were assumed for the utility boilers,
as well as a 7% discount rate and 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $15.80 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (100 / MW)A0.681
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.24 per kW per year
Variable O&M: omv = $0.73 mills per kW-hr
Capacity Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: The O&M cost breakdown is estimated using the detailed
information in the OAQPS Control Cost Manual-Section 4-NOx Controls. The
example problem in subsection 1.5 is used as an example for computing typical
capital and annual costs of a retrofit SNCR system being applied to a 1,000
MMBtu/hour wall-fired, industrial boiler firing sub-bituminous coal. In this analysis, the
SNCR system is assumed to operate for 5 months of the year with a capacity factor
of 65 percent, resulting in a total capacity factor of 27 percent. The total variable
direct annual cost is the sum of the cost of the reagent, electricity, water, coal, and
ash. Indirect annual costs are zero.
Electricity Cost: $0.05 $/kW-hr
Coal Cost: $1.60/MMBtu
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $15.80 per kW; the fixed
O&M costs of $0.24 per kW per year; and variable O&M costs of $0.73 mills
per kW per year (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Wall
Control Measure Name: Natural Gas Reburn (NGR)
Rule Name: Not Applicable
Pechan Measure Code: N00102	POD: 01
Application: Natural gas reburning (NGR) involves add-on controls to reduce NOx emissions. NGR
is a combustion control technology in which part of the main fuel heat input is diverted
to locations above the main burners, called the reburn zone. As flue gas passes
through the reburn zone, a portion of the NOx formed in the main combustion zone is
reduced by hydrocarbon radicals and converted to molecular nitrogen (N2).
This control applies to pulverized-dry bottom coal-fired electricity generation sources.
Affected SCC:
10100202 Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying NGR had capacities of 200 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu),
a 7% discount rate, and a 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $26.90 per kW
Scaling Factor: SF= (sfn / netdc)Asfe = (200 / MW)A0.35
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.41 per kW per year
Variable O&M: omv = $0 millions per kW-hr
Capacity Utilization Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Equipment Life in Years = Equiplife
Interest Rate = I
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: The O&M cost breakdown is estimated using the economic
analysis for a 200 megawatt unit provided in Appendix E: Cost Analysis of Reburning
Systems for conventional gas reburn. The example calculation with a $1.00 per
million Btu difference between the primary fuel cost and the reburn fuel cost was
used. The reference for this information is the 1998 Andover Technology Partners
report for NESCAUM/MARAMA. The fuel cost differential is the dominant operating
cost of NGR.
Coal Cost: $ 1.50/MM Btu
Natural Gas Cost: $2.50/MMBtu
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $26.90 per kW, the fixed
O&M of $0.41 per kW per year, and the variable O&M of $0 per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In a reburn boiler, fuel is injected into the upper furnace region to convert the NOx formed in the
primary combustion zone to molecular N2 and H20. In general, the overall process occurs within
three zones of the boiler; the combustion zone, the gas reburning zone, and the burnout zone (ERG,
2000). In the combustion zone the amount of fuel is reduced and the burners may be operated at
the lowest excess air level. In the gas reburning zone the fuel not used in the combustion zone is
injected to create a fuel-rich region where radicals can react with NOx to form molecular Nitrogen.
In the burnout zone a separate overfire air system redirects air from the primary combustion zone to
ensure complete combustion of unreacted fuel leaving the reburning zone.
Operational parameters that affect the performance of reburn include reburn zone stoichiometry,
residence time in the reburn zone, reburn fuel carrier gas and temperature and 02 levels in the
burnout zone (ERG, 2000).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Staudt, 1998: Staudt, James E., "Status Report on NOx Control Technologies and Cost
Effectiveness for Utility Boilers," Andover Technology Partners, North Andover, MA, prepared for
Document No. 05.09.009/9010.463	III-600	Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
NESCAUM and MARAMA, June 1998.
Document No. 05.09.009/9010.463	III-601	Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Wall
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N00103	POD: 01
Application: This control is the use of selective catalytic reduction add-on controls to coal/wall fired
utility boilers for the reduction of NOx emissions. SCR controls are post-combustion
control technologies based on the chemical reduction of nitrogen oxides (NOx) with a
nitrogen based reducing reagent, such as ammonia or urea, to reduce the NOx into
molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to
increase the NOx removal efficiency, which allows the process to occur at lower
temperatures.
This control applies to pulverized-dry bottom coal-fired electricity generation sources.
Affected SCC:
10100202 Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SCR had capacities of 243 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu)
and a capacity utilization factor of 65% were assumed for the utility boilers, as well as
a 7% discount rate and 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $100 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (243 / MW)A0.27
CC (for netdc < 600) = TCC * netdc * 1000 * SF
CC (for netdc > 600) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.66 per kW per year
Variable O&M: omv = $0.6 mills per kW-hr
Capacity Factor: capfac = 0.65
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: The O&M cost breakdown is estimated using the Chapter 4
costing algorithms in EPA, 2001. The fixed O&M cost is the sum of the annual
maintenance material and labor cost, and is estimated to be 0.66 percent of the
capital cost. This portion of the O&M cost is included in the database as maintenance
labor. The NH3 use cost equation is used to estimate chemicals costs. The annual
replacement cost equation is used to estimate replacement materials costs. The
energy requirement cost equation is used to estimate electricity costs.
Electricity cost = $0.03/kWhr
Ammonia cost = $225/ton
The above O&M component costs are in 2000 dollars. The model plant size used to
estimate utility boiler O&M cost components is 750 MMBtu/hour.
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $100 per kW; the fixed
O&M cost of $0.66 per kW per year; and the variable O&M cost of $0.6 mills
per KW-hr (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
EPA, 2001: U.S. Environmental Protection, Office of Research and Development, "Cost of Selective
Catalytic Reduction (SCR) Application for NOx Control on Coal-Fired Boilers," EPA-600/R-01-087,
Research Triangle Park, NC, October 2001.
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Wall
Control Measure Name: Low Nox Burner without Overfire Air
Rule Name: Not Applicable
Pechan Measure Code: N00901	POD: 01
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100202 Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 41% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $26.70 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.26 per kW per year
Variable O&M: omv = $0.05 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $17.26 per kW; the fixed
O&M costs of $0.26 per kW per year; and variable O&M costs of $0.05 mills
per kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed:
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
III-605
Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Wall
Control Measure Name: Low Nox Burner with Overfire Air
Rule Name: Not Applicable
Pechan Measure Code: N00902	POD: 01
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100202 Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 56% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $23.43 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.36 per kW per year
Variable O&M: omv = $0.07 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $23.43 per kW; the fixed
O&M costs of $0.36 per kW per year; and variable O&M costs of $0.07 mills
per kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Wall
Control Measure Name: Low Nox Burner without Overfire Air
Rule Name: Not Applicable
Pechan Measure Code: N00906	POD: 09
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100222 Electric Generation, Pulverized Coal: Dry Bottom (Subbituminous Coal)
10100301 Electric Generation, Pulverized Coal: Dry Bottom, Wall Fired (Lignite Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $26.70 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.26 per kW per year
Variable O&M: omv = $0.05 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $17.26 per kW; the fixed
O&M costs of $0.26 per kW per year; and variable O&M costs of $0.05 mills
per kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
III-609
Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Coal/Wall
Control Measure Name: Low Nox Burner with Overfire Air
Rule Name: Not Applicable
Pechan Measure Code: N00907	POD: 09
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions.
LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount
of oxygen available in another.
This control applies to wall fired (coal) utility boilers
Affected SCC:
10100222 Pulverized Coal: Dry Bottom (Subbituminous Coal)
10100301 Pulverized Coal: Dry Bottom, Wall Fired (Lignite Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying LNB had capacities of 300 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a capacity utilization factor of 85% for the
utility boilers, as well as a 7% discount rate and 15-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $23.43 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (300 / MW)A0.359
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.36 per kW per year
Variable O&M: omv = $0.07 mills per kW-hr
Capacity Factor: capfac = 0.85
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: With the retrofit of combustion controls, the boiler unburned
carbon may increase. This increase results in a reduction in boiler efficiency,
requiring more coal to be burned to maintain the boiler output. As the coal firing rate
increases, there are corresponding increases in the solid waste generation and
auxiliary power usage. The O&M costs were evaluated for tangential-fired boilers
only. With no changes in the capital cost for wall-fired boilers, the fixed O&M costs,
generally taken as a function of the capital cost, are not expected to vary. Also, no
changes in the variable O&M costs are expected, since unburned carbon
assumptions are unchanged.
For tangential-fired boilers, the general maintenance cost was conservatively taken
as 1.5 percent of the total project cost for each technology. Also, a plant capacity
factor of 85 percent was assumed.
Coal Cost: $1.20/MMBtu
Solid waste disposal: $12/ton
Auxiliary power: 25 mills/KWh
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $23.43 per kW; the fixed
O&M costs of $0.36 per kW per year; and variable O&M costs of $0.07 mills
per kW per year (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-
air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion
zone. Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of
excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
References:
EPA, 2004: U.S Enviornmental Protection Agency, Clean Air Market Division, "Updating
Performance and Cost of Nox Control Technologies in the Integrated Planning Model" Paper# 137
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Cyclone
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N00701	POD: 07
Application: This control is the use of selective non-catalytic reduction add-on controls to cyclone
utility boilers to reduce NOx emissions. SNCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) with a
nitrogen based reducing reagent, such as ammonia or urea, to reduce the NOx into
molecular nitrogen (N2) and water vapor (H20)
This control applies to bituminous/subbituminous coal-fired electricity generation
sources with cyclone furnaces.
Affected SCC:
10100203 Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 35% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SNCR had capacities of 100 MW.
The equations were scaled to develop costs for smaller or larger boilers than the
model plant. The cost equations also assume a high NOx rate (>=0.5 pounds per
MMBtu) and a capacity utilization factor of 65% were assumed for the utility boilers,
as well as a 7% discount rate and 20-year lifetime of the controls.
Control Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $8.00 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (100 / MW)A0.577
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.12 per kW per year
Variable O&M: omv = $1.05 mills per kW-hr
Capacity Factor: capfac = 0.65
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost is $8.00 per kW; the fixed
O&M cost is $0.12 per kW per year; and the variable O&M cost is $1.05 mills
per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Cyclone
Control Measure Name: Natural Gas Reburn (NGR)
Rule Name: Not Applicable
Pechan Measure Code: N00702	POD: 07
Application: Natural gas reburning (NGR) involves add-on controls to reduce NOx emissions. NGR
is a combustion control technology in which part of the main fuel heat input is diverted
to locations above the main burners, called the reburn zone. As flue gas passes
through the reburn zone, a portion of the NOx formed in the main combustion zone is
reduced by hydrocarbon radicals and converted to molecular nitrogen (N2).
This control applies to pulverized-dry bottom coal-fired electricity generation sources
with cyclone furnaces.
Applies to bituminous/subbituminous coal-fired electricity generation sources with
cyclone furnaces.
Affected SCC:
10100203 Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying NGR had capacities of 200 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu),
a 7% discount rate, and a 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $26.90 per kW
Scaling Factor: SF= (sfn / netdc)Asfe = (200 / MW)A0.35
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.41 per kW per year
Variable O&M: omv = $0 millions per kW-hr
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Capacity Utilization Factor: capfac = 0.65
O&M Cost Components: The O&M cost breakdown is estimated using the economic
analysis for a 200 megawatt unit provided in Appendix E: Cost Analysis of Reburning
Systems for conventional gas reburn. The example calculation with a $1.00 per
million Btu difference between the primary fuel cost and the reburn fuel cost was
used. The reference for this information is the 1998 Andover Technology Partners
report for NESCAUM/MARAMA. The fuel cost differential is the dominant operating
cost of NGR.
Coal Cost: $ 1.50/MM Btu
Natural Gas Cost: $2.50/MMBtu
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $26.90 per kW, the fixed
O&M of $0.41 per kW per year, and the variable O&M of $0 per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In a reburn boiler, fuel is injected into the upper furnace region to convert the NOx formed in the
primary combustion zone to molecular N2 and H20. In general, the overall process occurs within
three zones of the boiler; the combustion zone, the gas reburning zone, and the burnout zone (ERG,
2000). In the combustion zone the amount of fuel is reduced and the burners may be operated at
the lowest excess air level. In the gas reburning zone the fuel not used in the combustion zone is
injected to create a fuel-rich region where radicals can react with NOx to form molecular Nitrogen.
In the burnout zone a separate overfire air system redirects air from the primary combustion zone to
ensure complete combustion of unreacted fuel leaving the reburning zone.
Operational parameters that affect the performance of reburn include reburn zone stoichiometry,
residence time in the reburn zone, reburn fuel carrier gas and temperature and 02 levels in the
burnout zone (ERG, 2000).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Staudt, 1998: Staudt, James E., "Status Report on NOx Control Technologies and Cost
Effectiveness for Utility Boilers," Andover Technology Partners, North Andover, MA, prepared for
NESCAUM and MARAMA, June 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Cyclone
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N00703	POD: 07
Application: This control reduces NOx emissions using selective catalytic add-on controls on utility
boilers with cyclone burners. SCR controls are post-combustion control technologies
based on the chemical reduction of nitrogen oxides (NOx) with a nitrogen based
reducing reagent, such as ammonia or urea, to reduce the NOx into molecular
nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx
removal efficiency, which allows the process to occur at lower temperatures.
This control applies to bituminous/subbituminous coal-fired electricity generation
sources with cyclone furnaces.
Affected SCC:
10100203 Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SCR had capacities of 200 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu)
and a capacity utilization factor of 65% were assumed for the utility boilers, as well as
a 7% discount rate and 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $80 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (200 / MW)A0.35
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.53 per kW per year
Variable O&M: omv = $0.37 mills per kW-hr
Capacity Factor: capfac = 0.65
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: The O&M cost breakdown is estimated using the Chapter 4
costing algorithms in EPA, 2001. The fixed O&M cost is the sum of the annual
maintenance material and labor cost, and is estimated to be 0.66 percent of the
capital cost. This portion of the O&M cost is included in the database as maintenance
labor. The NH3 use cost equation is used to estimate chemicals costs. The annual
replacement cost equation is used to estimate replacement materials costs. The
energy requirement cost equation is used to estimate electricity costs.
Electricity cost = $0.03/kWhr
Ammonia cost = $225/ton
The above O&M component costs are in 2000 dollars. The model plant size used to
estimate utility boiler O&M cost components is 750 MMBtu/hour.
Note: All costs are in 1999 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $80 per kW; the fixed
O&M cost of $0.53 per kW per year; and the variable O&M cost of $0.37 mills
per KW-hr (1999$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
EPA, 2001: U.S. Environmental Protection, Office of Research and Development, "Cost of Selective
Catalytic Reduction (SCR) Application for NOx Control on Coal-Fired Boilers," EPA-600/R-01-087,
Research Triangle Park, NC, October 2001.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Oil-Gas/Tangential
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N00601	POD: 06
Application: This control reduces NOx emissions using selective non-catalytic reduction add-on
controls to tangentially fired (oil/gas) utility boilers. SNCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) with a nitrogen based reducing reagent, such as ammonia or urea, to reduce
the NOx into molecular nitrogen (N2) and water vapor (H20).
The control applies to tangentially natural-gas fired electricity generation sources.
Affected SCC:
10100604 Electric Generation, Natural Gas, Tangentially Fired Units
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SNCR had capacities of 200 MW.
The equations were scaled to develop costs for smaller or larger boilers than the
model plant. The cost equations also assume a high NOx rate (>=0.5 pounds per
MMBtu) and a capacity utilization factor of 65% were assumed for the utility boilers,
as well as a 7% discount rate and 20-year lifetime.
Control Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $7.80 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (200 / MW)A0.577
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.12 per kW per year
Variable O&M: omv = $0.37 mills per kW-hr
Capacity Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * TCC) + O&M
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital costs of $7.80 per kW; the fixed
O&M cost of $0.12 per kW per year; and the variable O&M cost of $0.37 mills
per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Oil-Gas/Tangential
Control Measure Name: Natural Gas Reburn (NGR)
Rule Name: Not Applicable
Pechan Measure Code: N00602	POD: 06
Application: Natural gas reburning (NGR) involves add-on controls to reduce NOx emissions. NGR
is a combustion control technology in which part of the main fuel heat input is diverted
to locations above the main burners, called the reburn zone. As flue gas passes
through the reburn zone, a portion of the NOx formed in the main combustion zone is
reduced by hydrocarbon radicals and converted to molecular nitrogen (N2).
This control applies to tangentially natural-gas fired electricity generation sources.
Affected SCC:
10100604 Electric Generation, Natural Gas, Tangentially Fired Units
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying NGR had capacities of 200 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu)
and a capacity utilization factor of 65% were assumed for the utility boilers, as well as
a 7% discount rate and 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $16.40 per kW
Scaling Factor: SF= (sfn / netdc)Asfe = (200 / MW)A0.35
CC (for netdc < 500) = TCC* netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.25 per kW per year
Variable O&M: omv = $0.02 mills per kW-hr
Capacity Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
O&M Cost Components: The O&M cost breakdown is estimated using the economic
analysis for a 200 megawatt unit provided in Appendix E: Cost Analysis of Reburning
Systems for conventional gas reburn. The example calculation with a $1.00 per
million Btu difference between the primary fuel cost and the reburn fuel cost was
used. The reference for this information is the 1998 Andover Technology Partners
report for NESCAUM/MARAMA. The fuel cost differential is the dominant operating
cost of NGR.
Coal Cost: $ 1.50/MM Btu
Natural Gas Cost: $2.50/MMBtu
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF *CC) + O&M
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $16.40 per kW, the fixed
O&M of $0.25 per kW per year, and the variable O&M of $0.02 mills per kW-hr
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In a reburn boiler, fuel is injected into the upper furnace region to convert the NOx formed in the
primary combustion zone to molecular N2 and H20. In general, the overall process occurs within
three zones of the boiler; the combustion zone, the gas reburning zone, and the burnout zone (ERG,
2000). In the combustion zone the amount of fuel is reduced and the burners may be operated at
the lowest excess air level. In the gas reburning zone the fuel not used in the combustion zone is
injected to create a fuel-rich region where radicals can react with NOx to form molecular Nitrogen.
In the burnout zone a separate overfire air system redirects air from the primary combustion zone to
ensure complete combustion of unreacted fuel leaving the reburning zone.
Operational parameters that affect the performance of reburn include reburn zone stoichiometry,
residence time in the reburn zone, reburn fuel carrier gas and temperature and 02 levels in the
burnout zone (ERG, 2000).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Staudt, 1998: Staudt, James E., "Status Report on NOx Control Technologies and Cost
Effectiveness for Utility Boilers," Andover Technology Partners, North Andover, MA, prepared for
NESCAUM and MARAMA, June 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Oil-Gas/Tangential
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N00603	POD: 06
Application: This control is the selective catalytic reduction of NOx through add-on controls to
tangentially fired (oil/gas) utility boilers. SCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) with a
nitrogen based reducing reagent, such as ammonia or urea, to reduce the NOx into
molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to
increase the NOx removal efficiency, which allows the process to occur at lower
temperatures.
This control applies to tangentially natural-gas fired electricity generation sources.
Affected SCC:
10100604 Electric Generation, Natural Gas, Tangentially Fired Units
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SCR had capacities of 200 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu)
and a capacity utilization factor of 65% were assumed for the utility boilers, as well as
a 7% discount rate and 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $23.30 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (200 / MW)A0.35
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.72 per kW per year
Variable O&M: omv = $0.08 mills per kW-hr
Capacity Factor: capfac = 0.65
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $23.30 per kW; the fixed
O&M cost of $0.72 per kW per year; and the variable O&M cost of $0.08 mills
per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Oil-Gas/Wall
Control Measure Name: Selective Non-Catalytic Reduction (SNCR)
Rule Name: Not Applicable
Pechan Measure Code: N00501	POD: 05
Application: This control is the use of selective non-catalytic reduction add-on controls to wall fired
(oil/gas) utility boilers for the reduction of NOx emissions. SNCR controls are post-
combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) with a nitrogen based reducing reagent, such as ammonia or urea, to reduce
the NOx into molecular nitrogen (N2) and water vapor (H20).
The control applies to large (>100 million Btu/hr) natural-gas fired electricity generation
sources, excluding tangentially fired sources.
Affected SCC:
10100601 Electric Generation, Natural Gas, Boilers > 100 Million Btu/hr except Tangential
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SNCR had capacities of 200 MW.
The equations were scaled to develop costs for smaller or larger boilers than the
model plant. The cost equations also assume a high NOx rate (>=0.5 pounds per
MMBtu) and a capacity utilization factor of 65% were assumed for the utility boilers,
as well as a 7% discount rate and 20-year lifetime.
Control Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $7.80 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (200 / MW)A0.577
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.12 per kW per year
Variable O&M: omv = $0.37 mills per kW-hr
Capacity Factor: capfac = 0.65
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * TCC) + O&M
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital costs of $7.80 per kW; the fixed
O&M cost of $0.12 per kW per year; and the variable O&M cost of $0.37 mills
per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of
flue gas components. However, the NOx reduction reaction is favored for a specific temperature
range and in the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the
choice of reagent is also based on physical properties and operational considerations (EPA, 2002).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Oil-Gas/Wall
Control Measure Name: Natural Gas Reburn (NGR)
Rule Name: Not Applicable
Pechan Measure Code: N00502	POD: 05
Application: Natural gas reburning (NGR) involves add-on controls to reduce NOx emissions. NGR
is a combustion control technology in which part of the main fuel heat input is diverted
to locations above the main burners, called the reburn zone. As flue gas passes
through the reburn zone, a portion of the NOx formed in the main combustion zone is
reduced by hydrocarbon radicals and converted to molecular nitrogen (N2).
This control applies to large (>100 million Btu/hr) natural-gas fired electricity generation
sources, excluding tangentially fired sources.
Affected SCC:
10100601 Electric Generation, Natural Gas, Boilers > 100 Million Btu/hr except Tangential
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*





V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying NGR had capacities of 200 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu)
and a capacity utilization factor of 65% were assumed for the utility boilers, as well as
a 7% discount rate and 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $16.40 per kW
Scaling Factor: SF= (sfn / netdc)Asfe = (200 / MW)A0.35
CC (for netdc < 500) = TCC* netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.25 per kW per year
Variable O&M: omv = $0.02 mills per kW-hr
Capacity Factor: capfac = 0.65
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O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
O&M Cost Components: The O&M cost breakdown is estimated using the economic
analysis for a 200 megawatt unit provided in Appendix E: Cost Analysis of Reburning
Systems for conventional gas reburn. The example calculation with a $1.00 per
million Btu difference between the primary fuel cost and the reburn fuel cost was
used. The reference for this information is the 1998 Andover Technology Partners
report for NESCAUM/MARAMA. The fuel cost differential is the dominant operating
cost of NGR.
Coal Cost: $ 1.50/MM Btu
Natural Gas Cost: $2.50/MMBtu
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF *CC) + O&M
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $16.40 per kW, the fixed
O&M of $0.25 per kW per year, and the variable O&M of $0.02 mills per kW-hr
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In a reburn boiler, fuel is injected into the upper furnace region to convert the NOx formed in the
primary combustion zone to molecular N2 and H20. In general, the overall process occurs within
three zones of the boiler; the combustion zone, the gas reburning zone, and the burnout zone (ERG,
2000). In the combustion zone the amount of fuel is reduced and the burners may be operated at
the lowest excess air level. In the gas reburning zone the fuel not used in the combustion zone is
injected to create a fuel-rich region where radicals can react with NOx to form molecular Nitrogen.
In the burnout zone a separate overfire air system redirects air from the primary combustion zone to
ensure complete combustion of unreacted fuel leaving the reburning zone.
Operational parameters that affect the performance of reburn include reburn zone stoichiometry,
residence time in the reburn zone, reburn fuel carrier gas and temperature and 02 levels in the
burnout zone (ERG, 2000).
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
ERG, 2000: Eastern Research Group, Inc., "How to Incorporate the Effects of Air Pollution Control
Device Efficiencies and Malfunctions into Emission Inventory Estimates," prepared for Emission
Inventory Improvement Program, Point Sources Committee, July 2000.
Staudt, 1998: Staudt, James E., "Status Report on NOx Control Technologies and Cost
Effectiveness for Utility Boilers," Andover Technology Partners, North Andover, MA, prepared for
NESCAUM and MARAMA, June 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boiler - Oil-Gas/Wall
Control Measure Name: Selective Catalytic Reduction (SCR)
Rule Name: Not Applicable
Pechan Measure Code: N00503	POD: 05
Application: This control is the selective catalytic reduction of NOx through add-on controls to wall
fired (oil/gas) utility boilers. SCR controls are post-combustion control technologies
based on the chemical reduction of nitrogen oxides (NOx) with a nitrogen based
reducing reagent, such as ammonia or urea, to reduce the NOx into molecular
nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx
removal efficiency, which allows the process to occur at lower temperatures.
Applies to large (>100 million Btu/hr) natural-gas fired electricity generation sources,
excluding tangentially fired sources.
Affected SCC:
10100601 Electric Generation, Natural Gas, Boilers > 100 Million Btu/hr except Tangential
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V*


X


V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 80% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost equations used in this analysis are based on cost equations from EPA's IPM
(EPA, 1998). In the IPM, model plants applying SCR had capacities of 200 MW. The
equations were scaled to develop costs for smaller or larger boilers than the model
plant. The cost equations also assume a high NOx rate (>=0.5 pounds per MMBtu)
and a capacity utilization factor of 65% were assumed for the utility boilers, as well as
a 7% discount rate and 20-year lifetime of the controls.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $23.30 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (200 / MW)A0.35
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $0.72 per kW per year
Variable O&M: omv = $0.08 mills per kW-hr
Capacity Factor: capfac = 0.65
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O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness is variable and based on plant size (nameplate capacity in
MW) and the following factors: the total capital cost of $23.30 per kW; the fixed
O&M cost of $0.72 per kW per year; and the variable O&M cost of $0.08 mills
per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction
(EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue
gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NOx.
References:
EPA, 1998: U.S. Environmental Protection Agency, Office of Air and Radiation, "Analyzing Electric
Power Generation Under the CAAA," Washington, DC, March 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Agricultural Burning
Control Measure Name: Bale Stack/Propane Burning
Rule Name: Not Applicable
Pechan Measure Code: Pagbu	POD: N/A
Application: Two control measures applied to area source agricultural burning sources are propane
and bale/stack burning. Propane flamers are an alternative to open filed burning. The
bale/stack burning technique is designed to increase the fire efficiency by stacking or
baling the fuel before burning. Burning in piles or stacks tends to foster more complete
combustion, thereby reducing PM emissions.
This control is applicable to field burning where the entire field would be set on fire,
and can be applied to all crop types. These sources are classified under 2801500000.
Affected SCC:
2801500000 Agricultural Field Burning - whole field set on fire, Total, all crop types
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 49-63% from uncontrolled; PM2.5 control efficiency is
25% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost of using a propane burner includes the cost for physical removal of residue,
and the costs for operating the flamer, which vary with the speed of operation. The
average cost of propane burning is $56 per acre, which includes the cost for residue
removal and for the propane flaming (Pechan, 1998).
The costs for baling and burning average $25 per ton of residue baled and $0.50 per
ton to burn, or approximately $25.50 per ton of residue burned (EPA, 1992).
Capital costs for both of these techniques are assumed to be zero.
Costs vary by state and crop type. The cost effectiveness ranges from $1,832 for
Georgia to $8,164 for Florida The PM10 control efficiency ranges from 49% for
Louisiana to 63% for Alabama, Georgia, Kansas, Mississippi, and North Carolina.
Note: All costs are in 1992 dollars.
Cost Effectiveness: The cost effectiveness per ton PM10 reduced is $2,591. (1992$)
Comments:
Status: Demonstrated
Last Reviewed: 1998
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Additional Information:
References:
EPA, 1992: U.S. Environmental Protection Agency, "Prescribed Burning Background Document,"
Office of Air Quality Planning and Standards, Research Triangle Park, NC, September 1992.
Pechan, 1995: E.H. Pechan & Associates, Inc., "Regional Particulate Strategies - Draft Report,"
prepared for U.S. Environmental Protection Agency, Office of Policy Planning and Evaluation,
Washington, DC, September 1995.
Pechan, 1998: E.H. Pechan & Associates, Inc., "Clean Air Act Section 812 Prospective Cost
Analysis - Draft Report," prepared for Industrial Economics, Inc., Cambridge, MA, September 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Agricultural Tilling
Control Measure Name: Soil Conservation Plans
Rule Name: Soil Conservation Plans
Pechan Measure Code: Pagtl	POD: N/A
Application: The soil conservation plan measure would require farmers and farmland owners to
develop soil conservation plans with the assistance of the U.S. Department of
Agriculture's (USDA) Natural Resource Conservation Service. Soil conservation plans
could include: establishment of rows of vegetation across the prevailing wind,
cessation of tilling on high-wind days, establishment of snow (sand) fences,
establishment of end-of-row turn-around areas, deep furrowing of fallow parcels,
prohibition of disking and improved tillage practices.
This control applies to the SCC for agricultural tilling, 2801000003.
Affected SCC:
2801000003 Agriculture - Crops, Tilling
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 12% from uncontrolled, PM2.5 control efficiency is
25% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: SCAQMD estimated control costs associated with wind erosion prevention
requirements to be $100 per acre or $154 per ton PM10 reduced (1993 dollars). This
estimate was derived from cost estimates developed for stabilization of fallow fields,
which along with the cessation of tilling on high-wind days, is considered to be the
most likely control included in the soil conservation plans (SCAQMD, 1996). No
capital expenditures have been identified, as most of the potential control actions
include a change in agricultural methods using equipment already possessed by farm
owners/operators.
Conversion to 1990 dollars was done using the U.S. Department of Agriculture's
index for prices paid for farm services/operations (Pechan, 1997).
Cost Effectiveness: The cost effectiveness is $138 per ton PM10 reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
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Additional Information:
Agricultural tilling is used for soil preparation and maintenance, and generally produces the bulk of
fugitive dust emissions from agricultural activities. Tilling includes plowing, harrowing, land leveling,
disking, and cultivating.
References:
Pechan, 1997: E.H. Pechan & Associates, "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
SCAQMD, 1996: South Coast Air Quality Management District, "1997 Air Quality Management Plan,
Appendix IV-A: Stationary and Mobile Source Control Measures." August 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Asphalt Manufacture
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2221	POD: 222
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to asphalt manufacturing operations.
Affected SCC:
30500101	Asphalt Roofing Manufacture, Asphalt Blowing: Saturant (Use 3-05-050-10 for MACT)
30500102	Mineral Products, Asphalt Roofing, Asphalt Blowing-Coating (Use 30505010 for MACT)
30500103	Asphalt Roofing Manufacture, Felt Saturation: Dipping Only
30500105	Asphalt Roofing Manufacture, General **
30500106	Asphalt Roofing Manufacture, Shingles and Rolls: Spraying Only
30500108 Asphalt Roofing Manufacture, Shingles and Rolls: Coating
30500110	Asphalt Roofing Manufacture, Blowing (Use 3-05-050-01 for MACT)
30500111	Mineral Products, Asphalt Roofing Manufacture, Dipping Only
30500117 Asphalt Roofing, Shingle Saturation-Dip Saturator, Drying-in Drum & Coater
30500198 Mineral Products, Asphalt Roofing Manufacture, Other Not Classified
30500201	Mineral Prod, Asphalt/Concrete, Rotary Dryer-Conventional (See 305002-50 -51 -52)
30500202	Mineral Products, Asphalt Concrete, Hot Elevators, Screens, Bins and Mixer
30500203	Mineral Products, Asphalt Concrete, Storage Piles
30500204	Mineral Products, Asphalt Concrete, Cold Aggregate Handling
30500205	Mineral Prod, Asphalt Concrete, Drum Dryer-Hot Asphalt Plants (See 305002-55, -58)
30500208 Mineral Products, Asphalt Concrete, Asphalt Heater-Distillate Oil (30505022 for MACT)
30500211 Asphalt Concrete, Rotary Dryer Conventional Plant-Cyclone (30500201 w/CTL)
30500213 Asphalt Concrete, Storage Silo
30500221 Asphalt Concrete, Elevators: Continuous Process
30500242 Asphalt Concrete, Mixers: Drum Mix Process ** (use 3-05-002-005 and subtypes)
30500290 Asphalt Concrete, Haul Roads: General
30500299 Asphalt Concrete, See Comment **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
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available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price	0.0671 $/kW-hr
Compressed air	0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
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(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
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AT-A-GLANCE TABLE FOR POINT SOURCES
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Asphalt Manufacture
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2222	POD: 222
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to asphalt manufacturing processes.
Affected SCC:
30500101	Asphalt Roofing Manufacture, Asphalt Blowing: Saturant (Use 3-05-050-10 for MACT)
30500102	Mineral Products, Asphalt Roofing, Asphalt Blowing-Coating (Use 30505010 for MACT)
30500103	Asphalt Roofing Manufacture, Felt Saturation: Dipping Only
30500105	Asphalt Roofing Manufacture, General **
30500106	Asphalt Roofing Manufacture, Shingles and Rolls: Spraying Only
30500108 Asphalt Roofing Manufacture, Shingles and Rolls: Coating
30500110	Asphalt Roofing Manufacture, Blowing (Use 3-05-050-01 for MACT)
30500111	Mineral Products, Asphalt Roofing Manufacture, Dipping Only
30500117 Asphalt Roofing, Shingle Saturation-Dip Saturator, Drying-in Drum & Coater
30500198 Mineral Products, Asphalt Roofing Manufacture, Other Not Classified
30500201	Mineral Prod, Asphalt/Concrete, Rotary Dryer-Conventional (See 305002-50 -51 -52)
30500202	Mineral Products, Asphalt Concrete, Hot Elevators, Screens, Bins and Mixer
30500203	Mineral Products, Asphalt Concrete, Storage Piles
30500204	Mineral Products, Asphalt Concrete, Cold Aggregate Handling
30500205	Mineral Prod, Asphalt Concrete, Drum Dryer-Hot Asphalt Plants (See 305002-55, -58)
30500208 Mineral Products, Asphalt Concrete, Asphalt Heater-Distillate Oil (30505022 for MACT)
30500211 Asphalt Concrete, Rotary Dryer Conventional Plant-Cyclone (30500201 w/CTL)
30500213 Asphalt Concrete, Storage Silo
30500221 Asphalt Concrete, Elevators: Continuous Process
30500242 Asphalt Concrete, Mixers: Drum Mix Process ** (use 3-05-002-005 and subtypes)
30500290 Asphalt Concrete, Haul Roads: General
30500299 Asphalt Concrete, See Comment **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
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Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal 25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
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ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
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AT-A-GLANCE TABLE FOR POINT SOURCES
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Asphalt Manufacture
Control Measure Name: Paper/Nonwoven Filters - Cartridge Collector Type
Rule Name: Not Applicable
Pechan Measure Code: P2223	POD: 222
Application: This control is the use of paper or non-woven filters (cartridge collector type) to reduce
PM emissions. The waste gas stream is passed through the fibrous filter media
causing PM in the gas stream to be collected on the media by sieving and other
mechanisms.
This control measure applies to asphalt manufacturing operations.
Affected SCC:
30500101	Asphalt Roofing Manufacture, Asphalt Blowing: Saturant (Use 3-05-050-10 for MACT)
30500102	Mineral Products, Asphalt Roofing, Asphalt Blowing-Coating (Use 30505010 for MACT)
30500103	Asphalt Roofing Manufacture, Felt Saturation: Dipping Only
30500105	Asphalt Roofing Manufacture, General **
30500106	Asphalt Roofing Manufacture, Shingles and Rolls: Spraying Only
30500108 Asphalt Roofing Manufacture, Shingles and Rolls: Coating
30500110	Asphalt Roofing Manufacture, Blowing (Use 3-05-050-01 for MACT)
30500111	Mineral Products, Asphalt Roofing Manufacture, Dipping Only
30500117 Asphalt Roofing, Shingle Saturation-Dip Saturator, Drying-in Drum & Coater
30500198 Mineral Products, Asphalt Roofing Manufacture, Other Not Classified
30500201	Mineral Prod, Asphalt/Concrete, Rotary Dryer-Conventional (See 305002-50 -51 -52)
30500202	Mineral Products, Asphalt Concrete, Hot Elevators, Screens, Bins and Mixer
30500203	Mineral Products, Asphalt Concrete, Storage Piles
30500204	Mineral Products, Asphalt Concrete, Cold Aggregate Handling
30500205	Mineral Prod, Asphalt Concrete, Drum Dryer-Hot Asphalt Plants (See 305002-55, -58)
30500208 Mineral Products, Asphalt Concrete, Asphalt Heater-Distillate Oil (30505022 for MACT)
30500211 Asphalt Concrete, Rotary Dryer Conventional Plant-Cyclone (30500201 w/CTL)
30500213 Asphalt Concrete, Storage Silo
30500221 Asphalt Concrete, Elevators: Continuous Process
30500242 Asphalt Concrete, Mixers: Drum Mix Process ** (use 3-05-002-005 and subtypes)
30500290 Asphalt Concrete, Haul Roads: General
30500299 Asphalt Concrete, See Comment **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are generated using EPA's cost-estimating spreadsheets for fabric filters
(EPA, 1998a). Costs are primarily driven by the waste stream volumetric flow rate
and pollutant loading. When stack gas flow rate data was available, the costs and
cost effectiveness were calculated using the typical values of capital and O&M costs.
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AT-A-GLANCE TABLE FOR POINT SOURCES
When stack gas flow rate data was not available, default typical capital and O&M cost
values based on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $7 to $13 per scfm
Typical value is $9 per scfm
O&M Costs:
Range from $9 to $25 per scfm
Typical value is $14 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average cartridge cost was estimated using the costs for standard
cartridge types. Capital recovery for the periodic replacement of cartridges was
included in the O&M cost of the cartridges using a cartridge life of 2 years (EPA,
1998a). The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $85 to $256 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $142 per ton PM10 reduced.
(1998$)
Comments:
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Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Materials handling operations including crushing, grinding, and screening, can produce significant
PM emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply. Fugitive dust emissions may come
from paved and unpaved roads in plants and from raw material and product loading, unloading, and
storage (STAPPA/ALAPCO, 1996).
The cost estimates assume a conventional design under typical operating conditions. Auxiliary
equipment, such as fans and ductwork, is not included (EPA, 2000). Pollutants that require an
unusually high level of control or that require the filter media or the unit itself to be constructed of
special materials, such as Nomex ® or stainless steel, will increase the costs of the system (EPA,
1998a). The additional costs for controlling more complex waste streams are not reflected in the
estimates given below. For these types of systems, the capital cost could increase by as much as
75% and the O&M cost could increase by as much as 10%. In general, a small unit controlling a low
pollutant loading will not be as cost effective as a large unit controlling a high pollutant loading (EPA,
2000).
Cartridge filters contain either a paper or nonwoven fibrous filter media (EPA, 2000). Paper media is
generally made of materials such as cellulose and fiberglass. The dust cake that forms on the filter
media from the collected PM can significantly increase collection efficiency (EPA, 1998b).
In general, the filter media is pleated to provide a larger surface area to volume flow rate. Close
pleating, however, can cause PM to bridge the pleat bottom, effectively reducing the surface
collection area (EPA, 1998b). Corrugated aluminum separators are used to prevent the pleats from
collapsing (Heumann, 1997). There are variety of cartridge designs and dimensions. Typical
designs include flat panels, V-shaped packs or cylindrical packs (Heumann, 1997). For certain
applications, two cartridges may be placed in series.
Cartridge collectors are useful for collecting particles with resistivities either too low or too high for
collection with electrostatic precipitators (STAPPA/AI_APCO, 1996). For similar air flow rates,
cartridge collectors are compact in size compared to traditional bag.
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Cartridge Collector with Pulse-Jet Cleaning," April 2000.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
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AT-A-GLANCE TABLE FOR POINT SOURCES
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Asphalt Manufacture
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2224	POD: 222
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to asphalt manufacturing operations
Affected SCC:
30500101	Asphalt Roofing Manufacture, Asphalt Blowing: Saturant (Use 3-05-050-10 for MACT)
30500102	Mineral Products, Asphalt Roofing, Asphalt Blowing-Coating (Use 30505010 for MACT)
30500103	Asphalt Roofing Manufacture, Felt Saturation: Dipping Only
30500105	Asphalt Roofing Manufacture, General **
30500106	Asphalt Roofing Manufacture, Shingles and Rolls: Spraying Only
30500108 Asphalt Roofing Manufacture, Shingles and Rolls: Coating
30500110	Asphalt Roofing Manufacture, Blowing (Use 3-05-050-01 for MACT)
30500111	Mineral Products, Asphalt Roofing Manufacture, Dipping Only
30500117 Asphalt Roofing, Shingle Saturation-Dip Saturator, Drying-in Drum & Coater
30500198 Mineral Products, Asphalt Roofing Manufacture, Other Not Classified
30500201	Mineral Prod, Asphalt/Concrete, Rotary Dryer-Conventional (See 305002-50 -51 -52)
30500202	Mineral Products, Asphalt Concrete, Hot Elevators, Screens, Bins and Mixer
30500203	Mineral Products, Asphalt Concrete, Storage Piles
30500204	Mineral Products, Asphalt Concrete, Cold Aggregate Handling
30500205	Mineral Prod, Asphalt Concrete, Drum Dryer-Hot Asphalt Plants (See 305002-55, -58)
30500208 Mineral Products, Asphalt Concrete, Asphalt Heater-Distillate Oil (30505022 for MACT)
30500211 Asphalt Concrete, Rotary Dryer Conventional Plant-Cyclone (30500201 w/CTL)
30500213 Asphalt Concrete, Storage Silo
30500221 Asphalt Concrete, Elevators: Continuous Process
30500242 Asphalt Concrete, Mixers: Drum Mix Process ** (use 3-05-002-005 and subtypes)
30500290 Asphalt Concrete, Haul Roads: General
30500299 Asphalt Concrete, See Comment **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
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AT-A-GLANCE TABLE FOR POINT SOURCES
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
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(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Hot mix asphalt (HMA) paving material is a scientifically proportioned mixture of graded aggregates
and asphalt cement. The process of producing involves drying and heating the aggregates to
prepare them for the asphalt cement coating.
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
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References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Asphalt Manufacture
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3222	POD: 222
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
305001** Mineral Products, Asphalt Roofing Manufacture
305002** Mineral Products, Asphalt Concrete
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Asphalt Manufacture
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4222	POD: 222
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
305001** Mineral Products, Asphalt Roofing Manufacture
305002** Mineral Products, Asphalt Concrete
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Beef Cattle Feedlots
Control Measure Name: Watering
Rule Name: Not Applicable
Pechan Measure Code: Pcatf
POD: N/A
Application: Control of fugitive dust emissions from agricultural (cattle) feedlots is most often
performed by watering from either stationary sprinklers or from water trucks.
This control is applicable to all beef cattle feedlots classified under SCC 2805001000.
Affected SCC:
2805001000 Beef Cattle Feedlots, Total (also see 2805020000)
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 50% from uncontrolled; PM2.5 control efficiency is
25% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Control costs were estimated by assuming that installation of a stationary sprinkler
system is required. Peters profiled estimates of capital and O&M costs (Peters,
1977). The mid-range capital cost was $6.50 per head and the mid-range O&M cost
was $0.30 per head. Both of these figures are in 1975 dollars. Assuming a 10-year
life and 5% discount rate for the sprinkler system, the TACs are $1.58 per head
(1975$). To estimate cost per ton of PM10 reduced the emission factor (0.017
tons/head) and the control efficiency (50%) are applied to yield $186 per ton PM10
reduced (1975$).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $307 per ton PM reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1998: E.H. Pechan & Associates, Inc., "Clean Air Act Section 812 Prospective Cost
Analysis - Draft Report," prepared for Industrial Economics, Inc., Cambridge, MA, September 1998.
Peters, 1977: J.A. Peters, and T>R> Blackwood, Monsanto Research Corporation, "Source
Assessment: Beef Cattle Feedlots," prepared for U.S. Environmental Agency, Office of Research
and Development, Research Triangle Park, NC, June 1977.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Chemical Manufacture
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2251	POD: 225
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to various chemical manufacturing operations, including (but not
limited to) adipic acid, ammonia, carbon black, charcoal, cleaners, phosphoric acids,
plastics, sulfuric acid, sodium carbonate, ammonium nitrate, rubbers, ammonium
phosphates, and inorganic pigments.
Affected SCC:
30100104 Adipic Acid, Nitric Acid Reaction
30100106 Adipic Acid, Drying, Loading, and Storage
30100199 Adipic Acid, Other Not Classified
30100305	Ammonia Production, Feedstock Desulfurization
30100306	Ammonia Production, Primary Reformer: Natural Gas Fired
30100309	Ammonia Production, Condensate Stripper
30100310	Ammonia Production, Storage and Loading Tanks
30100399 Ammonia Production, Other Not Classified
30100502	Carbon Black Production, Thermal Process
30100503	Carbon Black Production, Gas Furnace Process: Main Process Vent
30100504	Carbon Black Production, Oil Furnace Process: Main Process Vent
30100506	Carbon Black Production, Transport Air Vent
30100507	Carbon Black Production, Pellet Dryer
30100508	Carbon Black Production, Bagging/Loading
30100509	Carbon Black Production, Furnace Process: Fugitive Emissions
30100599 Carbon Black Production, Other Not Classified
30100601 Chemical Manufacturing, Charcoal Manufacturing, General
30100603	Charcoal Manufacturing, Batch Kiln
30100604	Charcoal Manufacturing, Continuous Kiln
30100605	Charcoal Manufacturing, Briquetting
30100699 Chemical Manufacturing, Charcoal Manufacturing, Other Not Classified
30100799 Chlorine, Other Not Classified **
30100801	Chloro-alkali Production, Liquefaction (Diaphragm Cell Process)
30100802	Chloro-alkali Production, Liquefaction (Mercury Cell Process)
30100899 Chloro-alkali Production, Other Not Classified
30100901	Chemical Manufacturing, Cleaning Chemicals, Spray Drying: Soaps and Detergents
30100902	Chemical Manufacturing, Cleaning Chemicals, Specialty Cleaners
30100999 Chemical Manufacturing, Cleaning Chemicals, Other Not Classified
30101001 Chemical Manufacturing, Explosives (Trinitrotoluene)
30101199 Hydrochloric Acid, Other Not Classified
30101205 Hydroflouric Acid, Fluorspar Transfer
30101401 Chemical Manufacturing, Paint Manufacture, General Mixing and Handling
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AT-A-GLANCE TABLE FOR POINT SOURCES
30101402 Chemical Manufacturing, Paint Manufacture, Pigment Handling
30101415 Paint Manufacture, Premix/Preassembly
30101499 Paint Manufacture, Other Not Classified
30101599 Chemical Manufacturing, Varnish Manufacturing, Other Not Classified
30101601	Phosphoric Acid: Wet Process, Reactor
30101602	Phosphoric Acid: Wet Process, Gypsum Pond
30101699 Phosphoric Acid: Wet Process, Other Not Classified
30101702	Phosphoric Acid: Thermal Process, Absorber: General
30101703	Phosphoric Acid: Thermal Process, Absorber with Packed Tower
30101704	Phosphoric Acid: Thermal Process, Absorber with Venturi Scrubber
30101706 Phosphoric Acid: Thermal Process, Absorber with Wire Mist Eliminator
30101799 Phosphoric Acid: Thermal Process, Other Not Classified
30101801	Plastics Production, Polyvinyl Chlorides and Copolymers ** (Use 6-46-3X0-XX)
30101802	Plastics Production, Polypropylene and Copolymers
30101805 Chemical Manufacturing, Plastics Production, Phenolic Resins
30101807 Plastics Production, General: Polyethylene (High Density)
30101810 Plastics Production, Conveying
30101812 Plastics Production, General: Polyethylene (Low Density)
30101819 Plastics Production, Solvent Recovery
30101821	Plastics Production, Extruding/Pelletizing/Conveying/Storage
30101822	Plastics Production, Acrylic Resins
30101827 Plastics Production, Polyamide Resins
30101837	Plastics Production, Polyester Resins
30101838	Plastics Production, Reactor Kettle ** (Use 6-45-200-11 or 6-45-210-11)
30101849 Plastics Production, Acrylonitrile-Butadiene-Styrene (ABS) Resin
30101883 Plastics Production, Transferring/Conveying/Storage (Polyurethane)
30101892 Plastics Production, Separation Processes
30101899 Chemical Manufacturing, Plastics Production, Others Not Specified
30101901 Phthalic Anhydride, o-Xylene Oxidation: Main Process Stream
30102001 Chemical Manufacturing, Printing Ink Manufacture, Vehicle Cooking: General
30102005 Chemical Manufacturing, Printing Ink Manufacture, Pigment Mixing
30102099 Printing Ink Manufacture, Other Not Classified
30102102 Sodium Carbonate, Solvay Process: Handling
30102113 Sodium Carbonate, Bleacher: Gas-fired
30102121	Sodium Carbonate, Ore Crushing and Screening
30102122	Sodium Carbonate, Soda Ash Storage: Loading and Unloading
30102127 Sodium Carbonate, Soda Ash Screening
30102199 Sodium Carbonate, Other Not Classified
30102301 Chemical Manufacturing, Sulfuric Acid (Contact Process), Absorber/@ 99.9% Conversion
30102304 Sulfuric Acid (Contact Process), Absorber/@ 99.5% Conversion
30102306 Sulfuric Acid (Contact Process), Absorber/@ 99.0% Conversion
30102308 Sulfuric Acid (Contact Process), Absorber/@ 98.0% Conversion
30102318 Sulfuric Acid (Contact Process), Absorber/@ 93.0% Conversion
30102399 Chemical Manufacturing, Sulfuric Acid (Contact Process), Other Not Classified
30102401	Synthetic Organic Fiber Manufacturing, Nylon #6: Staple (Uncontrolled)
30102402	Synthetic Organic Fiber Manufacturing, Polyesters: Staple
30102414 Synthetic Organic Fiber Manufacturing, Polyolefin: Melt Spun
30102499 Synthetic Organic Fiber Manufacturing, Other Not Classified
30102501 Cellulosic Fiber Production, Viscose (e.g., Rayon) ** (Use 6-49-200-XX)
30102505 Cellulosic Fiber Production, Cellulose Acetate: Filer Tow
30102601 Synthetic Rubber (Manufacturing Only), General
30102614 Synthetic Rubber (Manufacturing Only), Blending Tanks
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AT-A-GLANCE TABLE FOR POINT SOURCES
30102656 Synthetic Rubber (Manufacturing Only), Fugitive Emissions: Carbon Black Storage
30102699 Synthetic Rubber (Manufacturing Only), Other Not Classified
30102701 Ammonium Nitrate Production, Prilling Tower: Neutralizer **
30102704 Ammonium Nitrate Production, Neutralizer
30102707 Ammonium Nitrate Production, Rotary Drum Granulator
30102709	Ammonium Nitrate Production, Bulk Loading (General)
30102710	Ammonium Nitrate Production, Bagging of Product
30102711	Ammonium Nitrate Production, Neutralizer: High Density
30102712	Ammonium Nitrate Production, Prilling Tower: High Density
30102713	Ammonium Nitrate Production, High Density Dryers and Coolers (scb**
30102714	Ammonium Nitrate Production, Prilling Cooler: High Density
30102717	Ammonium Nitrate Production, Evaporator/Concentrator: High Density
30102718	Ammonium Nitrate Production, Coating: High Density
30102721	Ammonium Nitrate Production, Neutralizer: Low Density
30102722	Ammonium Nitrate Production, Prilling Tower: Low Density
30102724	Ammonium Nitrate Production, Prilling Cooler: Low Density
30102725	Ammonium Nitrate Production, Prilling Dryer: Low Density
30102727	Ammonium Nitrate Production, Evaporator/Concentrator: Low Density
30102728	Ammonium Nitrate Production, Coating: Low Density
30102801 Normal Superphosphates, Grinding/Drying
30102803 Normal Superphosphates, Rock Unloading
30102823 Normal Superphosphates, Ammoniator/Granulator
30102905	Triple Superphosphate, Run of Pile: Mixer/Den/Curing
30102906	Triple Superphosphate, Granulator: Reactor/Dryer
30102922 Triple Superphosphate, Curing
30102924 Triple Superphosphate, Dryer
30103001	Ammonium Phosphates, Dryers and Coolers
30103002	Ammonium Phosphates, Ammoniator/Granulator
30103004 Ammonium Phosphates, Bagging/Handling
30103023	Ammonium Phosphates, Ammoniator/Granulator
30103024	Ammonium Phosphates, Dryer
30103025	Ammonium Phosphates, Cooler
30103099 Ammonium Phosphates, Other Not Classified
30103101 Terephthalic Acid/Dimethyl Terephthalate, HN03- Para-xylene: General
30103105 Terephthalic Acid/Dimethyl Terephthalate, Product Transfer Vent
30103199 Terephthalic Acid/Dimethyl Terephthalate, Other Not Classified
30103399 Pesticides, Other Not Classified
30103501 Chemical Manufacturing, Inorganic Pigments, Ti02 Sulfate Process: Calciner
30103503 Inorganic Pigments, Ti02 Chloride Process: Reactor
30103551	Inorganic Pigments, Ore Dryer
30103552	Inorganic Pigments, Pigment Milling
30103553	Chemical Manufacturing, Inorganic Pigments, Pigment Dryer
30103554	Chemical Manufacturing, Inorganic Pigments, Conveying/Storage/Packing
30103599 Chemical Manufacturing, Inorganic Pigments, Other Not Classified
30103801 Sodium Bicarbonate, General
30104001	Urea Production, General: Specify in Comments
30104002	Urea Production, Solution Concentration (Controlled)
30104003	Urea Production, Prilling
30104004	Urea Production, Drum Granulation
30104006	Urea Production, Bagging
30104007	Urea Production, Bulk Loading
30104008	Urea Production, Non-fluidized Bed Prilling (Agricultural Grade)
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AT-A-GLANCE TABLE FOR POINT SOURCES
30104010	Urea Production, Fluidized Bed Prilling (Agricultural Grade)
30104011	Urea Production, Fluidized Bed Prilling (Feed Grade)
30104013 Urea Production, Solids Screening
30104501 Chemical Manufacturing, Organic Fertilizer, General: Mixing/Handling
30106010 Pharmaceutical Preparations, Storage/Transfer
30106099 Chemical Manufacturing, Pharmaceutical Preparations, Other Not Classified
30107001	Inorganic Chemical Manufacturing (General), Fugitive Leaks
30107002	Chemical Manufacturing, Inorganic Chemical Manufacturing (General), Storage/Transfer
30112199 Organic Dyes/Pigments, Other Not Classified
30112501 Chlorine Derivatives, Ethylene Dichloride via Oxychlorination
30112541 Chlorine Derivatives, Vinyl Chloride: Cracking Furnace
30112599 Chlorine Derivatives, Other Not Classified
30112699 Brominated Organics, Bromine Organics
30113003	Ammonium Sulfate (Use 3-01-210 for Caprolactum Production), Process Vents
30113004	Ammonium Sulfate (Use 301210 Caprolactum), Caprolactum By-product-Rotary Dryer
30113221 Organic Acid Manufacturing, General: Acrylic Acid
30113299 Organic Acid Manufacturing, Other Not Classified
30115201 Bisphenol A, General
30116799 Vinyl Acetate, Other Not Classified
30117601 Glycerin (Glycerol), General
30118101 Toluene Diisocyanate, General
30119080 Methyl Methacrylate, Fugitive Emissions
30119701 Butylene, Ethylene, Propylene, Olefin Production, Ethylene: General
30121101 Chemical Manufacturing, Linear Alkylbenzene, Olefin Process: General
30125001 Methanol/Alcohol Production, Methanol: General
30125010 Methanol/Alcohol Production, Ethanol by Fermentation
30125099 Methanol/Alcohol Production, Other Not Classified
30125420 Nitriles, Acrylonitrile, Adiponitrile Production, Fugitive Emissions
30125499 Nitriles, Acrylonitrile, Adiponitrile Production, Other Not Classified
30180001 General Processes, Fugitive Leaks
30181001 General Processes, Air Oxidation Units
30183001 General Processes, Storage/Transfer
30184001 General Processes, Distillation Units
30188801	Chemical Manufacturing, Fugitive Emissions, Specify in Comments Field
30188802	Fugitive Emissions, Specify in Comments Field
30188803	Fugitive Emissions, Specify in Comments Field
30188804	Fugitive Emissions, Specify in Comments Field
30190003 Fuel Fired Equipment, Natural Gas: Process Heaters
30190012	Fuel Fired Equipment, Residual Oil: Incinerators
30190013	Fuel Fired Equipment, Natural Gas: Incinerators
30190099 Fuel Fired Equipment, Specify in Comments Field
30199998	Chemical Manufacturing, Other Not Classified, Specify in Comments Field
30199999	Chemical Manufacturing, Other Not Classified, Specify in Comments Field
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
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AT-A-GLANCE TABLE FOR POINT SOURCES
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067 $/kW-hr
Process water price 0.20 $/1000gal
Dust disposal	20 $/ton disposed
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AT-A-GLANCE TABLE FOR POINT SOURCES
Wastewater treatment 1.5 $/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wre-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Chemical Manufacture
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3225	POD: 225
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
301028**
301040**
301033**
301030**
301031**
301032**
301029**
301034**
301038**
301091**
301045**
301050**
301112**
301027**
301015**
301060**
301070**
301111**
301100**
301035**
301820**
301001**
301005**
301006**
301007**
301008**
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Manufacturing, Normal Superphosphates
Manufacturing,Urea Production
Manufacturing, Pesticides
Manufacturing, Ammonium Phosphates
Manufacturing, Terephthalic Acid/Dimethyl Terephthalate
Manufacturing, Elemental Sulfur Production
Manufacturing, Triple Superphosphate
Manufacturing, Aniline/Ethanolamines
Manufacturing, Sodium Bicarbonate
Manufacturing, Acetone/Ketone Production
Manufacturing, Organic Fertilizer
Manufacturing, Adhesives
Manufacturing, Elemental Phosphorous
Manufacturing, Ammonium Nitrate Production
Manufacturing, Varnish Manufacturing
Manufacturing, Pharmaceutical Preparations
Manufacturing, Inorganic Chemical Manufacturing (General)
Manufacturing, Asbestos Chemical
Manufacturing, Fluorescent Lamp Manufacture
Manufacturing, Inorganic Pigments
Manufacturing, Wastewater Treatment
Manufacturing, Adipic Acid
Manufacturing, Carbon Black Production
Manufacturing, Charcoal Manufacturing
Manufacturing, Chlorine
Manufacturing, Chloro-alkali Production
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AT-A-GLANCE TABLE FOR POINT SOURCES
301009**
Chemical
Manufactur
ng,
301010**
Chemical
Manufactur
ng,
301011**
Chemical
Manufactur
ng,
301012**
Chemical
Manufactur
ng,
301017**
Chemical
Manufactur
ng,
301014**
Chemical
Manufactur
ng,
301026**
Chemical
Manufactur
ng,
301016**
Chemical
Manufactur
ng,
301114**
Chemical
Manufactur
ng,
301018**
Chemical
Manufactur
ng,
301019**
Chemical
Manufactur
ng,
301020**
Chemical
Manufactur
ng,
301021**
Chemical
Manufactur
ng,
301023**
Chemical
Manufactur
ng,
301024**
Chemical
Manufactur
ng,
301025**
Chemical
Manufactur
ng,
301013**
Chemical
Manufactur
ng,
301810**
Chemical
Manufactur
ng,
301800**
Chemical
Manufactur
ng,
301121**
Chemical
Manufactur
ng,
301999**
Chemical
Manufactur
ng,
301900**
Chemical
Manufactur
ng,
301888**
Chemical
Manufactur
ng,
301840**
Chemical
Manufactur
ng,
301830**
Chemical
Manufactur
ng,
301258**
Chemical
Manufactur
ng,
301254**
Chemical
Manufactur
ng,
301140**
Chemical
Manufactur
ng,
301125**
Chemical
Manufactur
ng,
301130**
Chemical
Manufactur
ng,
301132**
Chemical
Manufactur
ng,
301252**
Chemical
Manufactur
ng,
301152**
Chemical
Manufactur
ng,
301202**
Chemical
Manufactur
ng,
301210**
Chemical
Manufactur
ng,
Production)


301250**
Chemical
Manufacturing,
Cleaning Chemicals
Explosives (Trinitrotoluene)
Hydrochloric Acid
Hydroflouric Acid
Phosphoric Acid: Thermal Process
Paint Manufacture
Synthetic Rubber (Manufacturing Only)
Phosphoric Acid: Wet Process
Potassium Chloride
Plastics Production
Phthalic Anhydride
Printing Ink Manufacture
Sodium Carbonate
Sulfuric Acid (Contact Process)
Synthetic Organic Fiber Manufacturing
Cellulosic Fiber Production
Nitric Acid
General Processes, Air Oxidation Units
General Processes
Organic Dyes/Pigments
Other Not Classified
Fuel Fired Equipment
Fugitive Emissions
General Processes, Distillation Units
General Processe, Storage/Transfer
Benzene/Toluene/Aromatics/Xylenes
Nitriles, Acrylonitrile, Adiponitrile Production
Acetylene Producion
Chlorine Derivatives
Ammonium Sulfate (Use 3-01-210 for Caprolactum Production)
Organic Acid Manufacturing
Etherene Production
Bisphenol A
Phenol
Caprolactum (Use 3-01-130 for Ammonium Sulfate By-product
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
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monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Chemical Manufacture
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4225	POD: 225
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
301028**
301040**
301033**
301030**
301031**
301032**
301029**
301034**
301038**
301091**
301045**
301050**
301112**
301027**
301015**
301060**
301070**
301111**
301100**
301035**
301820**
301001**
301005**
301006**
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Chemica
Manufacturing, Normal Superphosphates
Manufacturing,Urea Production
Manufacturing, Pesticides
Manufacturing, Ammonium Phosphates
Manufacturing, Terephthalic Acid/Dimethyl Terephthalate
Manufacturing, Elemental Sulfur Production
Manufacturing, Triple Superphosphate
Manufacturing, Aniline/Ethanolamines
Manufacturing, Sodium Bicarbonate
Manufacturing, Acetone/Ketone Production
Manufacturing, Organic Fertilizer
Manufacturing, Adhesives
Manufacturing, Elemental Phosphorous
Manufacturing, Ammonium Nitrate Production
Manufacturing, Varnish Manufacturing
Manufacturing, Pharmaceutical Preparations
Manufacturing, Inorganic Chemical Manufacturing (General)
Manufacturing, Asbestos Chemical
Manufacturing, Fluorescent Lamp Manufacture
Manufacturing, Inorganic Pigments
Manufacturing, Wastewater Treatment
Manufacturing, Adipic Acid
Manufacturing, Carbon Black Production
Manufacturing, Charcoal Manufacturing
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AT-A-GLANCE TABLE FOR POINT SOURCES
301007**
Chemical
Manufactur
ng,
301008**
Chemical
Manufactur
ng,
301009**
Chemical
Manufactur
ng,
301010**
Chemical
Manufactur
ng,
301011**
Chemical
Manufactur
ng,
301012**
Chemical
Manufactur
ng,
301017**
Chemical
Manufactur
ng,
301014**
Chemical
Manufactur
ng,
301026**
Chemical
Manufactur
ng,
301016**
Chemical
Manufactur
ng,
301114**
Chemical
Manufactur
ng,
301018**
Chemical
Manufactur
ng,
301019**
Chemical
Manufactur
ng,
301020**
Chemical
Manufactur
ng,
301021**
Chemical
Manufactur
ng,
301023**
Chemical
Manufactur
ng,
301024**
Chemical
Manufactur
ng,
301025**
Chemical
Manufactur
ng,
301013**
Chemical
Manufactur
ng,
301810**
Chemical
Manufactur
ng,
301800**
Chemical
Manufactur
ng,
301121**
Chemical
Manufactur
ng,
301999**
Chemical
Manufactur
ng,
301900**
Chemical
Manufactur
ng,
301888**
Chemical
Manufactur
ng,
301840**
Chemical
Manufactur
ng,
301830**
Chemical
Manufactur
ng,
301258**
Chemical
Manufactur
ng,
301254**
Chemical
Manufactur
ng,
301140**
Chemical
Manufactur
ng,
301125**
Chemical
Manufactur
ng,
301130**
Chemical
Manufactur
ng,
301132**
Chemical
Manufactur
ng,
301252**
Chemical
Manufactur
ng,
301152**
Chemical
Manufactur
ng,
301202**
Chemical
Manufactur
ng,
301210**
Chemical
Manufactur
ng,
Production)


301250**
Chemical
Manufacturing,
Chlorine
Chloro-alkali Production
Cleaning Chemicals
Explosives (Trinitrotoluene)
Hydrochloric Acid
Hydroflouric Acid
Phosphoric Acid: Thermal Process
Paint Manufacture
Synthetic Rubber (Manufacturing Only)
Phosphoric Acid: Wet Process
Potassium Chloride
Plastics Production
Phthalic Anhydride
Printing Ink Manufacture
Sodium Carbonate
Sulfuric Acid (Contact Process)
Synthetic Organic Fiber Manufacturing
Cellulosic Fiber Production
Nitric Acid
General Processes, Air Oxidation Units
General Processes
Organic Dyes/Pigments
Other Not Classified
Fuel Fired Equipment
Fugitive Emissions
General Processes, Distillation Units
General Processe, Storage/Transfer
Benzene/Toluene/Aromatics/Xylenes
Nitriles, Acrylonitrile, Adiponitrile Production
Acetylene Producion
Chlorine Derivatives
Ammonium Sulfate (Use 3-01-210 for Caprolactum Production)
Organic Acid Manufacturing
Etherene Production
Bisphenol A
Phenol
Caprolactum (Use 3-01-130 for Ammonium Sulfate By-product
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
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AT-A-GLANCE TABLE FOR POINT SOURCES
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Commercial Institutional Boilers - Coal
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2051	POD: 205
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to commercial institutional operations with coal-fired boilers.
Affected SCC:
10300101	Anthracite Coal, Pulverized Coal
10300102	Anthracite Coal, Traveling Grate (Overfeed) Stoker
10300205	Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Bituminous Coal)
10300206	Commercial/Institutional, Pulverized Coal-Dry Bottom (Bituminous Coal)
10300207	Commercial/Institutional, Overfeed Stoker (Bituminous Coal)
10300208	Commercial/Institutional, Underfeed Stoker (Bituminous Coal)
10300209	Commercial/Institutional, Spreader Stoker (Bituminous Coal)
10300217 Commercial/Institutional, Atm. Fluidized Bed Combustion-Bubbling (Bituminous Coal)
10300223	Bituminous/Subbituminous Coal, Cyclone Furnace (Subbituminous Coal)
10300224	Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10300225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
10300309 Lignite, Spreader Stoker
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
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on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
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Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
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References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Commercial Institutional Boilers - Coal
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2052	POD: 205
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to point sources with coal-fired boilers.
Affected SCC:
10300101	Anthracite Coal, Pulverized Coal
10300102	Anthracite Coal, Traveling Grate (Overfeed) Stoker
10300205	Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Bituminous Coal)
10300206	Commercial/Institutional, Pulverized Coal-Dry Bottom (Bituminous Coal)
10300207	Commercial/Institutional, Overfeed Stoker (Bituminous Coal)
10300208	Commercial/Institutional, Underfeed Stoker (Bituminous Coal)
10300209	Commercial/Institutional, Spreader Stoker (Bituminous Coal)
10300217 Commercial/Institutional, Atm. Fluidized Bed Combustion-Bubbling (Bituminous Coal)
10300224	Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10300225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
10300309 Lignite, Spreader Stoker
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
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AT-A-GLANCE TABLE FOR POINT SOURCES
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal 25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
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AT-A-GLANCE TABLE FOR POINT SOURCES
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Commercial Institutional Boilers - Coal
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2053	POD: 205
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to commercial industrial operations with coal-fired boilers.
Affected SCC:
10300101	Anthracite Coal, Pulverized Coal
10300102	Anthracite Coal, Traveling Grate (Overfeed) Stoker
10300205	Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Bituminous Coal)
10300206	Commercial/Institutional, Pulverized Coal-Dry Bottom (Bituminous Coal)
10300207	Commercial/Institutional, Overfeed Stoker (Bituminous Coal)
10300208	Commercial/Institutional, Underfeed Stoker (Bituminous Coal)
10300209	Commercial/Institutional, Spreader Stoker (Bituminous Coal)
10300217 Commercial/Institutional, Atm. Fluidized Bed Combustion-Bubbling (Bituminous Coal)
10300223	Bituminous/Subbituminous Coal, Cyclone Furnace (Subbituminous Coal)
10300224	Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10300225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
10300309 Lignite, Spreader Stoker
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
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AT-A-GLANCE TABLE FOR POINT SOURCES
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
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AT-A-GLANCE TABLE FOR POINT SOURCES
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Coal
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3205	POD: 205
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103001** Anthracite Coal, Pulverized Coal
103002** Bituminous/Subbituminous Coal, Pulverized Coal
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Coal
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4205	POD: 205
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103001** Anthracite Coal, Pulverized Coal
103002** Bituminous/Subbituminous Coal, Pulverized Coal
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Liquid Waste
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3228	POD: 228
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103013** Commercial/Institutional, Liquid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Liquid Waste
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4228	POD: 228
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103013** Commercial/Institutional, Liquid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - LPG
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3227	POD: 227
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103010** Commercial/Institutional, Liquified Petroleum Gas (LPG)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - LPG
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4227	POD: 227
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103010** Commercial/Institutional, Liquified Petroleum Gas (LPG)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Natural Gas
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3229	POD: 229
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103006** Commercial/Institutional, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Natural Gas
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4229	POD: 229
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103006** Commercial/Institutional, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Commercial Institutional Boilers - Oil
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2071	POD: 207
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to point sources with oil-fired boilers.
Affected SCC:
10300401 Commercial/Institutional, Residual Oil, Grade 6 Oil
10300403 Residual Oil, < 10 Million Btu/hr**
10300501 Commercial/Institutional, Distillate Oil, Grades 1 and 2 Oil
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
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AT-A-GLANCE TABLE FOR POINT SOURCES
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25	$/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
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AT-A-GLANCE TABLE FOR POINT SOURCES
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Oil
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3207	POD: 207
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103004** Commercial/Institutional, Residual Oil
103005** Commercial/Institutional, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Oil
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4207	POD: 207
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103004** Commercial/Institutional, Residual Oil
103005** Commercial/Institutional, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Process Gas
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3230	POD: 230
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103007** Commercial/Institutional, Process Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Process Gas
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4230	POD: 230
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103007** Commercial/Institutional, Process Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Solid Waste
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3231	POD: 231
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103012** Commercial/Institutional, Solid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Solid Waste
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4231	POD: 231
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103012** Commercial/Institutional, Solid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Commercial Institutional Boilers - Wood
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3206	POD: 206
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103009** Commercial/Institutional, Wood/Bark Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Commercial Institutional Boilers - Wood
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4206	POD: 206
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
103009** Commercial/Institutional, Wood/Bark Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Commercial Institutional Boilers - Wood/Bark
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2061	POD: 206
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to commercial institutional operations with wood-fired boilers.
Affected SCC:
10300901	Wood/Bark Waste, Bark-fired Boiler
10300902	Wood/Bark Waste, Wood/Bark-fired Boiler
10300903	Commercial/Institutional, Wood/Bark Waste, Wood-fired Boiler
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000).. Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
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with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
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In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
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Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Commercial Institutional Boilers - Wood/Bark
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2062	POD: 206
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to point sources with wood-fired boilers.
Affected SCC:
10300901	Wood/Bark Waste, Bark-fired Boiler
10300902	Wood/Bark Waste, Wood/Bark-fired Boiler
10300903	Commercial/Institutional, Wood/Bark Waste, Wood-fired Boiler
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
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equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
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field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Commercial Institutional Boilers - Wood/Bark
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2063	POD: 206
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to commercial institutional operations with wood-fired boilers.
Affected SCC:
10300901	Wood/Bark Waste, Bark-fired Boiler
10300902	Wood/Bark Waste, Wood/Bark-fired Boiler
10300903	Commercial/Institutional, Wood/Bark Waste, Wood-fired Boiler
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
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AT-A-GLANCE TABLE FOR POINT SOURCES
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air	0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
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much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Construction Activities
Control Measure Name: Dust Control Plan
Rule Name: Dust Control Plan
Pechan Measure Code: Pcnst
POD: N/A
Application: The dust control plan includes chemical suppression and water treatment of disturbed
soil at construction sites.
This control is useful in the reduction of PM from construction areas, including heavy
construction sites and road construction operations.
Affected SCC:
2311010000 General Building Construction, Total
2311020000 Heavy Construction, Total
2311030000 Road Construction, Total
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 63% from uncontrolled; PM2.5 control efficiency is
37% from uncontrolled.
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The annual cost for the dust control plan ($4,900 per acre) can be calculated as the
sum of the annual costs for each control technique:
Site watering = $1,395 per acre ($3,720 per acre x 1 acre x 37.5 percent);
Chemical stabilization = $3,506 per acre ($9,350 per acre x 1 acre x 37.5 percent).
Annual emission reductions for the dust control plan can be calculated by applying
the 75 percent penetration factor and overall 62.5 percent control efficiency to annual
emissions. For one acre of construction activity, a 1.36 tpy reduction in PM-10
emissions is estimated for the dust control plan. Based on this information, the cost
effectiveness of the dust control plan is estimated to be $3,600 per ton of PM-10
reduced (Pechan, 1997).
Note: All costs are in 1990 dollars.
Cost Effectiveness: The cost effectiveness is $3,600 per ton PM10 reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
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AT-A-GLANCE TABLE FOR AREA SOURCES
Additional Information:
The most complete information available pertaining to construction PM emissions control is for site
watering. Site watering is an attractive option because many construction jobs already have
necessary equipment and facilities and need only more personnel for this task (EPA, 1974). The
length of PM emission reduction from site watering is brief, requiring more than one application a
day. Chemical suppressants provide a higher level of control which is longer-lasting than site
watering. The higher cost of suppressants versus watering generally precludes their use in
construction areas that undergo substantial improvements (e.g., earthmoving).
Chemical stabilization efficiency is dependent upon application rates. The EPA recommends that at
least dilute reapplications be employed every month (EPA, 1994).
References:
EPA, 1974: U.S. Environmental Protection Agency, "Investigation of Fugitive Dust, Volume I-
Sources, Emissions, and Control," EPA-450/3-74-036a. June 1974.
EPA, 1994: U.S. Environmental Protection Agency, Office of Policy, Planning, and Evaluation,
National PM Study: "OPPE Particulate Programs Implementation Evaluation System," Washington,
DC. September 1994.
Pechan, 1997: E.H. Pechan & Associates, "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Conveyorized Charbroilers
Control Measure Name: Catalytic Oxidizer
Rule Name: Not Applicable
Pechan Measure Code: Pcharb	POD: N/A
Application: Catalytic Oxidizer control device burns or oxidizes smoke and gases from the cooking
process to carbon dioxide and water, using an infrastructure coated with a noble metal
alloy.
Affected SCC:
2302002000 Food and Kindred Products: SIC 20, Commercial Charbroiling, Total
2302002100 Food and Kindred Products: SIC 20, Commercial Charbroiling
2302002200 Food and Kindred Products: SIC 20, Commercial Charbroiling
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*



V




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 83% from uncontrolled for PM & VOC
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Control costs were estimated by assuming that replacement catalyst is bought when
the original system is purchased.
The Cost per ton calculation:
Baseline PM Emissions per restaurant = 0.61 tons / yr
Capital Recovery Factor (CRF) (10 years @ 8%) = 0.149
$ / ton = [0.149($5,657.5 + $3,700)] + $107.5 / [(0.83 reduction) (0.61 PM)]
= $2,966 / year
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2966 per ton PM reduced
(2001$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
References:
Ventura County, 2004: Ventura County, "Final Staff Report: Proposed New Rule 74.25, Restaurant
Cooking Operations Proposed Revisions to Rule 23, Exemptions From Permit", August 31, 2004
CE-ERT, 2002: CE-CERT, UC-Riverside: "Assessment of Emissions from a Chain-Driven
Charbroilers using a Catalytic Control device." Final Report for Engelhard Corp., September 13,
2002
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Coke
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3232	POD: 232
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101008** Electric Generation, Coke
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Coke
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4232	POD: 232
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101008** Electric Generation, Coke
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Bagasse
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3233	POD: 233
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101011** Electric Generation, Bagasse
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Bagasse
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4233	POD: 233
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101011** Electric Generation, Bagasse
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Coal
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3226	POD: 226
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101001** Electric Generation, Anthracite Coal
101003** Electric Generation, Lignite
101002** Electric Generation, Bituminous/Subbituminous Coal
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Document No. 05.09.009/9010.463
III-735
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Coal
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4226	POD: 226
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101001** Electric Generation, Anthracite Coal
101003** Electric Generation, Lignite
101002** Electric Generation, Bituminous/Subbituminous Coal
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Note: All costs are in 2003 dollars.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Liquid Waste
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3235	POD: 235
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101013** Electric Generation, Liquid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Document No. 05.09.009/9010.463
III-739
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Liquid Waste
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4235	POD: 235
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101013** Electric Generation, Liquid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - LPG
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3234	POD: 234
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101010** Electric Generation, Liquified Petroleum Gas (LPG)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Document No. 05.09.009/9010.463
III-743
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - LPG
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4234	POD: 234
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101010** Electric Generation, Liquified Petroleum Gas (LPG)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Document No. 05.09.009/9010.463
III-745
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
Document No. 05.09.009/9010.463
III-746
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Natural Gas
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3236	POD: 236
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101006** Electric Generation, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Document No. 05.09.009/9010.463
III-747
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
Document No. 05.09.009/9010.463
III-748
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Natural Gas
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4236	POD: 236
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101006** Electric Generation, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Document No. 05.09.009/9010.463
III-749
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Oil
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3237	POD: 237
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101004** Electric Generation, Residual Oil
101005** Electric Generation, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Document No. 05.09.009/9010.463
III-751
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Oil
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4237	POD: 237
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101004** Electric Generation, Residual Oil
101005** Electric Generation, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Document No. 05.09.009/9010.463
III-753
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Solid Waste
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3238	POD: 238
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101012** Electric Generation, Solid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Document No. 05.09.009/9010.463
III-755
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Solid Waste
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4238	POD: 238
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101012** Electric Generation, Solid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Wood
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3239	POD: 239
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101009** Electric Generation, Wood/Bark Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Document No. 05.09.009/9010.463
III-759
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
Document No. 05.09.009/9010.463
III-760
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Electric Generation - Wood
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4239	POD: 239
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
101009** Electric Generation, Wood/Bark Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Fabricated Metal Products - Abrasive Blasting
Control Measure Name: Paper/Nonwoven Filters - Cartridge Collector Type
Rule Name: Not Applicable
Pechan Measure Code: P2271	POD: 227
Application: This control is the use of paper or non-woven filters (cartridge collector type) to reduce
PM emissions. The waste gas stream is passed through the fibrous filter media
causing PM in the gas stream to be collected on the media by sieving and other
mechanisms.
This control measure applies to abrasive blasting operations as a part of fabricated
metal products processing and production.
Affected SCC:
30900201	Fabricated Metal Products, Abrasive Blasting of Metal Parts, General
30900202	Fabricated Metal Products, Abrasive Blasting of Metal Parts, Sand Abrasive
30900203	Fabricated Metal Products, Abrasive Blasting of Metal Parts, Slag Abrasive
30900205 Fabricated Metal Products, Abrasive Blasting of Metal Parts, Steel Grit Abrasive
30900207	Fabricated Metal Products, Abrasive Blasting of Metal Parts, Shotblast with Air
30900208	Abrasive Blasting of Metal Parts, Shotblast w/o Air
30900299 Fabricated Metal Products, Abrasive Blasting of Metal Parts, General
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are generated using EPA's cost-estimating spreadsheets for fabric filters
(EPA, 1998a). Costs are primarily driven by the waste stream volumetric flow rate
and pollutant loading. When stack gas flow rate data was available, the costs and
cost effectiveness were calculated using the typical values of capital and O&M costs.
When stack gas flow rate data was not available, default typical capital and O&M cost
values based on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
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equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $7 to $13 per scfm
Typical value is $9 per scfm
O&M Costs:
Range from $9 to $25 per scfm
Typical value is $14 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average cartridge cost was estimated using the costs for standard
cartridge types. Capital recovery for the periodic replacement of cartridges was
included in the O&M cost of the cartridges using a cartridge life of 2 years (EPA,
1998a). The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal 25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available, the cost effectiveness varies from $85 to $256
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $142 per ton
PM10 reduced. (1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. Auxiliary
equipment, such as fans and ductwork, is not included (EPA, 2000). Pollutants that require an
unusually high level of control or that require the filter media or the unit itself to be constructed of
special materials, such as Nomex ® or stainless steel, will increase the costs of the system (EPA,
1998a). The additional costs for controlling more complex waste streams are not reflected in the
estimates given below. For these types of systems, the capital cost could increase by as much as
75% and the O&M cost could increase by as much as 10%. In general, a small unit controlling a low
pollutant loading will not be as cost effective as a large unit controlling a high pollutant loading (EPA,
2000).
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Cartridge filters contain either a paper or nonwoven fibrous filter media (EPA, 2000). Paper media is
generally made of materials such as cellulose and fiberglass. The dust cake that forms on the filter
media from the collected PM can significantly increase collection efficiency (EPA, 1998b).
In general, the filter media is pleated to provide a larger surface area to volume flow rate. Close
pleating, however, can cause PM to bridge the pleat bottom, effectively reducing the surface
collection area (EPA, 1998b). Corrugated aluminum separators are used to prevent the pleats from
collapsing (Heumann, 1997). There are variety of cartridge designs and dimensions. Typical
designs include flat panels, V-shaped packs or cylindrical packs (Heumann, 1997). For certain
applications, two cartridges may be placed in series.
Cartridge collectors are useful for collecting particles with resistivities either too low or too high for
collection with electrostatic precipitators (STAPPA/AI_APCO, 1996). For similar air flow rates,
cartridge collectors are compact in size compared to traditional bag
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Cartridge Collector with Pulse-Jet Cleaning," April 2000.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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Source Category: Fabricated Metal Products - Welding
Control Measure Name: Paper/Nonwoven Filters - Cartridge Collector Type
Rule Name: Not Applicable
Pechan Measure Code: P2291	POD: 229
Application: This control is the use of paper or non-woven filters (cartridge collector type) to reduce
PM emissions. The waste gas stream is passed through the fibrous filter media
causing PM in the gas stream to be collected on the media by sieving and other
mechanisms.
This control measure applies to welding operations as a part of fabricated metal
products processing and production, classified under SCCs 30900501 and 30904001.
Affected SCC:
30900501 Welding, Arc Welding: General ** (See 3-09-050)
30904001 Fabricated Metal Products, Metal Deposition, Metallizing-Wre Atomization & Spraying
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are generated using EPA's cost-estimating spreadsheets for fabric filters
(EPA, 1998a). Costs are primarily driven by the waste stream volumetric flow rate
and pollutant loading. When stack gas flow rate data was available, the costs and
cost effectiveness were calculated using the typical values of capital and O&M costs.
When stack gas flow rate data was not available, default typical capital and O&M cost
values based on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
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Capital Costs:
Range from $7 to $13 per scfm
Typical value is $9 per scfm
O&M Costs:
Range from $9 to $25 per scfm
Typical value is $14 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average cartridge cost was estimated using the costs for standard
cartridge types. Capital recovery for the periodic replacement of cartridges was
included in the O&M cost of the cartridges using a cartridge life of 2 years (EPA,
1998a). The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $85 to $256 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $142 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. Auxiliary
equipment, such as fans and ductwork, is not included (EPA, 2000). Pollutants that require an
unusually high level of control or that require the filter media or the unit itself to be constructed of
special materials, such as Nomex ® or stainless steel, will increase the costs of the system (EPA,
1998a). The additional costs for controlling more complex waste streams are not reflected in the
estimates given below. For these types of systems, the capital cost could increase by as much as
75% and the O&M cost could increase by as much as 10%. In general, a small unit controlling a low
pollutant loading will not be as cost effective as a large unit controlling a high pollutant loading (EPA,
2000).
Cartridge filters contain either a paper or nonwoven fibrous filter media (EPA, 2000). Paper media is
generally made of materials such as cellulose and fiberglass. The dust cake that forms on the filter
media from the collected PM can significantly increase collection efficiency (EPA, 1998b).
In general, the filter media is pleated to provide a larger surface area to volume flow rate. Close
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AT-A-GLANCE TABLE FOR POINT SOURCES
pleating, however, can cause PM to bridge the pleat bottom, effectively reducing the surface
collection area (EPA, 1998b). Corrugated aluminum separators are used to prevent the pleats from
collapsing (Heumann, 1997). There are variety of cartridge designs and dimensions. Typical
designs include flat panels, V-shaped packs or cylindrical packs (Heumann, 1997). For certain
applications, two cartridges may be placed in series.
Cartridge collectors are useful for collecting particles with resistivities either too low or too high for
collection with electrostatic precipitators (STAPPA/ALAPCO, 1996). For similar air flow rates,
cartridge collectors are compact in size compared to traditional bag
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Cartridge Collector with Pulse-Jet Cleaning," April 2000.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Coke
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2131	POD: 213
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to by-product coke metal processing operations.
Affected SCC:
30300302	Primary Metal Production, By-product Coke Manufacturing, Oven Charging
30300303	By-product Coke Manufacturing, Oven Pushing
30300304	By-product Coke Manufacturing, Quenching
30300305	By-product Coke Manufacturing, Coal Unloading
30300306	By-product Coke Manufacturing, Oven Underfiring
30300307	By-product Coke Manufacturing, Coal Crushing/Handling
30300308	By-product Coke Manufacturing, Oven/Door Leaks
30300309	By-product Coke Manufacturing, Coal Conveying
30300310	By-product Coke Manufacturing, Coal Crushing
30300312	By-product Coke Manufacturing, Coke: Crushing/Screening/Handling
30300313	By-product Coke Manufacturing, Coal Preheater
30300314	By-product Coke Manufacturing, Topside Leaks
30300315	Primary Metal Production, By-product Coke Manufacturing, Gas By-product Plant
30300316	By-product Coke Manufacturing, Coal Storage Pile
30300334 By-product Coke Manufacturing, Tar Dehydrator
30300399 By-product Coke Manufacturing, Not Classified **
30300401 Coke Manufacture: Beehive Process, General
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal 25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
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Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Coke
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2132	POD: 213
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to by-product coke metal processing operations.
Affected SCC:
30300302	Primary Metal Production, By-product Coke Manufacturing, Oven Charging
30300303	By-product Coke Manufacturing, Oven Pushing
30300304	By-product Coke Manufacturing, Quenching
30300305	By-product Coke Manufacturing, Coal Unloading
30300306	By-product Coke Manufacturing, Oven Underfiring
30300307	By-product Coke Manufacturing, Coal Crushing/Handling
30300308	By-product Coke Manufacturing, Oven/Door Leaks
30300309	By-product Coke Manufacturing, Coal Conveying
30300310	By-product Coke Manufacturing, Coal Crushing
30300312	By-product Coke Manufacturing, Coke: Crushing/Screening/Handling
30300313	By-product Coke Manufacturing, Coal Preheater
30300314	By-product Coke Manufacturing, Topside Leaks
30300315	Primary Metal Production, By-product Coke Manufacturing, Gas By-product Plant
30300316	By-product Coke Manufacturing, Coal Storage Pile
30300334 By-product Coke Manufacturing, Tar Dehydrator
30300399 By-product Coke Manufacturing, Not Classified **
30300401 Coke Manufacture: Beehive Process, General
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
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References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Ferrous Metals Processing - Coke
Control Measure Name: Venturi Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2133	POD: 213
Application: The control is the use of a venturi scrubber to reduce PM emissions. A scrubber is a
type of technology that removes air pollutants by inertial and diffusional interception. A
venturi scrubber accelerates the waste gas stream to atomize the scrubbing liquid and
to improve gas-liquid contact.
This control applies to by-product coke metal processing operations.
Affected SCC:
30300302	Primary Metal Production, By-product Coke Manufacturing, Oven Charging
30300303	By-product Coke Manufacturing, Oven Pushing
30300304	By-product Coke Manufacturing, Quenching
30300305	By-product Coke Manufacturing, Coal Unloading
30300306	By-product Coke Manufacturing, Oven Underfiring
30300307	By-product Coke Manufacturing, Coal Crushing/Handling
30300308	By-product Coke Manufacturing, Oven/Door Leaks
30300312 By-product Coke Manufacturing, Coke: Crushing/Screening/Handling
30300314	By-product Coke Manufacturing, Topside Leaks
30300315	Primary Metal Production, By-product Coke Manufacturing, Gas By-product Plant
30300316	By-product Coke Manufacturing, Coal Storage Pile
30300334 By-product Coke Manufacturing, Tar Dehydrator
30300399 By-product Coke Manufacturing, Not Classified **
30300401 Coke Manufacture: Beehive Process, General
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 93% from uncontrolled; PM2.5 control efficiency is
89% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for venturi wet scrubbers, developed using EPA cost-
estimating spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of
the waste stream treated. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
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costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $3 to $28 per scfm
Typical value is $11 per scfm
O&M Costs:
Range from $4 to $119 per scfm
Typical value is $42 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 2,000 and 150,000 acfm. The average percentage of the total O&M cost was
then calculated for each O&M cost component. The model plants were assumed to
have a dust loading of 3.0 grains per cubic feet. The operating time was assumed to
be 8760 hours per year. An inlet water flow rate for the scrubber was assumed to be
9.4 Ibs/min. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	25
Wastewater treatment 3.8
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $76 to $2,100
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $751 per ton
PM10 reduced. (1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The costs do not include costs for post-treatment or disposal of used solvent or waste. Actual costs
can be substantially higher than in the ranges shown for applications which require expensive
materials, solvents, or treatment methods (EPA, 1999). As a rule, smaller units controlling a low
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concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow.
By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
A venturi scrubber accelerates the waste gas stream to improve gas-liquid contact. In a venturi
scrubber, a "throat"' section is built into the duct that forces the gas stream to accelerate (EPA,
1999). As the gas enters the venturi throat, both gas velocity and turbulence increase.
After the throat section, the mixture decelerates, and further impacts occur causing the droplets to
agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid
are separated from the gas stream through entrainment. This section usually consists of a cyclonic
separator and/or a mist eliminator (EPA, 1998; Corbitt, 1990).
For PM applications, wet scrubbers generate waste, either a slurry or wet sludge. This creates the
need for both wastewater treatment and solid waste disposal. Initially, the slurry is treated to
separate the solid waste from the water (EPA, 1999). The treated water can then be reused or
discharged. Once the water is removed, the remaining waste will be in the form of a solid or sludge.
If the solid waste is inert and nontoxic, it can generally be land filled. Hazardous wastes will have
more stringent procedures for disposal. In some cases, the solid waste may have value and can be
sold or recycled (EPA, 1998).
References:
Corbitt, 1990: "Standard Handbook of Environmental Engineering," edited by Robert A. Corbitt,
McGraw-Hill, New York, NY, 1990.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Venturi Scrubber," July 1999.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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Source Category: Ferrous Metals Processing - Coke
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3213	POD: 213
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303003 Primary Metal Production, By-product Coke Manufacturing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Ferrous Metals Processing - Coke
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4213	POD: 213
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303003 Primary Metal Production, By-product Coke Manufacturing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Ferrous Metals Processing - Ferroalloy Production
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2141	POD: 214
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to ferroalloy production operations, including (but not limited to)
several processes within this industry were selected for control, basic oxygen process
furnace (SCC 30300914) and EAF argon 02 decarb vessels (SCC 30300928).
Affected SCC:
30300601	Ferroalloy, Open Furnace, 50% FeSi: Electric Smelting Furnace
30300602	Ferroalloy, Open Furnace, 75% FeSi: Electric Smelting Furnace
30300604	Ferroalloy, Open Furnace, Silicon Metal: Electric Smelting Furnace
30300605	Ferroalloy, Open Furnace, Silicomanaganese: Electric Smelting Furnace
30300610 Ferroalloy, Open Furnace, Ore Screening
30300613 Ferroalloy, Open Furnace, Raw Material Storage
30300621 Ferroalloy, Open Furnace, Casting
30300623	Ferroalloy, Open Furnace, Product Crushing
30300624	Ferroalloy, Open Furnace, Product Storage
30300699 Ferroalloy, Open Furnace, Other Not Classified
30300701	Ferroalloy, Semi-covered Furnace, Ferromanganese: Electric Arc Furnace
30300702	Ferroalloy, Semi-covered Furnace, Electric Arc Furnace: Other Alloys/Specify
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
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administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
Steel normally is produced in either basic oxygen process furnaces or electric arc furnaces. In the
basic oxygen process furnace, a mixture of 70 percent molten iron from the blast furnace and 30
percent iron scrap are melted together. Pure oxygen is blown across the top or through the molten
steel to oxidize carbon and oxygen impurities, thus removing these from the steel. Basic oxygen
process furnaces are large open-mouthed furnaces that can be tilted to accept a charge or to tap the
molten steel to a charging ladle for transfer to an ingot mold or continuous caster.
Because basic oxygen furnaces are open, they produce significant uncontrolled particulate
emissions, notably during the refining stage when oxygen is being blown. Electric arc furnaces use
the current passing between carbon electrodes to heat molten steel, but also use oxy-fuel burners to
accelerate the initial melting process. These furnaces are charged largely with scrap iron.
Significant emissions occur during charging, when the furnace roof is open, during melting, as the
electrodes are lowered into the scrap and the arc is struck, and during tapping, when alloying
elements are added to the melt.
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
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References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Ferrous Metals Processing - Ferroalloy Production
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2142	POD: 214
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to ferroalloy production operations, including (but not limited to)
several processes within this industry were selected for control, basic oxygen process
furnace (SCC 30300914) and EAF argon 02 decarb vessels (SCC 30300928).
Affected SCC:
30300601	Ferroalloy, Open Furnace, 50% FeSi: Electric Smelting Furnace
30300602	Ferroalloy, Open Furnace, 75% FeSi: Electric Smelting Furnace
30300604	Ferroalloy, Open Furnace, Silicon Metal: Electric Smelting Furnace
30300605	Ferroalloy, Open Furnace, Silicomanaganese: Electric Smelting Furnace
30300610 Ferroalloy, Open Furnace, Ore Screening
30300613 Ferroalloy, Open Furnace, Raw Material Storage
30300621 Ferroalloy, Open Furnace, Casting
30300623	Ferroalloy, Open Furnace, Product Crushing
30300624	Ferroalloy, Open Furnace, Product Storage
30300699 Ferroalloy, Open Furnace, Other Not Classified
30300701	Ferroalloy, Semi-covered Furnace, Ferromanganese: Electric Arc Furnace
30300702	Ferroalloy, Semi-covered Furnace, Electric Arc Furnace: Other Alloys/Specify
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
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administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067
Dust disposal 25
$/kW-hr
$/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
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Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Ferrous Metals Processing - Ferroalloy Production
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2143	POD: 214
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to ferroalloy production operations, including (but not limited to)
several processes within this industry were selected for control, basic oxygen process
furnace (SCC 30300914) and EAF argon 02 decarb vessels (SCC 30300928).
Affected SCC:
30300601	Ferroalloy, Open Furnace, 50% FeSi: Electric Smelting Furnace
30300602	Ferroalloy, Open Furnace, 75% FeSi: Electric Smelting Furnace
30300604	Ferroalloy, Open Furnace, Silicon Metal: Electric Smelting Furnace
30300605	Ferroalloy, Open Furnace, Silicomanaganese: Electric Smelting Furnace
30300610 Ferroalloy, Open Furnace, Ore Screening
30300613 Ferroalloy, Open Furnace, Raw Material Storage
30300621 Ferroalloy, Open Furnace, Casting
30300623	Ferroalloy, Open Furnace, Product Crushing
30300624	Ferroalloy, Open Furnace, Product Storage
30300699 Ferroalloy, Open Furnace, Other Not Classified
30300701	Ferroalloy, Semi-covered Furnace, Ferromanganese: Electric Arc Furnace
30300702	Ferroalloy, Semi-covered Furnace, Electric Arc Furnace: Other Alloys/Specify
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
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costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal 25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
Steel normally is produced in either basic oxygen process furnaces or electric arc furnaces. In the
basic oxygen process furnace, a mixture of 70 percent molten iron from the blast furnace and 30
percent iron scrap are melted together. Pure oxygen is blown across the top or through the molten
steel to oxidize carbon and oxygen impurities, thus removing these from the steel. Basic oxygen
process furnaces are large open-mouthed furnaces that can be tilted to accept a charge or to tap the
molten steel to a charging ladle for transfer to an ingot mold or continuous caster.
Because basic oxygen furnaces are open, they produce significant uncontrolled particulate
emissions, notably during the refining stage when oxygen is being blown. Electric arc furnaces use
the current passing between carbon electrodes to heat molten steel, but also use oxy-fuel burners to
accelerate the initial melting process. These furnaces are charged largely with scrap iron.
Significant emissions occur during charging, when the furnace roof is open, during melting, as the
electrodes are lowered into the scrap and the arc is struck, and during tapping, when alloying
elements are added to the melt.
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
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AT-A-GLANCE TABLE FOR POINT SOURCES
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Ferroalloy Production
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3214	POD: 214
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303007** Ferroalloy, Semi-covered Furnace,
303006** Primary Metal Production, Ferroalloy, Open Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Ferrous Metals Processing - Ferroalloy Production
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4214	POD: 214
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303007** Ferroalloy, Semi-covered Furnace,
303006** Primary Metal Production, Ferroalloy, Open Furnace
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Ferrous Metals Processing - Gray Iron Foundries
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2161
POD: 216
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to gray iron foundry operations.
Affected SCC:
30400301
30400302
30400303
30400304
30400305
30400310
30400315
30400318
30400320
30400321
30400322
30400325
30400331
30400333
30400340
30400341
30400350
30400351
30400352
30400353
30400357
30400358
30400360
30400370
30400371
30400398
30400399
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Reverberatory Furnace
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Electric Arc Furnace
Grey Iron Foundries, Annealing Operation
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Charge Handling
Grey Iron Foundries, Pouring, Cooling
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Magnesium Treatment
Grey Iron Foundries, Refining
Grey Iron Foundries, Castings Cooling
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Casting Cleaning/Tumblers
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Core Ovens
Grey Iron Foundries, Conveyors/Elevators
Grey Iron Foundries, Sand Screens
Grey Iron Foundries, Castings Finishing
Grey Iron Foundries, Shell Core Machine
Grey Iron Foundries, Core Machines/Other
Grey Iron Foundries, Other Not Classified
Grey Iron Foundries, Other Not Classified
Cupola
Electric Induction Furnace
Inoculation
Pouring/Casting
Casting Shakeout
Shakeout Machine
Grinding/Cleaning
Sand Grinding/Handling
Core Ovens
Sand Grinding/Handling
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
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Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
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Dust disposal 25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Grey iron is an alloy of iron, carbon, and silicon, containing a higher percentage of the last two
elements than found in malleable iron. The high strengths are obtained by the proper adjustment of
the carbon and silicon contents or by alloying.
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
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References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Gray Iron Foundries
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2162
POD: 216
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to gray iron foundry operations.
Affected SCC:
30400301
30400302
30400303
30400304
30400305
30400310
30400315
30400318
30400320
30400321
30400322
30400325
30400331
30400333
30400340
30400341
30400350
30400351
30400352
30400353
30400357
30400358
30400360
30400370
30400371
30400398
30400399
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Reverberatory Furnace
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Electric Arc Furnace
Grey Iron Foundries, Annealing Operation
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Charge Handling
Grey Iron Foundries, Pouring, Cooling
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Magnesium Treatment
Grey Iron Foundries, Refining
Grey Iron Foundries, Castings Cooling
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Casting Cleaning/Tumblers
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Core Ovens
Grey Iron Foundries, Conveyors/Elevators
Grey Iron Foundries, Sand Screens
Grey Iron Foundries, Castings Finishing
Grey Iron Foundries, Shell Core Machine
Grey Iron Foundries, Core Machines/Other
Grey Iron Foundries, Other Not Classified
Grey Iron Foundries, Other Not Classified
Cupola
Electric Induction Furnace
Inoculation
Pouring/Casting
Casting Shakeout
Shakeout Machine
Grinding/Cleaning
Sand Grinding/Handling
Core Ovens
Sand Grinding/Handling
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
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Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
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AT-A-GLANCE TABLE FOR POINT SOURCES
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Grey iron is an alloy of iron, carbon, and silicon, containing a higher percentage of the last two
elements than found in malleable iron. The high strengths are obtained by the proper adjustment of
the carbon and silicon contents or by alloying. Oil suppression can provide 75 to 99 percent control
of TSP emissions. While the oil suppression system is favored because of costs, for the purpose of
this study, fabric filters are being considered because they can achieve greater than 99 percent
control of TSP as well as small and light particles.
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Gray Iron Foundries
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2163
POD: 216
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to gray iron foundry operations.
Affected SCC:
30400301
30400302
30400303
30400304
30400305
30400310
30400315
30400318
30400320
30400321
30400322
30400325
30400331
30400333
30400340
30400341
30400350
30400351
30400352
30400353
30400357
30400358
30400360
30400370
30400371
30400398
30400399
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Reverberatory Furnace
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Electric Arc Furnace
Grey Iron Foundries, Annealing Operation
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Charge Handling
Grey Iron Foundries, Pouring, Cooling
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Magnesium Treatment
Grey Iron Foundries, Refining
Grey Iron Foundries, Castings Cooling
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Casting Cleaning/Tumblers
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Core Ovens
Grey Iron Foundries, Conveyors/Elevators
Grey Iron Foundries, Sand Screens
Grey Iron Foundries, Castings Finishing
Grey Iron Foundries, Shell Core Machine
Grey Iron Foundries, Core Machines/Other
Grey Iron Foundries, Other Not Classified
Grey Iron Foundries, Other Not Classified
Cupola
Electric Induction Furnace
Inoculation
Pouring/Casting
Casting Shakeout
Shakeout Machine
Grinding/Cleaning
Sand Grinding/Handling
Core Ovens
Sand Grinding/Handling
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
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AT-A-GLANCE TABLE FOR POINT SOURCES
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
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AT-A-GLANCE TABLE FOR POINT SOURCES
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Grey iron is an alloy of iron, carbon, and silicon, containing a higher percentage of the last two
elements than found in malleable iron. The high strengths are obtained by the proper adjustment of
the carbon and silicon contents or by alloying.
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
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AT-A-GLANCE TABLE FOR POINT SOURCES
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Gray Iron Foundries
Control Measure Name: Impingement-Plate Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2164	POD: 216
Application: This control is the use of an impingement-plate scrubber to reduce PM emissions. An
impingement-plate scrubber is a vertical chamber with plates mounted horizontally
inside a hollow shell. Impingement-plate scrubbers operate as countercurrent PM
collection devices. The scrubbing liquid flows down the tower while the gas stream
flows upward. Contact between the liquid and the particle-laden gas occurs on the
plates. The plates are equipped with openings that allow the gas to pass through.
Some plates are perforated or slotted, while more complex plates have valve-like
openings (EPA, 1998).
This control applies to iron and steel production operations.
Affected SCC:
30400301	Secondary Metal Production, Grey Iron Foundries,
30400302	Grey Iron Foundries, Reverberatory Furnace
30400303	Secondary Metal Production, Grey Iron Foundries,
30400304	Grey Iron Foundries, Electric Arc Furnace
30400305	Grey Iron Foundries, Annealing Operation
30400310 Secondary Metal Production, Grey Iron Foundries,
30400315 Grey Iron Foundries, Charge Handling
30400318 Grey Iron Foundries, Pouring, Cooling
30400320	Secondary Metal Production, Grey Iron Foundries,
30400321	Grey Iron Foundries, Magnesium Treatment
30400322	Grey Iron Foundries, Refining
30400325 Grey Iron Foundries, Castings Cooling
30400331 Secondary Metal Production, Grey Iron Foundries,
30400340 Secondary Metal Production, Grey Iron Foundries,
30400350	Secondary Metal Production, Grey Iron Foundries,
30400351	Secondary Metal Production, Grey Iron Foundries,
30400352	Secondary Metal Production, Grey Iron Foundries,
30400357 Grey Iron Foundries, Conveyors/Elevators
30400360 Grey Iron Foundries, Castings Finishing
30400370	Grey Iron Foundries, Shell Core Machine
30400371	Grey Iron Foundries, Core Machines/Other
30400398	Grey Iron Foundries, Other Not Classified
30400399	Grey Iron Foundries, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 64% from uncontrolled for both PM10 and PM2.5
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cupola
Electric Induction Furnace
Inoculation
Pouring/Casting
Casting Shakeout
Grinding/Cleaning
Sand Grinding/Handling
Core Ovens
Sand Grinding/Handling
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Basis:
The following are cost ranges for impingement-plate wet scrubbers of conventional
design under typical operating conditions, developed using EPA cost-estimating
spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of the waste
stream treated. When stack gas flow rate data was available, the costs and cost
effectiveness were calculated using the typical values of capital and O&M costs.
When stack gas flow rate data was not available, default typical capital and O&M cost
values based on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $2 to $11 per scfm
Typical value is $7 per scfm
O&M Costs:
Range from $3 to $70 per scfm
Typical value is $25 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 1,000 and 100,000 acfm. The 1,000 acfm plant required 1 scrubber unit while
the 100,000 acfm plant required 2 scrubber units. Both model plants were assumed
to have 3 scrubber stages per scrubber unit. The average percentage of the total
O&M cost was then calculated for each O&M cost component. The model plants were
assumed to have a dust loading of 3.0 grains per cubic feet. The operating time was
assumed to be 8760 hours per year. An inlet water flow rate for the scrubber was
assumed to be 9.4 Ibs/min. The following assumptions apply to the cost of utilities
and disposal:
Electricity price	0.067	$/kW-hr
Process water price 0.20	$/1000gal
Dust disposal	25	$/ton disposed
Wastewater treatment	3.8	$/thousand gal treated
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AT-A-GLANCE TABLE FOR POINT SOURCES
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $46 to $1,200
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $431 per ton
PM10 reduced. (1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates do not include costs for post-treatment or disposal of used solvent or waste.
Actual costs can be substantially higher than in the ranges shown for applications which require
expensive materials, solvents, or treatment methods. As a rule, smaller units controlling a low
concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow (EPA, 1999).
In all types of impingement-plate scrubbers, the scrubbing liquid flows across each plate and down
the inside of the tower onto the plate below. After the bottom plate, the liquid and collected PM flow
out of the bottom of the tower. Impingement-plate scrubbers are usually designed to provide
operator access to each tray, making them relatively easy to clean and maintain. Consequently,
impingement-plate scrubbers are more suitable for PM collection than packed-bed scrubbers.
Particles greater than 1 um in aerodynamic diameter can be collected effectively by impingement-
plate scrubbers, but many particles <1 um in aerodynamic diameter will penetrate these devices
(EPA, 1998).
The simplest impingement-plate scrubber is the sieve plate, which has round perforations (EPA,
1999). In this type of scrubber, the scrubbing liquid flows over the plates and the gas flows up
through the holes. The gas velocity prevents the liquid from flowing down through the perforations.
Gas-liquid-particle contact is achieved within the froth generated by the gas passing through the
liquid layer. Complex plates, such as bubble cap or baffle plates, introduce an additional means of
collecting PM. The bubble caps and baffles placed above the plate perforations force the gas to turn
before escaping the layer of liquid. While the gas turns to avoid the obstacles, most PM cannot and
is collected by impaction on the caps or baffles. Bubble caps and the like also prevent liquid from
flowing down the perforations if the gas flow is reduced (EPA, 1998).
References:
EPA, 1996. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February 1996.
EPA, 1998. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC, October 1998.
EPA, 1999 U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Impingement-Plate/ Tray-Tower Scrubber," July 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Gray Iron Foundries
Control Measure Name: Venturi Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2165
POD: 216
Application: The control is the use of a venturi scrubber to reduce PM emissions. A scrubber is a
type of technology that removes air pollutants by inertial and diffusional interception. A
venturi scrubber accelerates the waste gas stream to atomize the scrubbing liquid and
to improve gas-liquid contact.
This control applies to iron and steel production operations.
Affected SCC:
30400301
30400302
30400303
30400304
30400305
30400310
30400315
30400318
30400320
30400321
30400322
30400325
30400331
30400340
30400350
30400351
30400352
30400353
30400357
30400358
30400360
30400370
30400371
30400398
30400399
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Reverberatory Furnace
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Electric Arc Furnace
Grey Iron Foundries, Annealing Operation
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Charge Handling
Grey Iron Foundries, Pouring, Cooling
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Magnesium Treatment
Grey Iron Foundries, Refining
Grey Iron Foundries, Castings Cooling
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Secondary Metal Production, Grey Iron Foundries,
Grey Iron Foundries, Core Ovens
Grey Iron Foundries, Conveyors/Elevators
Grey Iron Foundries, Sand Screens
Grey Iron Foundries, Castings Finishing
Grey Iron Foundries, Shell Core Machine
Grey Iron Foundries, Core Machines/Other
Grey Iron Foundries, Other Not Classified
Grey Iron Foundries, Other Not Classified
Cupola
Electric Induction Furnace
Inoculation
Pouring/Casting
Casting Shakeout
Grinding/Cleaning
Sand Grinding/Handling
Core Ovens
Sand Grinding/Handling
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 94% from uncontrolled for both PM10 and PM2.5
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Basis: The following are cost ranges for venturi wet scrubbers, developed using EPA cost-
estimating spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of
the waste stream treated. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $3 to $28 per scfm
Typical value is $11 per scfm
O&M Costs:
Range from $4 to $119 per scfm
Typical value is $42 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 2,000 and 150,000 acfm. The average percentage of the total O&M cost was
then calculated for each O&M cost component. The model plants were assumed to
have a dust loading of 3.0 grains per cubic feet. The operating time was assumed to
be 8760 hours per year. An inlet water flow rate for the scrubber was assumed to be
9.4 Ibs/min. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	25
Wastewater treatment 3.8
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $76 to $2,100
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AT-A-GLANCE TABLE FOR POINT SOURCES
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $751 per ton
PM10 reduced. (1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Grey iron is an alloy of iron, carbon, and silicon, containing a higher percentage of the last two
elements than found in malleable iron. The high strengths are obtained by the proper adjustment of
the carbon and silicon contents or by alloying. Oil suppression can provide 75 to 99 percent control
of TSP emissions. While the oil suppression system is favored because of costs, for the purpose of
this study, fabric filters are being considered because they can achieve greater than 99 percent
control of TSP as well as small and light particles (EPA, 1999).
The costs do not include costs for post-treatment or disposal of used solvent or waste. Actual costs
can be substantially higher than in the ranges shown for applications which require expensive
materials, solvents, or treatment methods (EPA, 1999). As a rule, smaller units controlling a low
concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow.
By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
A venturi scrubber accelerates the waste gas stream to improve gas-liquid contact. In a venturi
scrubber, a "throat"' section is built into the duct that forces the gas stream to accelerate (EPA,
1999). As the gas enters the venturi throat, both gas velocity and turbulence increase.
After the throat section, the mixture decelerates, and further impacts occur causing the droplets to
agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid
are separated from the gas stream through entrainment. This section usually consists of a cyclonic
separator and/or a mist eliminator (EPA, 1998; Corbitt, 1990).
For PM applications, wet scrubbers generate waste, either a slurry or wet sludge. This creates the
need for both wastewater treatment and solid waste disposal. Initially, the slurry is treated to
separate the solid waste from the water (EPA, 1999). The treated water can then be reused or
discharged. Once the water is removed, the remaining waste will be in the form of a solid or sludge.
If the solid waste is inert and nontoxic, it can generally be land filled. Hazardous wastes will have
more stringent procedures for disposal. In some cases, the solid waste may have value and can be
sold or recycled (EPA, 1998).
References:
Corbitt, 1990: "Standard Handbook of Environmental Engineering," edited by Robert A. Corbitt,
McGraw-Hill, New York, NY, 1990.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Venturi Scrubber," July 1999.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Gray Iron Foundries
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3216	POD: 216
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
304003** Secondary Metal Production, Grey Iron Foundries
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Gray Iron Foundries
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4216	POD: 216
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
304003** Secondary Metal Production, Grey Iron Foundries
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Iron & Steel Production
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3215	POD: 215
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303008** Primary Metal Production, Iron Production
303009** Primary Metal Production, Steel Manufacturing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Iron & Steel Production
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4215	POD: 215
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303008** Primary Metal Production, Iron Production
303009** Primary Metal Production, Steel Manufacturing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Iron and Steel Production
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2151	POD: 215
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to iron and steel production operations.
Affected SCC:
30300801	Iron Production (See 3-03-015), Ore Charging
30300802	Iron Production (See 3-03-015), Agglomerate Charging
30300808	Primary Metal Production, Iron Production (See 3-03-015), Slag Crushing and Sizing
30300809	Iron Production (See 3-03-015), Slag Removal and Dumping
30300811 Iron Production (See 303015), Raw Mat'l Stockpiles, Coke Breeze, Limestone, Ore Fines
30300813	Iron Production (See 3-03-015), Windbox
30300814	Iron Production (See 3-03-015), Discharge End
30300817 Iron Production (See 3-03-015), Cooler
30300821 Iron Production (See 3-03-015), Unload Ore, Pellets, Limestone, into Blast Furnace
30300824	Iron Production (See 3-03-015), Blast Heating Stoves
30300825	Primary Metal Production, Iron Production (See 3-03-015), Cast House
30300826	Iron Production (See 3-03-015), Blast Furnace Slips
30300832	Iron Production (See 3-03-015), Unpaved Roads: Medium Duty Vehicles
30300833	Iron Production (See 3-03-015), Unpaved Roads: Heavy Duty Vehicles
30300834	Iron Production (See 3-03-015), Paved Roads: All Vehicle Types
30300841	Primary Metal Production, Iron Production (See 3-03-015), Flue Dust Unloading
30300842	Iron Production (See 3-03-015), Blended Ore Unloading
30300899 Iron Production (See 3-03-015), See Comment **
30300901 Primary Metal Production, Steel (See 303015), Open Hearth Furnace-Stack
30300904 Primary Metal Production, Steel (See 303015), Electric Arc FurnaceAlloy Steel (Stack)
30300906	Steel Manufacturing (See 3-03-015), Charging: Electric Arc Furnace
30300907	Steel Manufacturing (See 3-03-015), Tapping: Electric Arc Furnace
30300908	Primary Metal Prod., Steel (See 303015), Electric Arc Furnace-Carbon Steel (Stack)
30300910	Primary Metal Production, Steel Manufacturing (See 3-03-015), Pickling
30300911	Steel Manufacturing (See 3-03-015), Soaking Pits
30300912	Primary Metal Production, Steel Manufacturing (See 3-03-015), Grinding
30300913	Primary Metal Production, Steel (See 303015), Basic Oxygen Furnace-Open Hood-Stack
30300914	Steel Manufacturing (See 3-03-015), Basic Oxygen Furnace: Closed Hood-Stack
30300915	Steel Manufacturing (See 3-03-015), Hot Metal (Iron) Transfer to Steelmaking Furnace
30300916	Steel Manufacturing (See 3-03-015), Charging: BOF
30300917	Steel Manufacturing (See 3-03-015), Tapping: BOF
30300920	Steel Manufacturing (See 3-03-015), Hot Metal Desulfurization
30300921	Steel Manufacturing (See 3-03-015), Teeming (Unleaded Steel)
30300922	Primary Metal Production, Steel Manufacturing (See 3-03-015), Continuous Casting
30300923	Steel Manufacturing (See 3-03-015), Steel Furnace Slag Tapping and Dumping
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AT-A-GLANCE TABLE FOR POINT SOURCES
30300924 Steel Manufacturing (See 3-03-015), Steel Furnace Slag Processing
30300931	Primary Metal Production, Steel Manufacturing (See 3-03-015), Hot Rolling
30300932	Steel Manufacturing (See 3-03-015), Scarfing
30300933	Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
30300934	Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
30300935	Primary Metal Production, Steel Manufacturing (See 3-03-015), Cold Rolling
30300936	Primary Metal Production, Steel Manufacturing (See 3-03-015), Coating: Tin, Zinc, etc.
30300998	Steel Manufacturing (See 3-03-015), Other Not Classified
30300999	Primary Metal Production, Steel Manufacturing (See 3-03-015), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
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AT-A-GLANCE TABLE FOR POINT SOURCES
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price	0.0671 $/kW-hr
Compressed air	0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Steel normally is produced in either basic oxygen process furnaces or electric arc furnaces. In the
basic oxygen process furnace, a mixture of 70 percent molten iron from the blast furnace and 30
percent iron scrap are melted together. Pure oxygen is blown across the top or through the molten
steel to oxidize carbon and oxygen impurities, thus removing these from the steel. Basic oxygen
process furnaces are large open-mouthed furnaces that can be tilted to accept a charge or to tap the
molten steel to a charging ladle for transfer to an ingot mold or continuous caster.
Because basic oxygen furnaces are open, they produce significant uncontrolled particulate
emissions, notably during the refining stage when oxygen is being blown. Electric arc furnaces use
the current passing between carbon electrodes to heat molten steel, but also use oxy-fuel burners to
accelerate the initial melting process. These furnaces are charged largely with scrap iron.
Significant emissions occur during charging, when the furnace roof is open, during melting, as the
electrodes are lowered into the scrap and the arc is struck, and during tapping, when alloying
elements are added to the melt.
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
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AT-A-GLANCE TABLE FOR POINT SOURCES
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
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AT-A-GLANCE TABLE FOR POINT SOURCES
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Iron and Steel Production
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2152	POD: 215
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to iron and steel production operations.
Affected SCC:
30300801	Iron Production (See 3-03-015), Ore Charging
30300802	Iron Production (See 3-03-015), Agglomerate Charging
30300808	Primary Metal Production, Iron Production (See 3-03-015), Slag Crushing and Sizing
30300809	Iron Production (See 3-03-015), Slag Removal and Dumping
30300811 Iron Production (See 303015), Raw Mat'l Stockpiles, Coke Breeze, Limestone, Ore Fines
30300813	Iron Production (See 3-03-015), Windbox
30300814	Iron Production (See 3-03-015), Discharge End
30300817 Iron Production (See 3-03-015), Cooler
30300821 Iron Production (See 3-03-015), Unload Ore, Pellets, Limestone, into Blast Furnace
30300824	Iron Production (See 3-03-015), Blast Heating Stoves
30300825	Primary Metal Production, Iron Production (See 3-03-015), Cast House
30300826	Iron Production (See 3-03-015), Blast Furnace Slips
30300832	Iron Production (See 3-03-015), Unpaved Roads: Medium Duty Vehicles
30300833	Iron Production (See 3-03-015), Unpaved Roads: Heavy Duty Vehicles
30300834	Iron Production (See 3-03-015), Paved Roads: All Vehicle Types
30300841	Primary Metal Production, Iron Production (See 3-03-015), Flue Dust Unloading
30300842	Iron Production (See 3-03-015), Blended Ore Unloading
30300899 Iron Production (See 3-03-015), See Comment **
30300901 Primary Metal Production, Steel (See 303015), Open Hearth Furnace-Stack
30300904 Primary Metal Production, Steel (See 303015), Electric Arc FurnaceAlloy Steel (Stack)
30300906	Steel Manufacturing (See 3-03-015), Charging: Electric Arc Furnace
30300907	Steel Manufacturing (See 3-03-015), Tapping: Electric Arc Furnace
30300908	Primary Metal Prod., Steel (See 303015), Electric Arc Furnace-Carbon Steel (Stack)
30300910	Primary Metal Production, Steel Manufacturing (See 3-03-015), Pickling
30300911	Steel Manufacturing (See 3-03-015), Soaking Pits
30300912	Primary Metal Production, Steel Manufacturing (See 3-03-015), Grinding
30300913	Primary Metal Production, Steel (See 303015), Basic Oxygen Furnace-Open Hood-Stack
30300914	Steel Manufacturing (See 3-03-015), Basic Oxygen Furnace: Closed Hood-Stack
30300915	Steel Manufacturing (See 3-03-015), Hot Metal (Iron) Transfer to Steelmaking Furnace
30300916	Steel Manufacturing (See 3-03-015), Charging: BOF
30300917	Steel Manufacturing (See 3-03-015), Tapping: BOF
30300920	Steel Manufacturing (See 3-03-015), Hot Metal Desulfurization
30300921	Steel Manufacturing (See 3-03-015), Teeming (Unleaded Steel)
30300922	Primary Metal Production, Steel Manufacturing (See 3-03-015), Continuous Casting
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AT-A-GLANCE TABLE FOR POINT SOURCES
30300923	Steel Manufacturing (See 3-03-015), Steel Furnace Slag Tapping and Dumping
30300924	Steel Manufacturing (See 3-03-015), Steel Furnace Slag Processing
30300931	Primary Metal Production, Steel Manufacturing (See 3-03-015), Hot Rolling
30300932	Steel Manufacturing (See 3-03-015), Scarfing
30300933	Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
30300934	Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
30300935	Primary Metal Production, Steel Manufacturing (See 3-03-015), Cold Rolling
30300936	Primary Metal Production, Steel Manufacturing (See 3-03-015), Coating: Tin, Zinc, etc.
30300998	Steel Manufacturing (See 3-03-015), Other Not Classified
30300999	Primary Metal Production, Steel Manufacturing (See 3-03-015), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Steel normally is produced in either basic oxygen process furnaces or electric arc furnaces. In the
basic oxygen process furnace, a mixture of 70 percent molten iron from the blast furnace and 30
percent iron scrap are melted together. Pure oxygen is blown across the top or through the molten
steel to oxidize carbon and oxygen impurities, thus removing these from the steel. Basic oxygen
process furnaces are large open-mouthed furnaces that can be tilted to accept a charge or to tap the
molten steel to a charging ladle for transfer to an ingot mold or continuous caster.
Because basic oxygen furnaces are open, they produce significant uncontrolled particulate
emissions, notably during the refining stage when oxygen is being blown. Electric arc furnaces use
the current passing between carbon electrodes to heat molten steel, but also use oxy-fuel burners to
accelerate the initial melting process. These furnaces are charged largely with scrap iron.
Significant emissions occur during charging, when the furnace roof is open, during melting, as the
electrodes are lowered into the scrap and the arc is struck, and during tapping, when alloying
elements are added to the melt.
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
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AT-A-GLANCE TABLE FOR POINT SOURCES
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Iron and Steel Production
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2153	POD: 215
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to iron and steel production operations.
Affected SCC:
30300801	Iron Production (See 3-03-015), Ore Charging
30300802	Iron Production (See 3-03-015), Agglomerate Charging
30300808	Primary Metal Production, Iron Production (See 3-03-015), Slag Crushing and Sizing
30300809	Iron Production (See 3-03-015), Slag Removal and Dumping
30300811 Iron Production (See 303015), Raw Mat'l Stockpiles, Coke Breeze, Limestone, Ore Fines
30300813	Iron Production (See 3-03-015), Windbox
30300814	Iron Production (See 3-03-015), Discharge End
30300817 Iron Production (See 3-03-015), Cooler
30300821 Iron Production (See 3-03-015), Unload Ore, Pellets, Limestone, into Blast Furnace
30300824	Iron Production (See 3-03-015), Blast Heating Stoves
30300825	Primary Metal Production, Iron Production (See 3-03-015), Cast House
30300826	Iron Production (See 3-03-015), Blast Furnace Slips
30300832	Iron Production (See 3-03-015), Unpaved Roads: Medium Duty Vehicles
30300833	Iron Production (See 3-03-015), Unpaved Roads: Heavy Duty Vehicles
30300834	Iron Production (See 3-03-015), Paved Roads: All Vehicle Types
30300841	Primary Metal Production, Iron Production (See 3-03-015), Flue Dust Unloading
30300842	Iron Production (See 3-03-015), Blended Ore Unloading
30300899 Iron Production (See 3-03-015), See Comment **
30300901 Primary Metal Production, Steel (See 303015), Open Hearth Furnace-Stack
30300904 Primary Metal Production, Steel (See 303015), Electric Arc FurnaceAlloy Steel (Stack)
30300906	Steel Manufacturing (See 3-03-015), Charging: Electric Arc Furnace
30300907	Steel Manufacturing (See 3-03-015), Tapping: Electric Arc Furnace
30300908	Primary Metal Prod., Steel (See 303015), Electric Arc Furnace-Carbon Steel (Stack)
30300910	Primary Metal Production, Steel Manufacturing (See 3-03-015), Pickling
30300911	Steel Manufacturing (See 3-03-015), Soaking Pits
30300912	Primary Metal Production, Steel Manufacturing (See 3-03-015), Grinding
30300913	Primary Metal Production, Steel (See 303015), Basic Oxygen Furnace-Open Hood-Stack
30300914	Steel Manufacturing (See 3-03-015), Basic Oxygen Furnace: Closed Hood-Stack
30300915	Steel Manufacturing (See 3-03-015), Hot Metal (Iron) Transfer to Steelmaking Furnace
30300916	Steel Manufacturing (See 3-03-015), Charging: BOF
30300917	Steel Manufacturing (See 3-03-015), Tapping: BOF
30300920	Steel Manufacturing (See 3-03-015), Hot Metal Desulfurization
30300921	Steel Manufacturing (See 3-03-015), Teeming (Unleaded Steel)
30300922	Primary Metal Production, Steel Manufacturing (See 3-03-015), Continuous Casting
30300923	Steel Manufacturing (See 3-03-015), Steel Furnace Slag Tapping and Dumping
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AT-A-GLANCE TABLE FOR POINT SOURCES
30300924 Steel Manufacturing (See 3-03-015), Steel Furnace Slag Processing
30300931	Primary Metal Production, Steel Manufacturing (See 3-03-015), Hot Rolling
30300932	Steel Manufacturing (See 3-03-015), Scarfing
30300933	Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
30300934	Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
30300935	Primary Metal Production, Steel Manufacturing (See 3-03-015), Cold Rolling
30300936	Primary Metal Production, Steel Manufacturing (See 3-03-015), Coating: Tin, Zinc, etc.
30300998	Steel Manufacturing (See 3-03-015), Other Not Classified
30300999	Primary Metal Production, Steel Manufacturing (See 3-03-015), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067
Dust disposal 25
$/kW-hr
$/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Steel normally is produced in either basic oxygen process furnaces or electric arc furnaces. In the
basic oxygen process furnace, a mixture of 70 percent molten iron from the blast furnace and 30
percent iron scrap are melted together. Pure oxygen is blown across the top or through the molten
steel to oxidize carbon and oxygen impurities, thus removing these from the steel. Basic oxygen
process furnaces are large open-mouthed furnaces that can be tilted to accept a charge or to tap the
molten steel to a charging ladle for transfer to an ingot mold or continuous caster.
Because basic oxygen furnaces are open, they produce significant uncontrolled particulate
emissions, notably during the refining stage when oxygen is being blown. Electric arc furnaces use
the current passing between carbon electrodes to heat molten steel, but also use oxy-fuel burners to
accelerate the initial melting process. These furnaces are charged largely with scrap iron.
Significant emissions occur during charging, when the furnace roof is open, during melting, as the
electrodes are lowered into the scrap and the arc is struck, and during tapping, when alloying
elements are added to the melt.
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
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AT-A-GLANCE TABLE FOR POINT SOURCES
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Iron and Steel Production
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2154	POD: 215
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to iron and steel production operations.
Affected SCC:
30300801	Iron Production (See 3-03-015), Ore Charging
30300802	Iron Production (See 3-03-015), Agglomerate Charging
30300808	Primary Metal Production, Iron Production (See 3-03-015), Slag Crushing and Sizing
30300809	Iron Production (See 3-03-015), Slag Removal and Dumping
30300811 Iron Production (See 303015), Raw Mat'l Stockpiles, Coke Breeze, Limestone, Ore Fines
30300813	Iron Production (See 3-03-015), Wndbox
30300814	Iron Production (See 3-03-015), Discharge End
30300817 Iron Production (See 3-03-015), Cooler
30300821 Iron Production (See 3-03-015), Unload Ore, Pellets, Limestone, into Blast Furnace
30300824	Iron Production (See 3-03-015), Blast Heating Stoves
30300825	Primary Metal Production, Iron Production (See 3-03-015), Cast House
30300826	Iron Production (See 3-03-015), Blast Furnace Slips
30300832	Iron Production (See 3-03-015), Unpaved Roads: Medium Duty Vehicles
30300833	Iron Production (See 3-03-015), Unpaved Roads: Heavy Duty Vehicles
30300834	Iron Production (See 3-03-015), Paved Roads: All Vehicle Types
30300841	Primary Metal Production, Iron Production (See 3-03-015), Flue Dust Unloading
30300842	Iron Production (See 3-03-015), Blended Ore Unloading
30300899 Iron Production (See 3-03-015), See Comment **
30300901 Primary Metal Production, Steel (See 303015), Open Hearth Furnace-Stack
30300904 Primary Metal Production, Steel (See 303015), Electric Arc FurnaceAlloy Steel (Stack)
30300906	Steel Manufacturing (See 3-03-015), Charging: Electric Arc Furnace
30300907	Steel Manufacturing (See 3-03-015), Tapping: Electric Arc Furnace
30300908	Primary Metal Prod., Steel (See 303015), Electric Arc Furnace-Carbon Steel (Stack)
30300910	Primary Metal Production, Steel Manufacturing (See 3-03-015), Pickling
30300911	Steel Manufacturing (See 3-03-015), Soaking Pits
30300912	Primary Metal Production, Steel Manufacturing (See 3-03-015), Grinding
30300913	Primary Metal Production, Steel (See 303015), Basic Oxygen Furnace-Open Hood-Stack
30300914	Steel Manufacturing (See 3-03-015), Basic Oxygen Furnace: Closed Hood-Stack
30300915	Steel Manufacturing (See 3-03-015), Hot Metal (Iron) Transfer to Steelmaking Furnace
30300916	Steel Manufacturing (See 3-03-015), Charging: BOF
30300917	Steel Manufacturing (See 3-03-015), Tapping: BOF
30300920	Steel Manufacturing (See 3-03-015), Hot Metal Desulfurization
30300921	Steel Manufacturing (See 3-03-015), Teeming (Unleaded Steel)
30300922	Primary Metal Production, Steel Manufacturing (See 3-03-015), Continuous Casting
30300923	Steel Manufacturing (See 3-03-015), Steel Furnace Slag Tapping and Dumping
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AT-A-GLANCE TABLE FOR POINT SOURCES
30300924 Steel Manufacturing (See 3-03-015), Steel Furnace Slag Processing
30300931	Primary Metal Production, Steel Manufacturing (See 3-03-015), Hot Rolling
30300932	Steel Manufacturing (See 3-03-015), Scarfing
30300933	Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
30300934	Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
30300935	Primary Metal Production, Steel Manufacturing (See 3-03-015), Cold Rolling
30300936	Primary Metal Production, Steel Manufacturing (See 3-03-015), Coating: Tin, Zinc, etc.
30300998	Steel Manufacturing (See 3-03-015), Other Not Classified
30300999	Primary Metal Production, Steel Manufacturing (See 3-03-015), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
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AT-A-GLANCE TABLE FOR POINT SOURCES
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067	$/kW-hr
Process water price 0.20	$/1000gal
Dust disposal	20	$/ton disposed
Wastewater treatment 1.5	$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Steel normally is produced in either basic oxygen process furnaces or electric arc furnaces. In the
basic oxygen process furnace, a mixture of 70 percent molten iron from the blast furnace and 30
percent iron scrap are melted together. Pure oxygen is blown across the top or through the molten
steel to oxidize carbon and oxygen impurities, thus removing these from the steel. Basic oxygen
process furnaces are large open-mouthed furnaces that can be tilted to accept a charge or to tap the
molten steel to a charging ladle for transfer to an ingot mold or continuous caster.
Because basic oxygen furnaces are open, they produce significant uncontrolled particulate
emissions, notably during the refining stage when oxygen is being blown. Electric arc furnaces use
the current passing between carbon electrodes to heat molten steel, but also use oxy-fuel burners to
accelerate the initial melting process. These furnaces are charged largely with scrap iron.
Significant emissions occur during charging, when the furnace roof is open, during melting, as the
electrodes are lowered into the scrap and the arc is struck, and during tapping, when alloying
elements are added to the melt.
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
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AT-A-GLANCE TABLE FOR POINT SOURCES
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wire-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Iron and Steel Production
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2155	POD: 215
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to iron and steel production operations.
Affected SCC:
30300801	Iron Production (See 3-03-015), Ore Charging
30300802	Iron Production (See 3-03-015), Agglomerate Charging
30300808	Primary Metal Production, Iron Production (See 3-03-015), Slag Crushing and Sizing
30300809	Iron Production (See 3-03-015), Slag Removal and Dumping
30300811 Iron Production (See 303015), Raw Mat'l Stockpiles, Coke Breeze, Limestone, Ore Fines
30300813	Iron Production (See 3-03-015), Windbox
30300814	Iron Production (See 3-03-015), Discharge End
30300817 Iron Production (See 3-03-015), Cooler
30300821 Iron Production (See 3-03-015), Unload Ore, Pellets, Limestone, into Blast Furnace
30300824	Iron Production (See 3-03-015), Blast Heating Stoves
30300825	Primary Metal Production, Iron Production (See 3-03-015), Cast House
30300826	Iron Production (See 3-03-015), Blast Furnace Slips
30300832	Iron Production (See 3-03-015), Unpaved Roads: Medium Duty Vehicles
30300833	Iron Production (See 3-03-015), Unpaved Roads: Heavy Duty Vehicles
30300834	Iron Production (See 3-03-015), Paved Roads: All Vehicle Types
30300841	Primary Metal Production, Iron Production (See 3-03-015), Flue Dust Unloading
30300842	Iron Production (See 3-03-015), Blended Ore Unloading
30300899 Iron Production (See 3-03-015), See Comment **
30300901 Primary Metal Production, Steel (See 303015), Open Hearth Furnace-Stack
30300904 Primary Metal Production, Steel (See 303015), Electric Arc FurnaceAlloy Steel (Stack)
30300906	Steel Manufacturing (See 3-03-015), Charging: Electric Arc Furnace
30300907	Steel Manufacturing (See 3-03-015), Tapping: Electric Arc Furnace
30300908	Primary Metal Prod., Steel (See 303015), Electric Arc Furnace-Carbon Steel (Stack)
30300910	Primary Metal Production, Steel Manufacturing (See 3-03-015), Pickling
30300911	Steel Manufacturing (See 3-03-015), Soaking Pits
30300912	Primary Metal Production, Steel Manufacturing (See 3-03-015), Grinding
30300913	Primary Metal Production, Steel (See 303015), Basic Oxygen Furnace-Open Hood-Stack
30300914	Steel Manufacturing (See 3-03-015), Basic Oxygen Furnace: Closed Hood-Stack
30300915	Steel Manufacturing (See 3-03-015), Hot Metal (Iron) Transfer to Steelmaking Furnace
30300916	Steel Manufacturing (See 3-03-015), Charging: BOF
30300917	Steel Manufacturing (See 3-03-015), Tapping: BOF
30300920	Steel Manufacturing (See 3-03-015), Hot Metal Desulfurization
30300921	Steel Manufacturing (See 3-03-015), Teeming (Unleaded Steel)
30300922	Primary Metal Production, Steel Manufacturing (See 3-03-015), Continuous Casting
30300923	Steel Manufacturing (See 3-03-015), Steel Furnace Slag Tapping and Dumping
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AT-A-GLANCE TABLE FOR POINT SOURCES
30300924 Steel Manufacturing (See 3-03-015), Steel Furnace Slag Processing
30300931	Primary Metal Production, Steel Manufacturing (See 3-03-015), Hot Rolling
30300932	Steel Manufacturing (See 3-03-015), Scarfing
30300933	Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
30300934	Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
30300935	Primary Metal Production, Steel Manufacturing (See 3-03-015), Cold Rolling
30300936	Primary Metal Production, Steel Manufacturing (See 3-03-015), Coating: Tin, Zinc, etc.
30300998	Steel Manufacturing (See 3-03-015), Other Not Classified
30300999	Primary Metal Production, Steel Manufacturing (See 3-03-015), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
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AT-A-GLANCE TABLE FOR POINT SOURCES
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Steel normally is produced in either basic oxygen process furnaces or electric arc furnaces. In the
basic oxygen process furnace, a mixture of 70 percent molten iron from the blast furnace and 30
percent iron scrap are melted together. Pure oxygen is blown across the top or through the molten
steel to oxidize carbon and oxygen impurities, thus removing these from the steel. Basic oxygen
process furnaces are large open-mouthed furnaces that can be tilted to accept a charge or to tap the
molten steel to a charging ladle for transfer to an ingot mold or continuous caster.
Because basic oxygen furnaces are open, they produce significant uncontrolled particulate
emissions, notably during the refining stage when oxygen is being blown. Electric arc furnaces use
the current passing between carbon electrodes to heat molten steel, but also use oxy-fuel burners to
accelerate the initial melting process. These furnaces are charged largely with scrap iron.
Significant emissions occur during charging, when the furnace roof is open, during melting, as the
electrodes are lowered into the scrap and the arc is struck, and during tapping, when alloying
elements are added to the melt.
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Iron and Steel Production
Control Measure Name: Venturi Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2156	POD: 215
Application: The control is the use of a venturi scrubber to reduce PM emissions. A scrubber is a
type of technology that removes air pollutants by inertial and diffusional interception. A
venturi scrubber accelerates the waste gas stream to atomize the scrubbing liquid and
to improve gas-liquid contact.
This control applies to iron and steel processing and production operations.
Affected SCC:
30300801 Iron Production (See 3-03-015), Ore Charging
30300808	Primary Metal Production, Iron Production (See 3-03-015), Slag Crushing and Sizing
30300809	Iron Production (See 3-03-015), Slag Removal and Dumping
30300811 Iron Production (See 303015), Raw Mat'l Stockpiles, Coke Breeze, Limestone, Ore Fines
30300813 Iron Production (See 3-03-015), Windbox
30300817 Iron Production (See 3-03-015), Cooler
30300821 Iron Production (See 3-03-015), Unload Ore, Pellets, Limestone, into Blast Furnace
30300824	Iron Production (See 3-03-015), Blast Heating Stoves
30300825	Primary Metal Production, Iron Production (See 3-03-015), Cast House
30300826	Iron Production (See 3-03-015), Blast Furnace Slips
30300832	Iron Production (See 3-03-015), Unpaved Roads: Medium Duty Vehicles
30300833	Iron Production (See 3-03-015), Unpaved Roads: Heavy Duty Vehicles
30300834	Iron Production (See 3-03-015), Paved Roads: All Vehicle Types
30300841	Primary Metal Production, Iron Production (See 3-03-015), Flue Dust Unloading
30300842	Iron Production (See 3-03-015), Blended Ore Unloading
30300899 Iron Production (See 3-03-015), See Comment **
30300904 Primary Metal Production, Steel (See 303015), Electric Arc FurnaceAlloy Steel (Stack)
30300906	Steel Manufacturing (See 3-03-015), Charging: Electric Arc Furnace
30300907	Steel Manufacturing (See 3-03-015), Tapping: Electric Arc Furnace
30300908	Primary Metal Prod., Steel (See 303015), Electric Arc Furnace-Carbon Steel (Stack)
30300910	Primary Metal Production, Steel Manufacturing (See 3-03-015), Pickling
30300911	Steel Manufacturing (See 3-03-015), Soaking Pits
30300912	Primary Metal Production, Steel Manufacturing (See 3-03-015), Grinding
30300913	Primary Metal Production, Steel (See 303015), Basic Oxygen Furnace-Open Hood-Stack
30300914	Steel Manufacturing (See 3-03-015), Basic Oxygen Furnace: Closed Hood-Stack
30300916	Steel Manufacturing (See 3-03-015), Charging: BOF
30300917	Steel Manufacturing (See 3-03-015), Tapping: BOF
30300920	Steel Manufacturing (See 3-03-015), Hot Metal Desulfurization
30300921	Steel Manufacturing (See 3-03-015), Teeming (Unleaded Steel)
30300922	Primary Metal Production, Steel Manufacturing (See 3-03-015), Continuous Casting
30300923	Steel Manufacturing (See 3-03-015), Steel Furnace Slag Tapping and Dumping
30300924	Steel Manufacturing (See 3-03-015), Steel Furnace Slag Processing
30300931	Primary Metal Production, Steel Manufacturing (See 3-03-015), Hot Rolling
30300932	Steel Manufacturing (See 3-03-015), Scarfing
30300933	Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
30300934	Primary Metal Production, Steel (See 303015), Heat Treating Furnaces-Annealing
30300935	Primary Metal Production, Steel Manufacturing (See 3-03-015), Cold Rolling
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AT-A-GLANCE TABLE FOR POINT SOURCES
30300936 Primary Metal Production, Steel Manufacturing (See 3-03-015), Coating: Tin, Zinc, etc.
30300998	Steel Manufacturing (See 3-03-015), Other Not Classified
30300999	Primary Metal Production, Steel Manufacturing (See 3-03-015), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 73% from uncontrolled; PM2.5 control efficiency is
25% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for venturi wet scrubbers, developed using EPA cost-
estimating spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of
the waste stream treated. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $3 to $28 per scfm
Typical value is $11 per scfm
O&M Costs:
Range from $4 to $119 per scfm
Typical value is $42 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
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Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 2,000 and 150,000 acfm. The average percentage of the total O&M cost was
then calculated for each O&M cost component. The model plants were assumed to
have a dust loading of 3.0 grains per cubic feet. The operating time was assumed to
be 8760 hours per year. An inlet water flow rate for the scrubber was assumed to be
9.4 Ibs/min. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	25
Wastewater treatment 3.8
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $76 to $2,100
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $751 per ton
PM10 reduced. (1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Steel normally is produced in either basic oxygen process furnaces or electric arc furnaces. In the
basic oxygen process furnace, a mixture of 70 percent molten iron from the blast furnace and 30
percent iron scrap are melted together. Pure oxygen is blown across the top or through the molten
steel to oxidize carbon and oxygen impurities, thus removing these from the steel. Basic oxygen
process furnaces are large open-mouthed furnaces that can be tilted to accept a charge or to tap the
molten steel to a charging ladle for transfer to an ingot mold or continuous caster.
Because basic oxygen furnaces are open, they produce significant uncontrolled particulate
emissions, notably during the refining stage when oxygen is being blown. Electric arc furnaces use
the current passing between carbon electrodes to heat molten steel, but also use oxy-fuel burners to
accelerate the initial melting process. These furnaces are charged largely with scrap iron.
Significant emissions occur during charging, when the furnace roof is open, during melting, as the
electrodes are lowered into the scrap and the arc is struck, and during tapping, when alloying
elements are added to the melt.
The costs do not include costs for post-treatment or disposal of used solvent or waste. Actual costs
can be substantially higher than in the ranges shown for applications which require expensive
materials, solvents, or treatment methods (EPA, 1999). As a rule, smaller units controlling a low
concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow.
By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
A venturi scrubber accelerates the waste gas stream to improve gas-liquid contact. In a venturi
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scrubber, a "throat"' section is built into the duct that forces the gas stream to accelerate (EPA,
1999). As the gas enters the venturi throat, both gas velocity and turbulence increase.
After the throat section, the mixture decelerates, and further impacts occur causing the droplets to
agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid
are separated from the gas stream through entrainment. This section usually consists of a cyclonic
separator and/or a mist eliminator (EPA, 1998; Corbitt, 1990).
For PM applications, wet scrubbers generate waste, either a slurry or wet sludge. This creates the
need for both wastewater treatment and solid waste disposal. Initially, the slurry is treated to
separate the solid waste from the water (EPA, 1999). The treated water can then be reused or
discharged. Once the water is removed, the remaining waste will be in the form of a solid or sludge.
If the solid waste is inert and nontoxic, it can generally be land filled. Hazardous wastes will have
more stringent procedures for disposal. In some cases, the solid waste may have value and can be
sold or recycled (EPA, 1998).
References:
Corbitt, 1990: "Standard Handbook of Environmental Engineering," edited by Robert A. Corbitt,
McGraw-Hill, New York, NY, 1990.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Venturi Scrubber," July 1999.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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Source Category: Ferrous Metals Processing - Other
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3240	POD: 240
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303015** Primary Metal Production, Integrated Iron and Steel Manufacturing
303024** Primary Metal Production, Metal Mining (General Processes)
303023** Primary Metal Production, Zinc Production
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Ferrous Metals Processing - Other
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4240	POD: 240
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303015** Primary Metal Production, Integrated Iron and Steel Manufacturing
303024** Primary Metal Production, Metal Mining (General Processes)
303023** Primary Metal Production, Zinc Production
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
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Note: All costs are in 2003 dollars.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Ferrous Metals Processing - Steel Foundries
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2171
POD: 217
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to ferrous metals processing operations, specifically steel
foundries.
Affected SCC:
30400701
30400704
30400705
30400706
30400708
30400709
30400711
30400712
30400713
30400714
30400715
30400716
30400717
30400724
30400799
30400999
Secondary Metal Production, Steel Foundries, Electric Arc Furnace
Steel Foundries, Heat Treating Furnace
Steel Foundries, Electric Induction Furnace
Steel Foundries, Sand Grinding/Handling
Steel Foundries, Pouring/Casting
Steel Foundries, Casting Shakeout
Steel Foundries, Cleaning
Steel Foundries, Charge Handling
Steel Foundries, Castings Cooling
Steel Foundries, Shakeout Machine
Steel Foundries, Finishing
Secondary Metal Production, Steel Foundries, Sand Grinding/Handling
Steel Foundries, Core Ovens
Steel Foundries, Sand Screens
Steel Foundries, Other Not Classified
Malleable Iron, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
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coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Ferrous Metals Processing - Steel Foundries
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2172
POD: 217
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to ferrous metals processing operations, specifically steel
foundries.
Affected SCC:
30400701
30400704
30400705
30400706
30400708
30400709
30400711
30400712
30400713
30400714
30400715
30400716
30400717
30400724
30400799
30400999
Secondary Metal Production, Steel Foundries, Electric Arc Furnace
Steel Foundries, Heat Treating Furnace
Steel Foundries, Electric Induction Furnace
Steel Foundries, Sand Grinding/Handling
Steel Foundries, Pouring/Casting
Steel Foundries, Casting Shakeout
Steel Foundries, Cleaning
Steel Foundries, Charge Handling
Steel Foundries, Castings Cooling
Steel Foundries, Shakeout Machine
Steel Foundries, Finishing
Secondary Metal Production, Steel Foundries, Sand Grinding/Handling
Steel Foundries, Core Ovens
Steel Foundries, Sand Screens
Steel Foundries, Other Not Classified
Malleable Iron, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Steel Foundries
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2173
POD: 217
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to ferrous metals processing operations, specifically steel
foundries.
Affected SCC:
30400701
30400704
30400705
30400706
30400708
30400709
30400711
30400712
30400713
30400715
30400717
30400724
30400799
30400999
Secondary Metal Production, Steel Foundries, Electric Arc Furnace
Steel Foundries, Heat Treating Furnace
Steel Foundries, Electric Induction Furnace
Steel Foundries, Sand Grinding/Handling
Steel Foundries, Pouring/Casting
Steel Foundries, Casting Shakeout
Steel Foundries, Cleaning
Steel Foundries, Charge Handling
Steel Foundries, Castings Cooling
Steel Foundries, Finishing
Steel Foundries, Core Ovens
Steel Foundries, Sand Screens
Steel Foundries, Other Not Classified
Malleable Iron, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
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capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
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AT-A-GLANCE TABLE FOR POINT SOURCES
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Steel Foundries
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2174
POD: 217
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to ferrous metals processing operations, specifically steel
foundries.
Affected SCC:
30400701
30400704
30400705
30400706
30400708
30400709
30400711
30400712
30400713
30400714
30400715
30400716
30400717
30400724
30400799
30400999
Secondary Metal Production, Steel Foundries, Electric Arc Furnace
Steel Foundries, Heat Treating Furnace
Steel Foundries, Electric Induction Furnace
Steel Foundries, Sand Grinding/Handling
Steel Foundries, Pouring/Casting
Steel Foundries, Casting Shakeout
Steel Foundries, Cleaning
Steel Foundries, Charge Handling
Steel Foundries, Castings Cooling
Steel Foundries, Shakeout Machine
Steel Foundries, Finishing
Secondary Metal Production, Steel Foundries, Sand Grinding/Handling
Steel Foundries, Core Ovens
Steel Foundries, Sand Screens
Steel Foundries, Other Not Classified
Malleable Iron, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
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AT-A-GLANCE TABLE FOR POINT SOURCES
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	20
Wastewater treatment 1.5
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wire-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Steel Foundries
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2175
POD: 217
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to ferrous metals processing operations, specifically steel
foundries.
Affected SCC:
30400701
30400704
30400705
30400706
30400708
30400709
30400711
30400712
30400713
30400714
30400715
30400716
30400717
30400724
30400799
30400999
Secondary Metal Production, Steel Foundries, Electric Arc Furnace
Steel Foundries, Heat Treating Furnace
Steel Foundries, Electric Induction Furnace
Steel Foundries, Sand Grinding/Handling
Steel Foundries, Pouring/Casting
Steel Foundries, Casting Shakeout
Steel Foundries, Cleaning
Steel Foundries, Charge Handling
Steel Foundries, Castings Cooling
Steel Foundries, Shakeout Machine
Steel Foundries, Finishing
Secondary Metal Production, Steel Foundries, Sand Grinding/Handling
Steel Foundries, Core Ovens
Steel Foundries, Sand Screens
Steel Foundries, Other Not Classified
Malleable Iron, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price ~0.0671 ~$/kW-hr
Compressed air J0.25 ^$71000 scf
Dust disposal J25 ~$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Steel Foundries
Control Measure Name: Venturi Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2176	POD: 217
Application: The control is the use of a venturi scrubber to reduce PM emissions. A scrubber is a
type of technology that removes air pollutants by inertial and diffusional interception. A
venturi scrubber accelerates the waste gas stream to atomize the scrubbing liquid and
to improve gas-liquid contact.
This control applies to ferrous metals processing operations, specifically steel
foundries.
Affected SCC:
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 73% from uncontrolled; PM2.5 control efficiency is
25% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for venturi wet scrubbers, developed using EPA cost-
estimating spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of
the waste stream treated. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
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with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $3 to $28 per scfm
Typical value is $11 per scfm
O&M Costs:
Range from $4 to $119 per scfm
Typical value is $42 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 2,000 and 150,000 acfm. The average percentage of the total O&M cost was
then calculated for each O&M cost component. The model plants were assumed to
have a dust loading of 3.0 grains per cubic feet. The operating time was assumed to
be 8760 hours per year. An inlet water flow rate for the scrubber was assumed to be
9.4 Ibs/min. The following assumptions apply to the cost of utilities and disposal:
Electricity price	0.067	$/kW-hr
Process water price	0.20	$/1000gal
Dust disposal	25	$/ton disposed
Wastewater treatment 3.8 $/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $76 to $2,100
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $751 per ton
PM10 reduced. (1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The costs do not include costs for post-treatment or disposal of used solvent or waste. Actual costs
can be substantially higher than in the ranges shown for applications which require expensive
materials, solvents, or treatment methods (EPA, 1999). As a rule, smaller units controlling a low
concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow.
By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
A venturi scrubber accelerates the waste gas stream to improve gas-liquid contact. In a venturi
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scrubber, a "throat"' section is built into the duct that forces the gas stream to accelerate (EPA,
1999). As the gas enters the venturi throat, both gas velocity and turbulence increase.
After the throat section, the mixture decelerates, and further impacts occur causing the droplets to
agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid
are separated from the gas stream through entrainment. This section usually consists of a cyclonic
separator and/or a mist eliminator (EPA, 1998; Corbitt, 1990).
For PM applications, wet scrubbers generate waste, either a slurry or wet sludge. This creates the
need for both wastewater treatment and solid waste disposal. Initially, the slurry is treated to
separate the solid waste from the water (EPA, 1999). The treated water can then be reused or
discharged. Once the water is removed, the remaining waste will be in the form of a solid or sludge.
If the solid waste is inert and nontoxic, it can generally be land filled. Hazardous wastes will have
more stringent procedures for disposal. In some cases, the solid waste may have value and can be
sold or recycled (EPA, 1998).
References:
Corbitt, 1990: "Standard Handbook of Environmental Engineering," edited by Robert A. Corbitt,
McGraw-Hill, New York, NY, 1990.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Venturi Scrubber," July 1999.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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Source Category: Ferrous Metals Processing - Steel Foundries
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3217	POD: 217
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
304007** Secondary Metal Production, Steel Foundries
304009** Secondary Metal Production, Malleable Iron
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Ferrous Metals Processing - Steel Foundries
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4217	POD: 217
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
304007** Secondary Metal Production, Steel Foundries
304009** Secondary Metal Production, Malleable Iron
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Grain Milling
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2231	POD: 223
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to grain milling operations, including (but not limited to), wheat, dry
corn, wet corn, rice, and soybean operations.
Affected SCC:
30200701	Grain Millings, General **
30200702	Grain Millings, General **
30200730 Grain Millings, General **
30200731	Grain Millings, Wheat
30200732	Grain Millings, Wheat
30200733	Grain Millings, Wheat
30200734	Grain Millings, Wheat
Grain Receiving
Precleaning/Handling
Cleaning House
Millhouse
30200741	Grain Millings, Dry Corn Milling: Grain Receiving
30200742	Food and Agriculture, Grain Millings, Dry Corn Milling: Grain Drying
30200743	Food and Agriculture, Grain Millings, Dry Corn Milling: Precleaning/Handling
30200744	Grain Millings, Dry Corn Milling: Cleaning House
30200745	Food and Agriculture, Grain Millings, Dry Corn Milling: Degerming and Milling
30200751	Grain Millings, Wet Corn Milling: Grain Receiving
30200752	Grain Millings, Wet Corn Milling: Grain Handling
30200753	Grain Millings, Wet Corn Milling: Grain Cleaning
30200754	Grain Millings, Wet Corn Milling: Dryers
30200755	Grain Millings, Wet Corn Milling: Bulk Loading
30200756	Grain Millings, Wet Corn Milling: Milling
30200771	Grain Millings, Rice: Grain Receiving
30200772	Grain Millings, Rice: Precleaning/Handling
30200773	Grain Millings, Rice: Drying
30200781	Grain Millings, Soybean: Grain Receiving
30200782	Grain Millings, Soybean: Grain Handling
30200783	Grain Millings, Soybean: Grain Cleaning
30200784	Grain Millings, Soybean: Drying
30200785	Grain Millings, Soybean: Cracking and Dehulling
30200786	Grain Millings, Soybean: Hull Grinding
30200787	Grain Millings, Soybean: Bean Conditioning
30200788	Food and Agriculture, Grain Millings, Soybean: Flaking
30200789	Food and Agriculture, Grain Millings, Soybean: Meal Dryer
30200790	Food and Agriculture, Grain Millings, Soybean: Meal Cooler
30200791	Food and Agriculture, Grain Millings, Soybean: Bulk Loading
30200799 Grain Millings, **
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
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AT-A-GLANCE TABLE FOR POINT SOURCES
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
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taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Grain Milling
Control Measure Name: Paper/Nonwoven Filters - Cartridge Collector Type
Rule Name: Not Applicable
Pechan Measure Code: P2232	POD: 223
Application: This control is the use of paper or non-woven filters (cartridge collector type) to reduce
PM emissions. The waste gas stream is passed through the fibrous filter media
causing PM in the gas stream to be collected on the media by sieving and other
mechanisms.
This control measure applies to grain milling operations, including those involved with
the production of wheat, corn, rice, and soybeans, among others.
Affected SCC:
30200701	Grain Millings, General **
30200702	Grain Millings, General **
30200730 Grain Millings, General **
30200731	Grain Millings, Wheat
30200732	Grain Millings, Wheat
30200733	Grain Millings, Wheat
30200734	Grain Millings, Wheat
Grain Receiving
Precleaning/Handling
Cleaning House
Millhouse
30200741	Grain Millings, Dry Corn Milling: Grain Receiving
30200742	Food and Agriculture, Grain Millings, Dry Corn Milling: Grain Drying
30200743	Food and Agriculture, Grain Millings, Dry Corn Milling: Precleaning/Handling
30200744	Grain Millings, Dry Corn Milling: Cleaning House
30200745	Food and Agriculture, Grain Millings, Dry Corn Milling: Degerming and Milling
30200751	Grain Millings, Wet Corn Milling: Grain Receiving
30200752	Grain Millings, Wet Corn Milling: Grain Handling
30200753	Grain Millings, Wet Corn Milling: Grain Cleaning
30200754	Grain Millings, Wet Corn Milling: Dryers
30200755	Grain Millings, Wet Corn Milling: Bulk Loading
30200756	Grain Millings, Wet Corn Milling: Milling
30200771	Grain Millings, Rice: Grain Receiving
30200772	Grain Millings, Rice: Precleaning/Handling
30200773	Grain Millings, Rice: Drying
30200781	Grain Millings, Soybean: Grain Receiving
30200782	Grain Millings, Soybean: Grain Handling
30200783	Grain Millings, Soybean: Grain Cleaning
30200784	Grain Millings, Soybean: Drying
30200785	Grain Millings, Soybean: Cracking and Dehulling
30200786	Grain Millings, Soybean: Hull Grinding
30200787	Grain Millings, Soybean: Bean Conditioning
30200788	Food and Agriculture, Grain Millings, Soybean: Flaking
30200789	Food and Agriculture, Grain Millings, Soybean: Meal Dryer
30200790	Food and Agriculture, Grain Millings, Soybean: Meal Cooler
30200791	Food and Agriculture, Grain Millings, Soybean: Bulk Loading
30200799 Grain Millings, **
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are generated using EPA's cost-estimating spreadsheets for fabric filters
(EPA, 1998a). Costs are primarily driven by the waste stream volumetric flow rate
and pollutant loading. When stack gas flow rate data was available, the costs and
cost effectiveness were calculated using the typical values of capital and O&M costs.
When stack gas flow rate data was not available, default typical capital and O&M cost
values based on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $7 to $13 per scfm
Typical value is $9 per scfm
O&M Costs:
Range from $9 to $25 per scfm
Typical value is $14 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average cartridge cost was estimated using the costs for standard
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cartridge types. Capital recovery for the periodic replacement of cartridges was
included in the O&M cost of the cartridges using a cartridge life of 2 years (EPA,
1998a). The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal 25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $85 to $256 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $142 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. Auxiliary
equipment, such as fans and ductwork, is not included (EPA, 2000). Pollutants that require an
unusually high level of control or that require the filter media or the unit itself to be constructed of
special materials, such as Nomex ® or stainless steel, will increase the costs of the system (EPA,
1998a). The additional costs for controlling more complex waste streams are not reflected in the
estimates given below. For these types of systems, the capital cost could increase by as much as
75% and the O&M cost could increase by as much as 10%. In general, a small unit controlling a low
pollutant loading will not be as cost effective as a large unit controlling a high pollutant loading (EPA,
2000).
Cartridge filters contain either a paper or nonwoven fibrous filter media (EPA, 2000). Paper media is
generally made of materials such as cellulose and fiberglass. The dust cake that forms on the filter
media from the collected PM can significantly increase collection efficiency (EPA, 1998b).
In general, the filter media is pleated to provide a larger surface area to volume flow rate. Close
pleating, however, can cause PM to bridge the pleat bottom, effectively reducing the surface
collection area (EPA, 1998b). Corrugated aluminum separators are used to prevent the pleats from
collapsing (Heumann, 1997). There are variety of cartridge designs and dimensions. Typical
designs include flat panels, V-shaped packs or cylindrical packs (Heumann, 1997). For certain
applications, two cartridges may be placed in series.
Cartridge collectors are useful for collecting particles with resistivities either too low or too high for
collection with electrostatic precipitators (STAPPA/AI_APCO, 1996). For similar air flow rates,
cartridge collectors are compact in size compared to traditional bag
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Cartridge Collector with Pulse-Jet Cleaning," April 2000.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Grain Milling
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2233	POD: 223
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to grain milling operations, including (but not limited to), wheat, dry
corn, wet corn, rice, and soybean operations.
Affected SCC:
30200701	Grain Millings, General **
30200702	Grain Millings, General **
30200730 Grain Millings, General **
30200731	Grain Millings, Wheat
30200732	Grain Millings, Wheat
30200733	Grain Millings, Wheat
30200734	Grain Millings, Wheat
Grain Receiving
Precleaning/Handling
Cleaning House
Millhouse
30200741	Grain Millings, Dry Corn Milling: Grain Receiving
30200742	Food and Agriculture, Grain Millings, Dry Corn Milling: Grain Drying
30200743	Food and Agriculture, Grain Millings, Dry Corn Milling: Precleaning/Handling
30200744	Grain Millings, Dry Corn Milling: Cleaning House
30200745	Food and Agriculture, Grain Millings, Dry Corn Milling: Degerming and Milling
30200751	Grain Millings, Wet Corn Milling: Grain Receiving
30200752	Grain Millings, Wet Corn Milling: Grain Handling
30200753	Grain Millings, Wet Corn Milling: Grain Cleaning
30200754	Grain Millings, Wet Corn Milling: Dryers
30200755	Grain Millings, Wet Corn Milling: Bulk Loading
30200756	Grain Millings, Wet Corn Milling: Milling
30200771	Grain Millings, Rice: Grain Receiving
30200772	Grain Millings, Rice: Precleaning/Handling
30200773	Grain Millings, Rice: Drying
30200781	Grain Millings, Soybean: Grain Receiving
30200782	Grain Millings, Soybean: Grain Handling
30200783	Grain Millings, Soybean: Grain Cleaning
30200784	Grain Millings, Soybean: Drying
30200785	Grain Millings, Soybean: Cracking and Dehulling
30200786	Grain Millings, Soybean: Hull Grinding
30200787	Grain Millings, Soybean: Bean Conditioning
30200788	Food and Agriculture, Grain Millings, Soybean: Flaking
30200789	Food and Agriculture, Grain Millings, Soybean: Meal Dryer
30200790	Food and Agriculture, Grain Millings, Soybean: Meal Cooler
30200791	Food and Agriculture, Grain Millings, Soybean: Bulk Loading
30200799 Grain Millings, **
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
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AT-A-GLANCE TABLE FOR POINT SOURCES
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal 25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
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AT-A-GLANCE TABLE FOR POINT SOURCES
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Gasoline Engine
Control Measure Name: RFG and High Enhanced l/M Program
Rule Name: Not Applicable
Pechan Measure Code: mOT7
POD: N/A
Application: This control measure represents a combination of the year round national use of
Federal Reformulated gasoline and an enhanced l/M program for light duty gasoline
vehicles. Emission reduction benefits of NOx, CO, and VOC are estimated using
EPA's MOBILE6 model.
This control is applicable to all light duty gasoline vehicles, motor cycles, and trucks.
Affected SCC:
2201001000 Light Duty Gasoline Vehicles (LDGV), Total: All Road Types
2201020000 Light Duty Gasoline Trucks 1 (LDGT1), Total: All Road Types
2201040000 Light Duty Gasoline Trucks 2 (LDGT2), Total: All Road Types
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2201080000 Motorcycles (MC), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg




V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency ranged from: NOx (-1.6 % to 13.51%; VOC (-9.1 to
31.9%); CO (-2.1 to 35.4%)
Equipment Life: Not Applicable
Rule Effectiveness: Not applicable
Penetration: Not applicable
Cost Basis: The total annual cost was estimated using the number of vehicles and amount of fuel
consumed by county and vehicle type. Costs were estimated on a per-vehicle basis
in all counties with no RFG in the base case.
The number of vehicles was estimated by dividing the VMT by the average LDGV
annual mileage accumulation rate. The annual costs for is estimated assuming
$0,043 per gallon for RFG and $17.95 per vehicle inspected in counties with no l/M
program and $11.43 per vehicle inspected in counties with current basic or low l/M
program (Pechan 2002). All costs are $1997.
Cost Effectiveness: The cost effectiveness of varies greatly by county. Cost effectiveness for VOC
ranged from $1,180,340 to negative $484 per ton. The average C-E for VOC
is $16,164 per ton of VOC reduced (median is $8,093 per ton). All costs are
$1997.
Comments: In some cases this control produces a slight NOx disbenefit.
Status: Demonstrated
Last Reviewed: 2002
Additional Information:
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
References:
Pechan 2002: "AirControlNET Specifications and Methods for Mobile Source Controls" Memo
prepared for Larry Sorrels of the US EPA, December 2002.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Heavy Duty Diesel Engines
Control Measure Name: Voluntary Diesel Retrofit Program: Diesel Particulate Filter
Rule Name: Not Applicable
Pechan Measure Code: HDR199	POD:
Application: This control measure represents the application of EPA's voluntary diesel retrofit
program through the use of the diesel particulate filter as a retrofit technology in 1999.
Emissions reduction benefits of CO, VOC, PM10, PM2.5, and S02 are estimated using
EPA's MOBILE6 model and independent research on the percent reductions yielded by
this control measure.
This control is applicable to all heavy duty diesel vehicles. Light duty and gasoline-
fueled vehicles are not affected by this control.
Affected SCC:
2230070000 Heavy Duty Diesel Vehicles (HDDV), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V



V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies for the affected pollutants are:PM10 (61.99%); PM2.5
(62.26%); VOC (60%), S02 (97%); CO (60%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the use of the diesel particulate filter as a retrofit technology,
the assumption was made that all relevant vehicles would be affected by the control.
Therefore, all heavy duty diesel vehicles were assumed to employ the diesel
particulate filter as a retrofit technology through the voluntary diesel retrofit program.
The average costs for the diesel particulate filter range from $3,000 to $10,000
(Pechan, 2003). Prices vary depending on the size of the engine being retrofit, the
sales volume, the amount of particulate matter emitted by the engine, the emission
target that must be achieved, the regeneration method, and other factors. For this
AirControlNET analysis, an average estimated cost of $6,500 per heavy duty diesel
vehicle was used.
Diesel particulate filters require the use of low sulfur diesel fuel. The costs for the low
sulfur diesel fuel were applied to all gallons of diesel fuel used by the heavy duty
diesel vehicles. Low sulfur diesel fuel is estimated to cost an additional $0.05 per
gallon of diesel (EPA, 2000). All costs are in 1999 dollars.
Cost Effectiveness: The cost effectiveness of the diesel particulate filter varies greatly by county
and depends mostly on the number of vehicles. Cost effectiveness for PM10-
2.5 fell within the following range: $195,472 to $843,143 per ton PM10
reduced. The average cost effectiveness used in AirControlNET for PM10-2.5
is $727,689.14 per ton of PM 10-2.5 reduced. All costs are in $1999.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2000: U.S. Environmental Protection Agency, "Regulatory Impact Analysis: Control of
Emissions of Air Pollution from Highway Heavy-Duty Engines." EPA420-R-00-010, July 2000.
Pechan, 2003. E.H. Pechan & Associates, Inc., "Methodology to Implement Voluntary Diesel
Retrofit Program in AirControlNET," Memo prepared for Tyler Fox of the US EPA, July 2003.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Heavy Duty Diesel Engines
Control Measure Name: Voluntary Diesel Retrofit Program: Diesel Oxidation Catalyst
Rule Name: Not Applicable
Pechan Measure Code: HDR299	POD:
Application: This control measure represents the application of EPA's voluntary diesel retrofit
program through the use of the diesel oxidation catalyst as a retrofit technology in
1999. Emissions reduction benefits of CO, VOC, PM10, PM2.5, and S02 are
estimated using EPA's MOBILE6 model and independent research on the percent
reductions yielded by this control measure.
This control is applicable to all heavy duty diesel vehicles. Light duty and gasoline-
fueled vehicles are not affected by this control.
Affected SCC:
2230070000 Heavy Duty Diesel Vehicles (HDDV), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V



V
V

V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiencies vary by affected pollutant: PM10 (24.01%); PM2.5
(24.52%); VOC (50%); S02 (97%); CO (40%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the use of the diesel oxidation catalyst as a retrofit technology,
the assumption was made that all relevant vehicles would be affected by the control.
Therefore, all heavy duty diesel vehicles were assumed to employ the diesel oxidation
catalyst as a retrofit technology through the voluntary diesel retrofit program. The
average cost for diesel oxidation catalysts ranges from $500 to $3,000 depending on
the engine size, sales volume and whether the installation is a muffler replacement or
an in-line installation. For this AirControlNET analysis, the average estimated cost of
a disel oxidation catalyst is $1,750 per heavy duty diesel vehicle. All costs are in
1999 dollars.
Diesel oxidation catalysts require the use of low sulfur diesel fuel. The costs for the
low sulfur diesel fuel were applied to all gallons of diesel fuel used by the heavy duty
diesel vehicles. Low sulfur diesel fuel is estimated to cost an additional $0.05 per
gallon of diesel (EPA, 2000). All costs are in 1999 dollars.
Cost Effectiveness: The cost effectiveness of the diesel oxidation catalyst varies greatly by county
and depends mostly on the number of vehicles. Cost effectiveness for PM10
fell within the following range: $48,660 to $217,612 per ton PM10 reduced.
The average cost effectiveness used in AirControlNET for PM10 is
$167,639.74 per ton of PM10 reduced. All costs are in $1999.
Comments:
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2000: U.S. Environmental Protection Agency, "Regulatory Impact Analysis: Control of
Emissions of Air Pollution from Highway Heavy-Duty Engines." EPA420-R-00-010, July 2000.
Pechan, 2003. E.H. Pechan & Associates, Inc., "Methodology to Implement Voluntary Diesel
Retrofit Program in AirControlNET," Memo prepared for Tyler Fox of the US EPA, July 2003.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Heavy Duty Diesel Engines
Control Measure Name: Voluntary Diesel Retrofit Program: Biodiesel Fuel
Rule Name: Not Applicable
Pechan Measure Code: HDR499	POD:
Application: This control measure represents the application of EPA's voluntary diesel retrofit
program through the use of biodiesel fuel as a retrofit activity in 1999. Emissions
reduction benefits of CO, VOC, PM10-2.5, and PM2.5 are estimated as a result of
research conducted on the percent reductions yielded by this control measure.
This control is applicable to all heavy duty diesel vehicles. Light duty and gasoline-
fueled vehicles are not affected by this control.
Affected SCC:
2230070000 Heavy Duty Diesel Vehicles (HDDV), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V



V


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by pollutant: PM10 (7%); PM2.5 (7%); VOC (13%);
CO (5%)
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the use of biodiesel fuel as a retrofit activity, the assumption
was made that all relevant vehicles would be affected by the control. Therefore, the
costs of biodiesel fuel is applied to all gallons of fuel used by the heavy duty diesel
vehicles. The costs of biodiesel fuel are estimated to range from 15 to 30 cents per
gallon. For this AirControlNET analysis, the cost of biodiesel fuel was averaged to
$0,225 per gallon of fuel (Pechan 2003). All costs are in 1999 dollars.
Cost Effectiveness:
The cost effectiveness of selective catalytic reduction varies greatly by county
and depends mostly on the number of vehicles. Cost effectiveness for PM10
fell within the following range: $74,033 to $275,756 per ton PM10 reduced the
average control efficiency used in AirControlNET for PM10 is $209,913.27 per
ton of PM10 reduced. All costs are in $1999.
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
Pechan, 2003. E.H. Pechan & Associates, Inc., "Methodology to Implement Voluntary Diesel
Retrofit Program in AirControlNET," Memo prepared for Tyler Fox of the US EPA, July 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Boilers - Coal
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2011	POD: 201
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to operations with coal-fired boilers.
Affected SCC:
10200101 Anthracite Coal, Pulverized Coal
10200104 Anthracite Coal, Traveling Grate (Overfeed) Stoker
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
10200203	Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
10200204	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
10200205	Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
10200206	Industrial, Bituminous/Subbituminous Coal, Underfeed Stoker
10200210 Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker**
10200212 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
10200217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
10200219 Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
10200222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
10200224	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10200225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
10200229 Bituminous/Subbituminous Coal, Cogeneration (Subbituminous Coal)
10200303 Lignite, Cyclone Furnace
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price	0.0671 $/kW-hr
Compressed air	0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
Particulate composition and emission levels are a complex function of firing configuration, boiler
operation, and coal properties.
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
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with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Industrial Boilers - Coal
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2012	POD: 201
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to all coal-fired industrial boilers.
Affected SCC:
10200101 Anthracite Coal, Pulverized Coal
10200104 Anthracite Coal, Traveling Grate (Overfeed) Stoker
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
10200203	Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
10200204	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
10200205	Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
10200206	Industrial, Bituminous/Subbituminous Coal, Underfeed Stoker
10200210 Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker**
10200212 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
10200219 Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
10200222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
10200224	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10200225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
10200229 Bituminous/Subbituminous Coal, Cogeneration (Subbituminous Coal)
10200303 Lignite, Cyclone Furnace
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
There are two major coal combustion techniques in industrial boilers - suspension firing and grate
firing. Suspension firing is the primary combustion mechanism in pulverized-coal-fired and cyclone-
fired units and overfeed stoker-fired units. Both mechanisms are employed in spreader stokers.
Pulverized-coal and cyclone furnaces are used primarily in utility and large industrial boilers.
Stokers constitute the most practical method of firing coal for small industrial units. In spreader
stokers, a flipping mechanism throws the coal into the furnace and onto a moving fuel bed.
Combustion occurs partly in suspension and partly on the grate. In overfeed stokers, coal is fed
onto a traveling bed or vibrating grate, and it burns on the fuel bed as it progresses through the
furnace (AWMA, 1992).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
AWMA, 1992: Air & Waste Management Association, "Air Pollution Engineering Manual," edited by
A. Buonicore and W. Davis, Van Nostrand Reinhold, NY, NY, 1992.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
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EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Industrial Boilers - Coal
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2013	POD: 201
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to operations with coal-fired boilers.
Affected SCC:
10200101 Anthracite Coal, Pulverized Coal
10200104 Anthracite Coal, Traveling Grate (Overfeed) Stoker
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
10200203	Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
10200204	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
10200205	Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
10200206	Industrial, Bituminous/Subbituminous Coal, Underfeed Stoker
10200210 Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker**
10200212 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
10200217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
10200219 Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
10200222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
10200224	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10200225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
10200229 Bituminous/Subbituminous Coal, Cogeneration (Subbituminous Coal)
10200303 Lignite, Cyclone Furnace
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
There are two major coal combustion techniques in industrial boilers - suspension firing and grate
firing. Suspension firing is the primary combustion mechanism in pulverized-coal-fired and cyclone-
fired units and overfeed stoker-fired units. Both mechanisms are employed in spreader stokers.
Pulverized-coal and cyclone furnaces are used primarily in utility and large industrial boilers.
Stokers constitute the most practical method of firing coal for small industrial units. In spreader
stokers, a flipping mechanism throws the coal into the furnace and onto a moving fuel bed.
Combustion occurs partly in suspension and partly on the grate. In overfeed stokers, coal is fed
onto a traveling bed or vibrating grate, and it burns on the fuel bed as it progresses through the
furnace (AWMA, 1992).
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
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References:
AWMA, 1992: Air & Waste Management Association, "Air Pollution Engineering Manual," edited by
A. Buonicore and W. Davis, Van Nostrand Reinhold, NY, NY, 1992.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Industrial Boilers - Coal
Control Measure Name: Venturi Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2014	POD: 201
Application: The control is the use of a venturi scrubber to reduce PM emissions. A scrubber is a
type of technology that removes air pollutants by inertial and diffusional interception. A
venturi scrubber accelerates the waste gas stream to atomize the scrubbing liquid and
to improve gas-liquid contact.
This control applies to operations with coal-fired boilers.
Affected SCC:
10200101 Anthracite Coal, Pulverized Coal
10200104 Anthracite Coal, Traveling Grate (Overfeed) Stoker
10200201	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
10200202	Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
10200203	Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
10200204	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
10200205	Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
10200206	Industrial, Bituminous/Subbituminous Coal, Underfeed Stoker
10200210 Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker**
10200212 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
10200219 Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
10200222 Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
10200224	Industrial, Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10200225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
10200229 Bituminous/Subbituminous Coal, Cogeneration (Subbituminous Coal)
10200303 Lignite, Cyclone Furnace
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 82% from uncontrolled; PM2.5 control efficiency is
50% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for venturi wet scrubbers, developed using EPA cost-
estimating spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of
the waste stream treated. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
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capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $3 to $28 per scfm
Typical value is $11 per scfm
O&M Costs:
Range from $4 to $119 per scfm
Typical value is $42 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 2,000 and 150,000 acfm. The average percentage of the total O&M cost was
then calculated for each O&M cost component. The model plants were assumed to
have a dust loading of 3.0 grains per cubic feet. The operating time was assumed to
be 8760 hours per year. An inlet water flow rate for the scrubber was assumed to be
9.4 Ibs/min. The following assumptions apply to the cost of utilities and disposal:
Electricity price	0.067	$/kW-hr
Process water price	0.20	$/1000gal
Dust disposal	25	$/ton disposed
Wastewater treatment 3.8	$/thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $76 to $2,100
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $751 per ton
PM10 reduced. (1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
There are two major coal combustion techniques in industrial boilers - suspension firing and grate
firing. Suspension firing is the primary combustion mechanism in pulverized-coal-fired and cyclone-
fired units and overfeed stoker-fired units. Both mechanisms are employed in spreader stokers.
Pulverized-coal and cyclone furnaces are used primarily in utility and large industrial boilers.
Stokers constitute the most practical method of firing coal for small industrial units. In spreader
stokers, a flipping mechanism throws the coal into the furnace and onto a moving fuel bed.
Combustion occurs partly in suspension and partly on the grate. In overfeed stokers, coal is fed
onto a traveling bed or vibrating grate, and it burns on the fuel bed as it progresses through the
furnace (AWMA, 1992).
The costs do not include costs for post-treatment or disposal of used solvent or waste. Actual costs
can be substantially higher than in the ranges shown for applications which require expensive
materials, solvents, or treatment methods (EPA, 1999). As a rule, smaller units controlling a low
concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow.
By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
A venturi scrubber accelerates the waste gas stream to improve gas-liquid contact. In a venturi
scrubber, a "throat"' section is built into the duct that forces the gas stream to accelerate (EPA,
1999). As the gas enters the venturi throat, both gas velocity and turbulence increase.
After the throat section, the mixture decelerates, and further impacts occur causing the droplets to
agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid
are separated from the gas stream through entrainment. This section usually consists of a cyclonic
separator and/or a mist eliminator (EPA, 1998; Corbitt, 1990).
For PM applications, wet scrubbers generate waste, either a slurry or wet sludge. This creates the
need for both wastewater treatment and solid waste disposal. Initially, the slurry is treated to
separate the solid waste from the water (EPA, 1999). The treated water can then be reused or
discharged. Once the water is removed, the remaining waste will be in the form of a solid or sludge.
If the solid waste is inert and nontoxic, it can generally be land filled. Hazardous wastes will have
more stringent procedures for disposal. In some cases, the solid waste may have value and can be
sold or recycled (EPA, 1998).
References:
AWMA, 1992: Air & Waste Management Association, "Air Pollution Engineering Manual," edited by
A. Buonicore and W. Davis, Van Nostrand Reinhold, NY, NY, 1992.
Corbitt, 1990: "Standard Handbook of Environmental Engineering," edited by Robert A. Corbitt,
McGraw-Hill, New York, NY, 1990.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Venturi Scrubber," July 1999.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Boilers - Coal
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3201	POD: 201
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102002** Industrial, Bituminous/Subbituminous Coal
102003** Lignite, Pulverized Coal: Dry Bottom
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% from uncontrolled for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Boilers - Coal
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4201	POD: 201
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102002** Industrial, Bituminous/Subbituminous Coal
102003** Lignite, Pulverized Coal: Dry Bottom
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Boilers - Coke
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3241	POD: 241
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102008** Industrial, Coke
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Boilers - Coke
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4241	POD: 241
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102008** Industrial, Coke
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Boilers - Liquid Waste
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2041	POD: 204
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies operations that have industrial boilers fired with liquid waste,
including waste oil.
Affected SCC:
10201301	Industrial, Liquid Waste, Specify Waste Material in Comments
10201302	Industrial, Liquid Waste, Waste Oil
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
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AT-A-GLANCE TABLE FOR POINT SOURCES
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal 25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
ESPs are used when control efficiencies of 95 percent or more are required. In the wire-plate ESP,
the gas flows around vertical, metal plates. The electrodes are long, weighted wires hanging
between the plates. The voltage applied to the electrodes causes the gas between the electrodes to
break down, known as a "corona." The electrodes are most often given a negative polarity because
a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
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AT-A-GLANCE TABLE FOR POINT SOURCES
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Boilers - Liquid Waste
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3204	POD: 204
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102013** Industrial, Liquid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Boilers - Liquid Waste
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4204	POD: 204
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102013** Industrial, Liquid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Industrial Boilers - LPG
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3242	POD: 242
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102010** Industrial, Liquified Petroleum Gas (LPG)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Industrial Boilers - LPG
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4242	POD: 242
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102010** Industrial, Liquified Petroleum Gas (LPG)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Industrial Boilers - Natural Gas
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3243	POD: 243
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102006** Industrial, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Industrial Boilers - Natural Gas
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4243	POD: 243
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102006** Industrial, Natural Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Industrial Boilers - Oil
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2031	POD: 203
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to operations with oil-fired boilers.
Affected SCC:
10200401	Industrial, Residual Oil, Grade 6 Oil
10200402	Residual Oil, 10-100 Million Btu/hr**
10200404	Industrial, Residual Oil, Grade 5 Oil
10200405	Residual Oil, Cogeneration
10200501 Industrial, Distillate Oil, Grades 1 and 2 Oil
10200504 Industrial, Distillate Oil, Grade 4 Oil
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
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spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Heavier fuel oil derived from crude petroleum are referred to as residual oils and are graded from
No. 4 (very light residual) to No. 6 (residual). Emissions from fuel oil combustion depend on the
grade and composition of the oil, the type and size of the boiler, firing practices used, and the level
of equipment maintenance.
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
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sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Industrial Boilers - Oil
Control Measure Name: Venturi Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2032	POD: 203
Application: The control is the use of a venturi scrubber to reduce PM emissions. A scrubber is a
type of technology that removes air pollutants by inertial and diffusional interception. A
venturi scrubber accelerates the waste gas stream to atomize the scrubbing liquid and
to improve gas-liquid contact.
This control applies to operations with oil-fired boilers.
Affected SCC:
10200401	Industrial, Residual Oil, Grade 6 Oil
10200402	Residual Oil, 10-100 Million Btu/hr**
10200404	Industrial, Residual Oil, Grade 5 Oil
10200405	Residual Oil, Cogeneration
10200501 Industrial, Distillate Oil, Grades 1 and 2 Oil
10200504 Industrial, Distillate Oil, Grade 4 Oil
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 92% from uncontrolled; PM2.5 control efficiency is
89% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for venturi wet scrubbers, developed using EPA cost-
estimating spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of
the waste stream treated. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
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equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $3 to $28 per scfm
Typical value is $11 per scfm
O&M Costs:
Range from $4 to $119 per scfm
Typical value is $42 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 2,000 and 150,000 acfm. The average percentage of the total O&M cost was
then calculated for each O&M cost component. The model plants were assumed to
have a dust loading of 3.0 grains per cubic feet. The operating time was assumed to
be 8760 hours per year. An inlet water flow rate for the scrubber was assumed to be
9.4 Ibs/min. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	25
Wastewater treatment 3.8
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $76 to $2,100
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $751 per ton
PM10 reduced. (1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Fuel-oil types include heavier fuel oil derived from crude petroleum are referred to as residual oils
and are graded from No. 4 (very light residual) to No. 6 (residual). Emissions from fuel oil
combustion depend on the grade and composition of the oil, the type and size of the boiler, firing
practices used, and the level of equipment maintenance.
The costs do not include costs for post-treatment or disposal of used solvent or waste. Actual costs
can be substantially higher than in the ranges shown for applications which require expensive
materials, solvents, or treatment methods (EPA, 1999). As a rule, smaller units controlling a low
concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow.
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By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
A venturi scrubber accelerates the waste gas stream to improve gas-liquid contact. In a venturi
scrubber, a "throat"' section is built into the duct that forces the gas stream to accelerate (EPA,
1999). As the gas enters the venturi throat, both gas velocity and turbulence increase.
After the throat section, the mixture decelerates, and further impacts occur causing the droplets to
agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid
are separated from the gas stream through entrainment. This section usually consists of a cyclonic
separator and/or a mist eliminator (EPA, 1998; Corbitt, 1990).
For PM applications, wet scrubbers generate waste, either a slurry or wet sludge. This creates the
need for both wastewater treatment and solid waste disposal. Initially, the slurry is treated to
separate the solid waste from the water (EPA, 1999). The treated water can then be reused or
discharged. Once the water is removed, the remaining waste will be in the form of a solid or sludge.
If the solid waste is inert and nontoxic, it can generally be land filled. Hazardous wastes will have
more stringent procedures for disposal. In some cases, the solid waste may have value and can be
sold or recycled (EPA, 1998).
References:
Corbitt, 1990: "Standard Handbook of Environmental Engineering," edited by Robert A. Corbitt,
McGraw-Hill, New York, NY, 1990.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Venturi Scrubber," July 1999.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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Source Category: Industrial Boilers - Oil
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3203	POD: 203
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102004** Industrial, Residual Oil
102005** Industrial, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Industrial Boilers - Oil
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4203	POD: 203
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102004** Industrial, Residual Oil
102005** Industrial, Distillate Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Industrial Boilers - Process Gas
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3244	POD: 244
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102007** Industrial, Process Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Industrial Boilers - Process Gas
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4244	POD: 244
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102007** Industrial, Process Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Industrial Boilers - Solid Waste
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3245	POD: 245
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102012** Industrial, Solid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Industrial Boilers - Solid Waste
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4245	POD: 245
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102012** Industrial, Solid Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Industrial Boilers - Wood
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2021	POD: 202
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to operations with wood-fired boilers, classified under the following
SCCs: 10200901, 10200902, 10200903, 10200904, 10200905, 10200906, 10200907.
Affected SCC:
10200901	Industrial, Wood/Bark Waste, Bark-fired Boiler (> 50,000 Lb Steam)
10200902	Industrial, Wood/Bark Waste, Wood/Bark-fired Boiler (> 50,000 Lb Steam)
10200903	Industrial, Wood/Bark Waste, Wood-fired Boiler (> 50,000 Lb Steam)
10200904	Wood/Bark Waste, Bark-fired Boiler (< 50,000 Lb Steam)
10200905	Wood/Bark Waste, Wood/Bark-fired Boiler (< 50,000 Lb Steam)
10200906	Industrial, Wood/Bark Waste, Wood-fired Boiler (< 50,000 Lb Steam)
10200907	Wood/Bark Waste, Wood Cogeneration
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
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were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The burning of wood and bark waste in boilers is mostly confined to industries where wood and bark
waste is available as a byproduct. Wood and bark waste is burned to obtain heat energy and to
alleviate possible solid waste disposal problems. In boilers, the waste is burned in the form of
hogged wood, sawdust, shavings, chips, sander dust, or wood trim. Bark is the major type of waste
burned in "power" boilers at pulp and paper mills. At lumber, furniture, and plywood plants, either a
mixture of wood and bark waste or wood waste alone is burned most frequently (EPA, 1995).
The cost estimates assume a conventional design under typical operating conditions and do not
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include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
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References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.ary
1995.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996
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Source Category: Industrial Boilers - Wood
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2022	POD: 202
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to operations with wood-fired industrial boilers, including those
classified under the following SCCs 10200901, 10200902, 10200903, 10200904,
10200905 , 10200906, 10200907.
Affected SCC:
10200901	Industrial, Wood/Bark Waste, Bark-fired Boiler (> 50,000 Lb Steam)
10200902	Industrial, Wood/Bark Waste, Wood/Bark-fired Boiler (> 50,000 Lb Steam)
10200903	Industrial, Wood/Bark Waste, Wood-fired Boiler (> 50,000 Lb Steam)
10200904	Wood/Bark Waste, Bark-fired Boiler (< 50,000 Lb Steam)
10200905	Wood/Bark Waste, Wood/Bark-fired Boiler (< 50,000 Lb Steam)
10200906	Industrial, Wood/Bark Waste, Wood-fired Boiler (< 50,000 Lb Steam)
10200907	Wood/Bark Waste, Wood Cogeneration
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
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The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The burning of wood and bark waste in boilers is mostly confined to industries where wood and bark
waste is available as a byproduct. Wood and bark waste is burned to obtain heat energy and to
alleviate possible solid waste disposal problems. In boilers, the waste is burned in the form of
hogged wood, sawdust, shavings, chips, sander dust, or wood trim. Bark is the major type of waste
burned in "power" boilers at pulp and paper mills. At lumber, furniture, and plywood plants, either a
mixture of wood and bark waste or wood waste alone is burned most frequently (EPA, 1995).
ESPs are used when control efficiencies of 95 percent or more are required. In the wire-plate ESP,
the gas flows around vertical, metal plates. The electrodes are long, weighted wires hanging
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between the plates. The voltage applied to the electrodes causes the gas between the electrodes to
break down, known as a "corona." The electrodes are most often given a negative polarity because
a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1995: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,"
AP-42, Volume I, Fifth Edition, Research Triangle Park, NC, January 1995.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Industrial Boilers - Wood
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2023	POD: 202
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to operations with wood-fired boilers, classified under the following
SCCs: 10200901, 10200902, 10200903, 10200904, 10200905, 10200906, 10200907.
Affected SCC:
10200901	Industrial, Wood/Bark Waste, Bark-fired Boiler (> 50,000 Lb Steam)
10200902	Industrial, Wood/Bark Waste, Wood/Bark-fired Boiler (> 50,000 Lb Steam)
10200903	Industrial, Wood/Bark Waste, Wood-fired Boiler (> 50,000 Lb Steam)
10200904	Wood/Bark Waste, Bark-fired Boiler (< 50,000 Lb Steam)
10200905	Wood/Bark Waste, Wood/Bark-fired Boiler (< 50,000 Lb Steam)
10200906	Industrial, Wood/Bark Waste, Wood-fired Boiler (< 50,000 Lb Steam)
10200907	Wood/Bark Waste, Wood Cogeneration
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
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were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The burning of wood and bark waste in boilers is mostly confined to industries where wood and bark
waste is available as a byproduct. Wood and bark waste is burned to the burning of wood and bark
waste in boilers is mostly confined to industries where wood and bark waste is available as a
byproduct. Wood and bark waste is burned to obtain heat energy and to alleviate possible solid
waste disposal problems. In boilers, the waste is burned in the form of hogged wood, sawdust,
shavings, chips, sander dust, or wood trim. Bark is the major type of waste burned in "power"
boilers at pulp and paper mills. At lumber, furniture, and plywood plants, either a mixture of wood
and bark waste or wood waste alone is burned most frequently (EPA, 1995).
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The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1995: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,"
AP-42, Volume I, Fifth Edition, Research Triangle Park, NC, January 1995. EPA, 1998b: U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001, Research Triangle
Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
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EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.of Local
Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu of
Options, Washington, DC, July 1996
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Source Category: Industrial Boilers - Wood
Control Measure Name: Venturi Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2024	POD: 202
Application: The control is the use of a venturi scrubber to reduce PM emissions. A scrubber is a
type of technology that removes air pollutants by inertial and diffusional interception. A
venturi scrubber accelerates the waste gas stream to atomize the scrubbing liquid and
to improve gas-liquid contact.
This control applies to operations with wood-fired boilers, including those classified
under the following SCCs: 10200901,10200902, 10200903, 1020904, 1020905,
1020906, and 1020907.
Affected SCC:
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 93% from uncontrolled; PM2.5 control efficiency is
92% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for venturi wet scrubbers, developed using EPA cost-
estimating spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of
the waste stream treated. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
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equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $3 to $28 per scfm
Typical value is $11 per scfm
O&M Costs:
Range from $4 to $119 per scfm
Typical value is $42 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 2,000 and 150,000 acfm. The average percentage of the total O&M cost was
then calculated for each O&M cost component. The model plants were assumed to
have a dust loading of 3.0 grains per cubic feet. The operating time was assumed to
be 8760 hours per year. An inlet water flow rate for the scrubber was assumed to be
9.4 Ibs/min. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	25
Wastewater treatment 3.8
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $76 to $2,100
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $751 per ton
PM10 reduced. (1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The burning of wood and bark waste in boilers is mostly confined to industries where wood and bark
waste is available as a byproduct. Wood and bark waste is burned to obtain heat energy and to
alleviate possible solid waste disposal problems. In boilers, the waste is burned in the form of
hogged wood, sawdust, shavings, chips, sander dust, or wood trim. Bark is the major type of waste
burned in "power" boilers at pulp and paper mills. At lumber, furniture, and plywood plants, either a
mixture of wood and bark waste or wood waste alone is burned most frequently (EPA, 1995).
The costs do not include costs for post-treatment or disposal of used solvent or waste. Actual costs
can be substantially higher than in the ranges shown for applications which require expensive
materials, solvents, or treatment methods (EPA, 1999). As a rule, smaller units controlling a low
concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow.
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By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
A venturi scrubber accelerates the waste gas stream to improve gas-liquid contact. In a venturi
scrubber, a "throat"' section is built into the duct that forces the gas stream to accelerate (EPA,
1999). As the gas enters the venturi throat, both gas velocity and turbulence increase.
After the throat section, the mixture decelerates, and further impacts occur causing the droplets to
agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid
are separated from the gas stream through entrainment. This section usually consists of a cyclonic
separator and/or a mist eliminator (EPA, 1998; Corbitt, 1990).
For PM applications, wet scrubbers generate waste, either a slurry or wet sludge. This creates the
need for both wastewater treatment and solid waste disposal. Initially, the slurry is treated to
separate the solid waste from the water (EPA, 1999). The treated water can then be reused or
discharged. Once the water is removed, the remaining waste will be in the form of a solid or sludge.
If the solid waste is inert and nontoxic, it can generally be land filled. Hazardous wastes will have
more stringent procedures for disposal. In some cases, the solid waste may have value and can be
sold or recycled (EPA, 1998).
References:
Corbitt, 1990: "Standard Handbook of Environmental Engineering," edited by Robert A. Corbitt,
McGraw-Hill, New York, NY, 1990.
EPA, 1995: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,"
AP-42, Volume I, Fifth Edition, Research Triangle Park, NC, January 1995.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Venturi Scrubber," July 1999.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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STAPPA/ALAPCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, "Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options," Washington, DC, July 1996
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Source Category: Industrial Boilers - Wood
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3202	POD: 202
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102009** Industrial, Wood/Bark Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Industrial Boilers - Wood
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4202	POD: 202
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
102009** Industrial, Wood/Bark Waste
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Mineral Products - Cement Manufacture
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2181	POD: 218
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to electricity generation sources powered by pulverized dry-bottom
and bituminous/subbituminous coal.
Affected SCC:
30500606	Mineral Products, Cement Manufacturing (Dry Process), Kilns
30500607	Cement Manufacturing (Dry Process), Raw Material Unloading
30500608	Cement Manufacturing (Dry Process), Raw Material Piles
30500609	Mineral Products, Cement Manufacturing (Dry Process), Primary Crushing
Secondary Crushing
Screening
Raw Mat'l Transfer
Raw Mat'l Grinding & Drying
Clinker Cooler
Clinker Transfer
Clinker Grinding
Cement Silos
Cement Load Out
30500610	Mineral Products, Cement Manufacturing (Dry Process)
30500611	Mineral Products, Cement Manufacturing (Dry Process)
30500612	Mineral Products, Cement Manufacturing (Dry Process)
30500613	Mineral Products, Cement Manufacturing (Dry Process)
30500614	Mineral Products, Cement Manufacturing (Dry Process)
30500615	Cement Manufacturing (Dry Process), Clinker Piles
30500616	Mineral Products, Cement Manufacturing (Dry Process)
30500617	Mineral Products, Cement Manufacturing (Dry Process)
30500618	Mineral Products, Cement Manufacturing (Dry Process)
30500619	Mineral Products, Cement Manufacturing (Dry Process)
30500621	Cement Manufacturing (Dry Process), Pulverized Coal Kiln Feed Units
30500622	Cement Manufacturing (Dry Process), Preheater Kiln
30500623	Cement Manufacturing (Dry Process), Preheater/Precalciner Kiln
30500624	Cement Manufacturing (Dry Process), Raw Mill Feed Belt
30500626 Cement Manufacturing (Dry Process), Raw Mill Air Separator
30500699 Cement Manufacturing (Dry Process), Other Not Classified
30500706	Mineral Products, Cement Manufacturing (Wet Process), Kilns
30500707	Cement Manufacturing (Wet Process), Raw Material Unloading
30500708	Cement Manufacturing (Wet Process), Raw Material Piles
30500709	Cement Manufacturing (Wet Process), Primary Crushing
30500710	Cement Manufacturing (Wet Process), Secondary Crushing
30500712 Cement Manufacturing (Wet Process), Raw Material Transfer
30500714 Mineral Products, Cement Manufacturing (Wet Process), Clinker Cooler
30500716	Cement Manufacturing (Wet Process), Clinker Transfer
30500717	Cement Manufacturing (Wet Process), Clinker Grinding
30500718	Mineral Products, Cement Manufacturing (Wet Process), Cement Silos
30500719	Mineral Products, Cement Manufacturing (Wet Process), Cement Load Out
30500799 Mineral Products, Cement Manufacturing (Wet Process), Other Not Classified
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
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AT-A-GLANCE TABLE FOR POINT SOURCES
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The largest source of particulate emissions at a cement plant is the kiln used to produce clinker.
Cement kilns are rotary kilns, which are slowly rotating refractory-lined steel cylinders inclined
slightly from the horizontal. Raw materials are fed into the top end of the kiln and spend several
hours traversing the kiln. In wet process kilns (SCC 30500706), the raw materials are fed as a wet
slurry. During this time, the raw materials are heated by a flame at the discharge end of the kiln.
This heating dries the raw materials, converts limestone to lime, and promotes reaction between and
fusion of the separate ingredients to form clinker. Clinker exiting the kiln is fed to a clinker cooler
(SCC 30500714) for cooling before storage and further processing (STAPPA/ALAPCO, 1996).
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
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AT-A-GLANCE TABLE FOR POINT SOURCES
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Cement Manufacture
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2182	POD: 218
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to cement manufacturing operations.
Affected SCC:
30500606	Mineral Products, Cement Manufacturing (Dry Process), Kilns
30500607	Cement Manufacturing (Dry Process), Raw Material Unloading
30500608	Cement Manufacturing (Dry Process), Raw Material Piles
30500609	Mineral Products, Cement Manufacturing (Dry Process), Primary Crushing
30500610	Mineral Products, Cement Manufacturing (Dry Process), Secondary Crushing
30500611	Mineral Products, Cement Manufacturing (Dry Process), Screening
30500612	Mineral Products, Cement Manufacturing (Dry Process), Raw Mat'l Transfer
30500613	Mineral Products, Cement Manufacturing (Dry Process), Raw Mat'l Grinding & Drying
30500614	Mineral Products, Cement Manufacturing (Dry Process), Clinker Cooler
30500615	Cement Manufacturing (Dry Process), Clinker Piles
30500616	Mineral Products, Cement Manufacturing (Dry Process), Clinker Transfer
30500617	Mineral Products, Cement Manufacturing (Dry Process), Clinker Grinding
30500618	Mineral Products, Cement Manufacturing (Dry Process), Cement Silos
30500619	Mineral Products, Cement Manufacturing (Dry Process), Cement Load Out
30500621	Cement Manufacturing (Dry Process), Pulverized Coal Kiln Feed Units
30500622	Cement Manufacturing (Dry Process), Preheater Kiln
30500623	Cement Manufacturing (Dry Process), Preheater/Precalciner Kiln
30500624	Cement Manufacturing (Dry Process), Raw Mill Feed Belt
30500626 Cement Manufacturing (Dry Process), Raw Mill Air Separator
30500699 Cement Manufacturing (Dry Process), Other Not Classified
30500706	Mineral Products, Cement Manufacturing (Wet Process), Kilns
30500707	Cement Manufacturing (Wet Process), Raw Material Unloading
30500708	Cement Manufacturing (Wet Process), Raw Material Piles
30500709	Cement Manufacturing (Wet Process), Primary Crushing
30500710	Cement Manufacturing (Wet Process), Secondary Crushing
30500712 Cement Manufacturing (Wet Process), Raw Material Transfer
30500714 Mineral Products, Cement Manufacturing (Wet Process), Clinker Cooler
30500716	Cement Manufacturing (Wet Process), Clinker Transfer
30500717	Cement Manufacturing (Wet Process), Clinker Grinding
30500718	Mineral Products, Cement Manufacturing (Wet Process), Cement Silos
30500719	Mineral Products, Cement Manufacturing (Wet Process), Cement Load Out
30500799 Mineral Products, Cement Manufacturing (Wet Process), Other Not Classified
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
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AT-A-GLANCE TABLE FOR POINT SOURCES
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The largest source of particulate emissions at a cement plant is the kiln used to produce clinker.
Cement kilns are rotary kilns, which are slowly rotating refractory-lined steel cylinders inclined
slightly from the horizontal. Raw materials are fed into the top end of the kiln and spend several
hours traversing the kiln. In wet process kilns (SCC 30500706), the raw materials are fed as a wet
slurry. During this time, the raw materials are heated by a flame at the discharge end of the kiln.
This heating dries the raw materials, converts limestone to lime, and promotes reaction between and
fusion of the separate ingredients to form clinker. Clinker exiting the kiln is fed to a clinker cooler
(SCC 30500714) for cooling before storage and further processing (STAPPA/ALAPCO, 1996).
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
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AT-A-GLANCE TABLE FOR POINT SOURCES
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Cement Manufacture
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2183	POD: 218
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to cement manufacturing operations.
Affected SCC:
30500606	Mineral Products, Cement Manufacturing (Dry Process), Kilns
30500607	Cement Manufacturing (Dry Process), Raw Material Unloading
30500608	Cement Manufacturing (Dry Process), Raw Material Piles
30500609	Mineral Products, Cement Manufacturing (Dry Process), Primary Crushing
30500610	Mineral Products, Cement Manufacturing (Dry Process), Secondary Crushing
30500611	Mineral Products, Cement Manufacturing (Dry Process), Screening
30500612	Mineral Products, Cement Manufacturing (Dry Process), Raw Mat'l Transfer
30500613	Mineral Products, Cement Manufacturing (Dry Process), Raw Mat'l Grinding & Drying
30500614	Mineral Products, Cement Manufacturing (Dry Process), Clinker Cooler
30500615	Cement Manufacturing (Dry Process), Clinker Piles
30500616	Mineral Products, Cement Manufacturing (Dry Process), Clinker Transfer
30500617	Mineral Products, Cement Manufacturing (Dry Process), Clinker Grinding
30500618	Mineral Products, Cement Manufacturing (Dry Process), Cement Silos
30500619	Mineral Products, Cement Manufacturing (Dry Process), Cement Load Out
30500621	Cement Manufacturing (Dry Process), Pulverized Coal Kiln Feed Units
30500622	Cement Manufacturing (Dry Process), Preheater Kiln
30500623	Cement Manufacturing (Dry Process), Preheater/Precalciner Kiln
30500624	Cement Manufacturing (Dry Process), Raw Mill Feed Belt
30500626 Cement Manufacturing (Dry Process), Raw Mill Air Separator
30500699 Cement Manufacturing (Dry Process), Other Not Classified
30500706	Mineral Products, Cement Manufacturing (Wet Process), Kilns
30500707	Cement Manufacturing (Wet Process), Raw Material Unloading
30500708	Cement Manufacturing (Wet Process), Raw Material Piles
30500709	Cement Manufacturing (Wet Process), Primary Crushing
30500710	Cement Manufacturing (Wet Process), Secondary Crushing
30500712 Cement Manufacturing (Wet Process), Raw Material Transfer
30500714 Mineral Products, Cement Manufacturing (Wet Process), Clinker Cooler
30500716	Cement Manufacturing (Wet Process), Clinker Transfer
30500717	Cement Manufacturing (Wet Process), Clinker Grinding
30500718	Mineral Products, Cement Manufacturing (Wet Process), Cement Silos
30500719	Mineral Products, Cement Manufacturing (Wet Process), Cement Load Out
30500799 Mineral Products, Cement Manufacturing (Wet Process), Other Not Classified
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
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8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal 25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The largest source of particulate emissions at a cement plant is the kiln used to produce clinker.
Cement kilns are rotary kilns, which are slowly rotating refractory-lined steel cylinders inclined
slightly from the horizontal. Raw materials are fed into the top end of the kiln and spend several
hours traversing the kiln. In wet process kilns (SCC 30500706), the raw materials are fed as a wet
slurry. During this time, the raw materials are heated by a flame at the discharge end of the kiln.
This heating dries the raw materials, converts limestone to lime, and promotes reaction between and
fusion of the separate ingredients to form clinker. Clinker exiting the kiln is fed to a clinker cooler
(SCC 30500714) for cooling before storage and further processing (STAPPA/ALAPCO, 1996).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
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and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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Source Category: Mineral Products - Cement Manufacture
Control Measure Name: Paper/Nonwoven Filters - Cartridge Collector Type
Rule Name: Not Applicable
Pechan Measure Code: P2184
POD: 218
Application: This control is the use of paper or non-woven filters (cartridge collector type) to reduce
PM emissions. The waste gas stream is passed through the fibrous filter media
causing PM in the gas stream to be collected on the media by sieving and other
mechanisms.
This control measure applies to cement manufacturing operations.
Affected SCC:
30500606
30500607
30500608
30500609
30500610
30500611
30500612
30500613
30500614
30500615
30500616
30500617
30500618
30500619
30500621
30500622
30500623
30500624
30500626
30500699
30500706
30500707
30500708
30500709
30500710
30500712
30500714
30500716
30500717
30500718
30500719
30500799
Secondary Crushing
Screening
Raw Mat'l Transfer
Raw Mat'l Grinding & Drying
Clinker Cooler
Clinker Transfer
Clinker Grinding
Cement Silos
Cement Load Out
Mineral Products, Cement Manufacturing (Dry Process), Kilns
Cement Manufacturing (Dry Process), Raw Material Unloading
Cement Manufacturing (Dry Process), Raw Material Piles
Mineral Products, Cement Manufacturing (Dry Process), Primary Crushing
Mineral Products, Cement Manufacturing (Dry Process)
Mineral Products, Cement Manufacturing (Dry Process)
Mineral Products, Cement Manufacturing (Dry Process)
Mineral Products, Cement Manufacturing (Dry Process)
Mineral Products, Cement Manufacturing (Dry Process)
Cement Manufacturing (Dry Process), Clinker Piles
Mineral Products, Cement Manufacturing (Dry Process)
Mineral Products, Cement Manufacturing (Dry Process)
Mineral Products, Cement Manufacturing (Dry Process)
Mineral Products, Cement Manufacturing (Dry Process)
Cement Manufacturing (Dry Process), Pulverized Coal Kiln Feed Units
Cement Manufacturing (Dry Process), Preheater Kiln
Cement Manufacturing (Dry Process), Preheater/Precalciner Kiln
Cement Manufacturing (Dry Process), Raw Mill Feed Belt
Cement Manufacturing (Dry Process), Raw Mill Air Separator
Cement Manufacturing (Dry Process), Other Not Classified
Mineral Products, Cement Manufacturing (Wet Process), Kilns
Cement Manufacturing (Wet Process), Raw Material Unloading
Cement Manufacturing (Wet Process), Raw Material Piles
Cement Manufacturing (Wet Process), Primary Crushing
Cement Manufacturing (Wet Process), Secondary Crushing
Cement Manufacturing (Wet Process), Raw Material Transfer
Mineral Products, Cement Manufacturing (Wet Process), Clinker Cooler
Cement Manufacturing (Wet Process), Clinker Transfer
Cement Manufacturing (Wet Process), Clinker Grinding
Mineral Products, Cement Manufacturing (Wet Process), Cement Silos
Mineral Products, Cement Manufacturing (Wet Process), Cement Load Out
Mineral Products, Cement Manufacturing (Wet Process), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
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Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are generated using EPA's cost-estimating spreadsheets for fabric filters
(EPA, 1998a). Costs are primarily driven by the waste stream volumetric flow rate
and pollutant loading. When stack gas flow rate data was available, the costs and
cost effectiveness were calculated using the typical values of capital and O&M costs.
When stack gas flow rate data was not available, default typical capital and O&M cost
values based on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $7 to $13 per scfm
Typical value is $9 per scfm
O&M Costs:
Range from $9 to $25 per scfm
Typical value is $14 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average cartridge cost was estimated using the costs for standard
cartridge types. Capital recovery for the periodic replacement of cartridges was
included in the O&M cost of the cartridges using a cartridge life of 2 years (EPA,
1998a). The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
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Compressed air 0.25 $/1000scf
Dust disposal 25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $85 to $256 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $142 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The largest source of particulate emissions at a cement plant is the kiln used to produce clinker.
Cement kilns are rotary kilns, which are slowly rotating refractory-lined steel cylinders inclined
slightly from the horizontal. Raw materials are fed into the top end of the kiln and spend several
hours traversing the kiln. In wet process kilns (SCC 30500706), the raw materials are fed as a wet
slurry. During this time, the raw materials are heated by a flame at the discharge end of the kiln.
This heating dries the raw materials, converts limestone to lime, and promotes reaction between and
fusion of the separate ingredients to form clinker. Clinker exiting the kiln is fed to a clinker cooler
(SCC 30500714) for cooling before storage and further processing (STAPPA/ALAPCO, 1996).
The cost estimates assume a conventional design under typical operating conditions. Auxiliary
equipment, such as fans and ductwork, is not included (EPA, 2000). Pollutants that require an
unusually high level of control or that require the filter media or the unit itself to be constructed of
special materials, such as Nomex ® or stainless steel, will increase the costs of the system (EPA,
1998a). The additional costs for controlling more complex waste streams are not reflected in the
estimates given below. For these types of systems, the capital cost could increase by as much as
75% and the O&M cost could increase by as much as 10%. In general, a small unit controlling a low
pollutant loading will not be as cost effective as a large unit controlling a high pollutant loading (EPA,
2000).
Cartridge filters contain either a paper or nonwoven fibrous filter media (EPA, 2000). Paper media is
generally made of materials such as cellulose and fiberglass. The dust cake that forms on the filter
media from the collected PM can significantly increase collection efficiency (EPA, 1998b).
In general, the filter media is pleated to provide a larger surface area to volume flow rate. Close
pleating, however, can cause PM to bridge the pleat bottom, effectively reducing the surface
collection area (EPA, 1998b). Corrugated aluminum separators are used to prevent the pleats from
collapsing (Heumann, 1997). There are variety of cartridge designs and dimensions. Typical
designs include flat panels, V-shaped packs or cylindrical packs (Heumann, 1997). For certain
applications, two cartridges may be placed in series.
Cartridge collectors are useful for collecting particles with resistivities either too low or too high for
collection with electrostatic precipitators (STAPPA/AI_APCO, 1996). For similar air flow rates,
cartridge collectors are compact in size compared to traditional bag
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
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EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Cartridge Collector with Pulse-Jet Cleaning," April 2000.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/ALAPCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
STAPPA/ALAPCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, "Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options," Washington, DC, July 1996.
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Source Category: Mineral Products - Cement Manufacture
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2185	POD: 218
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to cement manufacturing operations.
Affected SCC:
30500606	Mineral Products, Cement Manufacturing (Dry Process), Kilns
30500607	Cement Manufacturing (Dry Process), Raw Material Unloading
30500608	Cement Manufacturing (Dry Process), Raw Material Piles
30500609	Mineral Products, Cement Manufacturing (Dry Process), Primary Crushing
30500610	Mineral Products, Cement Manufacturing (Dry Process), Secondary Crushing
30500611	Mineral Products, Cement Manufacturing (Dry Process), Screening
30500612	Mineral Products, Cement Manufacturing (Dry Process), Raw Mat'l Transfer
30500613	Mineral Products, Cement Manufacturing (Dry Process), Raw Mat'l Grinding & Drying
30500614	Mineral Products, Cement Manufacturing (Dry Process), Clinker Cooler
30500615	Cement Manufacturing (Dry Process), Clinker Piles
30500616	Mineral Products, Cement Manufacturing (Dry Process), Clinker Transfer
30500617	Mineral Products, Cement Manufacturing (Dry Process), Clinker Grinding
30500618	Mineral Products, Cement Manufacturing (Dry Process), Cement Silos
30500619	Mineral Products, Cement Manufacturing (Dry Process), Cement Load Out
30500621	Cement Manufacturing (Dry Process), Pulverized Coal Kiln Feed Units
30500622	Cement Manufacturing (Dry Process), Preheater Kiln
30500623	Cement Manufacturing (Dry Process), Preheater/Precalciner Kiln
30500624	Cement Manufacturing (Dry Process), Raw Mill Feed Belt
30500626 Cement Manufacturing (Dry Process), Raw Mill Air Separator
30500699 Cement Manufacturing (Dry Process), Other Not Classified
30500706	Mineral Products, Cement Manufacturing (Wet Process), Kilns
30500707	Cement Manufacturing (Wet Process), Raw Material Unloading
30500708	Cement Manufacturing (Wet Process), Raw Material Piles
30500709	Cement Manufacturing (Wet Process), Primary Crushing
30500710	Cement Manufacturing (Wet Process), Secondary Crushing
30500712 Cement Manufacturing (Wet Process), Raw Material Transfer
30500714 Mineral Products, Cement Manufacturing (Wet Process), Clinker Cooler
30500716	Cement Manufacturing (Wet Process), Clinker Transfer
30500717	Cement Manufacturing (Wet Process), Clinker Grinding
30500718	Mineral Products, Cement Manufacturing (Wet Process), Cement Silos
30500719	Mineral Products, Cement Manufacturing (Wet Process), Cement Load Out
30500799 Mineral Products, Cement Manufacturing (Wet Process), Other Not Classified
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
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types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal 25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The largest source of particulate emissions at a cement plant is the kiln used to produce clinker.
Cement kilns are rotary kilns, which are slowly rotating refractory-lined steel cylinders inclined
slightly from the horizontal. Raw materials are fed into the top end of the kiln and spend several
hours traversing the kiln. In wet process kilns (SCC 30500706), the raw materials are fed as a wet
slurry. During this time, the raw materials are heated by a flame at the discharge end of the kiln.
This heating dries the raw materials, converts limestone to lime, and promotes reaction between and
fusion of the separate ingredients to form clinker. Clinker exiting the kiln is fed to a clinker cooler
(SCC 30500714) for cooling before storage and further processing (STAPPA/ALAPCO, 1996).
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
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opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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Source Category: Mineral Products - Cement Manufacture
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3218	POD: 218
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
305006** Mineral Products, Cement Manufacturing (Dry Process)
305007** Mineral Products, Cement Manufacturing (WetProcess)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Mineral Products - Cement Manufacture
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4218	POD: 218
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
305006** Mineral Products, Cement Manufacturing (Dry Process)
305007** Mineral Products, Cement Manufacturing (WetProcess)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Coal Cleaning
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2191
POD: 219
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to coal cleaning PM10 and PM2.5 sources at mining operations.
Coa
Coa
Coa
Coa
Coa
Affected SCC:
30501001
30501002
30501004
30501007
30501008
30501009
30501010
30501011
30501012
30501014
30501015
30501016
30501017
30501021
30501022
30501023
30501024
30501030
30501031
30501032
30501033
30501036
30501037
30501038
30501039
30501040
30501041
30501043
30501044
30501045
30501046
30501047
30501049
30501050
30501051
Mineral Products, Coal Mining, Cleaning, & Mat'l Handling (See 305310), Fluidized Bed
Mineral Products, Coal Mining, Cleaning, and Material Handling (See 305310), Crushing
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
and Material Handling (See 305310), Flash or Suspension
and Material Handling (See 305310), Rotary
and Material Handling (See 305310), Screen
and Material Handling (See 305310), Unloading
and Material Handling (See 305310), Raw Coal Storage
Cleaning, and Material Handling (See 305310), Coal Transfer
Cleaning, and Material Handling (See 305310), Screening
Cleaning, and Material Handling (See 305310), Cleaned Coal Storage
Cleaning, and Material Handling (See 305310), Loading
Cleaning, and Material Handling (See 305310), Loading: Clean Coal
Cleaning, and Material Handling (See 305310), Secondary Crushing
Cleaning, and Material Handling (See 305310), Overburden Removal
Cleaning, and Material Handling (See 305310), Drilling/Blasting
Cleaning, and Material Handling (See 305310), Loading
Cleaning, and Material Handling (See 305310), Hauling
Cleaning, and Material Handling (See 305310), Topsoil Removal
Cleaning, and Material Handling (See 305310), Scrapers: Travel Mode
Cleaning, and Material Handling (See 305310), Topsoil Unloading
Cleaning, and Material Handling (See 305310), Overburden
Cleaning, & Mat'l Handling (See 305310), Dragline-Overburden Removal
Cleaning, and Material Handling (See 305310), Truck Loading: Overburden
Cleaning, and Material Handling (See 305310), Truck Loading: Coal
Cleaning, and Material Handling (See 305310), Hauling: Haul Trucks
Cleaning, & Mat'l Handling (See 305310), Truck Unloading-End Dump-Coal
Cleaning, & Mat'l Handling (See 305310), Truck Unload-Bottom Dump-Coal
Cleaning, and Material Handling (See 305310), Open Storage Pile: Coal
Cleaning, and Material Handling (See 305310),
Cleaning, and Material Handling (See 305310),
Cleaning, and Material Handling (See 305310),
Cleaning, and Material Handling (See 305310),
Cleaning, and Mat'l Handling (See 305310), Wind Erosion-Exposed Areas
Cleaning & Mat'l Handling (See 305310), Vehicles-Light/Med.
Cleaning & Mat'l Handling (See 305310), Surface Mining
Train Loading: Coal
Bulldozing: Overburden
Bulldozing: Coal
Grading
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AT-A-GLANCE TABLE FOR POINT SOURCES
30501090 Coal Mining, Cleaning, and Material Handling (See 305310), Haul Roads: General
30501099 Coal Mining, Cleaning, and Material Handling (See 305310), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
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AT-A-GLANCE TABLE FOR POINT SOURCES
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Coal mining, cleaning and material handling (305010) consists of the preparation and handling of
coal to upgrade its value. For the purpose of this study, thermal dryers, pneumatic coal cleaning
and truck/vehicle travel are the sources considered. Thermal dryers are used at the end of the
series of cleaning operations to remove moisture from coal, thereby reducing freezing problems and
weight, and increasing the heating value. The major portion of water is removed by the use of
screens, thickeners, and cyclones. The coal is then dried in a thermal dryer. Particulate emissions
result from the entrainment of fine coal particles during the thermal drying process (EPA, 1995).
Pneumatic coal-cleaning equipment classifies bituminous coal by size or separates bituminous coal
from refuse by application of air streams. Fugitive PM emissions result when haul trucks or other
vehicles travel on unpaved roads or surfaces.
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1995: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,"
AP-42, Volume I, Fifth Edition, Research Triangle Park, NC, January 1995
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Coal Cleaning
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2192
POD: 219
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to coal cleaning at coal mining operations. Coal mining, cleaning
and material handling (305010) consists of the preparation and handling of coal to
upgrade its value.
Coa
Coa
Coa
Coa
Coa
Affected SCC:
30501001
30501002
30501004
30501007
30501008
30501009
30501010
30501011
30501012
30501014
30501015
30501016
30501017
30501021
30501022
30501023
30501024
30501030
30501031
30501032
30501033
30501036
30501037
30501038
30501039
30501040
30501041
30501043
30501044
30501045
30501046
30501047
Mineral Products, Coal
Mineral Products, Coal
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning
Mining, Cleaning, & Mat'l Handling (See 305310), Fluidized Bed
and Material Handling (See 305310), Flash or Suspension
and Material Handling (See 305310), Rotary
and Material Handling (See 305310), Screen
and Material Handling (See 305310), Unloading
and Material Handling (See 305310), Raw Coal Storage
Mining, Cleaning, and Material Handling (See 305310), Crushing
and Material Handling (See 305310), Coal Transfer
and Material Handling (See 305310), Screening
and Material Handling (See 305310), Cleaned Coal Storage
and Material Handling (See 305310), Loading
and Material Handling (See 305310), Loading: Clean Coal
and Material Handling (See 305310), Secondary Crushing
and Material Handling (See 305310), Overburden Removal
and Material Handling (See 305310), Drilling/Blasting
and Material Handling (See 305310), Loading
and Material Handling (See 305310), Hauling
and Material Handling (See 305310), Topsoil Removal
and Material Handling (See 305310), Scrapers: Travel Mode
and Material Handling (See 305310), Topsoil Unloading
and Material Handling (See 305310), Overburden
& Mat'l Handling (See 305310), Dragline-Overburden Removal
and Material Handling (See 305310), Truck Loading: Overburden
and Material Handling (See 305310), Truck Loading: Coal
and Material Handling (See 305310), Hauling: Haul Trucks
& Mat'l Handling (See 305310), Truck Unloading-End Dump-Coal
& Mat'l Handling (See 305310), Truck Unload-Bottom Dump-Coal
and Material Handling (See 305310), Open Storage Pile: Coal
and Material Handling (See 305310),
and Material Handling (See 305310),
and Material Handling (See 305310),
and Material Handling (See 305310),
Train Loading: Coal
Bulldozing: Overburden
Bulldozing: Coal
Grading
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AT-A-GLANCE TABLE FOR POINT SOURCES
30501049	Coal Mining, Cleaning, and Mat'l Handling (See 305310), Wind Erosion-Exposed Areas
30501050	Coal Mining, Cleaning & Mat'l Handling (See 305310), Vehicles-Light/Med.
30501051	Coal Mining, Cleaning & Mat'l Handling (See 305310), Surface Mining
30501090 Coal Mining, Cleaning, and Material Handling (See 305310), Haul Roads: General
30501099 Coal Mining, Cleaning, and Material Handling (See 305310), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000).. Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
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AT-A-GLANCE TABLE FOR POINT SOURCES
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25	$/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
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AT-A-GLANCE TABLE FOR POINT SOURCES
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Coal Cleaning
Control Measure Name: Paper/Nonwoven Filters - Cartridge Collector Type
Rule Name: Not Applicable
Pechan Measure Code: P2193	POD: 219
Application: This control is the use of paper or non-woven filters (cartridge collector type) to reduce
PM emissions. The waste gas stream is passed through the fibrous filter media
causing PM in the gas stream to be collected on the media by sieving and other
mechanisms.
This control measure applies to coal cleaning processes at coal mining operations.
Coa
Coa
Coa
Coa
Coa
Affected SCC:
30501001
30501002
30501004
30501007
30501008
30501009
30501010
30501011
30501012
30501014
30501015
30501016
30501017
30501021
30501022
30501023
30501024
30501030
30501031
30501032
30501033
30501036
30501037
30501038
30501039
30501040
30501041
30501043
30501044
30501045
30501046
30501047
30501049
30501050
30501051
30501090
30501099
Mineral Products, Coal Mining, Cleaning, & Mat'l Handling (See 305310), Fluidized Bed
Mineral Products, Coal Mining, Cleaning, and Material Handling (See 305310), Crushing
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
and Material Handling (See 305310), Flash or Suspension
and Material Handling (See 305310), Rotary
and Material Handling (See 305310), Screen
and Material Handling (See 305310), Unloading
and Material Handling (See 305310), Raw Coal Storage
Cleaning, and Material Handling (See 305310), Coal Transfer
Cleaning, and Material Handling (See 305310), Screening
Cleaning, and Material Handling (See 305310), Cleaned Coal Storage
Cleaning, and Material Handling (See 305310), Loading
Cleaning, and Material Handling (See 305310), Loading: Clean Coal
Cleaning, and Material Handling (See 305310), Secondary Crushing
Cleaning, and Material Handling (See 305310), Overburden Removal
Cleaning, and Material Handling (See 305310), Drilling/Blasting
Cleaning, and Material Handling (See 305310), Loading
Cleaning, and Material Handling (See 305310), Hauling
Cleaning, and Material Handling (See 305310), Topsoil Removal
Cleaning, and Material Handling (See 305310), Scrapers: Travel Mode
Cleaning, and Material Handling (See 305310), Topsoil Unloading
Cleaning, and Material Handling (See 305310), Overburden
Cleaning, & Mat'l Handling (See 305310), Dragline-Overburden Removal
Cleaning, and Material Handling (See 305310), Truck Loading: Overburden
Cleaning, and Material Handling (See 305310), Truck Loading: Coal
Cleaning, and Material Handling (See 305310), Hauling: Haul Trucks
Cleaning, & Mat'l Handling (See 305310), Truck Unloading-End Dump-Coal
Cleaning, & Mat'l Handling (See 305310), Truck Unload-Bottom Dump-Coal
Cleaning, and Material Handling (See 305310), Open Storage Pile: Coal
Cleaning, and Material Handling (See 305310),
Cleaning, and Material Handling (See 305310),
Cleaning, and Material Handling (See 305310),
Cleaning, and Material Handling (See 305310),
Cleaning, and Mat'l Handling (See 305310), Wind Erosion-Exposed Areas
Cleaning & Mat'l Handling (See 305310), Vehicles-Light/Med.
Cleaning & Mat'l Handling (See 305310), Surface Mining
Cleaning, and Material Handling (See 305310), Haul Roads: General
Cleaning, and Material Handling (See 305310), Other Not Classified
Train Loading: Coal
Bulldozing: Overburden
Bulldozing: Coal
Grading
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are generated using EPA's cost-estimating spreadsheets for fabric filters
(EPA, 1998a). Costs are primarily driven by the waste stream volumetric flow rate
and pollutant loading. When stack gas flow rate data was available, the costs and
cost effectiveness were calculated using the typical values of capital and O&M costs.
When stack gas flow rate data was not available, default typical capital and O&M cost
values based on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $7 to $13 per scfm
Typical value is $9 per scfm
O&M Costs:
Range from $9 to $25 per scfm
Typical value is $14 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average cartridge cost was estimated using the costs for standard
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
cartridge types. Capital recovery for the periodic replacement of cartridges was
included in the O&M cost of the cartridges using a cartridge life of 2 years (EPA,
1998a). The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25	$/1000scf
Dust disposal 25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available, the cost effectiveness varies from $85 to $256
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $142 per ton
PM10 reduced. (1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Coal mining, cleaning and material handling (305010) consists of the preparation and handling of
coal to upgrade its value. For the purpose of this study, thermal dryers, pneumatic coal cleaning
and truck/vehicle travel are the sources considered. Thermal dryers are used at the end of the
series of cleaning operations to remove moisture from coal, thereby reducing freezing problems and
weight, and increasing the heating value. The major portion of water is removed by the use of
screens, thickeners, and cyclones. The coal is then dried in a thermal dryer. Particulate emissions
result from the entrainment of fine coal particles during the thermal drying process (EPA, 1995).
Pneumatic coal-cleaning equipment classifies bituminous coal by size or separates bituminous coal
from refuse by application of air streams. Fugitive PM emissions result when haul trucks or other
vehicles travel on unpaved roads or surfaces.
The cost estimates assume a conventional design under typical operating conditions. Auxiliary
equipment, such as fans and ductwork, is not included (EPA, 2000). Pollutants that require an
unusually high level of control or that require the filter media or the unit itself to be constructed of
special materials, such as Nomex ® or stainless steel, will increase the costs of the system (EPA,
1998a). The additional costs for controlling more complex waste streams are not reflected in the
estimates given below. For these types of systems, the capital cost could increase by as much as
75% and the O&M cost could increase by as much as 10%. In general, a small unit controlling a low
pollutant loading will not be as cost effective as a large unit controlling a high pollutant loading (EPA,
2000).
Cartridge filters contain either a paper or nonwoven fibrous filter media (EPA, 2000). Paper media is
generally made of materials such as cellulose and fiberglass. The dust cake that forms on the filter
media from the collected PM can significantly increase collection efficiency (EPA, 1998b).
In general, the filter media is pleated to provide a larger surface area to volume flow rate. Close
pleating, however, can cause PM to bridge the pleat bottom, effectively reducing the surface
collection area (EPA, 1998b). Corrugated aluminum separators are used to prevent the pleats from
collapsing (Heumann, 1997). There are variety of cartridge designs and dimensions. Typical
designs include flat panels, V-shaped packs or cylindrical packs (Heumann, 1997). For certain
applications, two cartridges may be placed in series.
Cartridge collectors are useful for collecting particles with resistivities either too low or too high for
Document No. 05.09.009/9010.463
III-1009
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AT-A-GLANCE TABLE FOR POINT SOURCES
collection with electrostatic precipitators (STAPPA/ALAPCO, 1996). For similar air flow rates,
cartridge collectors are compact in size compared to traditional bag
References:
EPA, 1995: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,"
AP-42, Volume I, Fifth Edition, Research Triangle Park, NC, January 1995.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Cartridge Collector with Pulse-Jet Cleaning," April 2000.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Coal Cleaning
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2194
POD: 219
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to coal cleaning at coal mining operations. .
Coa
Coa
Coa
Coa
Coa
Affected SCC:
30501001
30501002
30501004
30501007
30501008
30501009
30501010
30501011
30501012
30501014
30501015
30501016
30501017
30501021
30501022
30501023
30501024
30501030
30501031
30501032
30501033
30501036
30501037
30501038
30501039
30501040
30501041
30501043
30501044
30501045
30501046
30501047
30501049
30501050
30501051
Mineral Products, Coal Mining, Cleaning, & Mat'l Handling (See 305310), Fluidized Bed
Mineral Products, Coal Mining, Cleaning, and Material Handling (See 305310), Crushing
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
and Material Handling (See 305310), Flash or Suspension
and Material Handling (See 305310), Rotary
and Material Handling (See 305310), Screen
and Material Handling (See 305310), Unloading
and Material Handling (See 305310), Raw Coal Storage
Cleaning, and Material Handling (See 305310), Coal Transfer
Cleaning, and Material Handling (See 305310), Screening
Cleaning, and Material Handling (See 305310), Cleaned Coal Storage
Cleaning, and Material Handling (See 305310), Loading
Cleaning, and Material Handling (See 305310), Loading: Clean Coal
Cleaning, and Material Handling (See 305310), Secondary Crushing
Cleaning, and Material Handling (See 305310), Overburden Removal
Cleaning, and Material Handling (See 305310), Drilling/Blasting
Cleaning, and Material Handling (See 305310), Loading
Cleaning, and Material Handling (See 305310), Hauling
Cleaning, and Material Handling (See 305310), Topsoil Removal
Cleaning, and Material Handling (See 305310), Scrapers: Travel Mode
Cleaning, and Material Handling (See 305310), Topsoil Unloading
Cleaning, and Material Handling (See 305310), Overburden
Cleaning, & Mat'l Handling (See 305310), Dragline-Overburden Removal
Cleaning, and Material Handling (See 305310), Truck Loading: Overburden
Cleaning, and Material Handling (See 305310), Truck Loading: Coal
Cleaning, and Material Handling (See 305310), Hauling: Haul Trucks
Cleaning, & Mat'l Handling (See 305310), Truck Unloading-End Dump-Coal
Cleaning, & Mat'l Handling (See 305310), Truck Unload-Bottom Dump-Coal
Cleaning, and Material Handling (See 305310), Open Storage Pile: Coal
Cleaning, and Material Handling (See 305310),
Cleaning, and Material Handling (See 305310),
Cleaning, and Material Handling (See 305310),
Cleaning, and Material Handling (See 305310),
Cleaning, and Mat'l Handling (See 305310), Wind Erosion-Exposed Areas
Cleaning & Mat'l Handling (See 305310), Vehicles-Light/Med.
Cleaning & Mat'l Handling (See 305310), Surface Mining
Train Loading: Coal
Bulldozing: Overburden
Bulldozing: Coal
Grading
Document No. 05.09.009/9010.463
III-1011
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
30501090 Coal Mining, Cleaning, and Material Handling (See 305310), Haul Roads: General
30501099 Coal Mining, Cleaning, and Material Handling (See 305310), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
Document No. 05.09.009/9010.463
III-1012
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air	0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Coal mining, cleaning and material handling (305010) consists of the preparation and handling of
coal to upgrade its value. For the purpose of this study, thermal dryers, pneumatic coal cleaning
and truck/vehicle travel are the sources considered. Thermal dryers are used at the end of the
series of cleaning operations to remove moisture from coal, thereby reducing freezing problems and
weight, and increasing the heating value. The major portion of water is removed by the use of
screens, thickeners, and cyclones. The coal is then dried in a thermal dryer. Particulate emissions
result from the entrainment of fine coal particles during the thermal drying process (EPA, 1995).
Pneumatic coal-cleaning equipment classifies bituminous coal by size or separates bituminous coal
from refuse by application of air streams. Fugitive PM emissions result when haul trucks or other
vehicles travel on unpaved roads or surfaces.
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1995: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,"
AP-42, Volume I, Fifth Edition, Research Triangle Park, NC, January 1995.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
Document No. 05.09.009/9010.463
III-1014
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Coal Cleaning
Control Measure Name: Venturi Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2195	POD: 219
Application: The control is the use of a venturi scrubber to reduce PM emissions. A scrubber is a
type of technology that removes air pollutants by inertial and diffusional interception. A
venturi scrubber accelerates the waste gas stream to atomize the scrubbing liquid and
to improve gas-liquid contact.
This control applies to coal cleaning processes at coal mining operations. Coal mining,
cleaning and material handling (305010) consists of the preparation and handling of
coal to upgrade its value. For the purpose of this study, thermal dryers, pneumatic
coal cleaning and truck/vehicle travel are the sources considered.
Coa
Coa
Coa
Coa
Coa
Affected SCC:
30501001
30501002
30501004
30501007
30501008
30501009
30501010
30501011
30501012
30501014
30501015
30501016
30501017
30501021
30501022
30501023
30501024
30501030
30501031
30501032
30501033
30501036
30501037
30501038
30501039
30501040
30501041
30501043
30501044
30501045
30501046
30501047
30501049
30501050
Mineral Products, Coal Mining, Cleaning, & Mat'l Handling (See 305310), Fluidized Bed
Mineral Products, Coal Mining, Cleaning, and Material Handling (See 305310), Crushing
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Coa
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Mining
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
Cleaning
and Material Handling (See 305310), Flash or Suspension
and Material Handling (See 305310), Rotary
and Material Handling (See 305310), Screen
and Material Handling (See 305310), Unloading
and Material Handling (See 305310), Raw Coal Storage
and Material Handling (See 305310), Coal Transfer
and Material Handling (See 305310), Screening
and Material Handling (See 305310), Cleaned Coal Storage
and Material Handling (See 305310), Loading
and Material Handling (See 305310), Loading: Clean Coal
and Material Handling (See 305310), Secondary Crushing
and Material Handling (See 305310), Overburden Removal
and Material Handling (See 305310), Drilling/Blasting
and Material Handling (See 305310), Loading
and Material Handling (See 305310), Hauling
and Material Handling (See 305310), Topsoil Removal
and Material Handling (See 305310), Scrapers: Travel Mode
and Material Handling (See 305310), Topsoil Unloading
and Material Handling (See 305310), Overburden
& Mat'l Handling (See 305310), Dragline-Overburden Removal
and Material Handling (See 305310), Truck Loading: Overburden
and Material Handling (See 305310), Truck Loading: Coal
and Material Handling (See 305310), Hauling: Haul Trucks
& Mat'l Handling (See 305310), Truck Unloading-End Dump-Coal
& Mat'l Handling (See 305310), Truck Unload-Bottom Dump-Coal
and Material Handling (See 305310), Open Storage Pile: Coal
and Material Handling (See 305310),
and Material Handling (See 305310),
and Material Handling (See 305310),
and Material Handling (See 305310),
Train Loading: Coal
Bulldozing: Overburden
Bulldozing: Coal
Grading
and Mat'l Handling (See 305310), Wind Erosion-Exposed Areas
Cleaning & Mat'l Handling (See 305310), Vehicles-Light/Med.
Document No. 05.09.009/9010.463
III-1015
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
30501051 Coal Mining, Cleaning & Mat'l Handling (See 305310), Surface Mining
30501090 Coal Mining, Cleaning, and Material Handling (See 305310), Haul Roads: General
30501099 Coal Mining, Cleaning, and Material Handling (See 305310), Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
98% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for venturi wet scrubbers, developed using EPA cost-
estimating spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of
the waste stream treated. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $3 to $28 per scfm
Typical value is $11 per scfm
O&M Costs:
Range from $4 to $119 per scfm
Typical value is $42 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
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Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 2,000 and 150,000 acfm. The average percentage of the total O&M cost was
then calculated for each O&M cost component. The model plants were assumed to
have a dust loading of 3.0 grains per cubic feet. The operating time was assumed to
be 8760 hours per year. An inlet water flow rate for the scrubber was assumed to be
9.4 Ibs/min. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067	$/kW-hr
Process water price 0.20	$/1000gal
Dust disposal	25	$/ton disposed
Wastewater treatment 3.8	$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $76 to $2,100
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $751 per ton
PM10 reduced. (1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Thermal dryers are used at the end of the series of cleaning operations to remove moisture from
coal, thereby reducing freezing problems and weight, and increasing the heating value. The major
portion of water is removed by the use of screens, thickeners, and cyclones. The coal is then dried
in a thermal dryer. Particulate emissions result from the entrainment of fine coal particles during the
thermal drying process (EPA, 1995). Pneumatic coal-cleaning equipment classifies bituminous coal
by size or separates bituminous coal from refuse by application of air streams. Fugitive PM
emissions result when haul trucks or other vehicles travel on unpaved roads or surfaces.
The costs do not include costs for post-treatment or disposal of used solvent or waste. Actual costs
can be substantially higher than in the ranges shown for applications which require expensive
materials, solvents, or treatment methods (EPA, 1999). As a rule, smaller units controlling a low
concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow.
By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
A venturi scrubber accelerates the waste gas stream to improve gas-liquid contact. In a venturi
scrubber, a "throat"' section is built into the duct that forces the gas stream to accelerate (EPA,
1999). As the gas enters the venturi throat, both gas velocity and turbulence increase.
After the throat section, the mixture decelerates, and further impacts occur causing the droplets to
agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid
are separated from the gas stream through entrainment. This section usually consists of a cyclonic
separator and/or a mist eliminator (EPA, 1998; Corbitt, 1990).
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AT-A-GLANCE TABLE FOR POINT SOURCES
For PM applications, wet scrubbers generate waste, either a slurry or wet sludge. This creates the
need for both wastewater treatment and solid waste disposal. Initially, the slurry is treated to
separate the solid waste from the water (EPA, 1999). The treated water can then be reused or
discharged. Once the water is removed, the remaining waste will be in the form of a solid or sludge.
If the solid waste is inert and nontoxic, it can generally be land filled. Hazardous wastes will have
more stringent procedures for disposal. In some cases, the solid waste may have value and can be
sold or recycled (EPA, 1998).
References:
Corbitt, 1990: "Standard Handbook of Environmental Engineering," edited by Robert A. Corbitt,
McGraw-Hill, New York, NY, 1990.
EPA, 1995: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,"
AP-42, Volume I, Fifth Edition, Research Triangle Park, NC, January 1995.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Venturi Scrubber," July 1999.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Coal Cleaning
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3219	POD: 219
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
305010** Mineral Products, Coal Mining, Cleaning, and Material Handling
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Coal Cleaning
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4219	POD: 219
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
305010** Mineral Products, Coal Mining, Cleaning, and Material Handling
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Other
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2211	POD: 221
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to miscellaneous mineral production operations including (but not
limited to) brick manufacture, calcium carbide operations, clay and fly ash sintering,
concrete batching, gypsum manufacturing, lime production, phosphate rock
operations, sand production, fiberglass manufacturing and glass manufacturing
operations. Materials handling operations including crushing, grinding, and screening,
can produce significant PM emissions.
Affected SCC:
30500301	Mineral Products, Brick Manufacture, Raw Material Drying
30500302	Mineral Products, Brick Manufacture, Raw Material Grinding & Screening
30500303	Brick Manufacture, Storage of Raw Materials
30500305 Brick Manufacture, Raw Material Handling and Transferring
30500308	Brick Manufacture, Screening
30500309	Brick Manufacture, Blending and Mixing
30500310	Brick Manufacture, Curing and Firing: Sawdust Fired Tunnel Kilns
30500311	Mineral Products, Brick Manufacture, Curing and Firing: Gas-fired Tunnel Kilns
30500313 Mineral Products, Brick Manufacture, Curing and Firing: Coal-fired Tunnel Kilns
30500316 Brick Manufacture, Curing and Firing: Coal-fired Periodic Kilns
30500331 Brick Manufacture, Curing and Firing: Dual Fuel Fired Tunnel Kiln
30500398	Mineral Products, Brick Manufacture, Other Not Classified
30500399	Brick Manufacture, Other Not Classified
30500401	Calcium Carbide, Electric Furnace: Hoods and Main Stack
30500402	Mineral Products, Calcium Carbide, Coke Dryer
30500404 Calcium Carbide, Tap Fume Vents
30500406 Mineral Products, Calcium Carbide, Circular Charging: Conveyor
30500499 Mineral Products, Calcium Carbide, Other Not Classified
30500501	Castable Refractory, Fire Clay: Rotary Dryer
30500502	Castable Refractory, Raw Material Crushing/Processing
30500598	Castable Refractory, Other Not Classified
30500599	Castable Refractory, Other Not Classified
30500801	Ceramic Clay/Tile Manufacture, Drying ** (use SCC 3-05-008-13)
30500802	Mineral Products, Ceramic Clay/Tile, Comminution-Crushing, Grinding & Milling
30500803	Ceramic Clay/Tile Manufacture, Raw Material Storage
30500805 Ceramic Clay/Tile Manufacture, Granulation-Mixing of Ceramic Powder & Binder Sol'n
30500899 Mineral Products, Ceramic Clay/Tile Manufacture, Other Not Classified
30500901	Clay and Fly Ash Sintering, Fly Ash Sintering
30500902	Clay and Fly Ash Sintering, Clay/Coke Sintering
30500903	Clay and Fly Ash Sintering, Natural Clay/Shale Sintering
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AT-A-GLANCE TABLE FOR POINT SOURCES
30500904	Clay and Fly Ash Sintering, Raw Clay/Shale Crushing/Screening
30500905	Clay and Fly Ash Sintering, Raw Clay/Shale Transfer/Conveying
30500908	Clay and Fly Ash Sintering, Sintered Clay/Shale Product Crushing/Screening
30500909	Clay and Fly Ash Sintering, Expanded Shale Clinker Cooling
30500910	Clay and Fly Ash Sintering, Expanded Shale Storage
30500915 Clay and Fly Ash Sintering, Rotary Kiln
30500999 Mineral Products, Clay and Fly Ash Sintering, Other Not Classified
30501101 Mineral Products, Concrete Batching, General (Non-fugitive)
30501106	Concrete Batching, Transfer: Sand/Aggregate to Elevated Bins
30501107	Concrete Batching, Cement Unloading: Storage Bins
30501108	Concrete Batching, Weight Hopper Loading of Cement/Sand/Aggregate
30501109	Mineral Products, Concrete Batching, Mixer Loading of Cement/Sand/Aggregate
30501110	Concrete Batching, Loading of Transit Mix Truck
30501111	Concrete Batching, Loading of Dry-batch Truck
30501112	Mineral Products, Concrete Batching, Mixing: Wet
30501113	Concrete Batching, Mixing: Dry
30501114	Concrete Batching, Transferring: Conveyors/Elevators
30501115	Concrete Batching, Storage: Bins/Hoppers
30501199 Mineral Products, Concrete Batching, Other Not Classified
30501201 Fiberglass Manufacturing, Regenerative Furnace (Wool-type Fiber)
30501203	Fiberglass Manufacturing, Electric Furnace (Wool-type Fiber)
30501204	Fiberglass Manufacturing, Forming: Rotary Spun (Wool-type Fiber)
30501205	Fiberglass Manufacturing, Curing Oven: Rotary Spun (Wool-type Fiber)
30501206	Fiberglass Manufacturing, Cooling (Wool-type Fiber)
30501207	Fiberglass Manufacturing, Unit Melter Furnace (Wool-type Fiber)
30501208	Fiberglass Manufacturing, Forming: Flame Attenuation (Wool-type Fiber)
30501209	Fiberglass Manufacturing, Curing: Flame Attenuation (Wool-type Fiber)
30501211	Fiberglass Manufacturing, Regenerative Furnace (Textile-type Fiber)
30501212	Fiberglass Manufacturing, Recuperative Furnace (Textile-type Fiber)
30501213	Fiberglass Manufacturing, Unit Melter Furnace (Textile-type Fiber)
30501214	Fiberglass Manufacturing, Forming Process (Textile-type Fiber)
30501215	Fiberglass Manufacturing, Curing Oven (Textile-type Fiber)
30501221 Fiberglass Manufacturing, Raw Material: Unloading/Conveying
30501223 Fiberglass Manufacturing, Raw Material: Mixing/Weighing
30501299 Mineral Products, Fiberglass Manufacturing, Other Not Classified
30501401	Glass Manufacture, Furnace/General**
30501402	Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
30501403	Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
30501404	Glass Manufacture, Pressed and Blown Glass: Melting Furnace
30501406	Mineral Products, Glass Manufacture, Container Glass: Forming/Finishing
30501407	Glass Manufacture, Flat Glass: Forming/Finishing
30501408	Glass Manufacture, Pressed and Blown Glass: Forming/Finishing
30501410	Glass Manufacture, Raw Material Handling (All Types of Glass)
30501411	Glass Manufacture, General **
30501413 Mineral Products, Glass Manufacture, Cullet: Crushing/Grinding
30501415	Mineral Products, Glass Manufacture, Glass Etching with Hydrofluoric Acid Solution
30501416	Glass Manufacture, Glass Manufacturing
30501499 Glass Manufacture, See Comment **
30501501	Mineral Products, Gypsum Manufacture, Rotary Ore Dryer
30501502	Mineral Products, Gypsum Manufacture, Primary Grinder/Roller Mills
30501503	Gypsum Manufacture, Not Classified **
30501504	Mineral Products, Gypsum Manufacture, Conveying
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AT-A-GLANCE TABLE FOR POINT SOURCES
30501505	Gypsum Manufacture, Primary Crushing: Gypsum Ore
30501506	Gypsum Manufacture, Secondary Crushing: Gypsum Ore
30501507	Gypsum Manufacture, Screening: Gypsum Ore
30501508	Mineral Products, Gypsum Manufacture, Stockpile: Gypsum Ore
30501509	Mineral Products, Gypsum Manufacture, Storage Bins: Gypsum Ore
30501511	Gypsum Manufacture, Continuous Kettle: Calciner
30501512	Gypsum Manufacture, Flash Calciner
30501513	Gypsum Manufacture, Impact Mill
30501514	Gypsum Manufacture, Storage Bins: Stucco
30501515	Gypsum Manufacture, Tube/Ball Mills
30501516	Gypsum Manufacture, Mixers
30501518	Mineral Products, Gypsum Manufacture, Mixers/Conveyors
30501519	Gypsum Manufacture, Forming Line
30501520	Mineral Products, Gypsum Manufacture, Drying Kiln
30501521	Mineral Products, Gypsum Manufacture, End Sawing (8 Ft.)
30501522	Mineral Products, Gypsum Manufacture, End Sawing (12 Ft.)
30501601	Lime Manufacture, Primary Crushing
30501602	Lime Manufacture, Secondary Crushing/Screening
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime, Calcining-Rotary Kiln (See SCCs 305016-18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30501607	Lime Manufacture
30501608	Lime Manufacture
30501609	Lime Manufacture
30501610	Lime Manufacture
30501611	Lime Manufacture
30501612	Lime Manufacture
30501613	Mineral Products,
30501614	Lime Manufacture
30501615	Lime Manufacture
30501616	Lime Manufacture
30501617	Lime Manufacture
30501619	Lime Manufacture
30501620	Lime Manufacture
30501626 Lime Manufacture
30501640 Lime Manufacture
30501699 Lime Manufacture
30501701 Mineral Wool, Cupola
30501703	Mineral Wool, Blow Chamber
30501704	Mineral Wool, Curing Oven
30501705	Mineral Wool, Cooler
30501799 Mineral Wool, Other Not Classified
30501801 Perlite Manufacturing, Vertical Furnace
30501899 Perlite Manufacturing, Other Not Classified
30501901	Phosphate Rock, Drying
30501902	Phosphate Rock, Grinding
30501903	Phosphate Rock, Transfer/Storage
30501905	Mineral Products, Phosphate Rock, Calcining
30501906	Phosphate Rock, Rotary Dryer
30501907	Phosphate Rock, Ball Mill
30501999 Phosphate Rock, Other Not Classified
Raw Material Transfer and Conveying
Raw Material Unloading
Hydrator: Atmospheric
Raw Material Storage Piles
Product Cooler
Pressure Hydrator
Lime Manufacture, Lime Silos
Packing/Shipping
Product Transfer and Conveying
Primary Screening
Multiple Hearth Calciner
Calcining: Gas-fired Rotary Kiln
Calcining: Coal- and Gas-fired Rotary Kiln
Product Loading, Enclosed Truck
Vehicle Traffic
See Comment **
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AT-A-GLANCE TABLE FOR POINT SOURCES
30502101 Salt Mining, General
30502201 Potash Production, Mine: Grinding/Drying
30502299 Potash Production, Other Not Classified
30502401 Magnesium Carbonate, Mine/Process
30502501	Construction Sand and Gravel, Total Plant: General **
30502502	Construction Sand and Gravel, Aggregate Storage
30502503	Construction Sand and Gravel, Material Transfer and Conveying
30502504	Construction Sand and Gravel, Hauling
30502505	Construction Sand and Gravel, Pile Forming: Stacker
30502506	Construction Sand and Gravel, Bulk Loading
30502507	Construction Sand and Gravel, Storage Piles
30502508	Construction Sand & Gravel, Dryer (See 305027-20 thru -24 for Industrial Sand Dryers)
30502509	Construction Sand and Gravel, Cooler ** (See 3-05-027-30 for Industrial Sand Coolers)
30502510	Mineral Products, Construction Sand and Gravel, Crushing
30502511	Construction Sand and Gravel, Screening
30502599 Construction Sand and Gravel, Not Classified **
30502601 Diatomaceous Earth, Handling
30502699 Diatomaceous Earth, Other Not Classified
30502701 Industrial Sand and Gravel, Primary Crushing of Raw Material
30502705 Industrial Sand and Gravel, Secondary Crushing
30502709 Industrial Sand and Gravel, Grinding: Size Reduction to 50 Microns or Smaller
30502713 Industrial Sand and Gravel, Screening: Size Classification
30502760 Industrial Sand and Gravel, Sand Handling, Transfer, and Storage
30503099 Ceramic Electric Parts, Other Not Classified
30503301 Vermiculite, General
30504001	Mining and Quarrying of Nonmetallic Minerals, Open Pit Blasting
30504002	Mining and Quarrying of Nonmetallic Minerals, Open Pit Drilling
30504003	Mining and Quarrying of Nonmetallic Minerals, Open Pit Cobbing
30504010 Mining and Quarrying of Nonmetallic Minerals, Underground Ventilation
30504020	Mining and Quarrying of Nonmetallic Minerals, Loading
30504021	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Material
30504022	Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Waste
30504023	Mining and Quarrying of Nonmetallic Minerals, Unloading
30504024	Mining and Quarrying of Nonmetallic Minerals, Overburden Stripping
30504025	Mining and Quarrying of Nonmetallic Minerals, Stockpiling
30504030	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Primary Crusher
30504031	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Secondary Crusher
30504033	Mining and Quarrying of Nonmetallic Minerals, Ore Dryer
30504034	Mining and Quarrying of Nonmetallic Minerals, Screening
30504036 Mining and Quarrying of Nonmetallic Minerals, Tailing Piles
30504099 Mining and Quarrying of Nonmetallic Minerals, Other Not Classified
30504140 Clay processing: Kaolin, Calcining, rotary calciner
30510001	Bulk Materials Elevators, Unloading
30510002	Bulk Materials Elevators, Loading
30510101 Bulk Materials Conveyors, Ammonium Sulfate
30510103	Bulk Materials Conveyors, Coal
30510104	Bulk Materials Conveyors, Coke
30510105	Bulk Materials Conveyors, Limestone
30510197	Bulk Materials Conveyors, Fertilizer: Specify in Comments
30510198	Bulk Materials Conveyors, Mineral: Specify in Comments
30510199	Bulk Materials Conveyors, Other Not Classified
30510202 Mineral Products, Bulk Materials Storage Bins, Cement
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AT-A-GLANCE TABLE FOR POINT SOURCES
30510203	Bulk Materials Storage Bins, Coal
30510204	Bulk Materials Storage Bins, Coke
30510205	Bulk Materials Storage Bins, Limestone
30510298	Mineral Products, Bulk Materials Storage Bins, Mineral: Specify in Comments
30510299	Bulk Materials Storage Bins, Other Not Classified
30510303	Bulk Materials Open Stockpiles, Coal
30510304	Bulk Materials Open Stockpiles, Coke
30510397	Bulk Materials Open Stockpiles, Fertilizer: Specify in Comments
30510398	Bulk Materials Open Stockpiles, Mineral: Specify in Comments
30510399	Bulk Materials Open Stockpiles, Other Not Classified
30510402	Bulk Materials Unloading Operation, Cement
30510403	Mineral Products, Bulk Materials Unloading Operation, Coal
30510404	Bulk Materials Unloading Operation, Coke
30510405	Bulk Materials Unloading Operation, Limestone
30510406	Bulk Materials Unloading Operation, Phosphate Rock
30510407	Bulk Materials Unloading Operation, Scrap Metal
30510497	Bulk Materials Unloading Operation, Fertilizer: Specify in Comments
30510498	Bulk Materials Unloading Operation, Mineral: Specify in Comments
30510499	Bulk Materials Unloading Operation, Other Not Classified
30510503 Bulk Materials Loading Operation, Coal
30510505 Bulk Materials Loading Operation, Limestone
30510507 Bulk Materials Loading Operation, Scrap Metal
30510596	Bulk Materials Loading Operation, Chemical: Specify in Comments
30510597	Bulk Materials Loading Operation, Fertilizer: Specify in Comments
30510598	Bulk Materials Loading Operation, Mineral: Specify in Comments
30510599	Bulk Materials Loading Operation, Other Not Classified
30515001	Calcining, Raw Material Handling
30515002	Calcining, General
30515004 Calcining, Finished Product Handling
30531008	Coal Mining, Cleaning, and Material Handl
30531009	Coal Mining, Cleaning, and Material Handl
30531010	Coal Mining, Cleaning, and Material Handl
30531011	Coal Mining, Cleaning, and Material Handl
30531012	Coal Mining, Cleaning, and Material Handl
30531014 Coal Mining, Cleaning, and Material Handl
30531090 Coal Mining, Cleaning, and Material Handl
30531099 Coal Mining, Cleaning, and Material Handl
30532006 Stone Quarrying-Processing (See 305020), Misc. Operations
30532008 Stone Quarrying - Processing (See also 305020 for diff. units), Cut Stone: General
30588801	Fugitive Emissions, Specify in Comments Field
30588802	Fugitive Emissions, Specify in Comments Field
30588803	Fugitive Emissions, Specify in Comments Field
30588804	Fugitive Emissions, Specify in Comments Field
30588805	Fugitive Emissions, Specify in Comments Field
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590023 Fuel Fired Equipment, Natural Gas: Flares
30599999 Mineral Products, Other Not Defined, Specify in Comments Field
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
Unloading
Raw Coal Storage
Crushing
Coal Transfer
Screening
Cleaned Coal Storage
Haul Roads: General
Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Drying, the heating of minerals or mineral products to remove water, and calcination, heating to
higher temperatures to remove chemically bound water and other compounds, are normally
performed in dedicated, closed units. Emissions from these units will be through process vents, to
which PM controls can be applied relatively simply. Fugitive dust emissions may come from paved
and unpaved roads in plants and from raw material and product loading, unloading, and storage
(STAPPA/ALAPCO, 1996).
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
Document No. 05.09.009/9010.463
III-1030
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Other
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2212	POD: 221
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to miscellaneous mineral production operations including (but not
limited to) brick manufacture, calcium carbide operations, clay and fly ash sintering,
concrete batching, gypsum manufacturing, lime production, phosphate rock
operations, sand production, fiberglass manufacturing and glass manufacturing
operations.
Affected SCC:
30500301	Mineral Products, Brick Manufacture, Raw Material Drying
30500302	Mineral Products, Brick Manufacture, Raw Material Grinding & Screening
30500303	Brick Manufacture, Storage of Raw Materials
30500305 Brick Manufacture, Raw Material Handling and Transferring
30500308	Brick Manufacture, Screening
30500309	Brick Manufacture, Blending and Mixing
30500310	Brick Manufacture, Curing and Firing: Sawdust Fired Tunnel Kilns
30500311	Mineral Products, Brick Manufacture, Curing and Firing: Gas-fired Tunnel Kilns
30500313 Mineral Products, Brick Manufacture, Curing and Firing: Coal-fired Tunnel Kilns
30500316 Brick Manufacture, Curing and Firing: Coal-fired Periodic Kilns
30500331 Brick Manufacture, Curing and Firing: Dual Fuel Fired Tunnel Kiln
30500398	Mineral Products, Brick Manufacture, Other Not Classified
30500399	Brick Manufacture, Other Not Classified
30500401	Calcium Carbide, Electric Furnace: Hoods and Main Stack
30500402	Mineral Products, Calcium Carbide, Coke Dryer
30500404 Calcium Carbide, Tap Fume Vents
30500406 Mineral Products, Calcium Carbide, Circular Charging: Conveyor
30500499 Mineral Products, Calcium Carbide, Other Not Classified
30500501	Castable Refractory, Fire Clay: Rotary Dryer
30500502	Castable Refractory, Raw Material Crushing/Processing
30500598	Castable Refractory, Other Not Classified
30500599	Castable Refractory, Other Not Classified
30500801	Ceramic Clay/Tile Manufacture, Drying ** (use SCC 3-05-008-13)
30500802	Mineral Products, Ceramic Clay/Tile, Comminution-Crushing, Grinding & Milling
30500803	Ceramic Clay/Tile Manufacture, Raw Material Storage
30500805 Ceramic Clay/Tile Manufacture, Granulation-Mixing of Ceramic Powder & Binder Sol'n
30500899 Mineral Products, Ceramic Clay/Tile Manufacture, Other Not Classified
30500901	Clay and Fly Ash Sintering, Fly Ash Sintering
30500902	Clay and Fly Ash Sintering, Clay/Coke Sintering
30500903	Clay and Fly Ash Sintering, Natural Clay/Shale Sintering
Document No. 05.09.009/9010.463	III-1031	Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
30500904	Clay and Fly Ash Sintering, Raw Clay/Shale Crushing/Screening
30500905	Clay and Fly Ash Sintering, Raw Clay/Shale Transfer/Conveying
30500908	Clay and Fly Ash Sintering, Sintered Clay/Shale Product Crushing/Screening
30500909	Clay and Fly Ash Sintering, Expanded Shale Clinker Cooling
30500910	Clay and Fly Ash Sintering, Expanded Shale Storage
30500915 Clay and Fly Ash Sintering, Rotary Kiln
30500999 Mineral Products, Clay and Fly Ash Sintering, Other Not Classified
30501101 Mineral Products, Concrete Batching, General (Non-fugitive)
30501106	Concrete Batching, Transfer: Sand/Aggregate to Elevated Bins
30501107	Concrete Batching, Cement Unloading: Storage Bins
30501108	Concrete Batching, Weight Hopper Loading of Cement/Sand/Aggregate
30501109	Mineral Products, Concrete Batching, Mixer Loading of Cement/Sand/Aggregate
30501110	Concrete Batching, Loading of Transit Mix Truck
30501111	Concrete Batching, Loading of Dry-batch Truck
30501112	Mineral Products, Concrete Batching, Mixing: Wet
30501113	Concrete Batching, Mixing: Dry
30501114	Concrete Batching, Transferring: Conveyors/Elevators
30501115	Concrete Batching, Storage: Bins/Hoppers
30501199 Mineral Products, Concrete Batching, Other Not Classified
30501201 Fiberglass Manufacturing, Regenerative Furnace (Wool-type Fiber)
30501203	Fiberglass Manufacturing, Electric Furnace (Wool-type Fiber)
30501204	Fiberglass Manufacturing, Forming: Rotary Spun (Wool-type Fiber)
30501205	Fiberglass Manufacturing, Curing Oven: Rotary Spun (Wool-type Fiber)
30501206	Fiberglass Manufacturing, Cooling (Wool-type Fiber)
30501207	Fiberglass Manufacturing, Unit Melter Furnace (Wool-type Fiber)
30501208	Fiberglass Manufacturing, Forming: Flame Attenuation (Wool-type Fiber)
30501209	Fiberglass Manufacturing, Curing: Flame Attenuation (Wool-type Fiber)
30501211	Fiberglass Manufacturing, Regenerative Furnace (Textile-type Fiber)
30501212	Fiberglass Manufacturing, Recuperative Furnace (Textile-type Fiber)
30501213	Fiberglass Manufacturing, Unit Melter Furnace (Textile-type Fiber)
30501214	Fiberglass Manufacturing, Forming Process (Textile-type Fiber)
30501215	Fiberglass Manufacturing, Curing Oven (Textile-type Fiber)
30501221 Fiberglass Manufacturing, Raw Material: Unloading/Conveying
30501223 Fiberglass Manufacturing, Raw Material: Mixing/Weighing
30501299 Mineral Products, Fiberglass Manufacturing, Other Not Classified
30501401	Glass Manufacture, Furnace/General**
30501402	Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
30501403	Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
30501404	Glass Manufacture, Pressed and Blown Glass: Melting Furnace
30501406	Mineral Products, Glass Manufacture, Container Glass: Forming/Finishing
30501407	Glass Manufacture, Flat Glass: Forming/Finishing
30501408	Glass Manufacture, Pressed and Blown Glass: Forming/Finishing
30501410	Glass Manufacture, Raw Material Handling (All Types of Glass)
30501411	Glass Manufacture, General **
30501413 Mineral Products, Glass Manufacture, Cullet: Crushing/Grinding
30501415	Mineral Products, Glass Manufacture, Glass Etching with Hydrofluoric Acid Solution
30501416	Glass Manufacture, Glass Manufacturing
30501499 Glass Manufacture, See Comment **
30501501	Mineral Products, Gypsum Manufacture, Rotary Ore Dryer
30501502	Mineral Products, Gypsum Manufacture, Primary Grinder/Roller Mills
30501503	Gypsum Manufacture, Not Classified **
30501504	Mineral Products, Gypsum Manufacture, Conveying
Document No. 05.09.009/9010.463
III-1032
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
30501505	Gypsum Manufacture, Primary Crushing: Gypsum Ore
30501506	Gypsum Manufacture, Secondary Crushing: Gypsum Ore
30501507	Gypsum Manufacture, Screening: Gypsum Ore
30501508	Mineral Products, Gypsum Manufacture, Stockpile: Gypsum Ore
30501509	Mineral Products, Gypsum Manufacture, Storage Bins: Gypsum Ore
30501511	Gypsum Manufacture, Continuous Kettle: Calciner
30501512	Gypsum Manufacture, Flash Calciner
30501513	Gypsum Manufacture, Impact Mill
30501514	Gypsum Manufacture, Storage Bins: Stucco
30501515	Gypsum Manufacture, Tube/Ball Mills
30501516	Gypsum Manufacture, Mixers
30501518	Mineral Products, Gypsum Manufacture, Mixers/Conveyors
30501519	Gypsum Manufacture, Forming Line
30501520	Mineral Products, Gypsum Manufacture, Drying Kiln
30501521	Mineral Products, Gypsum Manufacture, End Sawing (8 Ft.)
30501522	Mineral Products, Gypsum Manufacture, End Sawing (12 Ft.)
30501601	Lime Manufacture, Primary Crushing
30501602	Lime Manufacture, Secondary Crushing/Screening
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime Manufacture, Calcining: Rotary Kiln ** (See SCC Codes 3-05-016-
18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30501607	Lime Manufacture, Raw Material Transfer and Conveying
30501608	Lime Manufacture, Raw Material Unloading
30501609	Lime Manufacture, Hydrator: Atmospheric
30501610	Lime Manufacture, Raw Material Storage Piles
30501611	Lime Manufacture, Product Cooler
30501612	Lime Manufacture, Pressure Hydrator
30501613	Mineral Products, Lime Manufacture, Lime Silos
30501614	Lime Manufacture, Packing/Shipping
30501615	Lime Manufacture, Product Transfer and Conveying
30501616	Lime Manufacture, Primary Screening
30501617	Lime Manufacture, Multiple Hearth Calciner
30501619	Lime Manufacture, Calcining: Gas-fired Rotary Kiln
30501620	Lime Manufacture, Calcining: Coal- and Gas-fired Rotary Kiln
30501626 Lime Manufacture, Product Loading, Enclosed Truck
30501640 Lime Manufacture, Vehicle Traffic
30501699 Lime Manufacture, See Comment **
30501701 Mineral Wool, Cupola
30501703	Mineral Wool, Blow Chamber
30501704	Mineral Wool, Curing Oven
30501705	Mineral Wool, Cooler
30501799 Mineral Wool, Other Not Classified
30501801 Perlite Manufacturing, Vertical Furnace
30501899 Perlite Manufacturing, Other Not Classified
30501901	Phosphate Rock, Drying
30501902	Phosphate Rock, Grinding
30501903	Phosphate Rock, Transfer/Storage
30501905	Mineral Products, Phosphate Rock, Calcining
30501906	Phosphate Rock, Rotary Dryer
30501907	Phosphate Rock, Ball
Document No. 05.09.009/9010.463
III-103 3
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
30501999 Phosphate Rock, Other Not Classified
30502101 Salt Mining, General
30502201 Potash Production, Mine: Grinding/Drying
30502299 Potash Production, Other Not Classified
30502401 Magnesium Carbonate, Mine/Process
30502501	Construction Sand and Gravel, Total Plant: General **
30502502	Construction Sand and Gravel, Aggregate Storage
30502503	Construction Sand and Gravel, Material Transfer and Conveying
30502504	Construction Sand and Gravel, Hauling
30502505	Construction Sand and Gravel, Pile Forming: Stacker
30502506	Construction Sand and Gravel, Bulk Loading
30502507	Construction Sand and Gravel, Storage Piles
30502508	Construction Sand & Gravel, Dryer (See 305027-20 thru -24 for Industrial Sand Dryers)
30502509	Construction Sand and Gravel, Cooler ** (See 3-05-027-30 for Industrial Sand Coolers)
30502510	Mineral Products, Construction Sand and Gravel, Crushing
30502511	Construction Sand and Gravel, Screening
30502599 Construction Sand and Gravel, Not Classified **
30502601 Diatomaceous Earth, Handling
30502699 Diatomaceous Earth, Other Not Classified
30502701 Industrial Sand and Gravel, Primary Crushing of Raw Material
30502705 Industrial Sand and Gravel, Secondary Crushing
30502709 Industrial Sand and Gravel, Grinding: Size Reduction to 50 Microns or Smaller
30502713 Industrial Sand and Gravel, Screening: Size Classification
30502760 Industrial Sand and Gravel, Sand Handling, Transfer, and Storage
30503099 Ceramic Electric Parts, Other Not Classified
30503301 Vermiculite, General
30504001	Mining and Quarrying of Nonmetallic Minerals, Open Pit Blasting
30504002	Mining and Quarrying of Nonmetallic Minerals, Open Pit Drilling
30504003	Mining and Quarrying of Nonmetallic Minerals, Open Pit Cobbing
30504010 Mining and Quarrying of Nonmetallic Minerals, Underground Ventilation
30504020	Mining and Quarrying of Nonmetallic Minerals, Loading
30504021	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Material
30504022	Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Waste
30504023	Mining and Quarrying of Nonmetallic Minerals, Unloading
30504024	Mining and Quarrying of Nonmetallic Minerals, Overburden Stripping
30504025	Mining and Quarrying of Nonmetallic Minerals, Stockpiling
30504030	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Primary Crusher
30504031	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Secondary Crusher
30504033	Mining and Quarrying of Nonmetallic Minerals, Ore Dryer
30504034	Mining and Quarrying of Nonmetallic Minerals, Screening
30504036 Mining and Quarrying of Nonmetallic Minerals, Tailing Piles
30504099 Mining and Quarrying of Nonmetallic Minerals, Other Not Classified
30504140 Clay processing: Kaolin, Calcining, rotary calciner
30510001	Bulk Materials Elevators, Unloading
30510002	Bulk Materials Elevators, Loading
30510101 Bulk Materials Conveyors, Ammonium Sulfate
30510103	Bulk Materials Conveyors, Coal
30510104	Bulk Materials Conveyors, Coke
30510105	Bulk Materials Conveyors, Limestone
30510197	Bulk Materials Conveyors, Fertilizer: Specify in Comments
30510198	Bulk Materials Conveyors, Mineral: Specify in Comments
30510199	Bulk Materials Conveyors, Other Not Classified
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
30510202	Mineral Products, Bulk Materials Storage Bins, Cement
30510203	Bulk Materials Storage Bins, Coal
30510204	Bulk Materials Storage Bins, Coke
30510205	Bulk Materials Storage Bins, Limestone
30510298	Mineral Products, Bulk Materials Storage Bins, Mineral: Specify in Comments
30510299	Bulk Materials Storage Bins, Other Not Classified
30510303	Bulk Materials Open Stockpiles, Coal
30510304	Bulk Materials Open Stockpiles, Coke
30510397	Bulk Materials Open Stockpiles, Fertilizer: Specify in Comments
30510398	Bulk Materials Open Stockpiles, Mineral: Specify in Comments
30510399	Bulk Materials Open Stockpiles, Other Not Classified
30510402	Bulk Materials Unloading Operation, Cement
30510403	Mineral Products, Bulk Materials Unloading Operation, Coal
30510404	Bulk Materials Unloading Operation, Coke
30510405	Bulk Materials Unloading Operation, Limestone
30510406	Bulk Materials Unloading Operation, Phosphate Rock
30510407	Bulk Materials Unloading Operation, Scrap Metal
30510497	Bulk Materials Unloading Operation, Fertilizer: Specify in Comments
30510498	Bulk Materials Unloading Operation, Mineral: Specify in Comments
30510499	Bulk Materials Unloading Operation, Other Not Classified
30510503 Bulk Materials Loading Operation, Coal
30510505 Bulk Materials Loading Operation, Limestone
30510507 Bulk Materials Loading Operation, Scrap Metal
30510596	Bulk Materials Loading Operation, Chemical: Specify in Comments
30510597	Bulk Materials Loading Operation, Fertilizer: Specify in Comments
30510598	Bulk Materials Loading Operation, Mineral: Specify in Comments
30510599	Bulk Materials Loading Operation, Other Not Classified
30515001	Calcining, Raw Material Handling
30515002	Calcining, General
30515004 Calcining, Finished Product Handling
30531008	Coal Mining, Cleaning, and Material Handl
30531009	Coal Mining, Cleaning, and Material Handl
30531010	Coal Mining, Cleaning, and Material Handl
30531011	Coal Mining, Cleaning, and Material Handl
30531012	Coal Mining, Cleaning, and Material Handl
30531014 Coal Mining, Cleaning, and Material Handl
30531090 Coal Mining, Cleaning, and Material Handl
30531099 Coal Mining, Cleaning, and Material Handl
30532006 Stone Quarrying-Processing (See 305020), Misc. Operations
30532008 Stone Quarrying - Processing (See also 305020 for diff. units), Cut Stone: General
30588801	Fugitive Emissions, Specify in Comments Field
30588802	Fugitive Emissions, Specify in Comments Field
30588803	Fugitive Emissions, Specify in Comments Field
30588804	Fugitive Emissions, Specify in Comments Field
30588805	Fugitive Emissions, Specify in Comments Field
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590023 Fuel Fired Equipment, Natural Gas: Flares
30599999 Mineral Products, Other Not Defined, Specify in Comments Field
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
Unloading
Raw Coal Storage
Crushing
Coal Transfer
Screening
Cleaned Coal Storage
Haul Roads: General
Other Not Classified
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
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types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air	0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Materials handling operations including crushing, grinding, and screening, can produce significant
PM emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply. Fugitive dust emissions may come
from paved and unpaved roads in plants and from raw material and product loading, unloading, and
storage (STAPPA/ALAPCO, 1996).
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
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AT-A-GLANCE TABLE FOR POINT SOURCES
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Other
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2213	POD: 221
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to mineral production operations not classified as cement
operations, coat cleaning, or stone quarrying.
Affected SCC:
30500301	Mineral Products, Brick Manufacture, Raw Material Drying
30500302	Mineral Products, Brick Manufacture, Raw Material Grinding & Screening
30500303	Brick Manufacture, Storage of Raw Materials
30500305 Brick Manufacture, Raw Material Handling and Transferring
30500308	Brick Manufacture, Screening
30500309	Brick Manufacture, Blending and Mixing
30500310	Brick Manufacture, Curing and Firing: Sawdust Fired Tunnel Kilns
30500311	Mineral Products, Brick Manufacture, Curing and Firing: Gas-fired Tunnel Kilns
30500313 Mineral Products, Brick Manufacture, Curing and Firing: Coal-fired Tunnel Kilns
30500316 Brick Manufacture, Curing and Firing: Coal-fired Periodic Kilns
30500331 Brick Manufacture, Curing and Firing: Dual Fuel Fired Tunnel Kiln
30500398	Mineral Products, Brick Manufacture, Other Not Classified
30500399	Brick Manufacture, Other Not Classified
30500401	Calcium Carbide, Electric Furnace: Hoods and Main Stack
30500402	Mineral Products, Calcium Carbide, Coke Dryer
30500404 Calcium Carbide, Tap Fume Vents
30500406 Mineral Products, Calcium Carbide, Circular Charging: Conveyor
30500499 Mineral Products, Calcium Carbide, Other Not Classified
30500501	Castable Refractory, Fire Clay: Rotary Dryer
30500502	Castable Refractory, Raw Material Crushing/Processing
30500598	Castable Refractory, Other Not Classified
30500599	Castable Refractory, Other Not Classified
30500801	Ceramic Clay/Tile Manufacture, Drying ** (use SCC 3-05-008-13)
30500802	Mineral Products, Ceramic Clay/Tile, Comminution-Crushing, Grinding & Milling
30500803	Ceramic Clay/Tile Manufacture, Raw Material Storage
30500899 Mineral Products, Ceramic Clay/Tile Manufacture, Other Not Classified
30500901	Clay and Fly Ash Sintering, Fly Ash Sintering
30500902	Clay and Fly Ash Sintering, Clay/Coke Sintering
30500903	Clay and Fly Ash Sintering, Natural Clay/Shale Sintering
30500904	Clay and Fly Ash Sintering, Raw Clay/Shale Crushing/Screening
30500905	Clay and Fly Ash Sintering, Raw Clay/Shale Transfer/Conveying
30500908	Clay and Fly Ash Sintering, Sintered Clay/Shale Product Crushing/Screening
30500909	Clay and Fly Ash Sintering, Expanded Shale Clinker Cooling
30500910	Clay and Fly Ash Sintering, Expanded Shale Storage
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AT-A-GLANCE TABLE FOR POINT SOURCES
30500915 Clay and Fly Ash Sintering, Rotary Kiln
30500999 Mineral Products, Clay and Fly Ash Sintering, Other Not Classified
30501101 Mineral Products, Concrete Batching, General (Non-fugitive)
30501106	Concrete Batching, Transfer: Sand/Aggregate to Elevated Bins
30501107	Concrete Batching, Cement Unloading: Storage Bins
30501108	Concrete Batching, Weight Hopper Loading of Cement/Sand/Aggregate
30501109	Mineral Products, Concrete Batching, Mixer Loading of Cement/Sand/Aggregate
30501110	Concrete Batching, Loading of Transit Mix Truck
30501111	Concrete Batching, Loading of Dry-batch Truck
30501112	Mineral Products, Concrete Batching, Mixing: Wet
30501113	Concrete Batching, Mixing: Dry
30501114	Concrete Batching, Transferring: Conveyors/Elevators
30501115	Concrete Batching, Storage: Bins/Hoppers
30501199 Mineral Products, Concrete Batching, Other Not Classified
30501201 Fiberglass Manufacturing, Regenerative Furnace (Wool-type Fiber)
30501203	Fiberglass Manufacturing, Electric Furnace (Wool-type Fiber)
30501204	Fiberglass Manufacturing, Forming: Rotary Spun (Wool-type Fiber)
30501205	Fiberglass Manufacturing, Curing Oven: Rotary Spun (Wool-type Fiber)
30501206	Fiberglass Manufacturing, Cooling (Wool-type Fiber)
30501207	Fiberglass Manufacturing, Unit Melter Furnace (Wool-type Fiber)
30501208	Fiberglass Manufacturing, Forming: Flame Attenuation (Wool-type Fiber)
30501209	Fiberglass Manufacturing, Curing: Flame Attenuation (Wool-type Fiber)
30501211	Fiberglass Manufacturing, Regenerative Furnace (Textile-type Fiber)
30501212	Fiberglass Manufacturing, Recuperative Furnace (Textile-type Fiber)
30501213	Fiberglass Manufacturing, Unit Melter Furnace (Textile-type Fiber)
30501214	Fiberglass Manufacturing, Forming Process (Textile-type Fiber)
30501215	Fiberglass Manufacturing, Curing Oven (Textile-type Fiber)
30501221 Fiberglass Manufacturing, Raw Material: Unloading/Conveying
30501223 Fiberglass Manufacturing, Raw Material: Mixing/Weighing
30501299 Mineral Products, Fiberglass Manufacturing, Other Not Classified
30501401	Glass Manufacture, Furnace/General**
30501402	Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
30501403	Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
30501404	Glass Manufacture, Pressed and Blown Glass: Melting Furnace
30501406	Mineral Products, Glass Manufacture, Container Glass: Forming/Finishing
30501407	Glass Manufacture, Flat Glass: Forming/Finishing
30501408	Glass Manufacture, Pressed and Blown Glass: Forming/Finishing
30501410	Glass Manufacture, Raw Material Handling (All Types of Glass)
30501411	Glass Manufacture, General **
30501413 Mineral Products, Glass Manufacture, Cullet: Crushing/Grinding
30501415	Mineral Products, Glass Manufacture, Glass Etching with Hydrofluoric Acid Solution
30501416	Glass Manufacture, Glass Manufacturing
30501499 Glass Manufacture, See Comment **
30501501	Mineral Products, Gypsum Manufacture, Rotary Ore Dryer
30501502	Mineral Products, Gypsum Manufacture, Primary Grinder/Roller Mills
30501503	Gypsum Manufacture, Not Classified **
30501504	Mineral Products, Gypsum Manufacture, Conveying
30501505	Gypsum Manufacture, Primary Crushing: Gypsum Ore
30501506	Gypsum Manufacture, Secondary Crushing: Gypsum Ore
30501507	Gypsum Manufacture, Screening: Gypsum Ore
30501508	Mineral Products, Gypsum Manufacture, Stockpile: Gypsum Ore
30501509	Mineral Products, Gypsum Manufacture, Storage Bins: Gypsum Ore
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AT-A-GLANCE TABLE FOR POINT SOURCES
30501511	Gypsum Manufacture, Continuous Kettle: Calciner
30501512	Gypsum Manufacture, Flash Calciner
30501513	Gypsum Manufacture, Impact Mill
30501514	Gypsum Manufacture, Storage Bins: Stucco
30501515	Gypsum Manufacture, Tube/Ball Mills
30501516	Gypsum Manufacture, Mixers
30501518	Mineral Products, Gypsum Manufacture, Mixers/Conveyors
30501519	Gypsum Manufacture, Forming Line
30501520	Mineral Products, Gypsum Manufacture, Drying Kiln
30501521	Mineral Products, Gypsum Manufacture, End Sawing (8 Ft.)
30501522	Mineral Products, Gypsum Manufacture, End Sawing (12 Ft.)
30501601	Lime Manufacture, Primary Crushing
30501602	Lime Manufacture, Secondary Crushing/Screening
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime Manufacture, Calcining: Rotary Kiln ** (See SCC Codes 3-05-016-
18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501607	Lime Manufacture, Raw Material Transfer and Conveying
30501608	Lime Manufacture, Raw Material Unloading
30501609	Lime Manufacture, Hydrator: Atmospheric
30501610	Lime Manufacture, Raw Material Storage Piles
30501611	Lime Manufacture, Product Cooler
30501612	Lime Manufacture, Pressure Hydrator
30501613	Mineral Products, Lime Manufacture, Lime Silos
30501614	Lime Manufacture, Packing/Shipping
30501615	Lime Manufacture, Product Transfer and Conveying
30501616	Lime Manufacture, Primary Screening
30501617	Lime Manufacture, Multiple Hearth Calciner
30501619	Lime Manufacture, Calcining: Gas-fired Rotary Kiln
30501620	Lime Manufacture, Calcining: Coal- and Gas-fired Rotary Kiln
30501626 Lime Manufacture, Product Loading, Enclosed Truck
30501640 Lime Manufacture, Vehicle Traffic
30501699 Lime Manufacture, See Comment **
30501701 Mineral Wool, Cupola
30501703	Mineral Wool, Blow Chamber
30501704	Mineral Wool, Curing Oven
30501705	Mineral Wool, Cooler
30501801 Perlite Manufacturing, Vertical Furnace
30501899 Perlite Manufacturing, Other Not Classified
30501901	Phosphate Rock, Drying
30501902	Phosphate Rock, Grinding
30501903	Phosphate Rock, Transfer/Storage
30501905	Mineral Products, Phosphate Rock, Calcining
30501906	Phosphate Rock, Rotary Dryer
30501999 Phosphate Rock, Other Not Classified
30502101 Salt Mining, General
30502201 Potash Production, Mine: Grinding/Drying
30502299 Potash Production, Other Not Classified
30502401 Magnesium Carbonate, Mine/Process
30502501	Construction Sand and Gravel, Total Plant: General **
30502502	Construction Sand and Gravel, Aggregate Storage
30502503	Construction Sand and Gravel, Material Transfer and Conveying
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AT-A-GLANCE TABLE FOR POINT SOURCES
30502504	Construction Sand and Gravel, Hauling
30502505	Construction Sand and Gravel, Pile Forming: Stacker
30502506	Construction Sand and Gravel, Bulk Loading
30502507	Construction Sand and Gravel, Storage Piles
30502508	Construction Sand & Gravel, Dryer (See 305027-20 thru -24 for Industrial Sand Dryers)
30502509	Construction Sand and Gravel, Cooler ** (See 3-05-027-30 for Industrial Sand Coolers)
30502510	Mineral Products, Construction Sand and Gravel, Crushing
30502511	Construction Sand and Gravel, Screening
30502599 Construction Sand and Gravel, Not Classified **
30502601 Diatomaceous Earth, Handling
30502699 Diatomaceous Earth, Other Not Classified
30502701 Industrial Sand and Gravel, Primary Crushing of Raw Material
30502705 Industrial Sand and Gravel, Secondary Crushing
30502709 Industrial Sand and Gravel, Grinding: Size Reduction to 50 Microns or Smaller
30502713 Industrial Sand and Gravel, Screening: Size Classification
30502760 Industrial Sand and Gravel, Sand Handling, Transfer, and Storage
30503099 Ceramic Electric Parts, Other Not Classified
30503301 Vermiculite, General
30504001	Mining and Quarrying of Nonmetallic Minerals, Open Pit Blasting
30504002	Mining and Quarrying of Nonmetallic Minerals, Open Pit Drilling
30504003	Mining and Quarrying of Nonmetallic Minerals, Open Pit Cobbing
30504010 Mining and Quarrying of Nonmetallic Minerals, Underground Ventilation
30504020	Mining and Quarrying of Nonmetallic Minerals, Loading
30504021	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Material
30504022	Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Waste
30504023	Mining and Quarrying of Nonmetallic Minerals, Unloading
30504024	Mining and Quarrying of Nonmetallic Minerals, Overburden Stripping
30504025	Mining and Quarrying of Nonmetallic Minerals, Stockpiling
30504030	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Primary Crusher
30504031	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Secondary Crusher
30504033	Mining and Quarrying of Nonmetallic Minerals, Ore Dryer
30504034	Mining and Quarrying of Nonmetallic Minerals, Screening
30504036 Mining and Quarrying of Nonmetallic Minerals, Tailing Piles
30504099 Mining and Quarrying of Nonmetallic Minerals, Other Not Classified
30504140 Clay processing: Kaolin, Calcining, rotary calciner
30510001	Bulk Materials Elevators, Unloading
30510002	Bulk Materials Elevators, Loading
30510101 Bulk Materials Conveyors, Ammonium Sulfate
30510103	Bulk Materials Conveyors, Coal
30510104	Bulk Materials Conveyors, Coke
30510105	Bulk Materials Conveyors, Limestone
30510197	Bulk Materials Conveyors, Fertilizer: Specify in Comments
30510198	Bulk Materials Conveyors, Mineral: Specify in Comments
30510199	Bulk Materials Conveyors, Other Not Classified
30510202	Mineral Products, Bulk Materials Storage Bins, Cement
30510203	Bulk Materials Storage Bins, Coal
30510204	Bulk Materials Storage Bins, Coke
30510205	Bulk Materials Storage Bins, Limestone
30510298	Mineral Products, Bulk Materials Storage Bins, Mineral: Specify in Comments
30510299	Bulk Materials Storage Bins, Other Not Classified
30510303	Bulk Materials Open Stockpiles, Coal
30510304	Bulk Materials Open Stockpiles, Coke
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AT-A-GLANCE TABLE FOR POINT SOURCES
30510397	Bulk Materials Open Stockpiles, Fertilizer: Specify in Comments
30510398	Bulk Materials Open Stockpiles, Mineral: Specify in Comments
30510399	Bulk Materials Open Stockpiles, Other Not Classified
30510402	Bulk Materials Unloading Operation, Cement
30510403	Mineral Products, Bulk Materials Unloading Operation, Coal
30510404	Bulk Materials Unloading Operation, Coke
30510405	Bulk Materials Unloading Operation, Limestone
30510406	Bulk Materials Unloading Operation, Phosphate Rock
30510407	Bulk Materials Unloading Operation, Scrap Metal
30510497	Bulk Materials Unloading Operation, Fertilizer: Specify in Comments
30510498	Bulk Materials Unloading Operation, Mineral: Specify in Comments
30510499	Bulk Materials Unloading Operation, Other Not Classified
30510503 Bulk Materials Loading Operation, Coal
30510505 Bulk Materials Loading Operation, Limestone
30510507 Bulk Materials Loading Operation, Scrap Metal
30510596	Bulk Materials Loading Operation, Chemical: Specify in Comments
30510597	Bulk Materials Loading Operation, Fertilizer: Specify in Comments
30510598	Bulk Materials Loading Operation, Mineral: Specify in Comments
30510599	Bulk Materials Loading Operation, Other Not Classified
30515001	Calcining, Raw Material Handling
30515002	Calcining, General
30515004 Calcining, Finished Product Handling
30531008	Coal Mining, Cleaning, and Material Handling (See 305010)
30531009	Coal Mining, Cleaning, and Material Handling (See 305010)
30531010	Coal Mining, Cleaning, and Material Handling (See 305010)
30531011	Coal Mining, Cleaning, and Material Handling (See 305010)
30531012	Coal Mining, Cleaning, and Material Handling (See 305010)
30531014 Coal Mining, Cleaning, and Material Handling (See 305010)
30531090 Coal Mining, Cleaning, and Material Handling (See 305010)
30531099 Coal Mining, Cleaning, and Material Handling (See 305010)
30532006 Stone Quarrying-Processing (See 305020), Misc. Operations
30532008 Stone Quarrying - Processing (See also 305020 for diff. units), Cut Stone: General
30588801	Fugitive Emissions, Specify in Comments Field
30588802	Fugitive Emissions, Specify in Comments Field
30588803	Fugitive Emissions, Specify in Comments Field
30588804	Fugitive Emissions, Specify in Comments Field
30588805	Fugitive Emissions, Specify in Comments Field
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590023 Fuel Fired Equipment, Natural Gas: Flares
30599999 Mineral Products, Other Not Defined, Specify in Comments Field
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Unloading
Raw Coal Storage
Crushing
Coal Transfer
Screening
Cleaned Coal Storage
Haul Roads: General
Other Not Classified
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal 25	$/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
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AT-A-GLANCE TABLE FOR POINT SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Material handling operations including crushing, grinding, and screening, can produce significant PM
emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply.
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Other
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2214	POD: 221
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to miscellaneous mineral production operations including (but not
limited to) brick manufacture, calcium carbide operations, clay and fly ash sintering,
concrete batching, gypsum manufacturing, lime production, phosphate rock
operations, sand production, fiberglass manufacturing and glass manufacturing
operations. Materials handling operations including crushing, grinding, and screening,
can produce significant PM emissions.
Affected SCC:
30500301	Mineral Products, Brick Manufacture, Raw Material Drying
30500302	Mineral Products, Brick Manufacture, Raw Material Grinding & Screening
30500303	Brick Manufacture, Storage of Raw Materials
30500305 Brick Manufacture, Raw Material Handling and Transferring
30500308	Brick Manufacture, Screening
30500309	Brick Manufacture, Blending and Mixing
30500310	Brick Manufacture, Curing and Firing: Sawdust Fired Tunnel Kilns
30500311	Mineral Products, Brick Manufacture, Curing and Firing: Gas-fired Tunnel Kilns
30500313 Mineral Products, Brick Manufacture, Curing and Firing: Coal-fired Tunnel Kilns
30500316 Brick Manufacture, Curing and Firing: Coal-fired Periodic Kilns
30500331 Brick Manufacture, Curing and Firing: Dual Fuel Fired Tunnel Kiln
30500398	Mineral Products, Brick Manufacture, Other Not Classified
30500399	Brick Manufacture, Other Not Classified
30500401	Calcium Carbide, Electric Furnace: Hoods and Main Stack
30500402	Mineral Products, Calcium Carbide, Coke Dryer
30500404 Calcium Carbide, Tap Fume Vents
30500406 Mineral Products, Calcium Carbide, Circular Charging: Conveyor
30500499 Mineral Products, Calcium Carbide, Other Not Classified
30500501	Castable Refractory, Fire Clay: Rotary Dryer
30500502	Castable Refractory, Raw Material Crushing/Processing
30500598	Castable Refractory, Other Not Classified
30500599	Castable Refractory, Other Not Classified
30500801	Ceramic Clay/Tile Manufacture, Drying ** (use SCC 3-05-008-13)
30500802	Mineral Products, Ceramic Clay/Tile, Comminution-Crushing, Grinding & Milling
30500803	Ceramic Clay/Tile Manufacture, Raw Material Storage
30500805 Ceramic Clay/Tile Manufacture, Granulation-Mixing of Ceramic Powder & Binder Sol'n
30500899 Mineral Products, Ceramic Clay/Tile Manufacture, Other Not Classified
30500901	Clay and Fly Ash Sintering, Fly Ash Sintering
30500902	Clay and Fly Ash Sintering, Clay/Coke Sintering
30500903	Clay and Fly Ash Sintering, Natural Clay/Shale Sintering
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AT-A-GLANCE TABLE FOR POINT SOURCES
30500904	Clay and Fly Ash Sintering, Raw Clay/Shale Crushing/Screening
30500905	Clay and Fly Ash Sintering, Raw Clay/Shale Transfer/Conveying
30500908	Clay and Fly Ash Sintering, Sintered Clay/Shale Product Crushing/Screening
30500909	Clay and Fly Ash Sintering, Expanded Shale Clinker Cooling
30500910	Clay and Fly Ash Sintering, Expanded Shale Storage
30500915 Clay and Fly Ash Sintering, Rotary Kiln
30500999 Mineral Products, Clay and Fly Ash Sintering, Other Not Classified
30501101 Mineral Products, Concrete Batching, General (Non-fugitive)
30501106	Concrete Batching, Transfer: Sand/Aggregate to Elevated Bins
30501107	Concrete Batching, Cement Unloading: Storage Bins
30501108	Concrete Batching, Weight Hopper Loading of Cement/Sand/Aggregate
30501109	Mineral Products, Concrete Batching, Mixer Loading of Cement/Sand/Aggregate
30501110	Concrete Batching, Loading of Transit Mix Truck
30501111	Concrete Batching, Loading of Dry-batch Truck
30501112	Mineral Products, Concrete Batching, Mixing: Wet
30501113	Concrete Batching, Mixing: Dry
30501114	Concrete Batching, Transferring: Conveyors/Elevators
30501115	Concrete Batching, Storage: Bins/Hoppers
30501199 Mineral Products, Concrete Batching, Other Not Classified
30501201 Fiberglass Manufacturing, Regenerative Furnace (Wool-type Fiber)
30501203	Fiberglass Manufacturing, Electric Furnace (Wool-type Fiber)
30501204	Fiberglass Manufacturing, Forming: Rotary Spun (Wool-type Fiber)
30501205	Fiberglass Manufacturing, Curing Oven: Rotary Spun (Wool-type Fiber)
30501206	Fiberglass Manufacturing, Cooling (Wool-type Fiber)
30501207	Fiberglass Manufacturing, Unit Melter Furnace (Wool-type Fiber)
30501208	Fiberglass Manufacturing, Forming: Flame Attenuation (Wool-type Fiber)
30501209	Fiberglass Manufacturing, Curing: Flame Attenuation (Wool-type Fiber)
30501211	Fiberglass Manufacturing, Regenerative Furnace (Textile-type Fiber)
30501212	Fiberglass Manufacturing, Recuperative Furnace (Textile-type Fiber)
30501213	Fiberglass Manufacturing, Unit Melter Furnace (Textile-type Fiber)
30501214	Fiberglass Manufacturing, Forming Process (Textile-type Fiber)
30501215	Fiberglass Manufacturing, Curing Oven (Textile-type Fiber)
30501221 Fiberglass Manufacturing, Raw Material: Unloading/Conveying
30501223 Fiberglass Manufacturing, Raw Material: Mixing/Weighing
30501299 Mineral Products, Fiberglass Manufacturing, Other Not Classified
30501401	Glass Manufacture, Furnace/General**
30501402	Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
30501403	Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
30501404	Glass Manufacture, Pressed and Blown Glass: Melting Furnace
30501406	Mineral Products, Glass Manufacture, Container Glass: Forming/Finishing
30501407	Glass Manufacture, Flat Glass: Forming/Finishing
30501408	Glass Manufacture, Pressed and Blown Glass: Forming/Finishing
30501410	Glass Manufacture, Raw Material Handling (All Types of Glass)
30501411	Glass Manufacture, General **
30501413 Mineral Products, Glass Manufacture, Cullet: Crushing/Grinding
30501415	Mineral Products, Glass Manufacture, Glass Etching with Hydrofluoric Acid Solution
30501416	Glass Manufacture, Glass Manufacturing
30501499 Glass Manufacture, See Comment **
30501501	Mineral Products, Gypsum Manufacture, Rotary Ore Dryer
30501502	Mineral Products, Gypsum Manufacture, Primary Grinder/Roller Mills
30501503	Gypsum Manufacture, Not Classified **
30501504	Mineral Products, Gypsum Manufacture, Conveying
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AT-A-GLANCE TABLE FOR POINT SOURCES
30501505	Gypsum Manufacture, Primary Crushing: Gypsum Ore
30501506	Gypsum Manufacture, Secondary Crushing: Gypsum Ore
30501507	Gypsum Manufacture, Screening: Gypsum Ore
30501508	Mineral Products, Gypsum Manufacture, Stockpile: Gypsum Ore
30501509	Mineral Products, Gypsum Manufacture, Storage Bins: Gypsum Ore
30501511	Gypsum Manufacture, Continuous Kettle: Calciner
30501512	Gypsum Manufacture, Flash Calciner
30501513	Gypsum Manufacture, Impact Mill
30501514	Gypsum Manufacture, Storage Bins: Stucco
30501515	Gypsum Manufacture, Tube/Ball Mills
30501516	Gypsum Manufacture, Mixers
30501518	Mineral Products, Gypsum Manufacture, Mixers/Conveyors
30501519	Gypsum Manufacture, Forming Line
30501520	Mineral Products, Gypsum Manufacture, Drying Kiln
30501521	Mineral Products, Gypsum Manufacture, End Sawing (8 Ft.)
30501522	Mineral Products, Gypsum Manufacture, End Sawing (12 Ft.)
30501601	Lime Manufacture, Primary Crushing
30501602	Lime Manufacture, Secondary Crushing/Screening
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime Manufacture, Calcining: Rotary Kiln ** (See SCC Codes 3-05-016-
18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30501607	Lime Manufacture, Raw Material Transfer and Conveying
30501608	Lime Manufacture, Raw Material Unloading
30501609	Lime Manufacture, Hydrator: Atmospheric
30501610	Lime Manufacture, Raw Material Storage Piles
30501611	Lime Manufacture, Product Cooler
30501612	Lime Manufacture, Pressure Hydrator
30501613	Mineral Products, Lime Manufacture, Lime Silos
30501614	Lime Manufacture, Packing/Shipping
30501615	Lime Manufacture, Product Transfer and Conveying
30501616	Lime Manufacture, Primary Screening
30501617	Lime Manufacture, Multiple Hearth Calciner
30501619	Lime Manufacture, Calcining: Gas-fired Rotary Kiln
30501620	Lime Manufacture, Calcining: Coal- and Gas-fired Rotary Kiln
30501626 Lime Manufacture, Product Loading, Enclosed Truck
30501640 Lime Manufacture, Vehicle Traffic
30501699 Lime Manufacture, See Comment **
30501701 Mineral Wool, Cupola
30501703	Mineral Wool, Blow Chamber
30501704	Mineral Wool, Curing Oven
30501705	Mineral Wool, Cooler
30501799 Mineral Wool, Other Not Classified
30501801 Perlite Manufacturing, Vertical Furnace
30501899 Perlite Manufacturing, Other Not Classified
30501901	Phosphate Rock, Drying
30501902	Phosphate Rock, Grinding
30501903	Phosphate Rock, Transfer/Storage
30501905	Mineral Products, Phosphate Rock, Calcining
30501906	Phosphate Rock, Rotary Dryer
30501907	Phosphate Rock, Ball
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AT-A-GLANCE TABLE FOR POINT SOURCES
30501999 Phosphate Rock, Other Not Classified
30502101 Salt Mining, General
30502201 Potash Production, Mine: Grinding/Drying
30502299 Potash Production, Other Not Classified
30502401 Magnesium Carbonate, Mine/Process
30502501	Construction Sand and Gravel, Total Plant: General **
30502502	Construction Sand and Gravel, Aggregate Storage
30502503	Construction Sand and Gravel, Material Transfer and Conveying
30502504	Construction Sand and Gravel, Hauling
30502505	Construction Sand and Gravel, Pile Forming: Stacker
30502506	Construction Sand and Gravel, Bulk Loading
30502507	Construction Sand and Gravel, Storage Piles
30502508	Construction Sand & Gravel, Dryer (See 305027-20 thru -24 for Industrial Sand Dryers)
30502509	Construction Sand & Gravel, Cooler (See 305027-30 for Industrial Sand Coolers)
30502510	Mineral Products, Construction Sand and Gravel, Crushing
30502511	Construction Sand and Gravel, Screening
30502599 Construction Sand and Gravel, Not Classified **
30502601 Diatomaceous Earth, Handling
30502699 Diatomaceous Earth, Other Not Classified
30502701 Industrial Sand and Gravel, Primary Crushing of Raw Material
30502705 Industrial Sand and Gravel, Secondary Crushing
30502709 Industrial Sand and Gravel, Grinding: Size Reduction to 50 Microns or Smaller
30502713 Industrial Sand and Gravel, Screening: Size Classification
30502760 Industrial Sand and Gravel, Sand Handling, Transfer, and Storage
30503099 Ceramic Electric Parts, Other Not Classified
30503301 Vermiculite, General
30504001	Mining and Quarrying of Nonmetallic Minerals, Open Pit Blasting
30504002	Mining and Quarrying of Nonmetallic Minerals, Open Pit Drilling
30504003	Mining and Quarrying of Nonmetallic Minerals, Open Pit Cobbing
30504010 Mining and Quarrying of Nonmetallic Minerals, Underground Ventilation
30504020	Mining and Quarrying of Nonmetallic Minerals, Loading
30504021	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Material
30504022	Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Waste
30504023	Mining and Quarrying of Nonmetallic Minerals, Unloading
30504024	Mining and Quarrying of Nonmetallic Minerals, Overburden Stripping
30504025	Mining and Quarrying of Nonmetallic Minerals, Stockpiling
30504030	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Primary Crusher
30504031	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Secondary Crusher
30504033	Mining and Quarrying of Nonmetallic Minerals, Ore Dryer
30504034	Mining and Quarrying of Nonmetallic Minerals, Screening
30504036 Mining and Quarrying of Nonmetallic Minerals, Tailing Piles
30504099 Mining and Quarrying of Nonmetallic Minerals, Other Not Classified
30504140 Clay processing: Kaolin, Calcining, rotary calciner
30510001	Bulk Materials Elevators, Unloading
30510002	Bulk Materials Elevators, Loading
30510101 Bulk Materials Conveyors, Ammonium Sulfate
30510103	Bulk Materials Conveyors, Coal
30510104	Bulk Materials Conveyors, Coke
30510105	Bulk Materials Conveyors, Limestone
30510197	Bulk Materials Conveyors, Fertilizer: Specify in Comments
30510198	Bulk Materials Conveyors, Mineral: Specify in Comments
30510199	Bulk Materials Conveyors, Other Not Classified
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AT-A-GLANCE TABLE FOR POINT SOURCES
30510202	Mineral Products, Bulk Materials Storage Bins, Cement
30510203	Bulk Materials Storage Bins, Coal
30510204	Bulk Materials Storage Bins, Coke
30510205	Bulk Materials Storage Bins, Limestone
30510298	Mineral Products, Bulk Materials Storage Bins, Mineral: Specify in Comments
30510299	Bulk Materials Storage Bins, Other Not Classified
30510303	Bulk Materials Open Stockpiles, Coal
30510304	Bulk Materials Open Stockpiles, Coke
30510397	Bulk Materials Open Stockpiles, Fertilizer: Specify in Comments
30510398	Bulk Materials Open Stockpiles, Mineral: Specify in Comments
30510399	Bulk Materials Open Stockpiles, Other Not Classified
30510402	Bulk Materials Unloading Operation, Cement
30510403	Mineral Products, Bulk Materials Unloading Operation, Coal
30510404	Bulk Materials Unloading Operation, Coke
30510405	Bulk Materials Unloading Operation, Limestone
30510406	Bulk Materials Unloading Operation, Phosphate Rock
30510407	Bulk Materials Unloading Operation, Scrap Metal
30510497	Bulk Materials Unloading Operation, Fertilizer: Specify in Comments
30510498	Bulk Materials Unloading Operation, Mineral: Specify in Comments
30510499	Bulk Materials Unloading Operation, Other Not Classified
30510503 Bulk Materials Loading Operation, Coal
30510505 Bulk Materials Loading Operation, Limestone
30510507 Bulk Materials Loading Operation, Scrap Metal
30510596	Bulk Materials Loading Operation, Chemical: Specify in Comments
30510597	Bulk Materials Loading Operation, Fertilizer: Specify in Comments
30510598	Bulk Materials Loading Operation, Mineral: Specify in Comments
30510599	Bulk Materials Loading Operation, Other Not Classified
30515001	Calcining, Raw Material Handling
30515002	Calcining, General
30515004 Calcining, Finished Product Handling
30531008	Coal Mining, Cleaning, and Material Handl
30531009	Coal Mining, Cleaning, and Material Handl
30531010	Coal Mining, Cleaning, and Material Handl
30531011	Coal Mining, Cleaning, and Material Handl
30531012	Coal Mining, Cleaning, and Material Handl
30531014 Coal Mining, Cleaning, and Material Handl
30531090 Coal Mining, Cleaning, and Material Handl
30531099 Coal Mining, Cleaning, and Material Handl
30532006 Stone Quarrying-Processing (See 305020), Misc. Operations
30532008 Stone Quarrying - Processing (See also 305020 for diff. units), Cut Stone: General
30588801	Fugitive Emissions, Specify in Comments Field
30588802	Fugitive Emissions, Specify in Comments Field
30588803	Fugitive Emissions, Specify in Comments Field
30588804	Fugitive Emissions, Specify in Comments Field
30588805	Fugitive Emissions, Specify in Comments Field
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590023 Fuel Fired Equipment, Natural Gas: Flares
30599999 Mineral Products, Other Not Defined, Specify in Comments Field
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
Unloading
Raw Coal Storage
Crushing
Coal Transfer
Screening
Cleaned Coal Storage
Haul Roads: General
Other Not Classified
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
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AT-A-GLANCE TABLE FOR POINT SOURCES
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price	0.067 $/kW-hr
Process water price	0.20 $/1000gal
Dust disposal	20 $/ton disposed
Wastewater treatment	1.5 $/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Materials handling operations including crushing, grinding, and screening, can produce significant
PM emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply. Fugitive dust emissions may come
from paved and unpaved roads in plants and from raw material and product loading, unloading, and
storage (STAPPA/ALAPCO, 1996).
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wre-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
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AT-A-GLANCE TABLE FOR POINT SOURCES
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, "Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options", Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Other
Control Measure Name: Paper/Nonwoven Filters - Cartridge Collector Type
Rule Name: Not Applicable
Pechan Measure Code: P2215	POD: 221
Application: This control is the use of paper or non-woven filters (cartridge collector type) to reduce
PM emissions. The waste gas stream is passed through the fibrous filter media
causing PM in the gas stream to be collected on the media by sieving and other
mechanisms.
This control applies to miscellaneous mineral production operations including (but not
limited to) brick manufacture, calcium carbide operations, clay and fly ash sintering,
concrete batching, gypsum manufacturing, lime production, phosphate rock
operations, sand production, fiberglass manufacturing and glass manufacturing
operations. Materials handling operations including crushing, grinding, and screening,
can produce significant PM emissions.
Affected SCC:
30500301	Mineral Products, Brick Manufacture, Raw Material Drying
30500302	Mineral Products, Brick Manufacture, Raw Material Grinding & Screening
30500303	Brick Manufacture, Storage of Raw Materials
30500305 Brick Manufacture, Raw Material Handling and Transferring
30500308	Brick Manufacture, Screening
30500309	Brick Manufacture, Blending and Mixing
30500310	Brick Manufacture, Curing and Firing: Sawdust Fired Tunnel Kilns
30500311	Mineral Products, Brick Manufacture, Curing and Firing: Gas-fired Tunnel Kilns
30500313 Mineral Products, Brick Manufacture, Curing and Firing: Coal-fired Tunnel Kilns
30500316 Brick Manufacture, Curing and Firing: Coal-fired Periodic Kilns
30500331 Brick Manufacture, Curing and Firing: Dual Fuel Fired Tunnel Kiln
30500398	Mineral Products, Brick Manufacture, Other Not Classified
30500399	Brick Manufacture, Other Not Classified
30500401	Calcium Carbide, Electric Furnace: Hoods and Main Stack
30500402	Mineral Products, Calcium Carbide, Coke Dryer
30500404 Calcium Carbide, Tap Fume Vents
30500406 Mineral Products, Calcium Carbide, Circular Charging: Conveyor
30500499 Mineral Products, Calcium Carbide, Other Not Classified
30500501	Castable Refractory, Fire Clay: Rotary Dryer
30500502	Castable Refractory, Raw Material Crushing/Processing
30500598	Castable Refractory, Other Not Classified
30500599	Castable Refractory, Other Not Classified
30500801	Ceramic Clay/Tile Manufacture, Drying ** (use SCC 3-05-008-13)
30500802	Mineral Products, Ceramic Clay/Tile, Comminution-Crushing, Grinding & Milling
30500803	Ceramic Clay/Tile Manufacture, Raw Material Storage
30500805 Ceramic Clay/Tile Manufacture, Granulation-Mixing of Ceramic Powder & Binder Sol'n
30500899 Mineral Products, Ceramic Clay/Tile Manufacture, Other Not Classified
30500901	Clay and Fly Ash Sintering, Fly Ash Sintering
30500902	Clay and Fly Ash Sintering, Clay/Coke Sintering
30500903	Clay and Fly Ash Sintering, Natural Clay/Shale Sintering
30500904	Clay and Fly Ash Sintering, Raw Clay/Shale Crushing/Screening
30500905	Clay and Fly Ash Sintering, Raw Clay/Shale Transfer/Conveying
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AT-A-GLANCE TABLE FOR POINT SOURCES
30500908	Clay and Fly Ash Sintering, Sintered Clay/Shale Product Crushing/Screening
30500909	Clay and Fly Ash Sintering, Expanded Shale Clinker Cooling
30500910	Clay and Fly Ash Sintering, Expanded Shale Storage
30500915 Clay and Fly Ash Sintering, Rotary Kiln
30500999 Mineral Products, Clay and Fly Ash Sintering, Other Not Classified
30501101 Mineral Products, Concrete Batching, General (Non-fugitive)
30501106	Concrete Batching, Transfer: Sand/Aggregate to Elevated Bins
30501107	Concrete Batching, Cement Unloading: Storage Bins
30501108	Concrete Batching, Weight Hopper Loading of Cement/Sand/Aggregate
30501109	Mineral Products, Concrete Batching, Mixer Loading of Cement/Sand/Aggregate
30501110	Concrete Batching, Loading of Transit Mix Truck
30501111	Concrete Batching, Loading of Dry-batch Truck
30501112	Mineral Products, Concrete Batching, Mixing: Wet
30501113	Concrete Batching, Mixing: Dry
30501114	Concrete Batching, Transferring: Conveyors/Elevators
30501115	Concrete Batching, Storage: Bins/Hoppers
30501199 Mineral Products, Concrete Batching, Other Not Classified
30501201 Fiberglass Manufacturing, Regenerative Furnace (Wool-type Fiber)
30501203	Fiberglass Manufacturing, Electric Furnace (Wool-type Fiber)
30501204	Fiberglass Manufacturing, Forming: Rotary Spun (Wool-type Fiber)
30501205	Fiberglass Manufacturing, Curing Oven: Rotary Spun (Wool-type Fiber)
30501206	Fiberglass Manufacturing, Cooling (Wool-type Fiber)
30501207	Fiberglass Manufacturing, Unit Melter Furnace (Wool-type Fiber)
30501208	Fiberglass Manufacturing, Forming: Flame Attenuation (Wool-type Fiber)
30501209	Fiberglass Manufacturing, Curing: Flame Attenuation (Wool-type Fiber)
30501211	Fiberglass Manufacturing, Regenerative Furnace (Textile-type Fiber)
30501212	Fiberglass Manufacturing, Recuperative Furnace (Textile-type Fiber)
30501213	Fiberglass Manufacturing, Unit Melter Furnace (Textile-type Fiber)
30501214	Fiberglass Manufacturing, Forming Process (Textile-type Fiber)
30501215	Fiberglass Manufacturing, Curing Oven (Textile-type Fiber)
30501221 Fiberglass Manufacturing, Raw Material: Unloading/Conveying
30501223 Fiberglass Manufacturing, Raw Material: Mixing/Weighing
30501299 Mineral Products, Fiberglass Manufacturing, Other Not Classified
30501401	Glass Manufacture, Furnace/General**
30501402	Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
30501403	Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
30501404	Glass Manufacture, Pressed and Blown Glass: Melting Furnace
30501406	Mineral Products, Glass Manufacture, Container Glass: Forming/Finishing
30501407	Glass Manufacture, Flat Glass: Forming/Finishing
30501408	Glass Manufacture, Pressed and Blown Glass: Forming/Finishing
30501410	Glass Manufacture, Raw Material Handling (All Types of Glass)
30501411	Glass Manufacture, General **
30501413 Mineral Products, Glass Manufacture, Cullet: Crushing/Grinding
30501415	Mineral Products, Glass Manufacture, Glass Etching with Hydrofluoric Acid Solution
30501416	Glass Manufacture, Glass Manufacturing
30501499 Glass Manufacture, See Comment **
30501501	Mineral Products, Gypsum Manufacture, Rotary Ore Dryer
30501502	Mineral Products, Gypsum Manufacture, Primary Grinder/Roller Mills
30501503	Gypsum Manufacture, Not Classified **
30501504	Mineral Products, Gypsum Manufacture, Conveying
30501505	Gypsum Manufacture, Primary Crushing: Gypsum Ore
30501506	Gypsum Manufacture, Secondary Crushing: Gypsum Ore
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AT-A-GLANCE TABLE FOR POINT SOURCES
30501507	Gypsum Manufacture, Screening: Gypsum Ore
30501508	Mineral Products, Gypsum Manufacture, Stockpile: Gypsum Ore
30501509	Mineral Products, Gypsum Manufacture, Storage Bins: Gypsum Ore
30501511	Gypsum Manufacture, Continuous Kettle: Calciner
30501512	Gypsum Manufacture, Flash Calciner
30501513	Gypsum Manufacture, Impact Mill
30501514	Gypsum Manufacture, Storage Bins: Stucco
30501515	Gypsum Manufacture, Tube/Ball Mills
30501516	Gypsum Manufacture, Mixers
30501518	Mineral Products, Gypsum Manufacture, Mixers/Conveyors
30501519	Gypsum Manufacture, Forming Line
30501520	Mineral Products, Gypsum Manufacture, Drying Kiln
30501521	Mineral Products, Gypsum Manufacture, End Sawing (8 Ft.)
30501522	Mineral Products, Gypsum Manufacture, End Sawing (12 Ft.)
30501601	Lime Manufacture, Primary Crushing
30501602	Lime Manufacture, Secondary Crushing/Screening
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime Manufacture, Calcining: Rotary Kiln ** (See SCC Codes 3-05-016-
18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30501607	Lime Manufacture, Raw Material Transfer and Conveying
30501608	Lime Manufacture, Raw Material Unloading
30501609	Lime Manufacture, Hydrator: Atmospheric
30501610	Lime Manufacture, Raw Material Storage Piles
30501611	Lime Manufacture, Product Cooler
30501612	Lime Manufacture, Pressure Hydrator
30501613	Mineral Products, Lime Manufacture, Lime Silos
30501614	Lime Manufacture, Packing/Shipping
30501615	Lime Manufacture, Product Transfer and Conveying
30501616	Lime Manufacture, Primary Screening
30501617	Lime Manufacture, Multiple Hearth Calciner
30501619	Lime Manufacture, Calcining: Gas-fired Rotary Kiln
30501620	Lime Manufacture, Calcining: Coal- and Gas-fired Rotary Kiln
30501626 Lime Manufacture, Product Loading, Enclosed Truck
30501640 Lime Manufacture, Vehicle Traffic
30501699 Lime Manufacture, See Comment **
30501701 Mineral Wool, Cupola
30501703	Mineral Wool, Blow Chamber
30501704	Mineral Wool, Curing Oven
30501705	Mineral Wool, Cooler
30501799 Mineral Wool, Other Not Classified
30501801 Perlite Manufacturing, Vertical Furnace
30501899 Perlite Manufacturing, Other Not Classified
30501901	Phosphate Rock, Drying
30501902	Phosphate Rock, Grinding
30501903	Phosphate Rock, Transfer/Storage
30501905	Mineral Products, Phosphate Rock, Calcining
30501906	Phosphate Rock, Rotary Dryer
30501907	Phosphate Rock, Ball Mill
30501999 Phosphate Rock, Other Not Classified
30502101 Salt Mining, General
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AT-A-GLANCE TABLE FOR POINT SOURCES
30502201 Potash Production, Mine: Grinding/Drying
30502299 Potash Production, Other Not Classified
30502401 Magnesium Carbonate, Mine/Process
30502501	Construction Sand and Gravel, Total Plant: General **
30502502	Construction Sand and Gravel, Aggregate Storage
30502503	Construction Sand and Gravel, Material Transfer and Conveying
30502504	Construction Sand and Gravel, Hauling
30502505	Construction Sand and Gravel, Pile Forming: Stacker
30502506	Construction Sand and Gravel, Bulk Loading
30502507	Construction Sand and Gravel, Storage Piles
30502508	Construction Sand & Gravel, Dryer (See 305027-20 thru -24 for Industrial Sand Dryers)
30502509	Construction Sand and Gravel, Cooler ** (See 3-05-027-30 for Industrial Sand Coolers)
30502510	Mineral Products, Construction Sand and Gravel, Crushing
30502511	Construction Sand and Gravel, Screening
30502599 Construction Sand and Gravel, Not Classified **
30502601 Diatomaceous Earth, Handling
30502699 Diatomaceous Earth, Other Not Classified
30502701 Industrial Sand and Gravel, Primary Crushing of Raw Material
30502705 Industrial Sand and Gravel, Secondary Crushing
30502709 Industrial Sand and Gravel, Grinding: Size Reduction to 50 Microns or Smaller
30502713 Industrial Sand and Gravel, Screening: Size Classification
30502760 Industrial Sand and Gravel, Sand Handling, Transfer, and Storage
30503099 Ceramic Electric Parts, Other Not Classified
30503301 Vermiculite, General
30504001	Mining and Quarrying of Nonmetallic Minerals, Open Pit Blasting
30504002	Mining and Quarrying of Nonmetallic Minerals, Open Pit Drilling
30504003	Mining and Quarrying of Nonmetallic Minerals, Open Pit Cobbing
30504010 Mining and Quarrying of Nonmetallic Minerals, Underground Ventilation
30504020	Mining and Quarrying of Nonmetallic Minerals, Loading
30504021	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Material
30504022	Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Waste
30504023	Mining and Quarrying of Nonmetallic Minerals, Unloading
30504024	Mining and Quarrying of Nonmetallic Minerals, Overburden Stripping
30504025	Mining and Quarrying of Nonmetallic Minerals, Stockpiling
30504030	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Primary Crusher
30504031	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Secondary Crusher
30504033	Mining and Quarrying of Nonmetallic Minerals, Ore Dryer
30504034	Mining and Quarrying of Nonmetallic Minerals, Screening
30504036 Mining and Quarrying of Nonmetallic Minerals, Tailing Piles
30504099 Mining and Quarrying of Nonmetallic Minerals, Other Not Classified
30504140 Clay processing: Kaolin, Calcining, rotary calciner
30510001	Bulk Materials Elevators, Unloading
30510002	Bulk Materials Elevators, Loading
30510101 Bulk Materials Conveyors, Ammonium Sulfate
30510103	Bulk Materials Conveyors, Coal
30510104	Bulk Materials Conveyors, Coke
30510105	Bulk Materials Conveyors, Limestone
30510197	Bulk Materials Conveyors, Fertilizer: Specify in Comments
30510198	Bulk Materials Conveyors, Mineral: Specify in Comments
30510199	Bulk Materials Conveyors, Other Not Classified
30510202	Mineral Products, Bulk Materials Storage Bins, Cement
30510203	Bulk Materials Storage Bins, Coal
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AT-A-GLANCE TABLE FOR POINT SOURCES
30510204	Bulk Materials Storage Bins, Coke
30510205	Bulk Materials Storage Bins, Limestone
30510298	Mineral Products, Bulk Materials Storage Bins, Mineral: Specify in Comments
30510299	Bulk Materials Storage Bins, Other Not Classified
30510303	Bulk Materials Open Stockpiles, Coal
30510304	Bulk Materials Open Stockpiles, Coke
30510397	Bulk Materials Open Stockpiles, Fertilizer: Specify in Comments
30510398	Bulk Materials Open Stockpiles, Mineral: Specify in Comments
30510399	Bulk Materials Open Stockpiles, Other Not Classified
30510402	Bulk Materials Unloading Operation, Cement
30510403	Mineral Products, Bulk Materials Unloading Operation, Coal
30510404	Bulk Materials Unloading Operation, Coke
30510405	Bulk Materials Unloading Operation, Limestone
30510406	Bulk Materials Unloading Operation, Phosphate Rock
30510407	Bulk Materials Unloading Operation, Scrap Metal
30510497	Bulk Materials Unloading Operation, Fertilizer: Specify in Comments
30510498	Bulk Materials Unloading Operation, Mineral: Specify in Comments
30510499	Bulk Materials Unloading Operation, Other Not Classified
30510503 Bulk Materials Loading Operation, Coal
30510505 Bulk Materials Loading Operation, Limestone
30510507 Bulk Materials Loading Operation, Scrap Metal
30510596	Bulk Materials Loading Operation, Chemical: Specify in Comments
30510597	Bulk Materials Loading Operation, Fertilizer: Specify in Comments
30510598	Bulk Materials Loading Operation, Mineral: Specify in Comments
30510599	Bulk Materials Loading Operation, Other Not Classified
30515001	Calcining, Raw Material Handling
30515002	Calcining, General
30515004 Calcining, Finished Product Handling
30531008	Coal Mining, Cleaning, and Material Handl
30531009	Coal Mining, Cleaning, and Material Handl
30531010	Coal Mining, Cleaning, and Material Handl
30531011	Coal Mining, Cleaning, and Material Handl
30531012	Coal Mining, Cleaning, and Material Handl
30531014 Coal Mining, Cleaning, and Material Handl
30531090 Coal Mining, Cleaning, and Material Handl
30531099 Coal Mining, Cleaning, and Material Handl
30532006 Stone Quarrying-Processing (See 305020), Misc. Operations
30532008 Stone Quarrying - Processing (See also 305020 for diff. units), Cut Stone: General
30588801	Fugitive Emissions, Specify in Comments Field
30588802	Fugitive Emissions, Specify in Comments Field
30588803	Fugitive Emissions, Specify in Comments Field
30588804	Fugitive Emissions, Specify in Comments Field
30588805	Fugitive Emissions, Specify in Comments Field
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590023 Fuel Fired Equipment, Natural Gas: Flares
30599999 Mineral Products, Other Not Defined, Specify in Comments Field
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
Unloading
Raw Coal Storage
Crushing
Coal Transfer
Screening
Cleaned Coal Storage
Haul Roads: General
Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
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AT-A-GLANCE TABLE FOR POINT SOURCES
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are generated using EPA's cost-estimating spreadsheets for fabric filters
(EPA, 1998a). Costs are primarily driven by the waste stream volumetric flow rate
and pollutant loading. When stack gas flow rate data was available, the costs and
cost effectiveness were calculated using the typical values of capital and O&M costs.
When stack gas flow rate data was not available, default typical capital and O&M cost
values based on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $7 to $13 per scfm
Typical value is $9 per scfm
O&M Costs:
Range from $9 to $25 per scfm
Typical value is $14 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average cartridge cost was estimated using the costs for standard
cartridge types. Capital recovery for the periodic replacement of cartridges was
included in the O&M cost of the cartridges using a cartridge life of 2 years (EPA,
1998a). The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Compressed air 0.25 $/1000scf
Dust disposal 25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $85 to $256 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $142 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Materials handling operations including crushing, grinding, and screening, can produce significant
PM emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply. Fugitive dust emissions may come
from paved and unpaved roads in plants and from raw material and product loading, unloading, and
storage (STAPPA/ALAPCO, 1996).
The cost estimates assume a conventional design under typical operating conditions. Auxiliary
equipment, such as fans and ductwork, is not included (EPA, 2000). Pollutants that require an
unusually high level of control or that require the filter media or the unit itself to be constructed of
special materials, such as Nomex ® or stainless steel, will increase the costs of the system (EPA,
1998a). The additional costs for controlling more complex waste streams are not reflected in the
estimates given below. For these types of systems, the capital cost could increase by as much as
75% and the O&M cost could increase by as much as 10%. In general, a small unit controlling a low
pollutant loading will not be as cost effective as a large unit controlling a high pollutant loading (EPA,
2000).
Cartridge filters contain either a paper or nonwoven fibrous filter media (EPA, 2000). Paper media is
generally made of materials such as cellulose and fiberglass. The dust cake that forms on the filter
media from the collected PM can significantly increase collection efficiency (EPA, 1998b).
In general, the filter media is pleated to provide a larger surface area to volume flow rate. Close
pleating, however, can cause PM to bridge the pleat bottom, effectively reducing the surface
collection area (EPA, 1998b). Corrugated aluminum separators are used to prevent the pleats from
collapsing (Heumann, 1997). There are variety of cartridge designs and dimensions. Typical
designs include flat panels, V-shaped packs or cylindrical packs (Heumann, 1997). For certain
applications, two cartridges may be placed in series.
Cartridge collectors are useful for collecting particles with resistivities either too low or too high for
collection with electrostatic precipitators (STAPPA/AI_APCO, 1996). For similar air flow rates,
cartridge collectors are compact in size compared to traditional bag.
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Cartridge Collector with Pulse-Jet Cleaning," April 2000.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/ALAPCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
STAPPA/ALAPCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, "Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options," Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Other
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2216	POD: 221
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to miscellaneous mineral production operations including (but not
limited to) brick manufacture, calcium carbide operations, clay and fly ash sintering,
concrete batching, gypsum manufacturing, lime production, phosphate rock
operations, sand production, fiberglass manufacturing and glass manufacturing
operations. Materials handling operations including crushing, grinding, and screening,
can produce significant PM emissions.
Affected SCC:
30500301	Mineral Products, Brick Manufacture, Raw Material Drying
30500302	Mineral Products, Brick Manufacture, Raw Material Grinding & Screening
30500303	Brick Manufacture, Storage of Raw Materials
30500305 Brick Manufacture, Raw Material Handling and Transferring
30500308	Brick Manufacture, Screening
30500309	Brick Manufacture, Blending and Mixing
30500310	Brick Manufacture, Curing and Firing: Sawdust Fired Tunnel Kilns
30500311	Mineral Products, Brick Manufacture, Curing and Firing: Gas-fired Tunnel Kilns
30500313 Mineral Products, Brick Manufacture, Curing and Firing: Coal-fired Tunnel Kilns
30500316 Brick Manufacture, Curing and Firing: Coal-fired Periodic Kilns
30500331 Brick Manufacture, Curing and Firing: Dual Fuel Fired Tunnel Kiln
30500398	Mineral Products, Brick Manufacture, Other Not Classified
30500399	Brick Manufacture, Other Not Classified
30500401	Calcium Carbide, Electric Furnace: Hoods and Main Stack
30500402	Mineral Products, Calcium Carbide, Coke Dryer
30500404 Calcium Carbide, Tap Fume Vents
30500406 Mineral Products, Calcium Carbide, Circular Charging: Conveyor
30500499 Mineral Products, Calcium Carbide, Other Not Classified
30500501	Castable Refractory, Fire Clay: Rotary Dryer
30500502	Castable Refractory, Raw Material Crushing/Processing
30500598	Castable Refractory, Other Not Classified
30500599	Castable Refractory, Other Not Classified
30500801	Ceramic Clay/Tile Manufacture, Drying ** (use SCC 3-05-008-13)
30500802	Mineral Products, Ceramic Clay/Tile, Comminution-Crushing, Grinding & Milling
30500803	Ceramic Clay/Tile Manufacture, Raw Material Storage
30500805 Ceramic Clay/Tile Manufacture, Granulation-Mixing of Ceramic Powder & Binder Sol'n
30500899 Mineral Products, Ceramic Clay/Tile Manufacture, Other Not Classified
30500901	Clay and Fly Ash Sintering, Fly Ash Sintering
30500902	Clay and Fly Ash Sintering, Clay/Coke Sintering
30500903	Clay and Fly Ash Sintering, Natural Clay/Shale Sintering
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AT-A-GLANCE TABLE FOR POINT SOURCES
30500904	Clay and Fly Ash Sintering, Raw Clay/Shale Crushing/Screening
30500905	Clay and Fly Ash Sintering, Raw Clay/Shale Transfer/Conveying
30500908	Clay and Fly Ash Sintering, Sintered Clay/Shale Product Crushing/Screening
30500909	Clay and Fly Ash Sintering, Expanded Shale Clinker Cooling
30500910	Clay and Fly Ash Sintering, Expanded Shale Storage
30500915 Clay and Fly Ash Sintering, Rotary Kiln
30500999 Mineral Products, Clay and Fly Ash Sintering, Other Not Classified
30501101 Mineral Products, Concrete Batching, General (Non-fugitive)
30501106	Concrete Batching, Transfer: Sand/Aggregate to Elevated Bins
30501107	Concrete Batching, Cement Unloading: Storage Bins
30501108	Concrete Batching, Weight Hopper Loading of Cement/Sand/Aggregate
30501109	Mineral Products, Concrete Batching, Mixer Loading of Cement/Sand/Aggregate
30501110	Concrete Batching, Loading of Transit Mix Truck
30501111	Concrete Batching, Loading of Dry-batch Truck
30501112	Mineral Products, Concrete Batching, Mixing: Wet
30501113	Concrete Batching, Mixing: Dry
30501114	Concrete Batching, Transferring: Conveyors/Elevators
30501115	Concrete Batching, Storage: Bins/Hoppers
30501199 Mineral Products, Concrete Batching, Other Not Classified
30501201 Fiberglass Manufacturing, Regenerative Furnace (Wool-type Fiber)
30501203	Fiberglass Manufacturing, Electric Furnace (Wool-type Fiber)
30501204	Fiberglass Manufacturing, Forming: Rotary Spun (Wool-type Fiber)
30501205	Fiberglass Manufacturing, Curing Oven: Rotary Spun (Wool-type Fiber)
30501206	Fiberglass Manufacturing, Cooling (Wool-type Fiber)
30501207	Fiberglass Manufacturing, Unit Melter Furnace (Wool-type Fiber)
30501208	Fiberglass Manufacturing, Forming: Flame Attenuation (Wool-type Fiber)
30501209	Fiberglass Manufacturing, Curing: Flame Attenuation (Wool-type Fiber)
30501211	Fiberglass Manufacturing, Regenerative Furnace (Textile-type Fiber)
30501212	Fiberglass Manufacturing, Recuperative Furnace (Textile-type Fiber)
30501213	Fiberglass Manufacturing, Unit Melter Furnace (Textile-type Fiber)
30501214	Fiberglass Manufacturing, Forming Process (Textile-type Fiber)
30501215	Fiberglass Manufacturing, Curing Oven (Textile-type Fiber)
30501221 Fiberglass Manufacturing, Raw Material: Unloading/Conveying
30501223 Fiberglass Manufacturing, Raw Material: Mixing/Weighing
30501299 Mineral Products, Fiberglass Manufacturing, Other Not Classified
30501401	Glass Manufacture, Furnace/General**
30501402	Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
30501403	Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
30501404	Glass Manufacture, Pressed and Blown Glass: Melting Furnace
30501406	Mineral Products, Glass Manufacture, Container Glass: Forming/Finishing
30501407	Glass Manufacture, Flat Glass: Forming/Finishing
30501408	Glass Manufacture, Pressed and Blown Glass: Forming/Finishing
30501410	Glass Manufacture, Raw Material Handling (All Types of Glass)
30501411	Glass Manufacture, General **
30501413 Mineral Products, Glass Manufacture, Cullet: Crushing/Grinding
30501415	Mineral Products, Glass Manufacture, Glass Etching with Hydrofluoric Acid Solution
30501416	Glass Manufacture, Glass Manufacturing
30501499 Glass Manufacture, See Comment **
30501501	Mineral Products, Gypsum Manufacture, Rotary Ore Dryer
30501502	Mineral Products, Gypsum Manufacture, Primary Grinder/Roller Mills
30501503	Gypsum Manufacture, Not Classified **
30501504	Mineral Products, Gypsum Manufacture, Conveying
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AT-A-GLANCE TABLE FOR POINT SOURCES
30501505	Gypsum Manufacture, Primary Crushing: Gypsum Ore
30501506	Gypsum Manufacture, Secondary Crushing: Gypsum Ore
30501507	Gypsum Manufacture, Screening: Gypsum Ore
30501508	Mineral Products, Gypsum Manufacture, Stockpile: Gypsum Ore
30501509	Mineral Products, Gypsum Manufacture, Storage Bins: Gypsum Ore
30501511	Gypsum Manufacture, Continuous Kettle: Calciner
30501512	Gypsum Manufacture, Flash Calciner
30501513	Gypsum Manufacture, Impact Mill
30501514	Gypsum Manufacture, Storage Bins: Stucco
30501515	Gypsum Manufacture, Tube/Ball Mills
30501516	Gypsum Manufacture, Mixers
30501518	Mineral Products, Gypsum Manufacture, Mixers/Conveyors
30501519	Gypsum Manufacture, Forming Line
30501520	Mineral Products, Gypsum Manufacture, Drying Kiln
30501521	Mineral Products, Gypsum Manufacture, End Sawing (8 Ft.)
30501522	Mineral Products, Gypsum Manufacture, End Sawing (12 Ft.)
30501601	Lime Manufacture, Primary Crushing
30501602	Lime Manufacture, Secondary Crushing/Screening
30501603	Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
30501604	Mineral Products, Lime Manufacture, Calcining: Rotary Kiln ** (See SCC Codes 3-05-016-
18,-19,-20,-21)
30501605	Mineral Products, Lime Manufacture, Calcining: Gas-fired Calcimatic Kiln
30501606	Lime Manufacture, Fluidized Bed Kiln
30501607	Lime Manufacture, Raw Material Transfer and Conveying
30501608	Lime Manufacture, Raw Material Unloading
30501609	Lime Manufacture, Hydrator: Atmospheric
30501610	Lime Manufacture, Raw Material Storage Piles
30501611	Lime Manufacture, Product Cooler
30501612	Lime Manufacture, Pressure Hydrator
30501613	Mineral Products, Lime Manufacture, Lime Silos
30501614	Lime Manufacture, Packing/Shipping
30501615	Lime Manufacture, Product Transfer and Conveying
30501616	Lime Manufacture, Primary Screening
30501617	Lime Manufacture, Multiple Hearth Calciner
30501619	Lime Manufacture, Calcining: Gas-fired Rotary Kiln
30501620	Lime Manufacture, Calcining: Coal- and Gas-fired Rotary Kiln
30501626 Lime Manufacture, Product Loading, Enclosed Truck
30501640 Lime Manufacture, Vehicle Traffic
30501699 Lime Manufacture, See Comment **
30501701 Mineral Wool, Cupola
30501703	Mineral Wool, Blow Chamber
30501704	Mineral Wool, Curing Oven
30501705	Mineral Wool, Cooler
30501799 Mineral Wool, Other Not Classified
30501801 Perlite Manufacturing, Vertical Furnace
30501899 Perlite Manufacturing, Other Not Classified
30501901	Phosphate Rock, Drying
30501902	Phosphate Rock, Grinding
30501903	Phosphate Rock, Transfer/Storage
30501905	Mineral Products, Phosphate Rock, Calcining
30501906	Phosphate Rock, Rotary Dryer
30501907	Phosphate Rock, Ball
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AT-A-GLANCE TABLE FOR POINT SOURCES
30501999 Phosphate Rock, Other Not Classified
30502101 Salt Mining, General
30502201 Potash Production, Mine: Grinding/Drying
30502299 Potash Production, Other Not Classified
30502401 Magnesium Carbonate, Mine/Process
30502501	Construction Sand and Gravel, Total Plant: General **
30502502	Construction Sand and Gravel, Aggregate Storage
30502503	Construction Sand and Gravel, Material Transfer and Conveying
30502504	Construction Sand and Gravel, Hauling
30502505	Construction Sand and Gravel, Pile Forming: Stacker
30502506	Construction Sand and Gravel, Bulk Loading
30502507	Construction Sand and Gravel, Storage Piles
30502508	Construction Sand & Gravel, Dryer (See 305027-20 thru -24 for Industrial Sand Dryers)
30502509	Construction Sand and Gravel, Cooler ** (See 3-05-027-30 for Industrial Sand Coolers)
30502510	Mineral Products, Construction Sand and Gravel, Crushing
30502511	Construction Sand and Gravel, Screening
30502599 Construction Sand and Gravel, Not Classified **
30502601 Diatomaceous Earth, Handling
30502699 Diatomaceous Earth, Other Not Classified
30502701 Industrial Sand and Gravel, Primary Crushing of Raw Material
30502705 Industrial Sand and Gravel, Secondary Crushing
30502709 Industrial Sand and Gravel, Grinding: Size Reduction to 50 Microns or Smaller
30502713 Industrial Sand and Gravel, Screening: Size Classification
30502760 Industrial Sand and Gravel, Sand Handling, Transfer, and Storage
30503099 Ceramic Electric Parts, Other Not Classified
30503301 Vermiculite, General
30504001	Mining and Quarrying of Nonmetallic Minerals, Open Pit Blasting
30504002	Mining and Quarrying of Nonmetallic Minerals, Open Pit Drilling
30504003	Mining and Quarrying of Nonmetallic Minerals, Open Pit Cobbing
30504010 Mining and Quarrying of Nonmetallic Minerals, Underground Ventilation
30504020	Mining and Quarrying of Nonmetallic Minerals, Loading
30504021	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Material
30504022	Mining and Quarrying of Nonmetallic Minerals, Convey/Haul Waste
30504023	Mining and Quarrying of Nonmetallic Minerals, Unloading
30504024	Mining and Quarrying of Nonmetallic Minerals, Overburden Stripping
30504025	Mining and Quarrying of Nonmetallic Minerals, Stockpiling
30504030	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Primary Crusher
30504031	Mineral Products, Mining and Quarrying of Nonmetallic Minerals, Secondary Crusher
30504033	Mining and Quarrying of Nonmetallic Minerals, Ore Dryer
30504034	Mining and Quarrying of Nonmetallic Minerals, Screening
30504036 Mining and Quarrying of Nonmetallic Minerals, Tailing Piles
30504099 Mining and Quarrying of Nonmetallic Minerals, Other Not Classified
30504140 Clay processing: Kaolin, Calcining, rotary calciner
30510001	Bulk Materials Elevators, Unloading
30510002	Bulk Materials Elevators, Loading
30510101 Bulk Materials Conveyors, Ammonium Sulfate
30510103	Bulk Materials Conveyors, Coal
30510104	Bulk Materials Conveyors, Coke
30510105	Bulk Materials Conveyors, Limestone
30510197	Bulk Materials Conveyors, Fertilizer: Specify in Comments
30510198	Bulk Materials Conveyors, Mineral: Specify in Comments
30510199	Bulk Materials Conveyors, Other Not Classified
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AT-A-GLANCE TABLE FOR POINT SOURCES
30510202	Mineral Products, Bulk Materials Storage Bins, Cement
30510203	Bulk Materials Storage Bins, Coal
30510204	Bulk Materials Storage Bins, Coke
30510205	Bulk Materials Storage Bins, Limestone
30510298	Mineral Products, Bulk Materials Storage Bins, Mineral: Specify in Comments
30510299	Bulk Materials Storage Bins, Other Not Classified
30510303	Bulk Materials Open Stockpiles, Coal
30510304	Bulk Materials Open Stockpiles, Coke
30510397	Bulk Materials Open Stockpiles, Fertilizer: Specify in Comments
30510398	Bulk Materials Open Stockpiles, Mineral: Specify in Comments
30510399	Bulk Materials Open Stockpiles, Other Not Classified
30510402	Bulk Materials Unloading Operation, Cement
30510403	Mineral Products, Bulk Materials Unloading Operation, Coal
30510404	Bulk Materials Unloading Operation, Coke
30510405	Bulk Materials Unloading Operation, Limestone
30510406	Bulk Materials Unloading Operation, Phosphate Rock
30510407	Bulk Materials Unloading Operation, Scrap Metal
30510497	Bulk Materials Unloading Operation, Fertilizer: Specify in Comments
30510498	Bulk Materials Unloading Operation, Mineral: Specify in Comments
30510499	Bulk Materials Unloading Operation, Other Not Classified
30510503 Bulk Materials Loading Operation, Coal
30510505 Bulk Materials Loading Operation, Limestone
30510507 Bulk Materials Loading Operation, Scrap Metal
30510596	Bulk Materials Loading Operation, Chemical: Specify in Comments
30510597	Bulk Materials Loading Operation, Fertilizer: Specify in Comments
30510598	Bulk Materials Loading Operation, Mineral: Specify in Comments
30510599	Bulk Materials Loading Operation, Other Not Classified
30515001	Calcining, Raw Material Handling
30515002	Calcining, General
30515004 Calcining, Finished Product Handling
30531008	Coal Mining, Cleaning, and Material Handl
30531009	Coal Mining, Cleaning, and Material Handl
30531010	Coal Mining, Cleaning, and Material Handl
30531011	Coal Mining, Cleaning, and Material Handl
30531012	Coal Mining, Cleaning, and Material Handl
30531014 Coal Mining, Cleaning, and Material Handl
30531090 Coal Mining, Cleaning, and Material Handl
30531099 Coal Mining, Cleaning, and Material Handl
30532006 Stone Quarrying-Processing (See 305020), Misc. Operations
30532008 Stone Quarrying - Processing (See also 305020 for diff. units), Cut Stone: General
30588801	Fugitive Emissions, Specify in Comments Field
30588802	Fugitive Emissions, Specify in Comments Field
30588803	Fugitive Emissions, Specify in Comments Field
30588804	Fugitive Emissions, Specify in Comments Field
30588805	Fugitive Emissions, Specify in Comments Field
30590001 Fuel Fired Equipment, Distillate Oil (No. 2): Process Heaters
30590003 Fuel Fired Equipment, Natural Gas: Process Heaters
30590023 Fuel Fired Equipment, Natural Gas: Flares
30599999 Mineral Products, Other Not Defined, Specify in Comments Field
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
ng (See 305010)
Unloading
Raw Coal Storage
Crushing
Coal Transfer
Screening
Cleaned Coal Storage
Haul Roads: General
Other Not Classified
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
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AT-A-GLANCE TABLE FOR POINT SOURCES
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Materials handling operations including crushing, grinding, and screening, can produce significant
PM emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply. Fugitive dust emissions may come
from paved and unpaved roads in plants and from raw material and product loading, unloading, and
storage (STAPPA/ALAPCO, 1996).
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
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AT-A-GLANCE TABLE FOR POINT SOURCES
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Other
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3221	POD: 221
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual

emi
ssions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate

NEI
emissions to include excess emissions.
Affected SCC:


305004**
Mineral
Products,
Calcium Carbide
305003**
Mineral
Products,
Brick Manufacture
305092**
Mineral
Products,
Catalyst Manufacturing
305100**
Mineral
Products,
Bulk Materials Elevators
305101**
Mineral
Products,
Bulk Materials Conveyors
305102**
Mineral
Products,
Bulk Materials Storage Bins
305104**
Mineral
Products,
Bulk Materials Unloading Operation
305005**
Mineral
Products,
Castable Refractory
305900**
Mineral
Products,
Fuel Fired Equipment
305888**
Mineral
Products,
Fugitive Emissions
305105**
Mineral
Products,
Bulk Materials Loading Operation
305106**
Mineral
Products,
Bulk Materials Screening/Size Classification
305999**
Mineral
Products,
Other Not Defined
305108**
Mineral
Products,
Bulk Materials: Grinding/Crushing
305150**
Mineral
Products,
Calcining
305310**
Mineral
Products,
Coal Mining, Cleaning, and Material Handling
305320**
Mineral
Products,
Stone Quarrying - Processing
305090**
Mineral
Products,
Mica
305103**
Mineral
Products,
Bulk Materials Open Stockpiles
305040**
Mineral
Products,
Mining and Quarrying of Nonmetallic Minerals
305022**
Mineral
Products,
Potash Production
305025**
Mineral
Products,
Construction Sand and Gravel
305026**
Mineral
Products,
Diatomaceous Earth
305027**
Mineral
Products,
Industrial Sand and Gravel
305033**
Mineral
Products,
Vermiculite
305021**
Mineral
Products,
Salt Mining
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AT-A-GLANCE TABLE FOR POINT SOURCES
305036**
Mineral
Products
305030**
Mineral
Products
305008**
Mineral
Products
305041**
Mineral
Products
305042**
Mineral
Products
305044**
Mineral
Products
305089**
Mineral
Products
305050**
Mineral
Products
305034**
Mineral
Products
305017**
Mineral
Products
305015**
Mineral
Products
305016**
Mineral
Products
305014**
Mineral
Products
305018**
Mineral
Products
305013**
Mineral
Products
305012**
Mineral
Products
305011**
Mineral
Products
305019**
Mineral
Products
305009**
Mineral
Products
Bonded Abrasives Manufacturing
Ceramic Electric Parts
Ceramic Clay/Tile Manufacture
Clay processing: Kaolin
Clay processing: Ball clay
Clay processing: Bentonite
Talc Processing
Asphalt Processing (Blowing)
Feldspar
Mineral Wool
Gypsum Manufacture
Lime Manufacture
Glass Manufacture
Perlite Manufacturing
Frit Manufacture
Fiberglass Manufacturing
Concrete Batching
Phosphate Rock
Clay and Fly Ash Sintering
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Other
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4221
POD: 221
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
305004**
305003**
305092**
305100**
305101**
305102**
305104**
305005**
305900**
305888**
305105**
305106**
305999**
305108**
305150**
305310**
305320**
305090**
305103**
305040**
305022**
305025**
305026**
305027**
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Minera
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Products
Calcium Carbide
Brick Manufacture
Catalyst Manufacturing
Bulk Materials Elevators
Bulk Materials Conveyors
Bulk Materials Storage Bins
Bulk Materials Unloading Operation
Castable Refractory
Fuel Fired Equipment
Fugitive Emissions
Bulk Materials Loading Operation
Bulk Materials Screening/Size Classification
Other Not Defined
Bulk Materials: Grinding/Crushing
Calcining
Coal Mining, Cleaning, and Material Handling
Stone Quarrying - Processing
Mica
Bulk Materials Open Stockpiles
Mining and Quarrying of Nonmetallic Minerals
Potash Production
Construction Sand and Gravel
Diatomaceous Earth
Industrial Sand and Gravel
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AT-A-GLANCE TABLE FOR POINT SOURCES
305033**
Mineral
Products
305021**
Mineral
Products
305036**
Mineral
Products
305030**
Mineral
Products
305008**
Mineral
Products
305041**
Mineral
Products
305042**
Mineral
Products
305044**
Mineral
Products
305089**
Mineral
Products
305050**
Mineral
Products
305034**
Mineral
Products
305017**
Mineral
Products
305015**
Mineral
Products
305016**
Mineral
Products
305014**
Mineral
Products
305018**
Mineral
Products
305013**
Mineral
Products
305012**
Mineral
Products
305011**
Mineral
Products
305019**
Mineral
Products
305009**
Mineral
Products
Vermiculite
Salt Mining
Bonded Abrasives Manufacturing
Ceramic Electric Parts
Ceramic Clay/Tile Manufacture
Clay processing: Kaolin
Clay processing: Ball clay
Clay processing: Bentonite
Talc Processing
Asphalt Processing (Blowing)
Feldspar
Mineral Wool
Gypsum Manufacture
Lime Manufacture
Glass Manufacture
Perlite Manufacturing
Frit Manufacture
Fiberglass Manufacturing
Concrete Batching
Phosphate Rock
Clay and Fly Ash Sintering
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
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References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Mineral Products - Stone Quarrying & Processing
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3220	POD: 220
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
305020** Mineral Products, Stone Quarrying - Processing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Stone Quarrying & Processing
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4220	POD: 220
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
305020** Mineral Products, Stone Quarrying - Processing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Mineral Products - Stone Quarrying and Processing
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: P2201
POD: 220
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Particulate-laden gas
flows into the filter bag from the outside to the inside. The particles collected on the
outside drop into a hopper below the fabric filter. During pulse-jet cleaning, a short
burst of high pressure air is injected into the bags, dislodging the dust cake.
This control applies to stone quarrying and processing operations. Nonmetallic Mineral
Processing (305020) - ore crushing, grinding, and screening, and Calciners (SCC
305150) and Dryers (SCC 30502012) are considered in this category, among others.
Materials handling operations including crushing, grinding, and screening, can produce
significant PM emissions.
Affected SCC:
30502001
30502002
30502003
30502004
30502005
30502006
30502007
30502008
30502009
30502010
30502011
30502012
30502013
30502014
30502015
30502017
30502020
30502031
30502033
30502099
Mineral Products,
Mineral Products,
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying
Stone Quarrying-
Stone Quarrying-
Processing (See
Processing (See
Stone Quarrying-
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Stone Quarrying
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
-	Processing (See also 305320), Primary Crushing
Processing, Secondary Crushing/Screening
Processing, Tertiary Crushing/Screening
also 305320), Recrushing/Screening
also 305320), Fines Mill
Processing (See 305320), Misc. Operations
also 305320), Open Storage
also 305320), Cut Stone: General
also 305320), Blasting: General
also 305320), Drilling
also 305320), Hauling
-	Processing (See also 305320), Drying
also 305320), Bar Grizzlies
also 305320), Shaker Screens
also 305320), Vibrating Screens
also 305320), Pugmill
also 305320), Drilling
also 305320), Truck Unloading
also 305320), Truck Loading: Front End Loader
also 305320), Not Classified **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air	0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
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AT-A-GLANCE TABLE FOR POINT SOURCES
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Drying, the heating of minerals or mineral products to remove water, and calcination, heating to
higher temperatures to remove chemically bound water and other compounds, are normally
performed in dedicated, closed units. Emissions from these units will be through process vents, to
which PM controls can be applied relatively simply. Fugitive dust emissions may come from paved
and unpaved roads in plants and from raw material and product loading, unloading, and storage
(STAPPA/ALAPCO, 1996).
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
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AT-A-GLANCE TABLE FOR POINT SOURCES
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Stone Quarrying and Processing
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2202	POD: 220
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to stone quarrying and processing operations. Nonmetallic Mineral
Processing (305020) - ore crushing, grinding, and screening, and Calciners (SCC
305150) and Dryers (SCC 30502012), among others, are considered in this category.
Affected SCC:
30502001
30502002
30502003
30502004
30502005
30502006
30502007
30502008
30502009
30502010
30502011
30502012
30502013
30502014
30502015
30502017
30502020
30502031
30502033
30502099
Mineral Products,
Mineral Products,
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying
Stone Quarrying-
Stone Quarrying-
Processing (See
Processing (See
Stone Quarrying-
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Stone Quarrying
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
-	Processing (See also 305320), Primary Crushing
Processing, Secondary Crushing/Screening
Processing, Tertiary Crushing/Screening
also 305320), Recrushing/Screening
also 305320), Fines Mill
Processing (See 305320), Misc. Operations
also 305320), Open Storage
also 305320), Cut Stone: General
also 305320), Blasting: General
also 305320), Drilling
also 305320), Hauling
-	Processing (See also 305320), Drying
also 305320), Bar Grizzlies
also 305320), Shaker Screens
also 305320), Vibrating Screens
also 305320), Pugmill
also 305320), Drilling
also 305320), Truck Unloading
also 305320), Truck Loading: Front End Loader
also 305320), Not Classified **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
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AT-A-GLANCE TABLE FOR POINT SOURCES
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Materials handling operations including crushing, grinding, and screening, can produce significant
PM emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply. Fugitive dust emissions may come
from paved and unpaved roads in plants and from raw material and product loading, unloading, and
storage (STAPPA/ALAPCO, 1996).
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Stone Quarrying and Processing
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2203	POD: 220
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to stone quarrying and processing operations. Nonmetallic Mineral
Processing (305020) - ore crushing, grinding, and screening, and Calciners (SCC
305150) and Dryers (SCC 30502012) are considered in this category. Materials
handling operations including crushing, grinding, and screening, can produce
significant PM emissions.
Affected SCC:
30502001
30502002
30502003
30502004
30502005
30502006
30502007
30502008
30502009
30502010
30502011
30502012
30502013
30502014
30502015
30502017
30502020
30502031
30502033
30502099
Mineral Products,
Mineral Products,
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying
Stone Quarrying-
Stone Quarrying-
Processing (See
Processing (See
Stone Quarrying-
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Stone Quarrying
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
-	Processing (See also 305320), Primary Crushing
Processing, Secondary Crushing/Screening
Processing, Tertiary Crushing/Screening
also 305320), Recrushing/Screening
also 305320), Fines Mill
Processing (See 305320), Misc. Operations
also 305320), Open Storage
also 305320), Cut Stone: General
also 305320), Blasting: General
also 305320), Drilling
also 305320), Hauling
-	Processing (See also 305320), Drying
also 305320), Bar Grizzlies
also 305320), Shaker Screens
also 305320), Vibrating Screens
also 305320), Pugmill
also 305320), Drilling
also 305320), Truck Unloading
also 305320), Truck Loading: Front End Loader
also 305320), Not Classified **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
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AT-A-GLANCE TABLE FOR POINT SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Minerals processing operations include drying, the heating of minerals or mineral products to
remove water, and calcination, heating to higher temperatures to remove chemically bound water
and other compounds, are normally performed in dedicated, closed units. Emissions from these
units will be through process vents, to which PM controls can be applied relatively simply. Fugitive
dust emissions may come from paved and unpaved roads in plants and from raw material and
product loading, unloading, and storage (STAPPA/ALAPCO, 1996).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Stone Quarrying and Processing
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2204
POD: 220
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to stone quarrying and processing operations, including (but not
limited to) nonmetallic mineral processing (305020) - ore crushing, grinding, and
screening, and calciners (SCC 305150) and dryers (SCC 30502012).
Affected SCC:
30502001
30502002
30502003
30502004
30502005
30502006
30502007
30502008
30502009
30502010
30502011
30502012
30502013
30502014
30502015
30502017
30502020
30502031
30502033
30502099
Mineral Products,
Mineral Products,
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying
Stone Quarrying-
Stone Quarrying-
Processing (See
Processing (See
Stone Quarrying-
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Stone Quarrying
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
-	Processing (See also 305320), Primary Crushing
Processing, Secondary Crushing/Screening
Processing, Tertiary Crushing/Screening
also 305320), Recrushing/Screening
also 305320), Fines Mill
Processing (See 305320), Misc. Operations
also 305320), Open Storage
also 305320), Cut Stone: General
also 305320), Blasting: General
also 305320), Drilling
also 305320), Hauling
-	Processing (See also 305320), Drying
also 305320), Bar Grizzlies
also 305320), Shaker Screens
also 305320), Vibrating Screens
also 305320), Pugmill
also 305320), Drilling
also 305320), Truck Unloading
also 305320), Truck Loading: Front End Loader
also 305320), Not Classified **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	20
Wastewater treatment 1.5
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Materials handling operations including crushing, grinding, and screening, can produce significant
PM emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply. Fugitive dust emissions may come
from paved and unpaved roads in plants and from raw material and product loading, unloading, and
storage (STAPPA/ALAPCO, 1996).
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wire-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, "Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options", Washington, DC, July 1996.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Stone Quarrying and Processing
Control Measure Name: Paper/Nonwoven Filters - Cartridge Collector Type
Rule Name: Not Applicable
Pechan Measure Code: P2205
POD: 220
Application: This control is the use of paper or non-woven filters (cartridge collector type) to reduce
PM emissions. The waste gas stream is passed through the fibrous filter media
causing PM in the gas stream to be collected on the media by sieving and other
mechanisms.
This control measure applies to stone quarrying and processing operations.
Nonmetallic mineral processing (305020) operations include, but are not limited to, ore
crushing, grinding, and screening, and calciners (SCC 305150) and dryers (SCC
30502012).
Affected SCC:
30502001
30502002
30502003
30502004
30502005
30502006
30502007
30502008
30502009
30502010
30502011
30502012
30502013
30502014
30502015
30502017
30502020
30502031
30502033
30502099
Mineral Products,
Mineral Products,
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying
Stone Quarrying-
Stone Quarrying-
Processing (See
Processing (See
Stone Quarrying-
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Stone Quarrying
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
-	Processing (See also 305320), Primary Crushing
Processing, Secondary Crushing/Screening
Processing, Tertiary Crushing/Screening
also 305320), Recrushing/Screening
also 305320), Fines Mill
Processing (See 305320), Misc. Operations
also 305320), Open Storage
also 305320), Cut Stone: General
also 305320), Blasting: General
also 305320), Drilling
also 305320), Hauling
-	Processing (See also 305320), Drying
also 305320), Bar Grizzlies
also 305320), Shaker Screens
also 305320), Vibrating Screens
also 305320), Pugmill
also 305320), Drilling
also 305320), Truck Unloading
also 305320), Truck Loading: Front End Loader
also 305320), Not Classified **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are generated using EPA's cost-estimating spreadsheets for fabric filters
(EPA, 1998a). Costs are primarily driven by the waste stream volumetric flow rate
and pollutant loading. When stack gas flow rate data was available, the costs and
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AT-A-GLANCE TABLE FOR POINT SOURCES
cost effectiveness were calculated using the typical values of capital and O&M costs.
When stack gas flow rate data was not available, default typical capital and O&M cost
values based on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $7 to $13 per scfm
Typical value is $9 per scfm
O&M Costs:
Range from $9 to $25 per scfm
Typical value is $14 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average cartridge cost was estimated using the costs for standard
cartridge types. Capital recovery for the periodic replacement of cartridges was
included in the O&M cost of the cartridges using a cartridge life of 2 years (EPA,
1998a). The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal 25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $85 to $256 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $142 per ton PM10 reduced.
(1998$)
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AT-A-GLANCE TABLE FOR POINT SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Materials handling operations including crushing, grinding, and screening, can produce significant
PM emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply. Fugitive dust emissions may come
from paved and unpaved roads in plants and from raw material and product loading, unloading, and
storage (STAPPA/ALAPCO, 1996).
The cost estimates assume a conventional design under typical operating conditions. Auxiliary
equipment, such as fans and ductwork, is not included (EPA, 2000). Pollutants that require an
unusually high level of control or that require the filter media or the unit itself to be constructed of
special materials, such as Nomex ® or stainless steel, will increase the costs of the system (EPA,
1998a). The additional costs for controlling more complex waste streams are not reflected in the
estimates given below. For these types of systems, the capital cost could increase by as much as
75% and the O&M cost could increase by as much as 10%. In general, a small unit controlling a low
pollutant loading will not be as cost effective as a large unit controlling a high pollutant loading (EPA,
2000).
Cartridge filters contain either a paper or nonwoven fibrous filter media (EPA, 2000). Paper media is
generally made of materials such as cellulose and fiberglass. The dust cake that forms on the filter
media from the collected PM can significantly increase collection efficiency (EPA, 1998b).
In general, the filter media is pleated to provide a larger surface area to volume flow rate. Close
pleating, however, can cause PM to bridge the pleat bottom, effectively reducing the surface
collection area (EPA, 1998b). Corrugated aluminum separators are used to prevent the pleats from
collapsing (Heumann, 1997). There are variety of cartridge designs and dimensions. Typical
designs include flat panels, V-shaped packs or cylindrical packs (Heumann, 1997). For certain
applications, two cartridges may be placed in series.
Cartridge collectors are useful for collecting particles with resistivities either too low or too high for
collection with electrostatic precipitators (STAPPA/AI_APCO, 1996). For similar air flow rates,
cartridge collectors are compact in size compared to traditional bag
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Cartridge Collector with Pulse-Jet Cleaning," April 2000.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
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Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators and
Association of Local Air Pollution Control Officials, "Controlling Particulate Matter Under the
Clean Air Act: A Menu of Options," July 1996.
STAPPA/ALAPCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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Source Category: Mineral Products - Stone Quarrying and Processing
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2206
POD: 220
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to ferroalloy production operations, including (but not limited to)
nonmetallic mineral processing (305020) - ore crushing, grinding, and screening, and
calciners (SCC 305150) and dryers (SCC 30502012). Materials handling operations
including crushing, grinding, and screening, can produce significant PM emissions.
Affected SCC:
30502001
30502002
30502003
30502004
30502005
30502006
30502007
30502008
30502009
30502010
30502011
30502012
30502013
30502014
30502015
30502017
30502020
30502031
30502033
30502099
Mineral Products,
Mineral Products,
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying
Stone Quarrying-
Stone Quarrying-
Processing (See
Processing (See
Stone Quarrying-
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Stone Quarrying
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
-	Processing (See also 305320), Primary Crushing
Processing, Secondary Crushing/Screening
Processing, Tertiary Crushing/Screening
also 305320), Recrushing/Screening
also 305320), Fines Mill
Processing (See 305320), Misc. Operations
also 305320), Open Storage
also 305320), Cut Stone: General
also 305320), Blasting: General
also 305320), Drilling
also 305320), Hauling
-	Processing (See also 305320), Drying
also 305320), Bar Grizzlies
also 305320), Shaker Screens
also 305320), Vibrating Screens
also 305320), Pugmill
also 305320), Drilling
also 305320), Truck Unloading
also 305320), Truck Loading: Front End Loader
also 305320), Not Classified **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
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Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price	0.0671 $/kW-hr
Compressed air	0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
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ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Drying, the heating of minerals or mineral products to remove water, and calcination, heating to
higher temperatures to remove chemically bound water and other compounds, are normally
performed in dedicated, closed units. Emissions from these units will be through process vents, to
which PM controls can be applied relatively simply. Fugitive dust emissions may come from paved
and unpaved roads in plants and from raw material and product loading, unloading, and storage
(STAPPA/ALAPCO, 1996)..
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
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AT-A-GLANCE TABLE FOR POINT SOURCES
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options, Washington, DC, July 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products - Stone Quarrying and Processing
Control Measure Name: Venturi Scrubber
Rule Name: Not Applicable
Pechan Measure Code: P2207
POD: 220
Application: The control is the use of a venturi scrubber to reduce PM emissions. A scrubber is a
type of technology that removes air pollutants by inertial and diffusional interception. A
venturi scrubber accelerates the waste gas stream to atomize the scrubbing liquid and
to improve gas-liquid contact.
This control applies to stone quarrying an processing operations, including (but not
limited to) nonmetallic mineral processing (305020) - ore crushing, grinding, and
screening, and calciners (SCC 305150) and dryers (SCC 30502012).
Affected SCC:
30502001
30502002
30502003
30502004
30502005
30502006
30502007
30502008
30502009
30502010
30502011
30502012
30502013
30502014
30502015
30502020
30502031
30502033
30502099
Mineral Products,
Mineral Products,
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Mineral Products,
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying -
Stone Quarrying
Stone Quarrying-
Stone Quarrying-
Processing (See
Processing (See
Stone Quarrying-
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Stone Quarrying
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
Processing (See
-	Processing (See also 305320), Primary Crushing
Processing, Secondary Crushing/Screening
Processing, Tertiary Crushing/Screening
also 305320), Recrushing/Screening
also 305320), Fines Mill
Processing (See 305320), Misc. Operations
also 305320), Open Storage
also 305320), Cut Stone: General
also 305320), Blasting: General
also 305320), Drilling
also 305320), Hauling
-	Processing (See also 305320), Drying
also 305320), Bar Grizzlies
also 305320), Shaker Screens
also 305320), Vibrating Screens
also 305320), Drilling
also 305320), Truck Unloading
also 305320), Truck Loading: Front End Loader
also 305320), Not Classified **
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 95% from uncontrolled; PM2.5 control efficiency is
90% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for venturi wet scrubbers, developed using EPA cost-
estimating spreadsheets (EPA, 1996) and referenced to the volumetric flow rate of
the waste stream treated. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
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costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (10 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $3 to $28 per scfm
Typical value is $11 per scfm
O&M Costs:
Range from $4 to $119 per scfm
Typical value is $42 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for Impingement Plate
Scrubbers (EPA, 1996). O&M costs were calculated for two model plants with flow
rates of 2,000 and 150,000 acfm. The average percentage of the total O&M cost was
then calculated for each O&M cost component. The model plants were assumed to
have a dust loading of 3.0 grains per cubic feet. The operating time was assumed to
be 8760 hours per year. An inlet water flow rate for the scrubber was assumed to be
9.4 Ibs/min. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	25
Wastewater treatment 3.8
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $76 to $2,100
per ton PM10 removed, depending on stack flow. The default cost
effectiveness value, used when stack flow is not available, is $751 per ton
PM10 reduced. (1995$)
Comments:
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Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Materials handling operations including crushing, grinding, and screening, can produce significant
PM emissions. Drying, the heating of minerals or mineral products to remove water, and calcination,
heating to higher temperatures to remove chemically bound water and other compounds, are
normally performed in dedicated, closed units. Emissions from these units will be through process
vents, to which PM controls can be applied relatively simply. Fugitive dust emissions may come
from paved and unpaved roads in plants and from raw material and product loading, unloading, and
storage (STAPPA/ALAPCO, 1996).
The costs do not include costs for post-treatment or disposal of used solvent or waste. Actual costs
can be substantially higher than in the ranges shown for applications which require expensive
materials, solvents, or treatment methods (EPA, 1999). As a rule, smaller units controlling a low
concentration waste stream will be much more expensive (per unit volumetric flow rate) than a large
unit cleaning a high pollutant load flow.
By product coke production is used to manufacture metallurgical coke by heating high-grade
bituminous coal (low sulfur and low ash) in an enclosed oven chamber without oxygen. The
resulting solid material consists of elemental carbon and any minerals (ash) that were present in the
coal blend that did not volatilize during the process. Sources of air emissions consist of coke oven
doors, coke oven lids and off-takes, coke oven charging, coke oven pushing, coke oven underfire
stack, coke quenching, battery venting, and coke by-product-recovery plants.
A venturi scrubber accelerates the waste gas stream to improve gas-liquid contact. In a venturi
scrubber, a "throat"' section is built into the duct that forces the gas stream to accelerate (EPA,
1999). As the gas enters the venturi throat, both gas velocity and turbulence increase.
After the throat section, the mixture decelerates, and further impacts occur causing the droplets to
agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid
are separated from the gas stream through entrainment. This section usually consists of a cyclonic
separator and/or a mist eliminator (EPA, 1998; Corbitt, 1990).
For PM applications, wet scrubbers generate waste, either a slurry or wet sludge. This creates the
need for both wastewater treatment and solid waste disposal. Initially, the slurry is treated to
separate the solid waste from the water (EPA, 1999). The treated water can then be reused or
discharged. Once the water is removed, the remaining waste will be in the form of a solid or sludge.
If the solid waste is inert and nontoxic, it can generally be land filled. Hazardous wastes will have
more stringent procedures for disposal. In some cases, the solid waste may have value and can be
sold or recycled (EPA, 1998).
References:
Corbitt, 1990: "Standard Handbook of Environmental Engineering," edited by Robert A. Corbitt,
McGraw-Hill, New York, NY, 1990.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC
February.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
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EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Venturi Scrubber," July 1999.
Heumann, 1997: W. L. Heumann, "Industrial Air Pollution Control Systems," McGraw Hill
Publishers, Inc., Washington, D.C., 1997.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
STAPPA/AI_APCO, 1996: State and Territorial Air Pollution Program Administrators - Association of
Local Air Pollution Control Officials, "Controlling Particulate Matter Under the Clean Air Act: A Menu
of Options," Washington, DC, July 1996.
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Source Category: Municipal Waste Incineration
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2261	POD: 226
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to municipal waste incineration operations classified under SCCs:
50100101,
50100102,	50100103, 50100105, and 50100107.
Affected SCC:
50100101	Solid Waste Disposal-Gov't, Municipal Incineration, Starved Air-Multiple Chamber
50100102	Municipal Incineration, Mass Burn: Single Chamber
50100103	Municipal Incineration, Refuse Derived Fuel
50100105 Municipal Incineration, Mass Burn Waterwall Combustor
50100107 Municipal Incineration, Modular Excess Air Combustor
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V







V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
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were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal 25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
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main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Aluminum
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2111	POD: 211
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to aluminum processing and production operations.
Affected SCC:
30300001	Aluminum Ore (Bauxite), Crushing/Handling
30300002	Aluminum Ore (Bauxite), Drying Oven
30300003	Aluminum Ore (Bauxite), Fine Ore Storage
30300101	Primary Metal Production, Aluminum Ore (Electro-reduction), Prebaked Reduction Cell
30300102	Aluminum Ore (Electro-reduction), Horizontal Stud Soderberg Cell
30300103	Aluminum Ore (Electro-reduction), Vertical Stud Soderberg Cell
30300104	Primary Metal Production, Aluminum Ore (Electro-reduction), Materials Handling
30300105	Primary Metal Production, Aluminum Ore (Electro-reduction), Anode Baking Furnace
30300106	Aluminum Ore (Electro-reduction), Degassing
30300107	Aluminum Ore (Electro-reduction), Roof Vents
30300108	Aluminum Ore (Electro-reduction), Prebake: Fugitive Emissions
30300109	Aluminum Ore (Electro-reduction), H.S.S.: Fugitive Emissions
30300110	Aluminum Ore (Electro-reduction), V.S.S.: Fugitive Emissions
30300199 Aluminum Ore (Electro-reduction), Not Classified **
30300201 Aluminum Hydroxide Calcining, Overall Process
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
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capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000).. Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Aluminum
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2112	POD: 211
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to aluminum processing operations.
Affected SCC:
30300001	Aluminum Ore (Bauxite), Crushing/Handling
30300002	Aluminum Ore (Bauxite), Drying Oven
30300003	Aluminum Ore (Bauxite), Fine Ore Storage
30300101	Primary Metal Production, Aluminum Ore (Electro-reduction), Prebaked Reduction Cell
30300102	Aluminum Ore (Electro-reduction), Horizontal Stud Soderberg Cell
30300103	Aluminum Ore (Electro-reduction), Vertical Stud Soderberg Cell
30300104	Primary Metal Production, Aluminum Ore (Electro-reduction), Materials Handling
30300105	Primary Metal Production, Aluminum Ore (Electro-reduction), Anode Baking Furnace
30300106	Aluminum Ore (Electro-reduction), Degassing
30300107	Aluminum Ore (Electro-reduction), Roof Vents
30300108	Aluminum Ore (Electro-reduction), Prebake: Fugitive Emissions
30300109	Aluminum Ore (Electro-reduction), H.S.S.: Fugitive Emissions
30300110	Aluminum Ore (Electro-reduction), V.S.S.: Fugitive Emissions
30300199 Aluminum Ore (Electro-reduction), Not Classified **
30300201 Aluminum Hydroxide Calcining, Overall Process
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
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capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The costs for ESPs of conventional design under typical operating conditions are developed using
EPA cost estimating spreadsheets (EPA, 1996). When stack gas flow rate data was available, the
costs and cost effectiveness were calculated using the typical values of capital and O&M costs.
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When stack gas flow rate data was not available, default typical capital and O&M cost values based
on a tons per year of PM10 removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed capital recovery
charges, and a fixed annual charge for taxes, insurance and administrative costs. The fixed annual
charge for taxes, insurance and administrative costs was estimated as 4 percent of the total capital
investment (EPA, 1990). Total installed capital costs were annualized using a capital recovery
factor, with is based on a 7 percent discount rate and the expected life of the control equipment (20
years) (Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets were calculated
based on the OAQPS Control Cost Manual and associated spreadsheets (EPA, 1996). The low
costs in the ranges below are representative of equipment sized based on the maximum flow rate
recommended in the cost manual, with no exotic materials. The high costs in the ranges below are
representative of equipment sized based on the minimum flow rate recommended in the cost
manual, with not exotic materials. No optional pre- or post treatment equipment costs are included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
Note: All costs are in 1995 dollars.
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Aluminum
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2113	POD: 211
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to aluminum processing and production operations.
Affected SCC:
30300001	Aluminum Ore (Bauxite), Crushing/Handling
30300002	Aluminum Ore (Bauxite), Drying Oven
30300003	Aluminum Ore (Bauxite), Fine Ore Storage
30300101	Primary Metal Production, Aluminum Ore (Electro-reduction), Prebaked Reduction Cell
30300102	Aluminum Ore (Electro-reduction), Horizontal Stud Soderberg Cell
30300103	Aluminum Ore (Electro-reduction), Vertical Stud Soderberg Cell
30300104	Primary Metal Production, Aluminum Ore (Electro-reduction), Materials Handling
30300105	Primary Metal Production, Aluminum Ore (Electro-reduction), Anode Baking Furnace
30300106	Aluminum Ore (Electro-reduction), Degassing
30300107	Aluminum Ore (Electro-reduction), Roof Vents
30300108	Aluminum Ore (Electro-reduction), Prebake: Fugitive Emissions
30300109	Aluminum Ore (Electro-reduction), H.S.S.: Fugitive Emissions
30300110	Aluminum Ore (Electro-reduction), V.S.S.: Fugitive Emissions
30300199 Aluminum Ore (Electro-reduction), Not Classified **
30300201 Aluminum Hydroxide Calcining, Overall Process
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
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(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067 $/kW-hr
Process water price 0.20 $/1000gal
Dust disposal	20 $/ton disposed
Wastewater treatment 1.5 $/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wire-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
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Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Aluminum
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2114	POD: 211
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to aluminum processing and production operations.
Affected SCC:
30300001	Aluminum Ore (Bauxite), Crushing/Handling
30300002	Aluminum Ore (Bauxite), Drying Oven
30300003	Aluminum Ore (Bauxite), Fine Ore Storage
30300101	Primary Metal Production, Aluminum Ore (Electro-reduction), Prebaked Reduction Cell
30300102	Aluminum Ore (Electro-reduction), Horizontal Stud Soderberg Cell
30300103	Aluminum Ore (Electro-reduction), Vertical Stud Soderberg Cell
30300104	Primary Metal Production, Aluminum Ore (Electro-reduction), Materials Handling
30300105	Primary Metal Production, Aluminum Ore (Electro-reduction), Anode Baking Furnace
30300106	Aluminum Ore (Electro-reduction), Degassing
30300107	Aluminum Ore (Electro-reduction), Roof Vents
30300108	Aluminum Ore (Electro-reduction), Prebake: Fugitive Emissions
30300109	Aluminum Ore (Electro-reduction), H.S.S.: Fugitive Emissions
30300110	Aluminum Ore (Electro-reduction), V.S.S.: Fugitive Emissions
30300199 Aluminum Ore (Electro-reduction), Not Classified **
30300201 Aluminum Hydroxide Calcining, Overall Process
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
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administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
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and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Aluminum
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3211	POD: 211
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303000** Primary Metal Production, Aluminum Ore (Bauxite)
303001** Primary Metal Production, Aluminum Ore (Electro-reduction)
303002** Aluminum Hydroxide Calcining
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Aluminum
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4211	POD: 211
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303000** Primary Metal Production, Aluminum Ore (Bauxite)
303001** Primary Metal Production, Aluminum Ore (Electro-reduction)
303002** Aluminum Hydroxide Calcining
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Note: All costs are in 2003 dollars.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Non-Ferrous Metals Processing - Copper
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2081
POD: 208
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to copper and copper alloy production operations.
Affected SCC:
30300502	Primary Copper Smelting, Multiple Hearth Roaster
30300503	Primary Copper Smelting, Reverberatory Smelting Furnace after Roaster
30300504	Primary Copper Smelting, Converter (All Configurations)
30300505	Primary Copper Smelting, Fire (Furnace) Refining
30300506	Primary Copper Smelting, Ore Concentrate Dryer
30300512 Primary Copper Smelting, Flash Smelting
30300515	Primary Copper Smelting, Converter: Fugitive Emissions
30300516	Primary Copper Smelting, Anode Refining Furnace: Fugitive Emissions
30300519 Primary Copper Smelting, Unpaved Road Traffic: Fugitive Emissions
30300522 Primary Copper Smelting, Slag Cleaning Furnace
30300527 Primary Copper Smelting, Dryer with Flash Furnace and Converter
30300534 Primary Copper Smelting, Flash Furnace After Concentrate Dryer
30300599 Primary Copper Smelting, Other Not Classified
30400208 Copper, Wire Burning: Incinerator
30400210 Copper, Charge with Scrap Copper: Cupolas
30400214	Copper, Charge with Copper: Reverberatory Furnace
30400215	Copper, Charge with Brass and Bronze: Reverberatory Furnace
30400217 Copper, Charge with Brass and Bronze: Rotary Furnace
30400219	Copper, Charge with Brass and Bronze: Crucible and Pot Furnace
30400220	Secondary Metal Production, Copper, Charge with Copper: Electric Arc Furnace
30400223	Copper, Charge with Copper: Electric Induction
30400224	Copper, Charge with Brass and Bronze: Electric Induction
30400231	Copper, Scrap Dryer
30400232	Copper, Wire Incinerator
30400235	Copper, Reverberatory Furnace
30400236	Copper, Rotary Furnace
30400239 Copper, Casting Operations
30400299 Secondary Metal Production, Copper, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
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AT-A-GLANCE TABLE FOR POINT SOURCES
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
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AT-A-GLANCE TABLE FOR POINT SOURCES
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
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EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Copper
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2082
POD: 208
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESOPs, the collectors
are knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to copper and copper-allow metal processing operations.
Affected SCC:
30300502	Primary Copper Smelting, Multiple Hearth Roaster
30300503	Primary Copper Smelting, Reverberatory Smelting Furnace after Roaster
30300504	Primary Copper Smelting, Converter (All Configurations)
30300505	Primary Copper Smelting, Fire (Furnace) Refining
30300506	Primary Copper Smelting, Ore Concentrate Dryer
30300512 Primary Copper Smelting, Flash Smelting
30300515	Primary Copper Smelting, Converter: Fugitive Emissions
30300516	Primary Copper Smelting, Anode Refining Furnace: Fugitive Emissions
30300519 Primary Copper Smelting, Unpaved Road Traffic: Fugitive Emissions
30300522 Primary Copper Smelting, Slag Cleaning Furnace
30300527 Primary Copper Smelting, Dryer with Flash Furnace and Converter
30300534 Primary Copper Smelting, Flash Furnace After Concentrate Dryer
30300599 Primary Copper Smelting, Other Not Classified
30400210 Copper, Charge with Scrap Copper: Cupolas
30400214	Copper, Charge with Copper: Reverberatory Furnace
30400215	Copper, Charge with Brass and Bronze: Reverberatory Furnace
30400217 Copper, Charge with Brass and Bronze: Rotary Furnace
30400219 Copper, Charge with Brass and Bronze: Crucible and Pot Furnace
30400223	Copper, Charge with Copper: Electric Induction
30400224	Copper, Charge with Brass and Bronze: Electric Induction
30400231	Copper, Scrap Dryer
30400232	Copper, Wire Incinerator
30400235	Copper, Reverberatory Furnace
30400236	Copper, Rotary Furnace
30400239 Copper, Casting Operations
30400299 Secondary Metal Production, Copper, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
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Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
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ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Copper
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2083
POD: 208
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to copper and copper alloy processing and production operations.
Affected SCC:
30300502	Primary Copper Smelting, Multiple Hearth Roaster
30300503	Primary Copper Smelting, Reverberatory Smelting Furnace after Roaster
30300504	Primary Copper Smelting, Converter (All Configurations)
30300505	Primary Copper Smelting, Fire (Furnace) Refining
30300506	Primary Copper Smelting, Ore Concentrate Dryer
30300512 Primary Copper Smelting, Flash Smelting
30300515	Primary Copper Smelting, Converter: Fugitive Emissions
30300516	Primary Copper Smelting, Anode Refining Furnace: Fugitive Emissions
30300519 Primary Copper Smelting, Unpaved Road Traffic: Fugitive Emissions
30300522 Primary Copper Smelting, Slag Cleaning Furnace
30300527 Primary Copper Smelting, Dryer with Flash Furnace and Converter
30300534 Primary Copper Smelting, Flash Furnace After Concentrate Dryer
30300599 Primary Copper Smelting, Other Not Classified
30400208 Copper, Wre Burning: Incinerator
30400210 Copper, Charge with Scrap Copper: Cupolas
30400214	Copper, Charge with Copper: Reverberatory Furnace
30400215	Copper, Charge with Brass and Bronze: Reverberatory Furnace
30400217 Copper, Charge with Brass and Bronze: Rotary Furnace
30400219	Copper, Charge with Brass and Bronze: Crucible and Pot Furnace
30400220	Secondary Metal Production, Copper, Charge with Copper: Electric Arc Furnace
30400223	Copper, Charge with Copper: Electric Induction
30400224	Copper, Charge with Brass and Bronze: Electric Induction
30400231	Copper, Scrap Dryer
30400232	Copper, Wre Incinerator
30400235	Copper, Reverberatory Furnace
30400236	Copper, Rotary Furnace
30400239 Copper, Casting Operations
30400299 Secondary Metal Production, Copper, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
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Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price	0.067 $/kW-hr
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Process water price 0.20 $/1000gal
Dust disposal	20 $/ton disposed
Wastewater treatment 1.5 $/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wre-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
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References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Copper
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2084
POD: 208
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to copper and copper alloy production operations.
Affected SCC:
30300502	Primary Copper Smelting, Multiple Hearth Roaster
30300503	Primary Copper Smelting, Reverberatory Smelting Furnace after Roaster
30300504	Primary Copper Smelting, Converter (All Configurations)
30300505	Primary Copper Smelting, Fire (Furnace) Refining
30300506	Primary Copper Smelting, Ore Concentrate Dryer
30300512 Primary Copper Smelting, Flash Smelting
30300515	Primary Copper Smelting, Converter: Fugitive Emissions
30300516	Primary Copper Smelting, Anode Refining Furnace: Fugitive Emissions
30300519 Primary Copper Smelting, Unpaved Road Traffic: Fugitive Emissions
30300522 Primary Copper Smelting, Slag Cleaning Furnace
30300527 Primary Copper Smelting, Dryer with Flash Furnace and Converter
30300534 Primary Copper Smelting, Flash Furnace After Concentrate Dryer
30300599 Primary Copper Smelting, Other Not Classified
30400208 Copper, Wire Burning: Incinerator
30400210 Copper, Charge with Scrap Copper: Cupolas
30400214	Copper, Charge with Copper: Reverberatory Furnace
30400215	Copper, Charge with Brass and Bronze: Reverberatory Furnace
30400217 Copper, Charge with Brass and Bronze: Rotary Furnace
30400219	Copper, Charge with Brass and Bronze: Crucible and Pot Furnace
30400220	Secondary Metal Production, Copper, Charge with Copper: Electric Arc Furnace
30400223	Copper, Charge with Copper: Electric Induction
30400224	Copper, Charge with Brass and Bronze: Electric Induction
30400231	Copper, Scrap Dryer
30400232	Copper, Wire Incinerator
30400235	Copper, Reverberatory Furnace
30400236	Copper, Rotary Furnace
30400239 Copper, Casting Operations
30400299 Secondary Metal Production, Copper, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
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Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25	$/1000scf
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Dust disposal 25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
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precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Copper
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3208	POD: 208
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303005** Primary Copper Smelting
304002** Copper, Wire Burning
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Non-Ferrous Metals Processing - Copper
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4208	POD: 208
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303005** Primary Copper Smelting
304002** Copper, Wire Burning
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Non-Ferrous Metals Processing - Lead
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2091
POD: 209
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies lead production operations.
Affected SCC:
30301002
30301004
30301005
30301009
30301010
30301012
30301013
30301017
30301020
30301022
30301024
30301025
30301099
30400401
30400402
30400403
30400413
30400499
Lead Production, Blast Furnace Operation
Lead Production, Ore Crushing
Lead Production, Materials Handling (Includes 11, 12, 13, 04, 14)
Lead Production, Lead Drossing
Lead Production, Raw Material Crushing and Grinding
Lead Production, Raw Material Storage Piles
Lead Production, Raw Material Transfer
Lead Production, Sinter Fines Return Handling
Lead Production, Blast Furnace Lead Pouring
Lead Production, Lead Refining/Silver Retort
Lead Production, Reverberatory or Kettle Softening
Lead Production, Sinter Machine Leakage
Lead Production, Other Not Classified
Lead, Pot Furnace
Lead, Reverberatory Furnace
Lead, Blast Furnace (Cupola)
Lead, Smelting Furnace: Fugitive Emissions
Lead, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
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removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
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Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Lead
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2092	POD: 209
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to lead processing operations.
Affected SCC:
30301002 Lead Production, Blast Furnace Operation
30301004	Lead Production, Ore Crushing
30301005	Lead Production, Materials Handling (Includes 11, 12, 13, 04, 14)
30301009 Lead Production, Lead Drossing
30301012	Lead Production, Raw Material Storage Piles
30301013	Lead Production, Raw Material Transfer
30301017 Lead Production, Sinter Fines Return Handling
30301020 Lead Production, Blast Furnace Lead Pouring
30301022 Lead Production, Lead Refining/Silver Retort
30301024	Lead Production, Reverberatory or Kettle Softening
30301025	Lead Production, Sinter Machine Leakage
30301099 Lead Production, Other Not Classified
30400401	Lead, Pot Furnace
30400402	Lead, Reverberatory Furnace
30400403	Lead, Blast Furnace (Cupola)
30400413 Lead, Smelting Furnace: Fugitive Emissions
30400499 Lead, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Lead
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2093	POD: 209
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to lead processing and production operations.
Affected SCC:
30301002 Lead Production, Blast Furnace Operation
30301004	Lead Production, Ore Crushing
30301005	Lead Production, Materials Handling (Includes 11, 12, 13, 04, 14)
30301009	Lead Production, Lead Drossing
30301010	Lead Production, Raw Material Crushing and Grinding
30301012	Lead Production, Raw Material Storage Piles
30301013	Lead Production, Raw Material Transfer
30301017 Lead Production, Sinter Fines Return Handling
30301020 Lead Production, Blast Furnace Lead Pouring
30301022 Lead Production, Lead Refining/Silver Retort
30301024	Lead Production, Reverberatory or Kettle Softening
30301025	Lead Production, Sinter Machine Leakage
30301099 Lead Production, Other Not Classified
30400401	Lead, Pot Furnace
30400402	Lead, Reverberatory Furnace
30400403	Lead, Blast Furnace (Cupola)
30400413 Lead, Smelting Furnace: Fugitive Emissions
30400499 Lead, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
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and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	20
Wastewater treatment 1.5
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
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Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wire-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
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Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Lead
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2094	POD: 209
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to lead processing and production applications.
Affected SCC:
30301002 Lead Production, Blast Furnace Operation
30301004	Lead Production, Ore Crushing
30301005	Lead Production, Materials Handling (Includes 11, 12, 13, 04, 14)
30301009	Lead Production, Lead Drossing
30301010	Lead Production, Raw Material Crushing and Grinding
30301012	Lead Production, Raw Material Storage Piles
30301013	Lead Production, Raw Material Transfer
30301017 Lead Production, Sinter Fines Return Handling
30301020 Lead Production, Blast Furnace Lead Pouring
30301022 Lead Production, Lead Refining/Silver Retort
30301024	Lead Production, Reverberatory or Kettle Softening
30301025	Lead Production, Sinter Machine Leakage
30301099 Lead Production, Other Not Classified
30400401	Lead, Pot Furnace
30400402	Lead, Reverberatory Furnace
30400403	Lead, Blast Furnace (Cupola)
30400413 Lead, Smelting Furnace: Fugitive Emissions
30400499 Lead, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
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Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
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Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Lead
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3209	POD: 209
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303010** Lead Production
304004** Zinc Production
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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Source Category: Non-Ferrous Metals Processing - Lead
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4209	POD: 209
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
303010** Primary Metal Production, Lead Production
304004** Primary Metal Production, Zinc Production
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Non-Ferrous Metals Processing - Other
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2121	POD: 212
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to miscellaneous non-ferrous metals processing operations,
including molybdenum, titanium, gold, barium ore, lead battery, magnesium, nickel,
electrode manufacture and metal heat treating operations.
Affected SCC:
30301102 Molybdenum, Milling: General
30301199 Molybdenum, Other Not Classified
30301201	Primary Metal Production, Titanium, Chlorination
30301202	Titanium, Drying Titanium Sand Ore (Cyclone Exit)
30301299 Titanium, Other Not Classified
30301301 Gold, General Processes
30301401 Barium Ore Processing, Ore Grinding
30301403 Barium Ore Processing, Dryers/Calciners
30301499 Barium Ore Processing, Other Not Classified
30400506	Lead Battery Manufacture, Grid Casting
30400507	Lead Battery Manufacture, Paste Mixing
30400512 Lead Battery Manufacture, Formation
30400523 Lead Battery Manufacture, Paste Mixing
30400525 Lead Battery Manufacture, Three Process Operation
30400650 Magnesium, American Magnesium Process
30400699 Magnesium, Other Not Classified
30401010 Nickel, Finishing: Pickling/Neutralizing
30401099 Nickel, Other Not Classified
30402001	Furnace Electrode Manufacture, Calcination
30402002	Furnace Electrode Manufacture, Mixing
30402004	Furnace Electrode Manufacture, Bake Furnaces
30402005	Furnace Electrode Manufacture, Grafitization of Coal by Heating Process
30402099 Furnace Electrode Manufacture, Other Not Classified
30402201 Metal Heat Treating, Furnace: General
30402211 Metal Heat Treating, Quenching
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
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Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
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Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
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EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Other
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2122	POD: 212
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to miscellaneous non-ferrous metals processing operations,
including molybdenum, titanium, gold, barium ore, lead battery, magnesium, nickel,
electrode manufacture and metal heat treating operations.
Affected SCC:
30301102 Molybdenum, Milling: General
30301199 Molybdenum, Other Not Classified
30301201	Primary Metal Production, Titanium, Chlorination
30301202	Titanium, Drying Titanium Sand Ore (Cyclone Exit)
30301299 Titanium, Other Not Classified
30301301 Gold, General Processes
30301401 Barium Ore Processing, Ore Grinding
30301403 Barium Ore Processing, Dryers/Calciners
30301499 Barium Ore Processing, Other Not Classified
30400506 Lead Battery Manufacture, Grid Casting
30400512 Lead Battery Manufacture, Formation
30400525 Lead Battery Manufacture, Three Process Operation
30400650 Magnesium, American Magnesium Process
30400699 Magnesium, Other Not Classified
30401010 Nickel, Finishing: Pickling/Neutralizing
30401099 Nickel, Other Not Classified
30402001	Furnace Electrode Manufacture, Calcination
30402002	Furnace Electrode Manufacture, Mixing
30402004	Furnace Electrode Manufacture, Bake Furnaces
30402005	Furnace Electrode Manufacture, Grafitization of Coal by Heating Process
30402099 Furnace Electrode Manufacture, Other Not Classified
30402201 Metal Heat Treating, Furnace: General
30402211 Metal Heat Treating, Quenching
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
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AT-A-GLANCE TABLE FOR POINT SOURCES
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal	25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
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value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Other
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2123	POD: 212
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to miscellaneous non-ferrous metals processing operations,
including molybdenum, titanium, gold, barium ore, lead battery, magnesium, nickel,
electrode manufacture and metal heat treating operations.
Affected SCC:
30301102 Molybdenum, Milling: General
30301199 Molybdenum, Other Not Classified
30301201	Primary Metal Production, Titanium, Chlorination
30301202	Titanium, Drying Titanium Sand Ore (Cyclone Exit)
30301299 Titanium, Other Not Classified
30301301 Gold, General Processes
30301401 Barium Ore Processing, Ore Grinding
30301403 Barium Ore Processing, Dryers/Calciners
30301499 Barium Ore Processing, Other Not Classified
30400506	Lead Battery Manufacture, Grid Casting
30400507	Lead Battery Manufacture, Paste Mixing
30400512 Lead Battery Manufacture, Formation
30400523 Lead Battery Manufacture, Paste Mixing
30400525 Lead Battery Manufacture, Three Process Operation
30400650 Magnesium, American Magnesium Process
30400699 Magnesium, Other Not Classified
30401010 Nickel, Finishing: Pickling/Neutralizing
30401099 Nickel, Other Not Classified
30402001	Furnace Electrode Manufacture, Calcination
30402002	Furnace Electrode Manufacture, Mixing
30402004	Furnace Electrode Manufacture, Bake Furnaces
30402005	Furnace Electrode Manufacture, Grafitization of Coal by Heating Process
30402099 Furnace Electrode Manufacture, Other Not Classified
30402201 Metal Heat Treating, Furnace: General
30402211 Metal Heat Treating, Quenching
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
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AT-A-GLANCE TABLE FOR POINT SOURCES
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price	0.067 $/kW-hr
Process water price 0.20 $/1000gal
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Dust disposal	20 $/ton disposed
Wastewater treatment 1.5 $/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wre-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Other
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2124	POD: 212
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to miscellaneous non-ferrous metals processing operations,
including molybdenum, titanium, gold, barium ore, lead battery, magnesium, nickel,
electrode manufacture and metal heat treating operations.
Affected SCC:
30301102 Molybdenum, Milling: General
30301199 Molybdenum, Other Not Classified
30301201	Primary Metal Production, Titanium, Chlorination
30301202	Titanium, Drying Titanium Sand Ore (Cyclone Exit)
30301299 Titanium, Other Not Classified
30301301 Gold, General Processes
30301401 Barium Ore Processing, Ore Grinding
30301403 Barium Ore Processing, Dryers/Calciners
30301499 Barium Ore Processing, Other Not Classified
30400506	Lead Battery Manufacture, Grid Casting
30400507	Lead Battery Manufacture, Paste Mixing
30400512 Lead Battery Manufacture, Formation
30400523 Lead Battery Manufacture, Paste Mixing
30400525 Lead Battery Manufacture, Three Process Operation
30400650 Magnesium, American Magnesium Process
30400699 Magnesium, Other Not Classified
30401010 Nickel, Finishing: Pickling/Neutralizing
30401099 Nickel, Other Not Classified
30402001	Furnace Electrode Manufacture, Calcination
30402002	Furnace Electrode Manufacture, Mixing
30402004	Furnace Electrode Manufacture, Bake Furnaces
30402005	Furnace Electrode Manufacture, Grafitization of Coal by Heating Process
30402099 Furnace Electrode Manufacture, Other Not Classified
30402201 Metal Heat Treating, Furnace: General
30402211 Metal Heat Treating, Quenching
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
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AT-A-GLANCE TABLE FOR POINT SOURCES
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25 $/ton disposed
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AT-A-GLANCE TABLE FOR POINT SOURCES
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Other
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3212	POD: 212
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
304010**
303888**
303014**
303013**
303012**
303011**
303999**
304001**
303900**
304006**
304020**
304022**
304050**
304888**
304900**
304999**
304005**
Nickel, Finishing
Primary Metal Production, Fugitive Emissions
Primary Metal Production, Barium Ore Processing
Primary Metal Production, Gold
Primary Metal Production, Titanium
Primary Metal Production, Molybdenum
Primary Metal Production, Other Not Classified
Secondary Metal Production, Aluminum
Primary Metal Production, Fuel Fired Equipment
Secondary Metal Production, Magnesium
Secondary Metal Production, Furnace Electrode Manufacture
Secondary Metal Production, Metal HeatTrating
Secondary Metal Production, Miscellaneous Casting and Fabricating
Secondary Metal Production, Fugitive emission
Secondary Metal Production, Fuel Fireed equipment
Secondary Metal Production, Other Not Classified
Secondary Metal Production, Lead Battery Manufacture
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
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AT-A-GLANCE TABLE FOR POINT SOURCES
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Other
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4212
POD: 212
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
304010**
303888**
303014**
303013**
303012**
303011**
303999**
304001**
303900**
304006**
304020**
304022**
304050**
304888**
304900**
304999**
304005**
Nickel, Finishing
Primary Metal Production, Fugitive Emissions
Primary Metal Production, Barium Ore Processing
Primary Metal Production, Gold
Primary Metal Production, Titanium
Primary Metal Production, Molybdenum
Primary Metal Production, Other Not Classified
Secondary Metal Production, Aluminum
Primary Metal Production, Fuel Fired Equipment
Secondary Metal Production, Magnesium
Secondary Metal Production, Furnace Electrode Manufacture
Secondary Metal Production, Metal HeatTrating
Secondary Metal Production, Miscellaneous Casting and Fabricating
Secondary Metal Production, Fugitive emission
Secondary Metal Production, Fuel Fireed equipment
Secondary Metal Production, Other Not Classified
Secondary Metal Production, Lead Battery Manufacture
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
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AT-A-GLANCE TABLE FOR POINT SOURCES
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Zinc
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: P2101	POD: 210
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions. In a fabric filter, flue gas is passed through a tightly woven or felted fabric,
collecting PM by sieving and other mechanisms. The gas stream is drawn from
beneath a cell plate in the floor and into the filter bags. The gas proceeds from the
inside to the outside of the filter bags. The particles collect on the inside of the bags,
forming a filter cake. In mechanical shaking units, the tops of bags are attached to a
shaker bar, moved briskly to clean the bags.
This control applies to zinc production and processing operations.
Affected SCC:
30303002	Zinc Production, Multiple Hearth Roaster
30303003	Zinc Production, Sinter Strand
30303005	Zinc Production, Vertical Retort/Electrothermal Furnace
30303006	Zinc Production, Electrolytic Processor
30303009 Zinc Production, Raw Material Handling and Transfer
30400801	Zinc, Retort Furnace
30400802	Zinc, Horizontal Muffle Furnace
30400803	Zinc, Pot Furnace
30400805 Zinc, Galvanizing Kettle
30400812 Zinc, Crushing/Screening of Zinc Residues
30400855 Zinc, Muffle Distillation/Oxidation
30400899 Zinc, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
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AT-A-GLANCE TABLE FOR POINT SOURCES
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the
O&M cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air	0.25 $/1000scf
Dust disposal	25 $/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
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AT-A-GLANCE TABLE FOR POINT SOURCES
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Zinc
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2102	POD: 210
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to zinc processing operations.
Affected SCC:
30303002	Zinc Production, Multiple Hearth Roaster
30303003	Zinc Production, Sinter Strand
30303005	Zinc Production, Vertical Retort/Electrothermal Furnace
30303006	Zinc Production, Electrolytic Processor
30400801	Zinc, Retort Furnace
30400802	Zinc, Horizontal Muffle Furnace
30400803	Zinc, Pot Furnace
30400805 Zinc, Galvanizing Kettle
30400855 Zinc, Muffle Distillation/Oxidation
30400899 Zinc, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
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(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal 25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
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AT-A-GLANCE TABLE FOR POINT SOURCES
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Zinc
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2103	POD: 210
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump.
This control applies to zinc processing and production operations.
Affected SCC:
30303002	Zinc Production, Multiple Hearth Roaster
30303003	Zinc Production, Sinter Strand
30303005	Zinc Production, Vertical Retort/Electrothermal Furnace
30303006	Zinc Production, Electrolytic Processor
30303009 Zinc Production, Raw Material Handling and Transfer
30400801	Zinc, Retort Furnace
30400802	Zinc, Horizontal Muffle Furnace
30400803	Zinc, Pot Furnace
30400805 Zinc, Galvanizing Kettle
30400812 Zinc, Crushing/Screening of Zinc Residues
30400855 Zinc, Muffle Distillation/Oxidation
30400899 Zinc, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
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capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price 0.067
Process water price 0.20
Dust disposal	20
Wastewater treatment 1.5
$/kW-hr
$/1000 gal
$/ton disposed
$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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Additional Information:
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wire-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
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Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Zinc
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: P2104	POD: 210
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams. In a fabric filter, flue gas is passed through a tightly woven or
felted fabric, collecting PM by sieving and other mechanisms. Reverse-air cleaning is
performed by forcing clean air through the filters in the opposite direction of the dusty
gas flow. The change in direction of the gas flow causes the bag to flex and crack the
filter cake allowing for internal cake collection.
This control applies to zinc processing and production operations.
Affected SCC:
30303002	Zinc Production, Multiple Hearth Roaster
30303003	Zinc Production, Sinter Strand
30303005	Zinc Production, Vertical Retort/Electrothermal Furnace
30303006	Zinc Production, Electrolytic Processor
30303009 Zinc Production, Raw Material Handling and Transfer
30400801	Zinc, Retort Furnace
30400802	Zinc, Horizontal Muffle Furnace
30400803	Zinc, Pot Furnace
30400805 Zinc, Galvanizing Kettle
30400812 Zinc, Crushing/Screening of Zinc Residues
30400855 Zinc, Muffle Distillation/Oxidation
30400899 Zinc, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
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AT-A-GLANCE TABLE FOR POINT SOURCES
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
O&M costs were calculated for three model plants with flow rates of 25, 75 and 150
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 4.0 grains per cubic feet. The operating time was assumed to be 8760
hours per year. An average bag cost was estimated using the costs for standard bag
types. Capital recovery for the periodic replacement of bags was included in the O&M
cost of the bags using a bag life of 2 years (EPA, 1998a). The following
assumptions apply to the cost of utilities and disposal:
Electricity price 0.0671 $/kW-hr
Compressed air 0.25 $/1000scf
Dust disposal	25	$/ton disposed
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
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AT-A-GLANCE TABLE FOR POINT SOURCES
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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Source Category: Non-Ferrous Metals Processing - Zinc
Control Measure Name: Increased Monitoring Frequency (IMF) of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P3210	POD: 210
Application: This measure is to conduct improved monitoring for PM2.5 emissions at stationary
sources. Improved monitoring in this case means increasing the monitoring frequency
of electrostatic precipitators, scrubbers, and fabric filters from once per day to four
times per hour, with no change in monitoring technique.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (Barr and Schaffner) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
304008** Zinc
303030** Zinc Production
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 6.5% for both PM10 and PM2.5
Equipment Life: Not applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs included the incremental record keeping and reporting associated with the
increased monitoring frequency. Labor rates for 2003 were made that were obtained
from the Bureau of Labor Statistics (labor rates include 140 percent overhead). The
incremental costs included a one-time cost for development of the improved
monitoring and recurring annual burden costs for incremental record keeping,
reporting, and certification activities.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $620 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
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Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 2003.
BLS, 2003: Bureau of Labor Statistics, "Employer Costs for Employee Compensation - June 2003,"
Table 12, page 16, 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Non-Ferrous Metals Processing - Zinc
Control Measure Name: CEM Upgrade and Increased Monitoring Frequency of PM Controls
Rule Name: Not Applicable
Pechan Measure Code: P4210	POD: 210
Application: This measure examines the impacts of improving the PM monitoring technique at units
currently using an ESP, scrubber, or fabric filter. In this improved technique scenario,
the monitoring technique is upgraded to a PM continuous emission monitor. This
improved monitoring technique also results in an increase to the monitoring frequency
because a PM CEMS can make a measurement every 7.5 minutes. The monitoring
frequency increases from once per day to eight times per hour.
RTI's improved monitoring frequency analysis evaluates each scenario for four
different excess emission rates (i.e., the sources limit their excess emissions to x
percent after the improved monitoring method is applied). The most cost-effective
scenarios are those where the source is able to limit excess emissions to less than one
percent. The cost effectiveness of this measure is based on a case where the excess
emissions are limited to 0.46 percent.
The RTI memo (see References) offers two methods for estimating emission
reductions from an NEI baseline. These are labeled the original calculation method,
and an alternative calculation method. The original calculation method keeps actual
emissions at NEI amounts, and is used in AirControlNET to avoid having to re-estimate
NEI emissions to include excess emissions.
Affected SCC:
304008** Zinc
303030** Zinc Production
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 7.7% for both PM10 and PM2.5
Equipment Life: Unknown
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The total capital and annual operating costs for implementing an improved monitoring
technique are calculated based on data from the EPA CEMS Cost Model and the PM
CEMS Knowledge document. Labor rates in the EPA CEMS Cost Model are scaled
to reflect 2003 labor rates (including 140 percent overhead) provided by the Bureau of
Labor Statistics.
The cost effectiveness at a percent excess emission rate of 0.46 percent is $5,200
per ton of PM2.5. This is based on a $34 million capital investment cost, and a $14
million total annualized cost when applied to 128 facilities.
Note: All costs are in 2003 dollars.
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Cost Effectiveness: The cost effectiveness used in AirControlNET is $5,200 per ton PM reduced
(2003$).
Comments:
Status:
Last Reviewed: 2004
Additional Information:
References:
Barr and Schaffner, 2003: Barr, Leigh and Karen Schaffner, "Impact of Improved Monitoring on
PM2.5 Emissions," RTI International, memorandum to Barrett Parker, U.S. Environmental Protection
Agency, Research Triangle Park, NC, December 8, 2003.
EPA CEMS Cost Model, Version 3.0, U.S. Environmental Protection Agency.
EPA, 2000: U.S. Environmental Protection Agency, "Current Knowledge of Particulate Matter (PM)
Continuous Emissions Monitoring," Chapter 9, PM CEMS Cost, September 8, 2000.
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Source Category: Nonroad Diesel Engines
Control Measure Name: Heavy Duty Retrofit Program
Rule Name: Heavy Duty Retrofit Program
Pechan Measure Code: PHDRET
POD: N/A
Application: The heavy-duty diesel standards regulate emissions from nonroad engines at or above
37 kW (50 horsepower), and emissions from new engines at or above 130 kW (175
horsepower).
This control applies to all non-road diesel engines.
Affected SCC:
2270001060
2270002003
2270002015
2270002018
2270002021
2270002024
2270002027
2270002030
2270002033
2270002036
2270002045
2270002048
2270002051
2270002054
2270002057
2270002060
2270002066
2270002069
2270002072
2270002075
2270002081
2270003010
2270003020
2270003030
2270003040
2270003060
2270003070
2270004056
2270004066
2270004071
2270005015
2270005020
2270006005
2270006010
2270006015
2270006025
2270007015
2270008005
Recreational
Equipment, Specialty Vehicles/Carts
Construction
and
M
ning
Equipment,
Pavers
Construction
and
M
ning
Equipment,
Rollers
Construction
and
M
ning
Equipment,
Scrapers
Construction
and
M
ning
Equipment,
Paving Equipment
Construction
and
M
ning
Equipment,
Surfacing Equipment
Construction
and
M
ning
Equipment,
Signal Boards/Light Plants
Construction
and
M
ning
Equipment,
Trenchers
Construction
and
M
ning
Equipment,
Bore/Drill Rigs
Construction
and
M
ning
Equipment,
Excavators
Construction
and
M
ning
Equipment,
Cranes
Construction
and
M
ning
Equipment,
Graders
Construction
and
M
ning
Equipment,
Off-highway Trucks
Construction
and
M
ning
Equipment,
Crushing/Processing Equipment
Construction
and
M
ning
Equipment,
Rough Terrain Forklifts
Construction
and
M
ning
Equipment,
Rubber Tire Loaders
Construction
and
M
ning
Equipment,
T ractors/Loaders/Backhoes
Construction
and
M
ning
Equipment,
Crawler T ractor/Dozers
Construction
and
M
ning
Equipment,
Skid Steer Loaders
Construction
and
M
ning
Equipment,
Off-highway Tractors
Construction
and
M
ning
Equipment,
Other Construction Equipment
Industrial Equipment, Aerial Lifts
Industrial Equipment, Forklifts
Industrial Equipment, Sweepers/Scrubbers
Industrial Equipment, Other General Industrial Equipment
Industrial Equipment, AC\Refrigeration
Industrial Equipment, Terminal Tractors
Lawn and Garden Equipment, Lawn and Garden Tractors (Commercial)
Lawn and Garden Equipment, Chippers/Stump Grinders (Commercial)
Lawn and Garden Equipment, Turf Equipment (Commercial)
Agricultural Equipment, Agricultural Tractors
Agricultural Equipment, Combines
Commercial Equipment, Generator Sets
Commercial Equipment, Pumps
Commercial Equipment, Air Compressors
Commercial Equipment, Welders
Logging Equipment, Forest Eqp - Feller/Bunch/Skidder
Airport Ground Support Equipment, Airport Ground Support Equipment
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AT-A-GLANCE TABLE FOR AREA SOURCES
2270009010 Underground Mining Equipment, Other Underground Mining Equipment
2270010010 Industrial Equipment, Other Oil Field Equipment
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 1% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Since source specific data is not available for area and nonroad sources, costs for
control measures are simply expressed as the cost per ton reduced (Pechan, 1995).
The annual cost is estimated using the following equation:
Annual Cost = Cost Per Ton * Emissions * (Control Efficiency * Rule Effectiveness *
Rule Penetration)
Cost-effectiveness, in $/ton of PM removed, is calculated as the total annual cost
divided by the annual PM reduction, in tons.
Cost Effectiveness: The cost effectiveness is $9,500 per ton PM reduced (1990$).
Comments: Note: This control measure is currently under evaluation and will be updated in the
near future.
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
References:
Pechan, 1995: E.H. Pechan & Associates, Inc., "Regional Particulate Strategies - Draft Report,"
prepared for U.S. Environmental Agency, Office of Planning and Evaluation, Washington, DC,
September 1995.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Paved Roads
Control Measure Name: Vacuum Sweeping
Rule Name: Not Applicable
Pechan Measure Code: PPVAC
POD: N/A
Application: Vacuum sweeping is a road surface cleaning operation that removes loose material
from the roadway, preventing it from becoming airborne particulate when vehicles
travel over the road surface.
This control applies to all paved roads classified under SCC 2294000000.
Affected SCC:
2294000000 All Paved Roads, Total: Fugitives
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 51% from uncontrolled;PM2.5 control efficiency is
25% from uncontrolled
Equipment Life: 8 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital costs vary from $150K to $190K (1999 dollars) for compressed natural gas
(CNG) fueled units. Diesel-powered units are approximately $30K less (Harrison,
1999).
Unit life is approximately 5 years; however, with thorough maintenance, life can be
extended to 8 years. For best performance, operating speed is limited to 5 miles per
hour. Based on a 7 percent discount rate and 8-year life, annualized costs are $25K
to $32 K.
O&M costs are approximately $16 to $18 per curb mile, based on operation with
CNG, a thorough maintenance regimen, and a wage scale of approximately $ 13/hr
(Clapper, 1999).
Note: All costs are in 1999 dollars.
Cost Effectiveness: The cost effectiveness for this control is $485 per ton PM reduced. (1999$)
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
The closed-loop regenerative air vacuum systems use an air jet generated by a blower and
distributed by the floating pickup head to loosen particles in the surface cracks and crevices before
drawing them into an internal hopper. A mechanical broom precedes the vacuum section (Pechan,
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AT-A-GLANCE TABLE FOR AREA SOURCES
1999). No water is used. An internal centrifugal dust separator retains and collects the PM for
proper disposal.
References:
Clapper, 1999: W. Clapper, Sunline Transit Services, personal communication with J. Reisman,
E.H. Pechan & Associates, Inc., August 18, 1999.
Harrison, 1999: J. Harrison, GCS Western Power, personal communication with J. Reisman, E.H.
Pechan & Associates, Inc., August 18, 1999.
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base for the National Emissions Trends Inventory (Control NET)," prepared for U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards, Innovative
Strategies and Economics Group, Research Triangle Park, NC, September 1999
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Prescribed Burning
Control Measure Name: Increase Fuel Moisture
Rule Name: Not Applicable
Pechan Measure Code: Ppreb	POD: N/A
Application: Prescribed burning is defined as the intentional burning of forest and range lands. For
forestry burning, increasing the fuel moisture will decrease particulate emissions by
decreasing the amount of fuel burned.
This control is applicable to prescribed burning for forest management.
Affected SCC:
2810015000 Prescribed Burning for Forest Management, Total
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled for both PM10 and PM2.5
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: EPA estimated a range of $38 to $161 per acre cost for increasing fuel moisture in
1986 (EPA, 1992). Costs vary based on the current burn schedule and method,
along with the type of land under consideration (federal versus private).
Based on the emission factor for PM10 emissions and the 50 percent control
efficiency, a $826-$3,500 PM10 cost per ton range (in 1986 dollars) is estimated.
For PM10: (($38-$161 per acre) / (0.092 tons PM-10/acre)) * ((1 ton emitted) / (0.50
ton reduced)) = $826-$3,500 per ton PM10 reduced (in 1986 dollars)
Because this measure entails work practice changes, costs were converted to 1990
dollar terms using the 1986-1990 producer price index for employment costs (BLS,
1994).
For PM10: $826-$3,500 per ton in 1986 dollars * 1.21 = $999-$4,235 per ton PM10
reduced (in 1990 dollars)
The midpoint of these cost ranges was used in the analysis, PM10 costs are
estimated at $2,617 per ton.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,617 per ton PM reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
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AT-A-GLANCE TABLE FOR AREA SOURCES
Additional Information:
Decreasing PM emissions is accomplished by either removing lighter and drier fuels or burning in
early spring when moisture levels are naturally higher. Emission reductions estimates range from 30
to more than 50 percent (EPA, 1992; Hardy, 1997). Reductions will vary significantly depending on
a given area. Variation is based on current burn schedule and method, along with the
characteristics of the material to be burned.
References:
BLS, 1994: U.S. Department of Labor, Bureau of Labor Statistics, Producer Price Indices,
Washington DC. Various issues 1985 through 1994.
EPA, 1992: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Prescribed Burning Background Document and Technical Information Document for Best Available
Control Measures, Research Triangle Park, NC. September 1992.
Hardy, 1997: C. Hardy, Intermountain Research Station, USDA Forest Service, Forest Service Fire
Research Library, Missoula, MT, personal communication with M. Cohen, E.H. Pechan &
Associates, Inc. February 1997.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Residential Wood Combustion
Control Measure Name: Education and Advisory Program
Rule Name: Education and Advisory Program
Pechan Measure Code: Presw	POD: N/A
Application: The education and advisory programs provide instruction in proper wood burning
operation and maintenance of a wood stove as well as the hazards of wood stove
emissions.
Residential wood combustion (RWC) emissions include those from traditional masonry
fireplaces, freestanding fireplaces (metal zero clearance), wood stoves, and furnaces.
Affected SCC:
2104008001 Wood, Fireplaces
2104008030 Wood, Catalytic Woodstoves: General
2104008051 Wood, Non-catalytic Woodstoves: Conventional
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 50% from uncontrolled for both PM10 and PM2.5
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs of education and advisory programs are variable since they are dependent on
program parameters and area characteristics. The costs here are based on the
Clement Falls, Oregon education and advisory program and mandatory curtailment
program. It is assumed that the costs are proportional to population. This results in a
per capita cost of $0.79 for the education and advisory program, $0.01 for the
forecasting system, and $0.02 for the mandatory curtailment program.
The cost per ton reduced varies depending on the assumed fraction of Phase II
woodstoves versus conventional woodstoves. Here the percentage of Phase II
stoves is assumed to be 72% (Pechan, 1997).
Cost Effectiveness: The cost effectiveness is $1,320 per ton PM10 reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
In many areas of the country with PM10 nonattainment designations, residential wood combustion
devices account for a large fraction of PM emissions in the winter.
References:
Pechan, 1997: E.H. Pechan & Associates, "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Residential Wood Stoves
Control Measure Name: NSPS compliant Wood Stoves
Rule Name: Not Applicable
Pechan Measure Code: Pwdstv
POD: N/A
Application: The key to EPA-certified woodburning appliances is more complete combustion.
Uncertified stoves starve the fire of oxygen which burns wood incompletely, and
creates excessive levels of smoke. In contrast, certified appliances create the right
conditions for complete combustion - high temperature, enough oxygen, or air, and
sufficient time for the combustion gases to burn before being cooled.
Affected SCC:
2104008010 Stationary Source Fuel Combustion, Residential, Wood, WoodStoves: General
2104008050	Stationary Source Fuel Combustion, Residential, Wood, WoodStoves: General, Non-
Catalytic WoodStoves - General
2104008051	Stationary Source Fuel Combustion, Residential, Wood, WoodStoves: General, Non-
Catalytic WoodStoves - Conventional
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V*
V*








V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 98% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 90%
Penetration: 100%
Cost Basis: The Cost effectiveness is $2,000/ton of PM reduced (2001$).
Cost Effectiveness: The Cost effectiveness is $2,000/ton of PM reduced (2001$).
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
References:
Personal Email Communication with Larry Sorrels, EPA dated September 16, 2005
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Unpaved Roads
Control Measure Name: Chemical Stabilization
Rule Name: Not Applicable
Pechan Measure Code: PUCHS	POD: N/A
Application: Chemical stabilization is a surface treatment option for unpaved roads. Unpaved roads
comprise a sizable percentage of total PM10/PM2.5 emissions. Unpaved roads,
especially rural roads, do not generally experience the type of traffic volume associated
with paved roads.
This control applies to unpaved roads classified under SCC 2296000000.
Affected SCC:
2296000000 All Unpaved Roads, Total: Fugitives
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V







V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 38% from uncontrolled;PM2.5 control efficiency is
25% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: SCAQMD estimated a $17,000 per mile cost estimate for chemical stabilization of
unpaved roads for the 1994 Air Quality Management Plan (SCAQMD, 1994). From
this, Pechan estimated a cost effectiveness of $2,753 per ton PM removed.
Cost Effectiveness: The cost effectiveness is $2,753 per ton PM removed (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
Chemical stabilization was investigated as a supplemental control option to hot asphalt paving for
urban areas. For rural areas, chemical stabilization was evaluated as an alternative to watering
(Pechan, 1995).
The control application parameters that affect the control efficiency of chemical dust suppressants
are application intensity, application frequency, dilution ratio and application procedure (EPA, 1986).
Other factors that influence the control efficiency are the silt content of the soil, weather conditions
and the weight and level of traffic. An increase in vehicle weight and speed serves to accelerate the
decay in efficiency for chemical suppression.
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
EPA, 1986: U.S. Environmental Protection Agency, Air and Engineering Research Laboratory,
Identification, Assessment, and Control of Fugitive Particulate Emissions, EPA/600/8-86/023,
prepared by Midwest Research Institute, August 1986.
Pechan, 1995: E.H. Pechan & Associates, Inc., "Regional Particulate Strategies, Draft Report,"
prepared for U.S. Environmental Protection Agency, Office of Policy Planning and Evaluation,
Washington, DC. September 1995.
SCAQMD, 1994: South Coast Air Quality Management District, "1994 Air Quality Management Plan,
Appendix l-D: Best Available Control Measures PM-10 SIP for the South Coast Air Basin," April
1994.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Unpaved Roads
Control Measure Name: Hot Asphalt Paving
Rule Name: Not Applicable
Pechan Measure Code: PUHAP	POD: N/A
Application: This control is the paving of unpaved roads with hot asphalt. Hot asphalt paving is
based on the use of paving materials which meet RACT requirements and thereby do
not emit VOCs. Hot asphalt paving was selected as the control option for urban areas.
This control measure applies to all unpaved roads classified under SCC 2296000000.
Affected SCC:
2296000000 All Unpaved Roads, Total: Fugitives
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 68% from uncontrolled;PM2.5 control efficiency is
25% from uncontrolled
Equipment Life: 40 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In determining per VMT cost, average daily traffic (ADT) is assumed to be 400 for
urban roads (Pechan, 1995). The cost of hot asphalt paving is $0.08 per VMT
(Pechan, 1995). Once the control options have been weighted the annual cost for
urban areas is $0.09 per VMT.
The capital cost is determined in a similar manner to the annual costs, resulting in a
total capital cost of $0.43 per VMT.
Cost Effectiveness: The cost effectiveness per ton PM10 reduced is $537 (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:

This control technique is not applied in rural areas because of the high cost relative to the emission
reduction potential.

References:
Pechan, 1995: E.H. Pechan & Associates, Inc., "Regional Particulate Strategies - Draft Report,"
prepared for U.S. Environmental Agency, Office of Planning and Evaluation, Washington, DC,
September 1995.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Coal
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: PUDESP	POD: 01
Application: This control is the use of an electrostatic precipitator (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to electricity generation sources powered by pulverized dry-bottom
and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V





V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled; Hg control efficiency is 20% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
The particulate-bound form of mercury can be readily captured in the particulate matter (PM) control
devices, e.g., fabric filters (FF). Also, gaseous mercury (both HgO and Hg 2+) can potentially be
adsorbed on fly ash and subsequently be collected on a PM device. However, the level of this
adsorption depends on the speciation of mercury, the flue gas concentration of fly ash, and many
other factors.
Average mercury capture efficiencies of PM post-combustion control measures for coal-fired utility
boilers are based on research data from National Risk Management Research Laboratory (EPA,
2002). Control efficiencies are based on a series of tests conducted on a several plants throughout
the United States. The background documents to National Risk Management Research Laboratory
Study (EPA, 2002) also provided estimates of control efficiencies of Hg species for a limited number
of tests
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Research and Development, Control Of Mercury Emissions From Coal-Fired Electric Utility Boilers:
Interim Report Including Errata Dated 3-21-02," EPA-600/R-01-109, April 2002.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Coal
Control Measure Name: Fabric Filter (Mech. Shaker Type)
Rule Name: Not Applicable
Pechan Measure Code: PUMECH	POD: 01
Application: This control is the addition of a mechanical shaker type fabric filter to reduce PM
emissions from utility boiler waste streams. In a fabric filter, flue gas is passed through
a tightly woven or felted fabric, collecting PM by sieving and other mechanisms. The
gas stream is drawn from beneath a cell plate in the floor and into the filter bags. The
gas proceeds from the inside to the outside of the filter bags. The particles collect on
the inside of the bags, forming a filter cake. In mechanical shaking units, the tops of
bags are attached to a shaker bar, moved briskly to clean the bags.
This control applies to electricity generation sources powered by pulverized dry-bottom
and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V





V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for mechanical shaker cleaned systems are generated using EPA's cost-
estimating spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data
was available, the costs and cost effectiveness were calculated using the typical
values of capital and O&M costs. When stack gas flow rate data was not available,
default typical capital and O&M cost values based on a tons per year of PM10
removed were used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
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equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $8 to $71 per scfm
Typical value is $29 per scfm
O&M Costs:
Range from $4 to $24 per scfm
Typical value is $11 per scfm
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $37 to $303 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $126 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
Cost estimates assume a conventional design under typical operating conditions. The costs do not
include auxiliary equipment such as fans and ductwork. (EPA, 2000)
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 30% and the O&M cost could increase by as much as 7%.
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Mechanical shaking is a popular cleaning method because it is both simple and effective. In typical
operation, dusty gas enters an inlet pipe to the fabric filter and very large particles are removed
using a baffle plate fall into the hopper. The gas stream is drawn from beneath a cell plate in the
floor and into the filter bags (EPA, 2000). The gas proceeds from the inside to the outside of the
filter bags. The particles collect on the inside of the bags, forming a filter cake. In mechanical
shaking units, the tops of bags are attached to a shaker bar, moved briskly (usually in a horizontal
direction) to clean the bags. The shaker bars are operated by mechanical motors or by hand (EPA,
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1998b)..
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Mechanical Shaker Cleaned Type," August 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Coal
Control Measure Name: Fabric Filter (Pulse Jet Type)
Rule Name: Not Applicable
Pechan Measure Code: PUPUJT	POD: 01
Application: This control is the addition of a pulse-jet cleaned fabric filter to reduce PM emissions
from waste streams from coal-fired utility boilers. In a fabric filter, flue gas is passed
through a tightly woven or felted fabric, collecting PM by sieving and other
mechanisms. Particulate-laden gas flows into the filter bag from the outside to the
inside. The particles collected on the outside drop into a hopper below the fabric filter.
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags,
dislodging the dust cake.
This control applies to electricity generation sources powered by pulverized dry-bottom
and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V





V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for pulse-jet cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
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with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $6 to $26 per scfm
Typical value is $13 per scfm
O&M Costs:
Range from $5 to $24 per scfm
Typical value is $11 per scfm
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $42 to $266 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $117 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions and do not
include auxiliary equipment such as fans and ductwork. The costs for pulse-jet cleaned systems are
generated using EPA's cost-estimating spreadsheet for fabric filters (EPA, 1998a).
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
waste streams are not included in the estimates. For these systems, the capital cost could increase
by as much as 75% and the operational and maintenance (O&M) cost could increase by as much as
20% (EPA, 2000).
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Pulse-jet cleaning of fabric filters is a relatively new type of fabric filter, as they have only been used
for the past 30 years. This cleaning mechanism has grown in popularity because it can treat high
dust loadings, operate at constant pressure drop, and occupy less space than other types of fabric
filters (EPA, 2000). Particulate-laden gas flows into the bag. The gas flows from the outside to the
inside of the bags, and then out the gas exhaust. The particles collected on the outside drop into a
hopper below the fabric filter (EPA, 1998b).
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
During pulse-jet cleaning, a short burst of high pressure air is injected into the bags (EPA, 1998b).
The pulse is blown through a venturi nozzle at the top of the bags and establishes a shock wave that
continues onto the bottom of the bag. The wave flexes the fabric dislodging the dust cake.
There are several unique attributes of pulse-jet cleaning. The cleaning pulse is very brief allowing
the flow of dusty gas to continue during cleaning. The bags not being cleaned continue to filter,
taking on extra duty from the bags being cleaned (EPA, 2000). Pulse-jet cleaning is more intense
and occurs with greater frequency than the other fabric filter cleaning methods. The cleaning
dislodges nearly all of the dust cake each time the bag is pulsed. Pulse-jet filters, as a result, do not
rely on a dust cake to provide filtration. Felted (non-woven) fabrics are used in these types of filters
because they do not require a dust cake. Also it has been found that woven fabrics used with pulse-
jet cleaning leak dust after they are cleaned (EPA, 1998b).
Since bags cleaned by the pulse-jet method do not need to be isolated for cleaning, pulsejet
cleaned fabric filters do not need extra compartments to maintain adequate filtration during
cleaning. Also, because of the intense and frequent nature of the cleaning, they can treat higher
gas flow rates with higher dust loadings. Consequently, fabric filters cleaned by the pulse-jet
method can be smaller than other filters in the treatment of the same amount of gas and dust,
making higher gas-to-cloth ratios achievable (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Pulse-Jet Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Coal
Control Measure Name: Fabric Filter (Reverse-Air Cleaned Type)
Rule Name: Not Applicable
Pechan Measure Code: PUREVA	POD: 01
Application: This control is the use of a reverse-air cleaned fabric filter to reduce PM emissions
from waste streams from coal-fired utility boilers. In a fabric filter, flue gas is passed
through a tightly woven or felted fabric, collecting PM by sieving and other
mechanisms. Reverse-air cleaning is performed by forcing clean air through the filters
in the opposite direction of the dusty gas flow. The change in direction of the gas flow
causes the bag to flex and crack the filter cake allowing for internal cake collection.
This control applies to electricity generation sources powered by pulverized dry-bottom
and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V





V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled for both PM10 and PM2.5
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for reverse-air cleaned systems are generated using EPA's cost-estimating
spreadsheet for fabric filters (EPA, 1998a). When stack gas flow rate data was
available, the costs and cost effectiveness were calculated using the typical values of
capital and O&M costs. When stack gas flow rate data was not available, default
typical capital and O&M cost values based on a tons per year of PM10 removed were
used (Pechan,2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 2000). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $9 to $84 per scfm
Typical value is $34 per scfm
O&M Costs:
Range from $6 to $27 per scfm
Typical value is $13 per scfm
Note: All costs are in 1998 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $53 to $337 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $148 per ton PM10 reduced.
(1998$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
The cost estimates assume a conventional design under typical operating conditions. The costs do
not include any auxiliary equipment (EPA, 2000).
The capital cost for the reverse-jet cleaned fabric baghouse is based on information provided by a
manufacturer (EPA, 2000). The capital cost includes only the purchased equipment cost.
Costs are primarily based on volumetric flow rate and the amount of PM in the waste stream. In
general, a small unit controlling a low pollutant levels will not be as cost effective as a large unit
controlling a high pollutant levels. (EPA, 2000)
Pollutants requiring a high level of control or the fabric filters to be constructed of special materials
will increase the costs of the system (EPA, 1998a). The additional costs for controlling complex
streams are not reflected in the estimates. For these systems, the capital cost could increase by as
much as 40% and the O&M cost could increase by as much as 5%. (EPA, 2000)
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Reverse-air cleaning is a popular filter cleaning method as it has been used extensively and
improved over the years. It is a gentler but sometimes less effective clearing mechanism than
mechanical shaking. Reverse-air cleaning is performed by forcing clean air through the filters in the
opposite direction of the dusty gas flow. The change in direction of the gas flow causes the bag to
flex and crack the filter cake allowing for internal cake collection (EPA, 2000).
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
The most common design is to have separate compartments within the fabric filter so that each can
be isolated and cleaned separately while the others continue to treat the dusty gas. There are
several methods of reversing the flow through the filters. One method of providing the reverse flow
is by the use of a fan or cleaned gas from other compartments. Reverse-air cleaning only used
alone in cases where the dust releases easily from the fabric. In many instances, reverse-air is used
along with shaking, pulsing or sonic horns (EPA, 1998b).
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 1998b: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter,:EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1998a: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, Chapter 5, EPA 453/B-96-001, Research Triangle
Park, NC. December 1998.
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Coal
Control Measure Name: Fabric Filter
Rule Name: Not Applicable
Pechan Measure Code: PUTILC	POD: 01
Application: This control is the use of a fabric filter on waste streams to reduce PM emissions. In a
fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by
sieving and other mechanisms.
This control applies to electricity generation sources powered by pulverized dry-bottom
and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V





V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled for both PM10 and PM2.5; 80% from uncontrolled for Hg
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: When stack gas flow rate data was available, the costs and cost effectiveness were
calculated using the typical values of capital and O&M costs.
Capital Costs (TCC):
Stackflow: stkflow (ftA3 / min)
Total Equipment Cost Factor: tecs = 5.7019
Total Equipment Cost Constant: teci = 77,489
Equipment to Capital Cost Multiplier: ec_to_cc
TCC = [(tecs * stkflow) +teci] * ec_to_cc
Operating and Maintenance Costs (O&M) are comprised of electricity, dust disposal
and bag replacement (compressed air is not applicable).
Electricity Factor: els = 0.1941
Electricity Constant: eli = -15.956
Dust Disposal Factor: dds = 0.7406
Dust Disposal Constant: ddi = 1.1461
Bag Replacement Factor: brs = 0.2497
Bag Replacement Constant: bri = 1220.7
O&M = [(els*stkflow) + eli] + [(dds *stkflow) + ddi] + [(brs * stkflow) +bri]
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Equipment Life in Years = Equiplife
Interest Rate =1 = 7 percent
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Costs = (CRF * TCC) + O&M
Note: All resulting costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness will vary depending on stack flow. The cost effectiveness is
based on the calculation of total capital costs and operation and maintenance
costs. (All resulting costs are in 1990 dollars.)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
The particulate-bound form of mercury can be readily captured in the particulate matter (PM) control
devices, e.g., fabric filters (FF). Also, gaseous mercury (both HgO and Hg 2+) can potentially be
adsorbed on fly ash and subsequently be collected on a PM device. However, the level of this
adsorption depends on the speciation of mercury, the flue gas concentration of fly ash, and many
other factors.
Average mercury capture efficiencies of PM post-combustion control measures for coal-fired utility
boilers are based on research data from National Risk Management Research Laboratory (EPA,
2002). Control efficiencies are based on a series of tests conducted on a several plants throughout
the United States. The background documents to National Risk Management Research Laboratory
Study (EPA, 2002) also provided estimates of control efficiencies of Hg species for a limited number
of tests
References:
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Research and Development, Control Of Mercury Emissions From Coal-Fired Electric Utility Boilers:
Interim Report Including Errata Dated 3-21-02," EPA-600/R-01-109, April 2002.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Gas/Oil
Control Measure Name: Fabric Filter
Rule Name: Not Applicable
Pechan Measure Code: PUTILG	POD: 05
Application: This control is the use of a fabric filter on waste streams to reduce PM emissions. In a
fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by
sieving and other mechanisms.
This control applies to electricity generation sources powered by natural gas.
Affected SCC:
10100601 Electric Generation, Natural Gas, Boilers > 100 Million Btu/hr except Tangential
10100604 Electric Generation, Natural Gas, Tangentially Fired Units
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V





V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled for both PM10 and PM2.5
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: When stack gas flow rate data was available, the costs and cost effectiveness were
calculated using the typical values of capital and O&M costs.
Capital Costs (TCC):
Stackflow: stkflow (ftA3 / min)
Total Equipment Cost Factor: tecs = 5.7019
Total Equipment Cost Constant: teci = 77,489
Equipment to Capital Cost Multiplier: ec_to_cc
TCC = [(tecs * stkflow) +teci] * ec_to_cc
Operating and Maintenance Costs (O&M) are comprised of electricity, dust disposal
and bag replacement (compressed air is not applicable).
Electricity Factor: els = 0.1876
Electricity Constant: eli = -19.576
Dust Disposal Factor: dds = 0.0007
Dust Disposal Constant: ddi = 0.1895
Bag Replacement Factor: brs = 0.2411
Bag Replacement Constant: bri = 1224.2
0$M = [(els*stkflow) + eli] + [(dds *stkflow) + ddi] + [(brs * stkflow) +bri]
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Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Costs = (CRF * TCC) + O&M
Note: All resultant costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness will vary depending on stack flow. The cost effectiveness is
based on the calculation of total capital costs and operation and maintenance
costs. (All resulting costs are in 1990 dollars.)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In a fabric filter, flue gas is passed through a tightly woven or felted fabric, collecting PM by sieving
and other mechanisms. Fabric filters may be in the form of sheets, cartridges, or bags, with many
individual filter units together in a group. Bags are the most common type of filter. The dust cake
that forms on the filter from the collected PM can significantly increase collection efficiency. (EPA,
2000)
Fabric filters are useful for collecting particles with resistivities either too low or too high for collection
with electrostatic precipitators. Fabric filters are useful in controlling particulate matter less than or
equal to 10 micrometers (|jm) in diameter (PM10) and particulate matter less than or equal to 2.5
|jm in diameter (PM2.5). Fabric filters may be good candidates for collecting fly ash from low-sulfur
coals or containing high unburned carbon levels and are relatively difficult to collect with electrostatic
precipitators. (EPA, 2000)
References:
EPA, 2000: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Fabric Filter - Reverse-Air Cleaned Type," April 2000.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
WDNR, 2000: Wisconsin Department of Natural Resources, "One-hour Ozone Attainment
Demonstration, State Implementation Plan and Rate of Progress Rules - Attachment 4, Stationary
Source NOx Control Program," Wisconsin Department of Natural Resources, December 2000.
http://www.dnr.state.wi.us/org/aw/air/hot/dec00sip/attachment4.pdf
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Wood Pulp & Paper
Control Measure Name: Dry ESP-Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2241
POD: 224
Application: This control is the use of dry electrostatic precipitators (ESP) to reduce PM emissions.
An ESP uses electrical forces to move particles in an exhaust stream onto collector
plates. Electrodes in the center of the flow are maintained at high voltage and generate
an electrical field forcing particles to the collector walls. In dry ESPs, the collectors are
knocked by various mechanical means to dislodge the particulate, which slides
downward into a hopper.
This control applies to wood pulp and paper product operations.
Affected SCC:
30700101
30700102
30700103
30700104
30700105
30700106
30700108
30700109
30700110
30700118
30700121
30700122
30700199
Pulp and Paper and Wood Products, Sulfate Pulping, Digester Relief & Blow Tank
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Washer/Screens
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Multi-effect Evaporator
Pulp, Paper & Wood, Sulfate Pulping, Recovery Furnace/Direct Contact Evaporator
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Smelt Dissolving Tank
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Lime Kiln
Sulfate (Kraft) Pulping, Fluid Bed Calciner
Sulfate (Kraft) Pulping, Liquor Oxidation Tower
Sulfate (Kraft) Pulping, Recovery Furnace/Indirect Contact Evaporator
Sulfate (Kraft) Pulping, Liquor Clarifiers
Sulfate (Kraft) Pulping, Wastewater: General
Sulfate (Kraft) Pulping, Causticizing: General
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 98% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for ESPs of conventional design under typical operating conditions are
developed using EPA cost estimating spreadsheets (EPA, 1996). When stack gas
flow rate data was available, the costs and cost effectiveness were calculated using
the typical values of capital and O&M costs. When stack gas flow rate data was not
available, default typical capital and O&M cost values based on a tons per year of
PM10 removed were used (Pechan, 2001).
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
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costs was estimated as 4 percent of the total capital investment (EPA, 1999). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $15 to $50 per scfm
Typical value is $27 per scfm
O&M Costs:
Range from $4 to $40 per scfm
Typical value is $16 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1996). O&M
costs were calculated for three model plants with flow rates of 200 and 500 thousand
acfm and 1 million acfm. The average percentage of the total O&M cost was then
calculated for each O&M cost component. All the model plants were assumed to have
a dust loading of 6.0 grains per cubic feet. The operating time was assumed to be
8640 hours per year. The following assumptions apply to the cost of utilities and
disposal:
Electricity price 0.067 $/kW-hr
Dust disposal 25 $/ton disposed
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $40 to $250 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $110 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Another factor in the performance of ESPs is the resistivity of the collected material. All the ion
current must pass through the collected layer to reach the ground plates. This creates an electric
field in the layer, and it can become large enough to cause electrical breakdown. When this occurs,
new ions of the wrong polarity are injected into the wire-plate gap reducing the charge on the
particles, which may cause sparking. This condition is called "back corona." When this happens the
collection ability of the unit is reduced. At low resistivities the particles are held on the plates so
loosely that reentrainment levels are much higher. Hence, care must be taken in measuring or
estimating resistivity because it is strongly affected by such variables as temperature, moisture, gas
composition, particle composition, and surface characteristics (EPA, 1999).
Dusts with high resistivities are also not well-suited for collection in dry ESPs. These particles are
not easily charged nor easily collected. High-resistivity particles form ash layers with very high
voltage gradients on the collecting electrodes lead to back corona, reducing the charge on particles
and lowering collection efficiency. Fly ash from the combustion of low-sulfur coal typically has a high
resistivity, and thus is difficult to collect using dry ESPs (EPA, 1999).
References:
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC.
February 1996.
EPA, 1998: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stationary Source Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001,
Research Triangle Park, NC., October 1998.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Dry Electrostatic Precipitator (ESP) - Wire-Plate Type," May 1999.
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Wood Pulp & Paper
Control Measure Name: Wet ESP - Wire Plate Type
Rule Name: Not Applicable
Pechan Measure Code: P2242	POD: 224
Application: This control is the use of a wire-plate type electrostatic precipitator (ESP) to reduce PM
emissions. An ESP uses electrical forces to move particles in an exhaust stream onto
collector plates. Electrodes in the center of the flow are maintained at high voltage and
generate an electrical field forcing particles to the collector walls. Wet ESPs use a
stream of water, in place of rapping mechanisms, to dislodge particulate from the
plates and into a sump..
This control measure applies wood pulp and paper processing and production
operations.
Affected SCC:
30700101
30700102
30700103
30700104
30700105
30700106
30700108
30700109
30700110
30700118
30700121
30700122
30700199
Pulp and Paper and Wood Products, Sulfate Pulping, Digester Relief & Blow Tank
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Washer/Screens
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Multi-effect Evaporator
Pulp, Paper & Wood, Sulfate Pulping, Recovery Furnace/Direct Contact Evaporator
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Smelt Dissolving Tank
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Lime Kiln
Sulfate (Kraft) Pulping, Fluid Bed Calciner
Sulfate (Kraft) Pulping, Liquor Oxidation Tower
Sulfate (Kraft) Pulping, Recovery Furnace/Indirect Contact Evaporator
Sulfate (Kraft) Pulping, Liquor Clarifiers
Sulfate (Kraft) Pulping, Wastewater: General
Sulfate (Kraft) Pulping, Causticizing: General
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
oc
NOx
VOC
S02
NH3
CO
Hg
V*
V
V
V






V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: PM10 control efficiency is 99% from uncontrolled; PM2.5 control efficiency is
95% from uncontrolled
Equipment Life: 20 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The following are cost ranges for wire-plate ESPs, developed using EPA cost-
estimating spreadsheets for dry wire-plate ESPs with adjustments made to reflect
wet wire-plate ESPs (EPA, 1999). Capital and operating costs are generally higher
due to noncorrosive materials requirements, increased water usage, and treatment
and disposal of wet effluent. When stack gas flow rate data was available, the costs
and cost effectiveness were calculated using the typical values of capital and O&M
costs. When stack gas flow rate data was not available, default typical capital and
O&M cost values based on a tons per year of PM10 removed were used
(Pechan,2001).
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AT-A-GLANCE TABLE FOR POINT SOURCES
Total annualized costs were determined by adding the annualized O&M costs, fixed
capital recovery charges, and a fixed annual charge for taxes, insurance and
administrative costs. The fixed annual charge for taxes, insurance and administrative
costs was estimated as 4 percent of the total capital investment (EPA, 1990). Total
installed capital costs were annualized using a capital recovery factor, with is based
on a 7 percent discount rate and the expected life of the control equipment (20 years)
(Pechan, 2001).
The range of high and low capital costs and O&M costs presented in the fact sheets
were calculated based on the OAQPS Control Cost Manual and associated
spreadsheets (EPA, 1996). The low costs in the ranges below are representative of
equipment sized based on the maximum flow rate recommended in the cost manual,
with no exotic materials. The high costs in the ranges below are representative of
equipment sized based on the minimum flow rate recommended in the cost manual,
with not exotic materials. No optional pre- or post treatment equipment costs are
included.
Capital Costs:
Range from $30 to $60 per scfm
Typical value is $40 per scfm
O&M Costs:
Range from $6 to $45 per scfm
Typical value is $19 per scfm
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's cost-estimating spreadsheet for ESP (EPA, 1999). O&M
costs were calculated for three model plants with flow rates of 10, 15 and 20
thousand acfm. The average percentage of the total O&M cost was then calculated
for each O&M cost component. All the model plants were assumed to have a dust
loading of 6.0 grains per cubic feet. The operating time was assumed to be 8640
hours per year. A water flow rate for the ESP was assumed to be 5 gal/min per
thousand acfm. The following assumptions apply to the cost of utilities and disposal:
Electricity price	0.067 $/kW-hr
Process water price	0.20	$/1000gal
Dust disposal	20	$/ton disposed
Wastewater treatment 1.5	$/ thousand gal treated
Note: All costs are in 1995 dollars.
Cost Effectiveness: When stack flow is available the cost effectiveness varies from $55 to $550 per
ton PM10 removed, depending on stack flow. The default cost effectiveness
value, used when stack flow is not available, is $220 per ton PM10 reduced.
(1995$)
Comments:
Status: Demonstrated
Last Reviewed: 2001
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
Costs can be substantially higher than in the ranges shown for pollutants which require an unusually
high level of control, or which require the ESP to be constructed of special materials such as
titanium (EPA, 1999). In most cases, smaller units controlling a low concentration waste stream will
not be as cost effective as a large unit cleaning a high pollutant load flow (EPA, 1998).
In the wire-plate ESP, the gas flows around vertical, metal plates. The electrodes are long, weighted
wires hanging between the plates. The voltage applied to the electrodes causes the gas between
the electrodes to break down, known as a "corona." The electrodes are most often given a negative
polarity because a negative corona supports a higher voltage than a positive corona.
Certain types of losses affect control efficiency. The dislodging of the accumulated layer also
projects some of the particles back into the gas stream. These particles are processed in later
sections of the ESP, but the particles from the last section have no chance to be recaptured. Due to
the space needed at the top of the ESP for nonelectrified components, part of the stream may flow
around the charged zones. This is called "sneakage" and places an upper limit on the collection
efficiency of the ESP. Anti-sneakage baffles are used to force the sneakage flow to mix with the
main gas stream for collection in later sections (EPA, 1998).
Wire-Plate Type Wet ESPs require a source of wash water near the top of the collector plates. This
wash system replaces the rapping mechanism used by dry ESPs. The water flows with the collected
particles into a sump from which the fluid is pumped or drained. A portion of the fluid may be
recycled to reduce the total amount of water required. The remainder is pumped into a settling pond
or passed through a dewatering stage, with subsequent disposal of the sludge (AWMA, 1992).
Unlike dry ESPs, resistivity of the collected material is not a major factor in performance. Because
of the high humidity in a wet ESP, the resistivity of particles is lowered, eliminating the "back corona"
condition. The frequent washing of the plates also limits particle buildup on the collectors (EPA,
1998).
For wet ESPs, the handling wastewaters must be considered (EPA, 1999). For simple systems with
innocuous dusts, water with particles collected by the ESP may be discharged from the ESP system
to a solids-removing clarifier. More complicated systems may require skimming and sludge removal,
clarification in dedicated equipment, pH adjustment, and/or treatment to remove dissolved solids.
Recirculation of treated water to the ESP may approach 100 percent (AWMA, 1992).
References:
AWMA, 1992: Air & Waste Management Association, Air Pollution Engineering Manual,
Van Nostrand Reinhold, New York.
EPA, 1996: U.S. EPA, Office of Air Quality Planning and Standards, "OAQPS Control Cost
Manual," Fifth Edition, EPA 453/B-96-001, Research Triangle Park, NC. February.
EPA, 1998: U.S. EPA, Office of Air Quality Planning and Standards, "Stationary Source
Control Techniques Document for Fine Particulate Matter," EPA-452/R-97-001, Research
Triangle Park, NC., October.
EPA, 1999: U.S. Environmental Protection Agency, Center on Air Pollution, "Air Pollution
Technology Fact Sheet - Wet Electrostatic Precipitator (ESP) - Wre-Plate Type," May 1999
Pechan, 2001: E.H. Pechan & Associates, Inc. "Revisions to AirControlNET and Particulate Matter
Control Strategies and Cost Analyses" prepared for U.S. Environmental Protection Agency,
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AT-A-GLANCE TABLE FOR POINT SOURCES
Innovative Strategies and Economics Group, Research Triangle Park, NC, September 2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Bituminous/Subbituminous Coal
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S1901
POD: 19
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to industrial bituminous/subbituminous fired operations. Emissions
from these sources are classified under SCCs beginning with 102002.
Affected SCC:
10200201
10200202
10200203
10200204
10200205
10200206
10200210
10200212
10200217
10200219
10200221
10200222
10200224
10200225
10200226
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
Industrial, Bituminous/Subbituminous Coal, Underfeed Stoker
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker**
Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Subbituminous Coal)
Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
Bituminous/Subbituminous Coal, Pulverized-Dry Bottom Tangential (Subbituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
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AT-A-GLANCE TABLE FOR POINT SOURCES
RF = retrofit factor = 1.1
For stack flowrate less than 1,028,000 cu. ft./min =
(1,028,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,028,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking
6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
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AT-A-GLANCE TABLE FOR POINT SOURCES
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Bituminous/Subbituminous Coal
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S2101	POD: 21
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to commercial/institutional bituminous/subbituminous fired
operations. Emissions from these sources are classified under SCCs beginning with
103002.
Affected SCC:
10300205	Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Bituminous Coal)
10300206	Commercial/Institutional, Pulverized Coal-Dry Bottom (Bituminous Coal)
10300207	Commercial/Institutional, Overfeed Stoker (Bituminous Coal)
10300208	Commercial/Institutional, Underfeed Stoker (Bituminous Coal)
10300209	Commercial/Institutional, Spreader Stoker (Bituminous Coal)
10300211 Commercial/Institutional, Bituminous/Subbituminous Coal, Overfeed Stoker**
10300217 Commercial/Institutional, Atm. Fluidized Bed Combustion-Bubbling (Bituminous Coal)
10300222	Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
10300223	Bituminous/Subbituminous Coal, Cyclone Furnace (Subbituminous Coal)
10300224	Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
10300225	Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
10300226	Bituminous/Subbituminous Coal, Pulverized Coal-Dry Bottom Tangential (Subbituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
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AT-A-GLANCE TABLE FOR POINT SOURCES
For stack flowrate less than 1,0280,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking
6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Document No. 05.09.009/9010.463	III-1240	Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
Document No. 05.09.009/9010.463
III-1241
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Bituminous/Subbituminous Coal (Industrial Boilers)
Control Measure Name: In-duct Dry Sorbent Injection
Rule Name: Not Applicable
Pechan Measure Code: S3000	POD: 19
Application: Two types of dry sorbents were injected into the ductwork downstream of the boiler to
reduce S02 emissions. Either calcium-based sorbent was injected upstream of the
economizer, or sodium-based sorbent downstream of the air heater. Humidification
downstream of the dry sorbent injection was incorporated to aid S02 capture and
lower flue gas temperature and gas flow before entering the fabric filter dust collector
(FFDC).
Affected SCC:
10200201
10200202
10200203
10200204
10200205
10200206
10200210
10200212
10200217
10200219
10200221
10200222
10200224
10200225
10200226
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
Industrial, Bituminous/Subbituminous Coal, Underfeed Stoker
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker**
Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Subbituminous Coal)
Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
Bituminous/Subbituminous Coal, Pulverized-Dry Bottom Tangential (Subbituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 30 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, an EPRI methodology was used for the cost estimates, with the following
cost factor is used for the non-process costs:
General Facilities: 5% of total direct process cost
Engineering and home pffice fees: 10% of total direct process cost
Process contingency: 5% of total direct process cost
Project contingency: 15% of total direct process and the above three non-process
costs
Retrofit Factor: 30%
Preproduction cost: 2% of total plant investment with retrofit costs
Inventory Capital: cost for a 30-day reagent storage
Document No. 05.09.009/9010.463	III-1242	Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
The levelized costs ($/ton of S02 removed) were calculated using the estimates of
the capital costs and increased consumable rates associated with each technology.
The costs are based on 1999 dollars. The economic factors used in these calculation
were as follows:
Lime: $ 50 / ton
Limestone: $15 /ton
Water: $0.0006 / gal
Solid Waste Disposal: $12 / ton
Operator Cost: $ 30 /hr
Useful life: 30 years
Carrying charges: 12%
Levelization factor: 1
Maintenance cost (% of capital cost): 2.0 for IDIS and SDA
Cost Effectiveness: Cost effectiveness is the fuction of boiler capacity. Following cost per ton
(1999$) is used depending on the boiler capacity.
For Boilers ,
< 100 MMBtu/hr- $2,107 per ton S02 reduced
>	100 MMBtu/hr and < 250 MMBtu/hr- $1,526 per ton S02 reduced
>	250 MMBtu/hr - $1,111 / ton of S02 reduced
Comments:
Status: Demonstrated
Last Reviewed:
Additional Information:
References:
EPA, 2003: U.S. Environmental Protection Agency: "Methdology, Assumptions, and References
Preliminary S02 Controls Cost Estimates For Industrial Boilers", October 2003.
Document No. 05.09.009/9010.463
III-1243
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Bituminous/Subbituminous Coal (Industrial Boilers)
Control Measure Name: Spray Dryer Abosrber
Rule Name: Not Applicable
Pechan Measure Code: S3001	POD: 19
Application: Two types of dry sorbents were injected into the ductwork downstream of the boiler to
reduce S02 emissions. Either calcium-based sorbent was injected upstream of the
economizer, or sodium-based sorbent downstream of the air heater. Humidification
downstream of the dry sorbent injection was incorporated to aid S02 capture and
lower flue gas temperature and gas flow before entering the fabric filter dust collector
(FFDC).
Affected SCC:
10200201
10200202
10200203
10200204
10200205
10200206
10200210
10200212
10200217
10200219
10200221
10200222
10200224
10200225
10200226
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
Industrial, Bituminous/Subbituminous Coal, Underfeed Stoker
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker**
Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Subbituminous Coal)
Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
Bituminous/Subbituminous Coal, Pulverized-Dry Bottom Tangential (Subbituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 30 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, an EPRI methodology was used for the cost estimates, with the following
cost factor is used for the non-process costs:
General Facilities: 5% of total direct process cost
Engineering and home pffice fees: 10% of total direct process cost
Process contingency: 5% of total direct process cost
Project contingency: 15% of total direct process and the above three non-process
costs
Retrofit Factor: 30%
Preproduction cost: 2% of total plant investment with retrofit costs
Inventory Capital: cost for a 30-day reagent storage
Document No. 05.09.009/9010.463	III-1244	Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
The levelized costs ($/ton of S02 removed) were calculated using the estimates of
the capital costs and increased consumable rates associated with each technology.
The costs are based on 1999 dollars. The economic factors used in these calculation
were as follows:
Lime: $ 50 / ton
Limestone: $15 /ton
Water: $0.0006 / gal
Solid Waste Disposal: $12 / ton
Operator Cost: $ 30 /hr
Useful life: 30 years
Carrying charges: 12%
Levelization factor: 1
Maintenance cost (% of capital cost): 2.0 for IDIS and SDA
Cost Effectiveness: Cost effectiveness is the fuction of boiler capacity. Following cost per ton
(1999$) is used depending on the boiler capacity.
For Boilers ,
< 100 MMBtu/hr- $1,973 per ton S02 reduced
>	100 MMBtu/hr and < 250 MMBtu/hr- $1,340 per ton S02 reduced
>	250 MMBtu/hr - $804 / ton of S02 reduced
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
References:
EPA, 2003: U.S. Environmental Protection Agency: "Methdology, Assumptions, and References
Preliminary S02 Controls Cost Estimates For Industrial Boilers", October 2003.
Document No. 05.09.009/9010.463
III-1245
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Bituminous/Subbituminous Coal (Industrial Boilers)
Control Measure Name: Wet Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S3002	POD: 19
Application: Two types of dry sorbents were injected into the ductwork downstream of the boiler to
reduce S02 emissions. Either calcium-based sorbent was injected upstream of the
economizer, or sodium-based sorbent downstream of the air heater. Humidification
downstream of the dry sorbent injection was incorporated to aid S02 capture and
lower flue gas temperature and gas flow before entering the fabric filter dust collector
(FFDC).
Affected SCC:
10200201
10200202
10200203
10200204
10200205
10200206
10200210
10200212
10200217
10200219
10200221
10200222
10200224
10200225
10200226
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom
Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
Industrial, Bituminous/Subbituminous Coal, Underfeed Stoker
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker**
Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Tangential)
Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Bituminous/Subbituminous Coal, Cogeneration (Bituminous Coal)
Bituminous/Subbituminous Coal, Pulverized Coal: Wet Bottom (Subbituminous Coal)
Bituminous/Subbituminous Coal, Pulverized Coal: Dry Bottom (Subbituminous Coal)
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker (Subbituminous Coal)
Bituminous/Subbituminous Coal, Traveling Grate (Overfeed) Stoker (Subbituminous)
Bituminous/Subbituminous Coal, Pulverized-Dry Bottom Tangential (Subbituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 30 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, an EPRI methodology was used for the cost estimates, with the following
cost factor is used for the non-process costs:
General Facilities: 5% of total direct process cost
Engineering and home pffice fees: 10% of total direct process cost
Process contingency: 5% of total direct process cost
Project contingency: 15% of total direct process and the above three non-process
costs
Retrofit Factor: 30%
Preproduction cost: 2% of total plant investment with retrofit costs
Inventory Capital: cost for a 30-day reagent storage
Document No. 05.09.009/9010.463	III-1246	Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
The levelized costs ($/ton of S02 removed) were calculated using the estimates of
the capital costs and increased consumable rates associated with each technology.
The costs are based on 1999 dollars. The economic factors used in these calculation
were as follows:
Lime: $ 50 / ton
Limestone: $15 /ton
Water: $0.0006 / gal
Solid Waste Disposal: $12 / ton
Operator Cost: $ 30 /hr
Useful life: 30 years
Carrying charges: 12%
Levelization factor: 1
Maintenance cost (% of capital cost): 3.0 for FGD
Cost Effectiveness: Cost effectiveness is the fuction of boiler capacity. Following cost per ton
(1999$) is used depending on the boiler capacity.
Comments:
For Boilers ,
< 100 MMBtu/hr- $1,980 per ton S02 reduced
>	100 MMBtu/hr and < 250 MMBtu/hr- $1,535 per ton S02 reduced
>	250 MMBtu/hr - $1,027 / ton of S02 reduced
Status:
Last Reviewed: 2005
Additional Information:
References:
EPA, 2003: U.S. Environmental Protection Agency: "Methdology, Assumptions, and References
Preliminary S02 Controls Cost Estimates For Industrial Boilers", October 2003.
Document No. 05.09.009/9010.463
III-1247
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: By-Product Coke Manufacturing
Control Measure Name: Vacuum Carbonate Plus Sulfur Recovery Plant
Rule Name: Not Applicable
Pechan Measure Code: S1201	POD: 12a
Application: This control is the use of vacuum carbonate to reduce S02 emissions.
This control applies to by-product coke manufacturing operations. Emissions are
classified under SCCs beginning with 303003.
Affected SCC:
30300302	Primary Metal Production, By-product Coke Manufacturing, Oven Charging
30300303	By-product Coke Manufacturing, Oven Pushing
30300304	By-product Coke Manufacturing, Quenching
30300306 By-product Coke Manufacturing, Oven Underfiring
30300308 By-product Coke Manufacturing, Oven/Door Leaks
30300313	By-product Coke Manufacturing, Coal Preheater
30300314	By-product Coke Manufacturing, Topside Leaks
30300315	Primary Metal Production, By-product Coke Manufacturing, Gas By-product Plant
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 82% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
It is assumed that costs for vacuum carbonate controls are similar to costs for flue
gas desulfurization.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
III-1249
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Distillate Oil (Industrial Boiler)
Control Measure Name: Wet Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S3007	POD: 30
Application: Two types of dry sorbents were injected into the ductwork downstream of the boiler to
reduce S02 emissions. Either calcium-based sorbent was injected upstream of the
economizer, or sodium-based sorbent downstream of the air heater. Humidification
downstream of the dry sorbent injection was incorporated to aid S02 capture and
lower flue gas temperature and gas flow before entering the fabric filter dust collector
(FFDC).
Affected SCC:
10200501 Industrial, Distillate Oil, Grades 1 and 2
Oil
Oil, 10-100 Million Btu/hr
10200503	Industrial, Distillate Oil, < 10 Million
Btu/hr
10200504	Industrial, Distillate Oil, Grade 4
Oil
Oil, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 30 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, an EPRI methodology was used for the cost estimates, with the following
cost factor is used for the non-process costs:
General Facilities: 5% of total direct process cost
Engineering and home pffice fees: 10% of total direct process cost
Process contingency: 5% of total direct process cost
Project contingency: 15% of total direct process and the above three non-process
costs
Retrofit Factor: 30%
Preproduction cost: 2% of total plant investment with retrofit costs
Inventory Capital: cost for a 30-day reagent storage
The levelized costs ($/ton of S02 removed) were calculated using the estimates of
the capital costs and increased consumable rates associated with each technology.
The costs are based on 1999 dollars. The economic factors used in these calculation
were as follows:
Lime: $ 50 / ton
10200502 Industrial, Distillate
10200505 Industrial, Distillate
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Limestone: $15 /ton
Water: $0.0006 / gal
Solid Waste Disposal: $12 / ton
Operator Cost: $ 30 /hr
Useful life: 30 years
Carrying charges: 12%
Levelization factor: 1
Maintenance cost (% of capital cost): 3.0 for FGD
Cost Effectiveness: Cost effectiveness is the fuction of boiler capacity. Following cost per ton
(1999$) is used depending on the boiler capacity.
For Boilers ,
<100 MMBtu/hr - $4,524 per ton S02 reduced
>100 MMBtu/hr and < 250 MMBtu/hr - $3,489 per ton S02 reduced
> 250 MMBtu/hr - $2,295 / ton of S02 reduced
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
EPA, 2003: U.S. Environmental Protection Agency: "Methdology, Assumptions, and References
Preliminary S02 Controls Cost Estimates For Industrial Boilers", October 2003.
Document No. 05.09.009/9010.463
III-1251
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Inorganic Chemical Manufacture
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S1101	POD: 11
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to inorganic chemical manufacture operations. Emissions from
these sources are classified under SCCs 30100509 and 30199999.
Affected SCC:
30100509 Carbon Black Production, Furnace Process: Fugitive Emissions
30199999 Chemical Manufacturing, Other Not Classified, Specify in Comments Field
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,028,000 cu. ft./min =
(1,028,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,028,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking
6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
Document No. 05.09.009/9010.463
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Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: In-process Fuel Use - Bituminous Coal
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S2201	POD: 22
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to operations with in-process bituminous coal use. Emissions from
these sources are classified under SCCs 39000288, 39000289, and 39000299.
Affected SCC:
39000288	Bituminous Coal, General (Subbituminous)
39000289	Bituminous Coal, General (Bituminous)
39000299 In-process Fuel Use, Bituminous Coal, General (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,028,000 cu. ft./min =
(1,028,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,028,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate	15 $/ton
Dibasic acid	430 $/ton
Disposal by gypsum stacking 6 $/ton
Disposal by landfill	30 $/ton
Credit for by-product	2 $/ton
Steam	3.5 $/1000 lb
Electrical energy	25 mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Lignite (Industrial Boiler)
Control Measure Name: In-duct Dry Sorbent Injection
Rule Name: Not Applicable
Pechan Measure Code: S3003	POD: 23
Application: Two types of dry sorbents were injected into the ductwork downstream of the boiler to
reduce S02 emissions. Either calcium-based sorbent was injected upstream of the
economizer, or sodium-based sorbent downstream of the air heater. Humidification
downstream of the dry sorbent injection was incorporated to aid S02 capture and
lower flue gas temperature and gas flow before entering the fabric filter dust collector
(FFDC).
Affected SCC:
10200301	Industrial, Lignite Coal, Pulverized Coal: Dry Bottom, Wall Fired
10200302	Industrial, Lignite Coal, Pulverized Coal: Dry Bottom, Tangential Fired
10200303	Industrial, Lignite Coal, Cyclone Furnace
10200304	Industrial, Lignite Coal, Traveling Grate (Overfeed) Stoker
10200306	Industrial, Lignite Coal, Spreader Stoker
10200307	Industrial, Lignite Coal, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 30 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, an EPRI methodology was used for the cost estimates, with the following
cost factor is used for the non-process costs:
General Facilities: 5% of total direct process cost
Engineering and home pffice fees: 10% of total direct process cost
Process contingency: 5% of total direct process cost
Project contingency: 15% of total direct process and the above three non-process
costs
Retrofit Factor: 30%
Preproduction cost: 2% of total plant investment with retrofit costs
Inventory Capital: cost for a 30-day reagent storage
The levelized costs ($/ton of S02 removed) were calculated using the estimates of
the capital costs and increased consumable rates associated with each technology.
The costs are based on 1999 dollars. The economic factors used in these calculation
were as follows:
Lime: $ 50 / ton
Limestone: $15 /ton
Water: $0.0006 / gal
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AT-A-GLANCE TABLE FOR POINT SOURCES
Solid Waste Disposal: $12 / ton
Operator Cost: $ 30 /hr
Useful life: 30 years
Carrying charges: 12%
Levelization factor: 1
Maintenance cost (% of capital cost): 2.0 for IDIS and SDA
Cost Effectiveness: Cost effectiveness is the fuction of boiler capacity. Following cost per ton
(1999$) is used depending on the boiler capacity.
Comments:
For Boilers ,
< 100 MMBtu/hr- $2,107 per ton S02 reduced
>	100 MMBtu/hr and < 250 MMBtu/hr- $1,526 per ton S02 reduced
>	250 MMBtu/hr - $1,111 / ton of S02 reduced
Status:
Last Reviewed: 2005
Additional Information:
References:
EPA, 2003: U.S. Environmental Protection Agency: "Methdology, Assumptions, and References
Preliminary S02 Controls Cost Estimates For Industrial Boilers", October 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Lignite (Industrial Boiler)
Control Measure Name: Spray Dryer Abosrber
Rule Name: Not Applicable
Pechan Measure Code: S3004	POD: 23
Application: Two types of dry sorbents were injected into the ductwork downstream of the boiler to
reduce S02 emissions. Either calcium-based sorbent was injected upstream of the
economizer, or sodium-based sorbent downstream of the air heater. Humidification
downstream of the dry sorbent injection was incorporated to aid S02 capture and
lower flue gas temperature and gas flow before entering the fabric filter dust collector
(FFDC).
Affected SCC:
10200301	Industrial, Lignite Coal, Pulverized Coal: Dry Bottom, Wall Fired
10200302	Industrial, Lignite Coal, Pulverized Coal: Dry Bottom, Tangential Fired
10200303	Industrial, Lignite Coal, Cyclone Furnace
10200304	Industrial, Lignite Coal, Traveling Grate (Overfeed) Stoker
10200306	Industrial, Lignite Coal, Spreader Stoker
10200307	Industrial, Lignite Coal, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 30 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, an EPRI methodology was used for the cost estimates, with the following
cost factor is used for the non-process costs:
General Facilities: 5% of total direct process cost
Engineering and home pffice fees: 10% of total direct process cost
Process contingency: 5% of total direct process cost
Project contingency: 15% of total direct process and the above three non-process
costs
Retrofit Factor: 30%
Preproduction cost: 2% of total plant investment with retrofit costs
Inventory Capital: cost for a 30-day reagent storage
The levelized costs ($/ton of S02 removed) were calculated using the estimates of
the capital costs and increased consumable rates associated with each technology.
The costs are based on 1999 dollars. The economic factors used in these calculation
were as follows:
Lime: $ 50 / ton
Limestone: $15 /ton
Water: $0.0006 / gal
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AT-A-GLANCE TABLE FOR POINT SOURCES
Solid Waste Disposal: $12 / ton
Operator Cost: $ 30 /hr
Useful life: 30 years
Carrying charges: 12%
Levelization factor: 1
Maintenance cost (% of capital cost): 2.0 for IDIS and SDA
Cost Effectiveness: Cost effectiveness is the fuction of boiler capacity. Following cost per ton
(1999$) is used depending on the boiler capacity.
Comments:
For Boilers ,
< 100 MMBtu/hr- $1,973 per ton S02 reduced
>	100 MMBtu/hr and < 250 MMBtu/hr- $1,340 per ton S02 reduced
>	250 MMBtu/hr - $804 / ton of S02 reduced
Status:
Last Reviewed: 2005
Additional Information:
References:
EPA, 2003: U.S. Environmental Protection Agency: "Methdology, Assumptions, and References
Preliminary S02 Controls Cost Estimates For Industrial Boilers", October 2003.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Lignite (Industrial Boiler)
Control Measure Name: Wet Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S3005	POD: 23
Application: Two types of dry sorbents were injected into the ductwork downstream of the boiler to
reduce S02 emissions. Either calcium-based sorbent was injected upstream of the
economizer, or sodium-based sorbent downstream of the air heater. Humidification
downstream of the dry sorbent injection was incorporated to aid S02 capture and
lower flue gas temperature and gas flow before entering the fabric filter dust collector
(FFDC).
Affected SCC:
10200301	Industrial, Lignite Coal, Pulverized Coal: Dry Bottom, Wall Fired
10200302	Industrial, Lignite Coal, Pulverized Coal: Dry Bottom, Tangential Fired
10200303	Industrial, Lignite Coal, Cyclone Furnace
10200304	Industrial, Lignite Coal, Traveling Grate (Overfeed) Stoker
10200306	Industrial, Lignite Coal, Spreader Stoker
10200307	Industrial, Lignite Coal, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 30 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, an EPRI methodology was used for the cost estimates, with the following
cost factor is used for the non-process costs:
General Facilities: 5% of total direct process cost
Engineering and home pffice fees: 10% of total direct process cost
Process contingency: 5% of total direct process cost
Project contingency: 15% of total direct process and the above three non-process
costs
Retrofit Factor: 30%
Preproduction cost: 2% of total plant investment with retrofit costs
Inventory Capital: cost for a 30-day reagent storage
The levelized costs ($/ton of S02 removed) were calculated using the estimates of
the capital costs and increased consumable rates associated with each technology.
The costs are based on 1999 dollars. The economic factors used in these calculation
were as follows:
Lime: $ 50 / ton
Limestone: $15 /ton
Water: $0.0006 / gal
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AT-A-GLANCE TABLE FOR POINT SOURCES
Solid Waste Disposal: $12 / ton
Operator Cost: $ 30 /hr
Useful life: 30 years
Carrying charges: 12%
Levelization factor: 1
Maintenance cost (% of capital cost): 3.0 for FGD
Cost Effectiveness: Cost effectiveness is the fuction of boiler capacity. Following cost per ton
(1999$) is used depending on the boiler capacity.
For Boilers ,
< 100 MMBtu/hr- $1,980 per ton S02 reduced
>	100 MMBtu/hr and < 250 MMBtu/hr- $1,535 per ton S02 reduced
>	250 MMBtu/hr - $1,027 / ton of S02 reduced
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
EPA, 2003: U.S. Environmental Protection Agency: "Methdology, Assumptions, and References
Preliminary S02 Controls Cost Estimates For Industrial Boilers", October 2003.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Lignite (Industrial Boilers)
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S2301	POD: 23
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to industrial lignite fired operations. Emissions from these sources
are classified under SCCs beginning with 102003.
Affected SCC:
10200301 Lignite, Pulverized Coal: Dry Bottom, Wall Fired
10200303 Lignite, Cyclone Furnace
10200306	Lignite, Spreader Stoker
10200307	Lignite, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,028,000 cu. ft./min =
(1,028,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,028,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
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AT-A-GLANCE TABLE FOR POINT SOURCES
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking
6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Mineral Products Industry
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S1601	POD: 16
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to S02 sources from the mineral products industry
Affected SCC:
30500606 Mineral Products, Cement Manufacturing (Dry Process), Kilns
30500612 Mineral Products, Cement Manufacturing (Dry Process), Raw Mat'l Transfer
30500622 Cement Manufacturing (Dry Process), Preheater Kiln
30500706 Mineral Products, Cement Manufacturing (Wet Process), Kilns
30500801 Ceramic Clay/Tile Manufacture, Drying ** (use SCC 3-05-008-13)
30501001	Mineral Products, Coal Mining, Cleaning, & Mat'l Handling (See 305310), Fluidized Bed
30501002	Coal Mining, Cleaning, and Material Handling (See 305310), Flash or Suspension
30501201	Fiberglass Manufacturing, Regenerative Furnace (Wool-type Fiber)
30501202	Fiberglass Manufacturing, Recuperative Furnace (Wool-type Fiber)
30501212 Fiberglass Manufacturing, Recuperative Furnace (Textile-type Fiber)
30501401	Glass Manufacture, Furnace/General**
30501402	Mineral Products, Glass Manufacture, Container Glass: Melting Furnace
30501403	Mineral Products, Glass Manufacture, Flat Glass: Melting Furnace
30501404	Glass Manufacture, Pressed and Blown Glass: Melting Furnace
30501410 Glass Manufacture, Raw Material Handling (All Types of Glass)
30501499 Glass Manufacture, See Comment **
30501604 Mineral Products, Lime Manufacture, Calcining: Rotary Kiln (See 305016-18,-19,-20,-21)
30501905 Mineral Products, Phosphate Rock, Calcining
30599999 Mineral Products, Other Not Defined, Specify in Comments Field
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
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AT-A-GLANCE TABLE FOR POINT SOURCES
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,028,000 cu. ft./min =
(1,028,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,028,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking
6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam 3.5
$/1000 lb
Electrical energy
25
mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Petroleum Industry
Control Measure Name: Flue Gas Desulfurization (FGD)
Rule Name: Not Applicable
Pechan Measure Code: S1801
POD: 18
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies S02 sources from the petroleum industry.
Affected SCC:
30600101
30600102
30600103
30600104
30600105
30600106
30600199
30600201
30600202
30600301
30600401
30600504
30600805
30600903
30600904
30600999
30601001
30601101
30601201
30601401
30609903
30609904
30699998
30699999
Process Heaters, Oil-fired **
Process Heaters, Gas-fired **
Petroleum Industry, Process Heaters, Oil-fired
Petroleum Industry, Process Heaters, Gas-fired
Process Heaters, Natural Gas-fired
Process Heaters, Process Gas-fired
Process Heaters, Other Not Classified
Petroleum Industry, Catalytic Cracking Units, Fluid Catalytic Cracking Unit
Catalytic Cracking Units, Catalyst Handling System
Catalytic Cracking Units, Thermal Catalytic Cracking Unit
Blowdown Systems, Blowdown System with Vapor Recovery System with Flaring
Petroleum Industry, Wastewater Treatment, Process Drains and Wastewater Separators
Petroleum Industry, Fugitive Emissions, Misc.-Sampling/Non-Asphalt Blowing/Purging/etc.
Flares, Natural Gas
Flares, Process Gas
Flares, Not Classified **
Sludge Converter, General
Petroleum Industry, Asphalt Blowing, General
Fluid Coking Units, General
Petroleum Coke Calcining, Coke Calciner
Incinerators, Natural Gas
Incinerators, Process Gas
Petroleum Products - Not Classified, Not Classified **
Petroleum Products - Not Classified, Not Classified **
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,028,000 cu. ft./min =
(1,028,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,028,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking
6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
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AT-A-GLANCE TABLE FOR POINT SOURCES
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Primary Lead Smelters - Sintering
Control Measure Name: Dual Absorption
Rule Name: Not Applicable
Pechan Measure Code: S2801	POD: 28
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%) to
reduce S02 emissions.
This control applies to primary lead smelters with contact absorption.
Affected SCC:
30102306 Sulfuric Acid (Contact Process), Absorber/@99.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual costs were developed from model plant data (EPA, 1985). The
costs are based on stack flowrate in cubic feet per minute.
Cost equations for dual absorption:
Capital cost = $990,000 + $9,836 * Flowrate
Operating cost = $75,800 + $12.82 * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The O&M cost components for dual absorbtion are based
on two model plants with sulfur intake of 750 tons per day and 1,500 tons per day
(EPA, 1985). There are no disposal costs and a credit for the recovered product.
Annual operating days are assumed to be 350 days. The following assumptions apply
to the cost of utilities and disposal:
Water	0.30 $/cubic meter
Steam	10.50 $/gJ
Catalyst	8,437,600 $/cubic meter
Credit for product 1,120 $/Mg
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AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.

Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.

Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Primary Metals Industry
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S1401	POD: 14
Application: This control is the use of flue gas desulfurization technologies to reduce NOx
emissions.
This control applies to S02 sources in the primary metals industry.
Affected SCC:
30300101	Primary Metal Production, Aluminum Ore (Electro-reduction), Prebaked Reduction Cell
30300102	Aluminum Ore (Electro-reduction), Horizontal Stud Soderberg Cell
30300103	Aluminum Ore (Electro-reduction), Vertical Stud Soderberg Cell
30300105 Primary Metal Production, Aluminum Ore (Electro-reduction), Anode Baking Furnace
30300199 Aluminum Ore (Electro-reduction), Not Classified **
30300813 Iron Production (See 3-03-015), Windbox
30300817 Iron Production (See 3-03-015), Cooler
30300824	Iron Production (See 3-03-015), Blast Heating Stoves
30300825	Primary Metal Production, Iron Production (See 3-03-015), Cast House
30300908 Primary Metal Prod., Steel (See 303015), Electric Arc Furnace-Carbon Steel (Stack)
30300911 Steel Manufacturing (See 3-03-015), Soaking Pits
30300933 Primary Metal Production, Steel Manufacturing (See 3-03-015), Reheat Furnaces
30300999 Primary Metal Production, Steel Manufacturing (See 3-03-015), Other Not Classified
30301001	Lead Production, Sintering: Single Stream
30301002	Lead Production, Blast Furnace Operation
30301199 Molybdenum, Other Not Classified
30399999 Other Not Classified, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min =
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AT-A-GLANCE TABLE FOR POINT SOURCES
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Primary Zinc Smelters - Sintering
Control Measure Name: Dual Absorption
Rule Name: Not Applicable
Pechan Measure Code: S2901	POD: 29
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%) to
reduce S02 emissions.
This control applies to primary lead smelters with contact absorption.
Affected SCC:
30102306 Sulfuric Acid (Contact Process), Absorber/@99.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual costs were developed from model plant data (EPA, 1985). The
costs are based on stack flowrate in cubic feet per minute.
Cost equations for dual absorption:
Capital cost = $990,000 + $9,836 * Flowrate
Operating cost = $75,800 + $12.82 * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The O&M cost components for dual absorbtion are based
on two model plants with sulfur intake of 750 tons per day and 1,500 tons per day
(EPA, 1985). There are no disposal costs and a credit for the recovered product.
Annual operating days are assumed to be 350 days. The following assumptions apply
to the cost of utilities and disposal:
Water	0.30 $/cubic meter
Steam	10.50 $/gJ
Catalyst	8,437,600 $/cubic meter
Credit for product 1,120 $/Mg
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.

Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.

Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Process Heaters (Oil and Gas Production)
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S1301	POD: 13
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to processes heaters involved in oil and gas production.
Emissions from these sources are classified under SCCs beginning with 310004.
Affected SCC:
31000402	Process Heaters, Residual Oil
31000403	Process Heaters, Crude Oil
31000404	Oil and Gas Production, Process Heaters, Natural Gas
31000405	Process Heaters, Process Gas
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
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AT-A-GLANCE TABLE FOR POINT SOURCES
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking 6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Pulp and Paper Industry (Sulfate Pulping)
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S1701	POD: 17
Application: This control is the use of flue gas desulfurization technologies to reduce NOx
emissions.
This control applies to sulfate pulping processes involved in the pulp and paper
industry. Emissions from these sources are classified under SCCs beginning with
307001.
Affected SCC:
30700104 Pulp, Paper & Wood, Sulfate Pulping, Recovery Furnace/Direct Contact Evaporator
30700106 Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping, Lime Kiln
30700110 Sulfate (Kraft) Pulping, Recovery Furnace/Indirect Contact Evaporator
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
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AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Residual Oil (Commercial/Institutional Boilers)
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S2401	POD: 24
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to residual oil-fired commercial and institutional boilers. Emissions
from these sources are classified under SCCs beginning with 103004.
Affected SCC:
10300401	Commercial/Institutional, Residual Oil, Grade 6 Oil
10300402	Commercial/Institutional, Residual Oil, 10-100 Million Btu/hr**
10300404 Commercial/Institutional, Residual Oil, Grade 5 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,028,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking
6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam 3.5
$/1000 lb
Electrical energy
25
mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Residual Oil (Commercial/Institutional Boilers)
Control Measure Name: Wet Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S3006	POD: 20
Application: Two types of dry sorbents were injected into the ductwork downstream of the boiler to
reduce S02 emissions. Either calcium-based sorbent was injected upstream of the
economizer, or sodium-based sorbent downstream of the air heater. Humidification
downstream of the dry sorbent injection was incorporated to aid S02 capture and
lower flue gas temperature and gas flow before entering the fabric filter dust collector
(FFDC).
Affected SCC:
10200401	Industrial, Residual Oil, Grade 6 Oil
10200402	Residual Oil, 10-100 Million Btu/hr**
10200404	Industrial, Residual Oil, Grade 5 Oil
10200405	Residual Oil, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 30 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In general, an EPRI methodology was used for the cost estimates, with the following
cost factor is used for the non-process costs:
General Facilities: 5% of total direct process cost
Engineering and home pffice fees: 10% of total direct process cost
Process contingency: 5% of total direct process cost
Project contingency: 15% of total direct process and the above three non-process
costs
Retrofit Factor: 30%
Preproduction cost: 2% of total plant investment with retrofit costs
Inventory Capital: cost for a 30-day reagent storage
The levelized costs ($/ton of S02 removed) were calculated using the estimates of
the capital costs and increased consumable rates associated with each technology.
The costs are based on 1999 dollars. The economic factors used in these calculation
were as follows:
Lime: $ 50 / ton
Limestone: $15 /ton
Water: $0.0006 / gal
Solid Waste Disposal: $12 / ton
Operator Cost: $ 30 /hr
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AT-A-GLANCE TABLE FOR POINT SOURCES
Useful life: 30 years
Carrying charges: 12%
Levelization factor: 1
Maintenance cost (% of capital cost): 3.0 for FGD
Cost Effectiveness: Cost effectiveness is the fuction of boiler capacity. Following cost per ton
(1999$) is used depending on the boiler capacity.
Comments:
For Boilers ,
<100 MMBtu/hr - $4,524 per ton S02 reduced
>100 MMBtu/hr and < 250 MMBtu/hr - $3,489 per ton S02 reduced
> 250 MMBtu/hr - $2,295 / ton of S02 reduced
Status:
Last Reviewed: 2005
Additional Information:
References:
EPA, 2003: U.S. Environmental Protection Agency: "Methdology, Assumptions, and References
Preliminary S02 Controls Cost Estimates For Industrial Boilers", October 2003.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Residual Oil (Industrial Boilers
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S2001	POD: 20
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to industrial residual-oil-fired boilers. Emissions from these
sources are classified under SCCs beginning with 102004.
Affected SCC:
10200401	Industrial, Residual Oil, Grade 6 Oil
10200402	Residual Oil, 10-100 Million Btu/hr**
10200404	Industrial, Residual Oil, Grade 5 Oil
10200405	Residual Oil, Cogeneration
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate	15 $/ton
Dibasic acid	430 $/ton
Disposal by gypsum stacking 6 $/ton
Disposal by landfill	30 $/ton
Credit for by-product	2 $/ton
Steam	3.5 $/1000 lb
Electrical energy	25 mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Secondary Metal Production
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S1501	POD: 15
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies secondary metal production classified under SCC 30499999.
Affected SCC:
30499999 Secondary Metal Production, Other Not Classified, Specify in Comments Field
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,028,000 cu. ft./min =
(1,028,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,028,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
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AT-A-GLANCE TABLE FOR POINT SOURCES
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate	15 $/ton
Dibasic acid	430 $/ton
Disposal by gypsum stacking 6 $/ton
Disposal by landfill	30 $/ton
Credit for by-product	2 $/tonD
Steam	3.5 $/1000 lb
Electrical energy	25 mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for the U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 17, 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Steam Generating Unit-Coal/Oil
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S2601	POD: 26
Application: This control is the use of flue gas desulfurization technologies to reduce NOx
emissions.
This control applies to coal and oil- fired steam generating units.
Affected SCC:
10200104 Anthracite Coal, Traveling Grate (Overfeed) Stoker
10200501	Industrial, Distillate Oil, Grades 1 and 2 Oil
10200502	Distillate Oil, 10-100 Million Btu/hr**
10200504	Industrial, Distillate Oil, Grade 4 Oil
10200505	Industrial, Distillate Oil, Cogeneration
10201101 Bagasse, All Boiler Sizes
10201404 CO Boiler, Residual Oil
10300102 Anthracite Coal, Traveling Grate (Overfeed) Stoker
10300309 Lignite, Spreader Stoker
10300501	Commercial/Institutional, Distillate Oil, Grades 1 and 2 Oil
10300502	Commercial/Institutional, Distillate Oil, 10-100 Million Btu/hr**
10300504 Commercial/Institutional, Distillate Oil, Grade 4 Oil
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on data for FGD scrubber cost assumptions for utility boilers
with a 3 percent coal sulfur content (Pechan, 1997). The assumptions apply to
capacities at or above 500 megawatts (MW) [approximately 1,000,000 actual cubic
feet per minute (acfm )]. For smaller sizes, the costs are scaled down using the
standard 0.6 power law. The costs are based on stack flowrate in cubic feet per
minute.
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
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AT-A-GLANCE TABLE FOR POINT SOURCES
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The percentages of each O&M cost component were
developed using a modified version of EPA's CUE Cost program (EPA, 2000). O&M
costs were calculated for a model plant with a flowrate of 800,000 acfm. The
percentage of the total O&M cost was then calculated for each O&M cost component.
A credit for the sale of by-product was subtracted from the disposal costs. A capacity
factor of 65% was assumed The following assumptions apply to the cost of utilities
and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking
6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 1981). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfur Recovery Plants - Elemental Sulfur
Control Measure Name: Amine Scrubbing
Rule Name: Not Applicable
Pechan Measure Code: S0601	POD: 06
Application: This control is the use of amine scrubbing add-on controls to reduce S02 emissions.
This control applies to stage 2 elemental sulfur recovery plants with out control, 92-
95% removal.
Affected SCC:
30103201 Elemental Sulfur Production, Mod. Claus: 2 Stage w/o Control (92-95% Removal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 98% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual costs were developed from model plant data (EPA, 1986). The
costs are based on stack flowrate in cubic feet per minute.
Cost equations for amine scrubbing:
Capital cost = $2,882,540 + $244.74 * Flow rate
Operating and Maintenance (O&M) cost = $749,170 + $148.40 * Flow rate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The O&M cost components for amine scrubbing of Claus
system tail gas are based on three model plants as given below (EPA, 1983):
Sulfur Intake Catalytic Recovery Claus Recovery
10 tons per day two-stage	95.1%
50 tons per day three-stage 96.4%
100 tons per day three-stage 96.4%
There are no disposal costs and a credit for the recovered product. Annual operating
days are assumed to be 350 days. The following assumptions apply to the cost of
utilities and disposal:
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Catalyst
a.	alumina	17 $/cubicfeet
b.	cobalt-molybdenum 170 $/cubicfeet
Reagent
a.	Diisopropanolamine 1.07 $/lb
b.	Soda	300 $/ton
Steam 6.00 $/1000 lb
Steam Condensate 1.25 $/1000 lb
Water
a.	Boiler	0.05 $/1000gal
b.	Cooling	1.50 $/1000 lb
Natural Gas 3.50 $/MMBtu
Electrical energy 0.05 $/kWh
Credit for byproduct recovery 1.88 $/ton
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
Refinery sour gas streams are generally fed to a regenerative type of H2S removal process. The
concentrated acid gas is then sent to the sulfur recovery unit. The Claus process is the most widely
used method of producing sulfur from refinery H2S (Pechan, 1999). The modified Claus process is
based on producing elemental sulfur by first converting one-third of the H2S feed by precise
combustion with air. The combustion products are then allowed to react thermally with the
remaining two-thirds of the H2S feed in the presence of a suitable catalyst to form sulfur vapor.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET) - Draft Report," prepared for
the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, NC, September 1999.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfur Recovery Plants - Elemental Sulfur
Control Measure Name: Amine Scrubbing + Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S0602	POD: 06
Application: This control is the use of amine scrubbing add-on controls combined with flue gas
desulfurization technologies to reduce S02 emissions.
This control applies to stage 4 elemental sulfur recovery plants with out control, 96-
97% removal.
Affected SCC:
30103201 Elemental Sulfur Production, Mod. Claus: 2 Stage w/o Control (92-95% Removal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99.8% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for amine scrubbing and FGD:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min = 2,882,540 + (244.74 * Flowrate)
+ ((1,0280,000/Flowrate)A0.6) * 93.3*RF*Flowrate*DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min = 2,882,540 +
(244.74 * Flowrate) + (93.3*RF*Flowrate*DEF)
Operating and Maintenance (O&M) cost = 749,170 + 148.40 * Flowrate +
3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
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AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.

Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.

Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
Refinery sour gas streams are generally fed to a regenerative type of H2S removal process. The
concentrated acid gas is then sent to the sulfur recovery unit. The Claus process is the most widely
used method of producing sulfur from refinery H2S (Pechan, 1999). The modified Claus process is
based on producing elemental sulfur by first converting one-third of the H2S feed by precise
combustion with air. The combustion products are then allowed to react thermally with the
remaining two-thirds of the H2S feed in the presence of a suitable catalyst to form sulfur vapor.
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET) - Draft Report," prepared for
the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, NC, September 1999.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfur Recovery Plants - Elemental Sulfur
Control Measure Name: Amine Scrubbing
Rule Name: Not Applicable
Pechan Measure Code: S0701	POD: 07
Application: This control is the use of amine scrubbing add-on controls to reduce S02 emissions.
This control applies to stage 3 elemental sulfur recovery plants with out control, 95-
96% removal.
Affected SCC:
30103202 Chemical, Element Sulfur, Mod. Claus-3Stage w/o Control (95-96% Removal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 98% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual costs were developed from model plant data (EPA, 1986). The
costs are based on stack flowrate in cubic feet per minute.
Cost equations for amine scrubbing:
Capital cost = $2,882,540 + $244.74 * Flow rate
Operating and Maintenance (O&M) cost = $749,170 + $148.40 * Flow rate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The O&M cost components for amine scrubbing of Claus
system tail gas are based on three model plants as given below (EPA, 1983):
Sulfur Intake Catalytic Recovery Claus Recovery
10 tons per day two-stage	95.1%
50 tons per day three-stage	96.4%
100 tons per day three-stage	96.4%
There are no disposal costs and a credit for the recovered product. Annual operating
days are assumed to be 350 days. The following assumptions apply to the cost of
utilities and disposal:
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Catalyst
a.	alumina	17 $/cubicfeet
b.	cobalt-molybdenum	170 $/cubicfeet
Reagent
a.	Diisopropanolamine	1.07 $/lb
b.	Soda	300 $/ton
Steam	6.00 $/1000 lb
Steam Condensate	1.25 $/1000 lb
Water
a.	Boiler	0.05 $/1000gal
b.	Cooling	1.50 $/1000 lb
Natural Gas	3.50 $/MMBtu
Electrical energy	0.05 $/kWh
Credit for byproduct recovery 1.88 $/ton
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
Refinery sour gas streams are generally fed to a regenerative type of H2S removal process. The
concentrated acid gas is then sent to the sulfur recovery unit. The Claus process is the most widely
used method of producing sulfur from refinery H2S (Pechan, 1999). The modified Claus process is
based on producing elemental sulfur by first converting one-third of the H2S feed by precise
combustion with air. The combustion products are then allowed to react thermally with the
remaining two-thirds of the H2S feed in the presence of a suitable catalyst to form sulfur vapor.
References:
EPA, 1983: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Review of New Performance Standards for Petroleum Refinery Claus Sulfur Recovery Plants," EPA-
450/3-83-014, Research Triangle Park, NC, August 1983.
Emmel, T.E., et al., 1986: "Cost of Controlling Directly Emitted Acidic Emissions from Major
Sources," Radian Corporation, Research Triangle Park, NC, (EPA/600/7-88-012), July 1986.
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET) - Draft Report," prepared for
the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, NC, September 1999.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfur Recovery Plants - Elemental Sulfur
Control Measure Name: Amine Scrubbing + Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S0702	POD: 07
Application: This control is the use of amine scrubbing add-on controls combined with flue gas
desulfurization technologies to reduce S02 emissions.
This control applies to stage 3 elemental sulfur recovery plants with out control, 95-
96% removal.
Affected SCC:
30103202 Chemical, Element Sulfur, Mod. Claus-3Stage w/o Control (95-96% Removal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99.8% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for amine scrubbing and FGD:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min = 2,882,540 + (244.74 * Flowrate)
+ ((1,0280,000/Flowrate)A0.6) * 93.3*RF*Flowrate*DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min = 2,882,540 +
(244.74 * Flowrate) + (93.3*RF*Flowrate*DEF)
Operating and Maintenance (O&M) cost = 749,170 + 148.40 * Flowrate +
3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.

Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.

Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
Refinery sour gas streams are generally fed to a regenerative type of H2S removal process. The
concentrated acid gas is then sent to the sulfur recovery unit. The Claus process is the most widely
used method of producing sulfur from refinery H2S (Pechan, 1999). The modified Claus process is
based on producing elemental sulfur by first converting one-third of the H2S feed by precise
combustion with air. The combustion products are then allowed to react thermally with the
remaining two-thirds of the H2S feed in the presence of a suitable catalyst to form sulfur vapor.
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET) - Draft Report," prepared for
the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, NC, September 1999.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfur Recovery Plants - Elemental Sulfur
Control Measure Name: Amine Scrubbing
Rule Name: Not Applicable
Pechan Measure Code: S0801	POD: 08
Application: This control is the use of amine scrubbing add-on controls to reduce S02 emissions.
This control applies to stage 4 elemental sulfur recovery plants with out control, 96-
97% removal.
Affected SCC:
30103203 Elemental Sulfur Production, Mod. Claus: 4 Stage w/o Control (96-97% Removal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 97% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual costs were developed from model plant data (EPA, 1986). The
costs are based on stack flowrate in cubic feet per minute.
Cost equations for amine scrubbing:
Capital cost = $2,882,540 + $244.74 * Flow rate
Operating and Maintenance (O&M) cost = $749,170 + $148.40 * Flow rate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The O&M cost components for amine scrubbing of Claus
system tail gas are based on three model plants as given below (EPA, 1983):
Sulfur Intake Catalytic Recovery Claus Recovery
10 tons per day two-stage	95.1%
50 tons per day three-stage 96.4%
100 tons per day three-stage 96.4%
There are no disposal costs and a credit for the recovered product. Annual operating
days are assumed to be 350 days. The following assumptions apply to the cost of
utilities and disposal:
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Catalyst
a.	alumina	17 $/cubicfeet
b.	cobalt-molybdenum	170 $/cubicfeet
Reagent
a.	Diisopropanolamine	1.07 $/lb
b.	Soda	300 $/ton
Steam	6.00 $/1000 lb
Steam Condensate	1.25 $/1000 lb
Water
a.	Boiler	0.05 $/1000gal
b.	Cooling	1.50 $/1000 lb
Natural Gas	3.50 $/MMBtu
Electrical energy	0.05 $/kWh
Credit for byproduct recovery 1.88 $/ton
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
Refinery sour gas streams are generally fed to a regenerative type of H2S removal process. The
concentrated acid gas is then sent to the sulfur recovery unit. The Claus process is the most widely
used method of producing sulfur from refinery H2S (Pechan, 1999). The modified Claus process is
based on producing elemental sulfur by first converting one-third of the H2S feed by precise
combustion with air. The combustion products are then allowed to react thermally with the
remaining two-thirds of the H2S feed in the presence of a suitable catalyst to form sulfur vapor.
References:
EPA, 1983: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Review of New Performance Standards for Petroleum Refinery Claus Sulfur Recovery Plants," EPA-
450/3-83-014, Research Triangle Park, NC, August 1983.
Emmel, T.E., et al., 1986: "Cost of Controlling Directly Emitted Acidic Emissions from Major
Sources," Radian Corporation, Research Triangle Park, NC, (EPA/600/7-88-012), July 1986.
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET) - Draft Report," prepared for
the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, NC, September 1999.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfur Recovery Plants - Elemental Sulfur
Control Measure Name: Amine Scrubbing + Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S0802	POD: 08
Application: This control is the use of amine scrubbing add-on controls combined with flue gas
desulfurization technologies to reduce S02 emissions.
This control applies to stage 4 elemental sulfur recovery plants with out control, 96-
97% removal.
Affected SCC:
30103203 Elemental Sulfur Production, Mod. Claus: 4 Stage w/o Control (96-97% Removal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 99.7% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for amine scrubbing and FGD:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min = 2,882,540 + (244.74 * Flowrate)
+ ((1,0280,000/Flowrate)A0.6) * 93.3*RF*Flowrate*DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min = 2,882,540 +
(244.74 * Flowrate) + (93.3*RF*Flowrate*DEF)
Operating and Maintenance (O&M) cost = 749,170 + 148.40 * Flowrate +
3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
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AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.

Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.

Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
Refinery sour gas streams are generally fed to a regenerative type of H2S removal process. The
concentrated acid gas is then sent to the sulfur recovery unit. The Claus process is the most widely
used method of producing sulfur from refinery H2S (Pechan, 1999). The modified Claus process is
based on producing elemental sulfur by first converting one-third of the H2S feed by precise
combustion with air. The combustion products are then allowed to react thermally with the
remaining two-thirds of the H2S feed in the presence of a suitable catalyst to form sulfur vapor.
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET) - Draft Report," prepared for
the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, NC, September 1999.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfur Recovery Plants - Elemental Sulfur
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S1001	POD: 10
Application: This control is the use of flue gas desulfurization technologies to reduce NOx
emissions.
This control applies elemental sulfur recovery plants classified under SCC 30103299.
Affected SCC:
30103299 Elemental Sulfur Production, Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfur Recovery Plants - Sulfur Removal
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S0901	POD: 09
Application: This control is the use of flue gas desulfurization technologies to reduce NOx
emissions.
This control applies to sulfur removal processes at sulfur recovery plants classified
under SCC 30103204.
Affected SCC:
30103204 Chem. Manufacturing, Elemental Sulfur Prod., Sulfur Removal (99.9% Removal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
The cost effectiveness is determined by dividing the annual cost by the annual tons
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AT-A-GLANCE TABLE FOR POINT SOURCES
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfuric Acid Plants - Contact Absorbers
Control Measure Name: Flue Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S0101	POD: 01
Application: This control is the use of flue gas desulfurization technologies to reduce S02
emissions.
This control applies to contact absorbers at 99% conversion involved in sulfuric acid
production classified under SCC 30102301.
Affected SCC:
30102301 Chemical Manufacturing, Sulfuric Acid (Contact Process), Absorber/@ 99.9% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min =
(1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate* DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min =
93.3*RF*Flowrate*DEF
Operating and Maintenance (O&M) cost = 3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
The cost effectiveness is determined by dividing the annual cost by the annual tons
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AT-A-GLANCE TABLE FOR POINT SOURCES
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfuric Acid Plants - Contact Absorbers
Control Measure Name: Increase Absorption Efficiency from Existing to NSPS Level (99.7%)
Rule Name: Not Applicable
Pechan Measure Code: S0201	POD: 02
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%) to
reduce S02 emissions.
This control applies to sulfuric acid plants with contact absorption processes at 99%
sulfur conversion efficiency.
Affected SCC:
30102306 Sulfuric Acid (Contact Process), Absorber/@ 99.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual costs were developed from model plant data (EPA, 1985). The
costs are based on stack flowrate in cubic feet per minute.
Cost equations for dual absorption:
Capital cost = $990,000 + $9,836 * Flowrate
Operating cost = $75,800 + $12.82 * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The O&M cost components for dual absorbtion are based
on two model plants with sulfur intake of 750 tons per day and 1,500 tons per day
(EPA, 1985). There are no disposal costs and a credit for the recovered product.
Annual operating days are assumed to be 350 days. The following assumptions apply
to the cost of utilities and disposal:
Water	0.30 $/cubic meter
Steam	10.50 $/gJ
Catalyst	8,437,600 $/cubic meter
Credit for product 1,120 $/Mg
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AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1985: U.S. Environmental Protection Agency, "Sulfuric Acid: Review of New Source
Performance Standards for Sulfuric Acid Plants," Research Triangle Park, NC, (EPA/450/3-85/012),
March 1985.
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfuric Acid Plants - Contact Absorbers
Control Measure Name: Increase Absorption Efficiency from Existing to NSPS Level (99.7%) + Flue
Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S0202	POD: 02
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%)
and the addition of flue gas desulfurization technologies to reduce S02 emissions.
This control applies to sulfuric acid plants with contact absorption processes at 99%
sulfur conversion efficiency.
Affected SCC:
30102306 Sulfuric Acid (Contact Process), Absorber/@ 99.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for dual absorption and flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min = 990,000 + (9.836 * Flowrate) +
((1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate*DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min = 990,000 + (9.836 *
Flowrate) + (93.3*RF*Flowrate*DEF)
Operating and Maintenance (O&M) cost = 75,800 + 12.82 * Flowrate +
3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
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AT-A-GLANCE TABLE FOR POINT SOURCES
Annual cost = (Capital cost * CRF) + O&M cost
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfuric Acid Plants - Contact Absorbers
Control Measure Name: Increase Absorption Efficiency from Existing to NSPS Level (99.7%)
Rule Name: Not Applicable
Pechan Measure Code: S0301	POD: 03
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%) to
reduce S02 emissions.
This control applies to sulfuric acid plants with contact absorption processes at 98%
sulfur conversion efficiency.
Affected SCC:
30102308 Sulfuric Acid (Contact Process), Absorber/@ 98.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 85% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual costs were developed from model plant data (EPA, 1985). The
costs are based on stack flowrate in cubic feet per minute.
Cost equations for dual absorption:
Capital cost = $990,000 + $9,836 * Flowrate
Operating cost = $75,800 + $12.82 * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The O&M cost components for dual absorbtion are based
on two model plants with sulfur intake of 750 tons per day and 1,500 tons per day
(EPA, 1985). There are no disposal costs and a credit for the recovered product.
Annual operating days are assumed to be 350 days. The following assumptions apply
to the cost of utilities and disposal:
Water	0.30	$/cubic meter
Steam	10.50	$/gJ
Catalyst	8,437,600	$/cubic meter
Credit for product 1,120 $/Mg
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1985: U.S. Environmental Protection Agency, "Sulfuric Acid: Review of New Source
Performance Standards for Sulfuric Acid Plants," Research Triangle Park, NC, (EPA/450/3-85/012),
March 1985.
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
Document No. 05.09.009/9010.463
III-1314
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfuric Acid Plants - Contact Absorbers
Control Measure Name: Increase Absorption Efficiency from Existing to NSPS Level (99.7%) + Flue
Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S0302	POD: 03
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%)
and the addition of flue gas desulfurization technologies to reduce S02 emissions.
This control applies to sulfuric acid plants with contact absorption processes at 98%
sulfur conversion efficiency.
Affected SCC:
30102308 Sulfuric Acid (Contact Process), Absorber/@ 98.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 85% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for dual absorption and flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min = 990,000 + (9.836 * Flowrate) +
((1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate*DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min = 990,000 + (9.836 *
Flowrate) + (93.3*RF*Flowrate*DEF)
Operating and Maintenance (O&M) cost = 75,800 + 12.82 * Flowrate +
3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Document No. 05.09.009/9010.463
III-1315
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Annual cost = (Capital cost * CRF) + O&M cost
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
Document No. 05.09.009/9010.463
III-1316
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
January 2002.
Document No. 05.09.009/9010.463
III-1317
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfuric Acid Plants - Contact Absorbers
Control Measure Name: Increase Absorption Efficiency from Existing to NSPS Level (99.7%)
Rule Name: Not Applicable
Pechan Measure Code: S0401	POD: 04
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%) to
reduce S02 emissions.
This control applies to sulfuric acid plants with contact absorption processes at 97%
sulfur conversion efficiency.
Affected SCC:
30102310 Sulfuric Acid (Contact Process), Absorber/@ 97.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual costs were developed from model plant data (EPA, 1985). The
costs are based on stack flowrate in cubic feet per minute.
Cost equations for dual absorption:
Capital cost = $990,000 + $9,836 * Flowrate
Operating cost = $75,800 + $12.82 * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The O&M cost components for dual absorbtion are based
on two model plants with sulfur intake of 750 tons per day and 1,500 tons per day
(EPA, 1985). There are no disposal costs and a credit for the recovered product.
Annual operating days are assumed to be 350 days. The following assumptions apply
to the cost of utilities and disposal:
Water	0.30 $/cubic meter
Steam	10.50 $/gJ
Catalyst	8,437,600 $/cubic meter
Credit for product 1,120 $/Mg
Document No. 05.09.009/9010.463
III-1318
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1985: U.S. Environmental Protection Agency, "Sulfuric Acid: Review of New Source
Performance Standards for Sulfuric Acid Plants," Research Triangle Park, NC, (EPA/450/3-85/012),
March 1985.
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
Document No. 05.09.009/9010.463
III-1319
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfuric Acid Plants - Contact Absorbers
Control Measure Name: Increase Absorption Efficiency from Existing to NSPS Level (99.7%) + Flue
Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S0402	POD: 04
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%)
and the addition of flue gas desulfurization technologies to reduce S02 emissions.
This control applies to sulfuric acid plants with contact absorption processes at 97%
sulfur conversion efficiency.
Affected SCC:
30102310 Sulfuric Acid (Contact Process), Absorber/@ 97.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for dual absorption and flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min = 990,000 + (9.836 * Flowrate) +
((1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate*DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min = 990,000 + (9.836 *
Flowrate) + (93.3*RF*Flowrate*DEF)
Operating and Maintenance (O&M) cost = 75,800 + 12.82 * Flowrate +
3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Document No. 05.09.009/9010.463
III-1320
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Annual cost = (Capital cost * CRF) + O&M cost
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
Document No. 05.09.009/9010.463
III-1321
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
January 2002.
Document No. 05.09.009/9010.463
III-1322
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfuric Acid Plants - Contact Absorbers
Control Measure Name: Increase Absorption Efficiency from Existing to NSPS Level (99.7%)
Rule Name: Not Applicable
Pechan Measure Code: S0501	POD: 05
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%) to
reduce S02 emissions.
This control applies to sulfuric acid plants with contact absorption processes at 93%
sulfur conversion efficiency.
Affected SCC:
30102318 Sulfuric Acid (Contact Process), Absorber/@ 93.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Capital and annual costs were developed from model plant data (EPA, 1985). The
costs are based on stack flowrate in cubic feet per minute.
Cost equations for dual absorption:
Capital cost = $990,000 + $9,836 * Flowrate
Operating cost = $75,800 + $12.82 * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Annual cost = (Capital cost * CRF) + O&M cost
O&M Cost Components: The O&M cost components for dual absorbtion are based
on two model plants with sulfur intake of 750 tons per day and 1,500 tons per day
(EPA, 1985). There are no disposal costs and a credit for the recovered product.
Annual operating days are assumed to be 350 days. The following assumptions apply
to the cost of utilities and disposal:
Water	0.30	$/cubic meter
Steam	10.50	$/gJ
Catalyst	8,437,600	$/cubic meter
Credit for product 1,120 $/Mg
Document No. 05.09.009/9010.463
III-1323
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1985: U.S. Environmental Protection Agency, "Sulfuric Acid: Review of New Source
Performance Standards for Sulfuric Acid Plants," Research Triangle Park, NC, (EPA/450/3-85/012),
March 1985.
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
Document No. 05.09.009/9010.463
III-1324
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Sulfuric Acid Plants - Contact Absorbers
Control Measure Name: Increase Absorption Efficiency from Existing to NSPS Level (99.7%) + Flue
Gas Desulfurization
Rule Name: Not Applicable
Pechan Measure Code: S0502	POD: 05
Application: This control is to increase adsorption efficiency from existing to NSPS level (99.7%)
and the addition of flue gas desulfurization technologies to reduce S02 emissions.
This control applies to sulfuric acid plants with contact absorption processes at 93%
sulfur conversion efficiency.
Affected SCC:
30102318 Sulfuric Acid (Contact Process), Absorber/@ 93.0% Conversion
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs are based on stack flowrate in cubic feet per minute. The equations below
are simplified from the EPA Control Cost Manual (EPA, 2002).
Cost equations for dual absorption and flue gas desulfurization:
Capital cost:
DEF = de-escalation factor (to convert to 1990 dollars) = 0.9383
RF = retrofit factor = 1.1
For stack flowrate less than 1,0280,000 cu. ft./min = 990,000 + (9.836 * Flowrate) +
((1,0280,000/Flowrate)A0.6)*93.3*RF*Flowrate*DEF
For stack flowrate greater than or equal to 1,0280,000 cu. ft./min = 990,000 + (9.836 *
Flowrate) + (93.3*RF*Flowrate*DEF)
Operating and Maintenance (O&M) cost = 75,800 + 12.82 * Flowrate +
3.35+0.000729*8736*DEF * Flowrate
Equipment Life in Years = Equiplife = 15 years
Interest Rate = I = 7%
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1
Document No. 05.09.009/9010.463
III-1325
Report

-------
AT-A-GLANCE TABLE FOR POINT SOURCES
Annual cost = (Capital cost * CRF) + O&M cost
The cost effectiveness is determined by dividing the annual cost by the annual tons
S02 reduced.
Cost Effectiveness: The cost effectiveness is variable depending on stack flow rate in cubic feet per
minute.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel. Limestone and lime-based reagents are most frequently used in
scrubbers in the United States (EPA, 2002). Dry and semi-dry FGD systems include spray dryers,
and dry injection into a duct or a combustion zone.
The contact process is used to produce sulfuric acid from waste gas which contains S02. First, the
waste gas must be pretreated, which usually involves dust removal, cooling, and scrubbing for
further removal of particulate matter and heavy metals, mist, and moisture. After pretreatment, the
gas is heated and passed through a catalytic converter (platinum mass units or units containing
beds of pelletized vanadium pentoxide) to oxidize the S02 to S03. The exothermic, reversible
oxidation reaction results in a conflict between high equilibrium conversions at lower temperatures
and high reaction rates at high temperatures. Because of this, the gas is passed between the
catalyst and two or three different heat exchangers in order to achieve conversion of S02 to S03 of
about 92.5 to 98 percent. The gas leaving the final catalyst stage is cooled and introduced to an
absorption tower by a stream of strong (98 to 99 percent) acid, where the S03 reacts with water in
the acid to form additional sulfuric acid. Dilute sulfuric acid or water is added to the recirculating acid
to maintain the desired concentration (EPA, 1981; EPA, 1997).
The double-contact, or double-absorption, process for making sulfuric acid from waste gas
containing S02 is essentially the same as the single-contact process with the addition of an
interpass absorption tower. The waste gas is cleaned and dried as in the single-contact process
before entering the process. Upon leaving the second or third catalyst bed, depending upon the
process, the gas is cooled and introduced to a packed-bed, counter-current absorption tower where
it contacts 98 to 99 percent sulfuric acid. After the absorbing tower, the gas is reheated and passed
to the third or fourth catalyst bed, where approximately 97 percent of the remaining S02 is
converted to S03 and passed to the final absorption tower for conversion to sulfuric acid as in the
single-contact process. No cost data were available for either single- or double-contact sulfuric acid
plants controls (EPA, 1981; EPA, 1997).
References:
EPA, 1981: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Control Techniques for Sulfur Oxide Emissions from Stationary Sources," Second Edition,
Research Triangle Park, NC, April 1981.
EPA, 1997: U.S. Environmental Protection Agency, "Compilation of Air Pollutant Emission Factors,
Volume I, Stationary Point and Area Sources," AP-42, Fifth Edition, Research Triangle Park, NC,
October 1997.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual," 6th ed., EPA/452/B-02-001, Research Triangle Park, NC,
Document No. 05.09.009/9010.463
III-1326
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
January 2002.
Document No. 05.09.009/9010.463
III-1327
Report

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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Coal-Fired
Control Measure Name: Repowering to IGCC
Rule Name: Not Applicable
Pechan Measure Code: SUT-R	POD: H
Application: Repowering is the integration of new technologies into existing power plant sites to
improve boiler and generation efficiency, thus reducing S02 emissions.
This control is applicable to electricity generating sources powered by pulverized dry-
bottom and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg




V

V*


V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by pollutant: S02 (99%); NOx (25%); Hg (90%)
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Control cost equations used for estimating the costs of repowering utility boilers were
developed for electric utility boilers. The cost equations used in this analysis are
based on cost equations developed to scale costs to smaller or larger boilers than the
model plant (EPA, 2002). Model plants were considered to have boiler design
capacities of 500 MW. Several simplifying assumptions were made in developing the
costing parameters used for this analysis. A capacity utilization factor of 65 percent
were assumed, as well as a 7-percent discount rate and 15-year lifetime of the
repowering equipment. A control efficiency of 99 percent was assumed for
repowering on all utility boiler fuel types (EPA, 1998).
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $1,566 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (500 / MW)A0.6
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $25.44 per kW per year
Variable O&M: omv = $2.42 millions per kW-hr
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Capacity Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
Note: All costs are in 1997 dollars.
Cost Effectiveness: Cost effectiveness varies depending on the nameplate capacity (in MW). The
cost effectiveness depends on the following factors: total capital costs of $783
per kW; fixed O&M costs of $25.44 per kW per year; and variable O&M costs
of $2.42 mills per kW-hr (1997$).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
There are several repowering options available to the utilities. Examples include coal to combined
cycle and coal to integrated gasification combined cycle (IGCC). Repowering improves power plant
efficiencies and implies significant waste reduction from the new systems relative to the performance
of technologies in widespread commercial use as of November 1990 (EPA, 1994). For example an
existing coal-fired plant can convert into a natural gas-combined cycle plant, resulting in higher plant
efficiency and yield lower NOx, PM and S02 emissions.
Typical repowering entails steps in which the coal handling system and the boiler are replaced with
new combustion turbines and a heat recovery boiler. The only significant part of the plant that is
maintained is the original turbine generator. However, many of the new combined-cycle plants are
packaged systems and because many older coal-fired plants were custom built, they do not always
come in standard sizes or configurations. If such facilities are to be repowered, additional work is
required to integrate the system components and this could be very costly.
The IGCC is a repowering option that required extensive gasification equipment to generate
synthetic gas from coal in order to feed the gas turbines. IGCC unit installation could also result in
significant reduction of Hg. IGCC plants offer the capability of removing the Hg from the
compressed syngas prior to combustion where the gas volume treated is much less than the low
pressure, post-combustion flow volume (Parsons, 2002). The predominant form of Hg in the IGCC
syngas is elemental and removing prior to combustion is considered to be far more cost-effective
than controlling emissions from the exhaust.
References:
EPA, 1998: U.S. Environmental Protection Agency, "Analyzing Electric Power Generation Under the
Clean Air Act Amendments, Appendix 3," March 1998.
Parsons, 2002: Parsons Infrastructure and Technology Group, Inc., "The Cost of Mercury Removal
in an IGCC Plant, Final Report," prepared for the U.S. Department of Energy, National Energy
Technology Laboratory, September 2002.
Seitz, 1994: John Seitz, U.S. Environmental Protection Agency, Office of Air Quality Planning and
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Standards, Memorandum: Subject: NOx Reasonably Available Control Technologies for the
Repowering of Utility Boilers, March, 1994.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Coal-Fired
Control Measure Name: Fuel Switching - High-Sulfur Coal to Low-Sulfur Coal
Rule Name: Not Applicable
Pechan Measure Code: SUT-S	POD: H
Application: In terms of fuel composition, sulfur content is a major factor in determining the
potential S02 emissions levels. S02 emissions can be reduced by switching from
high-sulfur to low-sulfur coal. However, the emission reduction levels will depend on
the types of coal that are being switched (DOE, 1997).
This control is applicable to electricity generating sources powered by pulverized dry-
bottom and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V




V*



V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by pollutant: S02 (60%.); PM10 (21.4%); PM2.5
(21.4%)
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs associated with switching from high-sulfur coal to low sulfur coal vary
widely depending on the original and replacement coal types. Capital costs may
include new storage and distribution systems as well as modifications to the
combustion operations. Switching from bituminous to a subbituminous coal can also
lead to an increase in the particulate matter emissions, requiring further investments
on controls.
The costs detailed here are based on fuel switching and blending from high-sulfur
content bituminous to low-sulfur bituminus and to subbituminous coal.
Cost Effectiveness: Cost effectiveness varies depending on the ranks of the old and new fuels and
is estimated based on the emission factors. The cost effectiveness ranged
from $113 to $167 per ton S02 reduced. The cost effectiveness value used in
AirControlNET is $140 per ton S02 reduced. All costs are in 1995 dollars.
Comments:
Status: Demonstrated
Last Reviewed: 2003
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Additional Information:
Coal contains noncombustible minerals and mineral oxides that are collectively referred to as ash.
In terms of fuel composition, ash content of fuel is the major factor in determining total suspended
particle emissions (TSP). The higher the ash content, the higher the amount of TSP emitted from
combustion. Fuel substitution can impact TSP emissions leading to their reduction. It should be
noted that if the new coal has a significantly lower energy content there may be an increase in TSP
emissions due to the higher amounts of coal needed to achieve the same energy output (DOE,
1994).
While effective in lowering S02 and PM emissions, the practice of switching to a low-sulfur content
can lead to reduced collection efficiency of electrostatic precipitators which are the most common
method of particulate controls for utility boilers. Lowering the flue gas sulfur content increases the
fly ash resistivity and subsequently lowers the overall particulate matter collection efficiency at these
post-combustion units. Lower particle collection efficiency in coal fired boilers leads to a lower
mercury removal efficiency. Therefore this form of fuel switching, from high-sulfur to low-sulfur coal,
is not a viable option for controlling mercury and will not be discussed in detail.
References:
DOE, 1994: U.S. Department of Energy, Energy Information Administration, Office of Coal, Nuclear,
Electric and Alternate Fuels, "Electric Utility Phase I Acid Rain Compliance Strategies for the Clean
Air Act Amendments of 1990," Washington, DC, March 1994.
DOE, 1997: U.S. Department of Energy, Energy Information Administration, Office of Coal, Nuclear,
Electric and Alternate Fuels, "The effects of Title IV of the Clean Air Act Amendments of 1990 on
Electric Utilities: An Update," DOE/EIA-0582(97), Washington, DC, March 1997.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Coal-Fired
Control Measure Name: Coal Washing
Rule Name: Not Applicable
Pechan Measure Code: SUT-W	POD: H
Application: Coal washing (or coal cleaning) is a pre-combustion process that improves the quality
of coal by removing impurities and increasing its heat content, thus reducing S02
emissions. Coal washing can also be effective in removing mercury (Hg) from the coal
and the utility plants emissions.
This control is applicable to electricity generating sources powered by pulverized dry-
bottom and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V




V*


V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by pollutant: S02 (35%); PM (45%); Hg (21%)
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs associated with coal washing are usually included in the price of coal in
terms of the added cost of the cleaned product over the original run-of-mine coal.
Disposal of the liquid wastes formed during these processes can be difficult and/or
expensive and are reflected in the operating and maintenance costs (ERG, 2000).
The cost of coal washing can vary significantly based on characteristics of the raw
coal and the types of processes involved, as well as the plant capacity. The capital
costs for coal washing facilities range form $12 to $16 per ton of coal. Operating
costs range from $3.17 to $4.40 per ton for systems that feature high BTU recovery,
high levels of ash rejection (40-50%) and 20 to 50% sulfur removal (SIU, 1997).
Cost Effectiveness: Cost effectiveness varies based on the characteristics of the raw coal, washing
processes and plant capacity from $70 to $563 per ton S02 reduced. The
average cost used in AirControlNET is $320 per ton S02 reduced. All costs
are in 1997 dollars.
Comments:
Status: Demonstrated
Last Reviewed: 2003
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Additional Information:
Coal contains noncombustible minerals and mineral oxides that are collectively referred to as ash.
Coal washing is a pre-combustion process which is used to remove ash and sulfur from the coal.
During this process rock, clay and other minerals can be separated from the coal in a liquid medium.
Coal washing is a process that is applied before delivery to the utility plant. In some cases,
however, coal is passed through a drying step at the power plant before loading into the boiler.
Coal washing can also be an effective method for removing Hg. Estimated overall reductions at
national levels were reported to be 21% (EPA, 1997).
Coal washing can separate minerals from coal through the difference in specific gravities of the
constituents or by surface-based floatation. Two types of coal washing methods can be performed
on intermediate and coarse coal:
1.	Gravity concentration method: Technologies that use this method include jigs, cyclones, shaking
tables and Reichert cones. A significant portion of coal preparation plants use jigs to separate coal
from non-coal material. The majority of jigs process wet coal, but some pneumatic jigs are also
used. Like jigs, the shaking tables, cyclones and Reichert cones rely on water flow and motion of the
equipment to separate more dense impurities from the lighter coal (EPA, 2000).
2.	Dense medium separation method: This process usually takes place in large open tanks, with
the pulverized magnetite (Fe304) in water used as the preferred medium for separation. The
density of the medium is adjusted to lie between the dense inorganic matter and the less dense
organic combustible fraction of coal. As a result, the inorganic material sinks to the bottom of the
tank and the organic coal floats to the top where it is skimmed from the tank.
Fine coal cleaning involves chemical conditioning of the coal followed by flotation to recover clean
coal. Depending on the characteristics of the coal, some mines may perform fine coal conditioning
using lime, sodium carbonate, sodium hydroxide or sulfuric acid. Conditioning is used to adjust pH,
to facilitate the flotation process (EPA, 2000).
References:
EPA, 1997: U.S. Environmental Protection Agency, "Mercury Study Report to Congress, Volume
III: Fate and Transport of Mercury in the Environment," EPA/452/R-97-005, December 1997.
EPA, 2000: U.S. Environmental Protection Agency, Office of Pollution Prevention and Toxics,
"EPCRA Section 313 Industry Guidance, Coal Mining Facilities," EPA/7450/B-00-003, Washington,
DC, February 2000.
ERG, 2000: Eastern Research Group, Inc., "Point Sources Committee Emission Inventory
Improvement Program: How to Incorporate the Effects of Air Pollution Control Device Efficiencies
and Malfunctions into Emission Inventory Estimates," prepared for U.S. Environmental Protection
Agency, July 2000.
SIU, 1997: Southern Illinois University, Office of Coal Development and Marketing, "Coal
Technology Profiles," Carbondale, IL, June 1997.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - High Sulfur Content
Control Measure Name: Flue Gas Desulfurization (Wet Scrubber Type)
Rule Name: Not Applicable
Pechan Measure Code: SUT-H	POD: H
Application: This control is based on the addition of wet scrubber type flue gas desulfurization add-
on controls to reduce S02 emissions. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel, removing PM from the gas flow. Limestone and
lime-based sorbents are most frequently used in scrubbers in the United States
(Pechan, 1997).
This control is applicable to electricity generating sources powered by pulverized dry-
bottom and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*


V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled for S02; 64% from uncontrolled for Hg
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Control cost equations used for estimating the costs of applying scrubbers were
developed for electric utility boilers. The cost equations used in this analysis are
based on cost equations developed to scale costs to smaller or larger boilers than the
model plant (EPA, 1998)). Model plants were considered to have boiler design
capacities of 500 MW. Several simplifying assumptions were made in developing the
costing parameters used for this analysis. A capacity utilization factor of 65 percent
was assumed, as well as a 7-percent discount rate and 15-year lifetime for the
scrubber. A control efficiency of 90 percent was assumed for scrubbers on all utility
boiler fuel types.
The fuel sulfur content level for these equations is 3% sulfur.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $166 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (500 / MW)A0.6
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Operating & Maintenance (O&M):
Fixed O&M: omf = $6.00 per kW per year
Variable O&M: omv = $6.30 mills per kW-hr
Capacity Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's CUE Cost (EPA, 2000) program. O&M costs were calculated
for the model plant and the percentage of the total O&M cost was then calculated for
each O&M cost component. A credit for the sale of by-product was subtracted from
the disposal costs. A capacity factor of 65% was assumed. The following
assumptions apply to the cost of utilities and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking 6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness varies depending on the nameplate capacity (in MW). The
cost effectiveness depends on the following factors: total capital costs of $166
per kW; fixed O&M costs of $6.00 per kW per year; and variable O&M costs of
$6.30 mills per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In wet systems, a liquid sorbent is sprayed into the flue gas in an absorber vessel. Limestone and
lime-based reagents are most frequently used in scrubbers in the United States (EPA, 2002a).
Studies have shown that Wet FGD can also be effective in controlling mercury emissions. The ionic
mercury compounds in coal flue gases are water-soluble and can be captured by WFGD scrubbers.
In Wet FGD, the soluble gaseous Hg is mixed with the water-based scrubbing liquid and then
removed from the flue stream with the disposed scrubbing solution. Wet Flue Gas Desulfurization
scrubbers use a caustic slurry, typically water and limestone or water and lime as S02 scrubbing
solutions.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
The level of mercury capture in Wet FGD systems depends on the relative level of Hg2+ present in
the flue gas that enters the system. The gaseous HgO is insoluble in water and does not dissolve in
such slurries. The majority of Hg2+ species in the flue gas are soluble in water. After they are
dissolved in the FGD solution, these mercury compounds are believed to react with dissolved
sulfides from the flue gas, such as H2S, to form mercuric sulfide (HgS), which precipitates from the
liquid solution as sludge. The level of Hg 2+ that enters the Wet FGD system depends on the flue
gas as well as the upstream control system (e.g., a FF and SCR, used for PM and NOx control,
respectively oxidizes the elemental mercury). A PM control device always precedes a wet Wet FGD
scrubber. Four types of PM control devices are commonly used upstream of the Wet FGD systems:
FFs, CS-ESPs, HS-ESPs, and PM scrubbers (PS). In systems with a FF upstream of the Wet FGD
system, an increase in mercury reduction is observed across the Wet FGD system due to the
oxidization of elemental mercury that occurs on the fabric filter cake. Units equipped with
FF+WFGD achieve the highest Hg reduction followed by units with CS-ESP, HS-ESP, and PS.
Units with HS-ESPs operate at temperatures where the oxidization and capture of Hg is limited;
therefore, a lower mercury reduction across the system is achieved (Massachusetts, 2002).
Mercury control efficiencies of existing post-combustion controls used for coal-fired electric utility
boilers were examined based on a series of tests that were conducted as part of a research and
development study by the National Risk Management Research Laboratory for EPA (EPA, 2002b).
Table 3 shows the overall mercury control efficiencies for the S02 co-controls. Note: the control
efficiencies are provided for a combined unit operations (WFGD plus a PM control device).
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Research and Development, Control Of Mercury Emissions From Coal-Fired Electric Utility Boilers:
Interim Report Including Errata Dated 3-21-02," EPA-600/R-01-109, April 2002.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
EPA, 1998: U.S. Environmental Protection Agency, "Analyzing Electric Power Generation Under the
Clean Air Act Amendments, Appendix 3," March 1998.
EPA, 1998: U.S. Environmental Protection Agency, "Analyzing Electric Power Generation Under the
Clean Air Act Amendments, Appendix 3," March 1998.
Massachusetts, 2002: Commonwealth of Massachusetts, Department of Environmental Protection,
Executive Office of Environmental Affairs, Division of Planning and Evaluation, Bureau of Waste
Prevention, "Evaluation Of The Technological and Economic Feasibility of Controlling and
Eliminating Mercury Emissions from the Combustion of Solid Fossil Fuel, Pursuant To 310 CMR
7.29 - Emissions Standards For Power Plants," Downloaded from
http://www.state.ma.us/dep/bwp/daqc/daqcpubs.htm#other, December 2002.
Pechan, 1997: E.H. Pechan & Associates: "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Medium Sulfur Content
Control Measure Name: Flue Gas Desulfurization (Wet Scrubber Type)
Rule Name: Not Applicable
Pechan Measure Code: SUT-M	POD: M
Application: This control is based on the addition of wet scrubber type flue gas desulfurization add-
on controls to reduce S02 emissions. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel, removing PM from the gas flow. Limestone and
lime-based sorbents are most frequently used in scrubbers in the United States
(Pechan, 1997).
This control is applicable to electricity generating sources powered by pulverized dry-
bottom, bituminous/subbituminous coal, and natural gas.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
10100217 Bituminous/Subbituminous Coal, Atm. Fluidized Bed Combustion-Bubbling (Bituminous)
10100601 Electric Generation, Natural Gas, Boilers > 100 Million Btu/hr except Tangential
10100604 Electric Generation, Natural Gas, Tangentially Fired Units
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*


V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled for S02; 64% from uncontrolled for Hg
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Control cost equations used for estimating the costs of applying scrubbers were
developed for electric utility boilers. The cost equations used in this analysis are
based on cost equations developed to scale costs to smaller or larger boilers than the
model plant (EPA, 1998). Model plants were considered to have boiler design
capacities of 500 MW. Several simplifying assumptions were made in developing the
costing parameters used for this analysis. A capacity utilization factor of 65 percent
was assumed, as well as a 7-percent discount rate and 15-year lifetime for the
scrubber. A control efficiency of 90 percent was assumed for scrubbers on all utility
boiler fuel types.
The fuel sulfur content level for these equations is 2% sulfur.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $149 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (500 / MW)A0.6
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
Operating & Maintenance (O&M):
Fixed O&M: omf = $5.40 per kW per year
Variable O&M: omv = $0.83 mills per kW-hr
Capacity Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's CUE Cost (EPA, 2000) program. O&M costs were calculated
for the model plant and the percentage of the total O&M cost was then calculated for
each O&M cost component. A credit for the sale of by-product was subtracted from
the disposal costs. A capacity factor of 65% was assumed. The following
assumptions apply to the cost of utilities and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking 6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness varies depending on the nameplate capacity (in MW). The
cost effectiveness depends on the following factors: total capital costs of $149
per kW; fixed O&M costs of $5.40 per kW per year; and variable O&M costs of
$0.83 mills per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In wet systems, a liquid sorbent is sprayed into the flue gas in an absorber vessel. Limestone and
lime-based reagents are most frequently used in scrubbers in the United States (EPA, 2002a).
Studies have shown that Wet FGD can also be effective in controlling mercury emissions. The ionic
mercury compounds in coal flue gases are water-soluble and can be captured by WFGD scrubbers.
In Wet FGD, the soluble gaseous Hg is mixed with the water-based scrubbing liquid and then
removed from the flue stream with the disposed scrubbing solution. Wet Flue Gas Desulfurization
scrubbers use a caustic slurry, typically water and limestone or water and lime as S02 scrubbing
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
solutions.
The level of mercury capture in Wet FGD systems depends on the relative level of Hg2+ present in
the flue gas that enters the system. The gaseous HgO is insoluble in water and does not dissolve in
such slurries. The majority of Hg2+ species in the flue gas are soluble in water. After they are
dissolved in the FGD solution, these mercury compounds are believed to react with dissolved
sulfides from the flue gas, such as H2S, to form mercuric sulfide (HgS), which precipitates from the
liquid solution as sludge. The level of Hg 2+ that enters the Wet FGD system depends on the flue
gas as well as the upstream control system (e.g., a FF and SCR, used for PM and NOx control,
respectively oxidizes the elemental mercury). A PM control device always precedes a wet Wet FGD
scrubber. Four types of PM control devices are commonly used upstream of the Wet FGD systems:
FFs, CS-ESPs, HS-ESPs, and PM scrubbers (PS). In systems with a FF upstream of the Wet FGD
system, an increase in mercury reduction is observed across the Wet FGD system due to the
oxidization of elemental mercury that occurs on the fabric filter cake. Units equipped with
FF+WFGD achieve the highest Hg reduction followed by units with CS-ESP, HS-ESP, and PS.
Units with HS-ESPs operate at temperatures where the oxidization and capture of Hg is limited;
therefore, a lower mercury reduction across the system is achieved (Massachusetts, 2002).
Mercury control efficiencies of existing post-combustion controls used for coal-fired electric utility
boilers were examined based on a series of tests that were conducted as part of a research and
development study by the National Risk Management Research Laboratory for EPA (EPA, 2002b).
Table 3 shows the overall mercury control efficiencies for the S02 co-controls. Note: the control
efficiencies are provided for a combined unit operations (WFGD plus a PM control device).
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Research and Development, Control Of Mercury Emissions From Coal-Fired Electric Utility Boilers:
Interim Report Including Errata Dated 3-21-02," EPA-600/R-01-109, April 2002.
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
EPA, 1998: U.S. Environmental Protection Agency, "Analyzing Electric Power Generation Under the
Clean Air Act Amendments, Appendix 3," March 1998.
Massachusetts, 2002: Commonwealth of Massachusetts, Department of Environmental Protection,
Executive Office of Environmental Affairs, Division of Planning and Evaluation, Bureau of Waste
Prevention, "Evaluation Of The Technological and Economic Feasibility of Controlling and
Eliminating Mercury Emissions from the Combustion of Solid Fossil Fuel, Pursuant To 310 CMR
7.29 - Emissions Standards For Power Plants," Downloaded from
http://www.state.ma.us/dep/bwp/daqc/daqcpubs.htm#other, December 2002.
Pechan, 1997: E.H. Pechan & Associates: "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Source Category: Utility Boilers - Very High Sulfur Content
Control Measure Name: Flue Gas Desulfurization (Wet Scrubber Type)
Rule Name: Not Applicable
Pechan Measure Code: SUT-VH	POD: VH
Application: This control is based on the addition of wet scrubber type flue gas desulfurization add-
on controls to reduce S02 emissions. In wet systems, a liquid sorbent is sprayed into
the flue gas in an absorber vessel, removing PM from the gas flow. Limestone and
lime-based sorbents are most frequently used in scrubbers in the United States
(Pechan, 1997).
This control is applicable to electricity generating sources powered by pulverized dry-
bottom and bituminous/subbituminous coal.
Affected SCC:
10100202	Electric Generation, Pulverized-Dry Bottom (Bituminous Coal)
10100203	Electric Generation, Bituminous/Subbituminous Coal, Cyclone Furnace (Bituminous)
10100212 Electric Generation, Pulverized Coal-Dry Bottom (Tangential) (Bituminous Coal)
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg






V*


V
V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: 15 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Control cost equations used for estimating the costs of applying scrubbers were
developed for electric utility boilers. The cost equations used in this analysis are
based on cost equations developed to scale costs to smaller or larger boilers than the
model plant (EPA, 1998). Model plants were considered to have boiler design
capacities of 500 MW. Several simplifying assumptions were made in developing the
costing parameters used for this analysis. A capacity utilization factor of 65 percent
was assumed, as well as a 7-percent discount rate and 15-year lifetime for the
scrubber. A control efficiency of 90 percent was assumed for scrubbers on all utility
boiler fuel types.
The fuel sulfur content level for these equations is 4% sulfur.
Capital Costs (CC):
Nameplate Capacity: netdc [=] MW
Total Capital Costs: TCC = $174 per kW
Scaling Factor: SF = (sfn / netdc)Asfe = (500 / MW)A0.6
CC (for netdc < 500) = TCC * netdc * 1000 * SF
CC (for netdc > 500) = TCC * netdc * 1000
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Operating & Maintenance (O&M):
Fixed O&M: omf = $6.30 per kW per year
Variable O&M: omv = $1.80 millions per kW-hr
Capacity Factor: capfac = 0.65
O&M = ( omf * netdc * 1000) + ( omv * netdc * 1000 * capfac * 8760 /1000)
Equipment Life in Years = Equiplife
Interest Rate = i
Capital Recovery Factor: CRF = [ i (1 + i) A Equiplife ] / [ ((1 + i )A Equiplife) -1]
Total Cost = (CRF * CC) + O&M
O&M Cost Components: The percentages of each O&M cost component were
developed using EPA's CUE Cost (EPA, 2000) program. O&M costs were calculated
for the model plant and the percentage of the total O&M cost was then calculated for
each O&M cost component. A credit for the sale of by-product was subtracted from
the disposal costs. A capacity factor of 65% was assumed. The following
assumptions apply to the cost of utilities and disposal:
Calcium Carbonate
15
$/ton
Dibasic acid
430
$/ton
Disposal by gypsum stacking 6
$/ton
Disposal by landfill
30
$/ton
Credit for by-product
2
$/ton
Steam
3.5
$/1000 lb
Electrical energy
25
mills/kWh
Note: All costs are in 1990 dollars.
Cost Effectiveness: Cost effectiveness varies depending on the nameplate capacity (in MW). The
cost effectiveness depends on the following factors: total capital costs of $174
per kW; fixed O&M costs of $6.30 per kW per year; and variable O&M costs of
$1.80 mills per kW-hr (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 2001
Additional Information:
In wet systems, a liquid sorbent is sprayed into the flue gas in an absorber vessel. Limestone and
lime-based reagents are most frequently used in scrubbers in the United States (EPA, 2002).
References:
EPA, 2000: U.S. Environmental Protection Agency, Office of Research and Development, "Coal
Utility Environmental Cost (CUECost) Version 3.0" [computer program], February 2000.
EPA, 1998: U.S. Environmental Protection Agency, "Analyzing Electric Power Generation Under the
Clean Air Act Amendments, Appendix 3," March 1998.
EPA, 1998: U.S. Environmental Protection Agency, "Analyzing Electric Power Generation Under the
Clean Air Act Amendments, Appendix 3," March 1998.
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AT-A-GLANCE TABLE FOR UTILITY SOURCES
Pechan, 1997: E.H. Pechan & Associates: "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Adhesives - Industrial
Control Measure Name: SCAQMD Rule 1168
Rule Name: South Coast Air Quality Management District Rule 1168 - Adhesive and
Sealant Applications
Pechan Measure Code: V22601
POD: 226
Application: The SCAQMD rule 1168 sets limits for adhesive and sealant VOC content. The rule
has been amended several times to require the use of waterborne, hot melt and other
types of adhesives (SCAQMD, 1996).
Emissions associated with the use of industrial adhesives are classified under SCC
2440020000.
Affected SCC:
2401020000 Wood Furniture: SIC 25, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 73% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost estimates are based on the SCAQMD Rule 1168 VOC limits. No cost
estimates were given in this document; however, the Bay Area adopted the same
limits as part of its 1991 plan. In the 1991 plan a cost estimate range was given
(BAAQMD, 1991). An estimate in the upper end of the range given in the 1991 Bay
Area Clean Air Plan, is assumed for this analysis.
Cost Effectiveness: The total cost effectiveness used in AirControlNET is $2,202 per ton VOC
reduction (1990$), an estimate in the upper end of the documented range.
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
This control measure is based on the SCAQMD's original Rule 1168 - Control of VOC Emissions
from Adhesive Application, and further reductions from the SCAQMD's amendments to its rule. At
the time of adoption, the SCAQMD's Rule 1168 was considered a technology-forcing regulation
because it assumed the future availability of low-VOC adhesives. The Bay Area AQMD adopted the
same content limits as specified in the SCAQMD's original Rule 1168.
References:
BAAQMD, 1991: Bay Area Air Quality Management District, "Bay Area'91 Clean Air Plan: Volume
III. Appendix G - Stationary Source Control Measure Descriptions," October 1991.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Pechan , 1997: E.H. Pechan & Associates: "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for U.S. Environmental Protection Agency, July
1997.
SCAQMD, 1996: South Coast Air Quality Management District, "1997 Air Quality Management
Plan - Appendix IV-A. Stationary and Mobile Source Control Measures," August 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Aircraft Surface Coating
Control Measure Name: MACT Standard
Rule Name: Maximum Achievable Control Technology for Aircraft Surface Coating
Pechan Measure Code: V25001	POD: 250
Application: This control measure represents the Aerospace Manufacturing NESHAP, promulgated
in September 1995. Options for compliance include work practice standards for
cleaning operations, carbon adsorber use, no HAP strippers, and control of HAP from
spray coating and blast depainting operations.
The rule affects over 2,800 major source facilities that produce or repair aerospace
vehicles or vehicle parts, such as airplanes, helicopters and missiles. (Pechan, 1998)
Affected SCC:
2401075000 Aircraft: SIC 372, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The nationwide annual cost of the regulation across all affected sources, including
monitoring, record keeping, and reporting, is estimated by EPA to be approximately
$20 million.
Cost Effectiveness: A cost effectiveness of $165 per ton of VOC reduced (1990$) is used, based
on EPA's assumption that 5 percent of sources will choose to incur abatement
costs, and the remaining sources will opt for pollution prevention measures
(60FR45948, 1995). Furthermore, EPA estimates the aircraft surface coating
MACT will provide a 60 percent reduction.
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
The rule has an emissions averaging provision that will allow facilities additional compliance flexibility.
References:
60FR45948, 1995: Federal Register, "National Emission Standards for Hazardous Air Pollutants for
Source Categories/Aerospace Manufacturing NESHAP, Final Rule," Vol. 60, No. 170, September
1995.
Pechan, 1998: E. H. Pechan & Associates Inc., "Emission Projections for the Clean Air Act Section
812 Prospective Analysis," June 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Architectural Coatings
Control Measure Name: AIM Coating Federal Rule
Rule Name: Architectural and Industrial Maintenance Coatings Federal Rule
Pechan Measure Code: V22001	POD: 220
Application: This federal rule provides uniformity over the state-level content limits that AIM coating
manufacturers must meet. The rule sets maximum allowable VOC content limits for 55
different categories of AIM coatings, and affects the manufacturers and importers of
the coating products. VOC content limits defined in the national rule took effect on
September 11, 1999. Manufacturers of FIFRA - regulated coatings had until March 10,
2000 to comply.
Sixty-four percent of the products included in the 1990 industry survey meet the VOC
content limits in this rule and, therefore, there will be no costs to reformulate these
products. The manufacturer of a product that does not meet the VOC content limits
will be required to reformulate the product if it will continue to be marketed, unless the
manufacturer chooses to use an alternative compliance option such as the
exceedance fee or tonnage exemption provision.
In AirControlNET, this control measure only affects architectural coatings.
Affected SCC:
2401001000 Architectural Coatings, Total: All Solvent Types
2401001999 Architectural Coatings, Solvents: NEC
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost estimates are based upon information provided to EPA by industry
representatives during the regulatory negotiation process. Industry representatives
estimated the level of effort required by a representative firm to research and develop
a new prototype coating to be 2.5 scientist-years over a 3-year time period. EPA
calculated an annualized cost of $17,772 per reformulation (1991 dollars) based on
an assumed cost of $100,000 per scientist-year as amortized over an assumed
repopulation cycle of 2.5 years.
The estimated average cost to reformulate a product was $87,000. The total
estimated national cost of the AIM Coating Federal rule is 25.6 million per year (1991
dollars).
Cost Effectiveness: EPA estimated emission reductions of 106,000 tons of VOC per year so that
the cost effectiveness is computed as $228 per ton VOC reduction (1990$)..
Comments: The EPA did not account for potential cost differences for reformulating coatings to
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AT-A-GLANCE TABLE FOR AREA SOURCES
various content limits. Instead, EPA assumed that a reformulation has a certain cost to
manufacturers regardless of the target content limit, or the anticipated VOC reduction
(Ducey, 1997).
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
In its analysis of the proposed federal rule, EPA assumed that the cost of product reformulation
would bring the VOC content limit for each noncompliant coating down to the level of the standards.
The EPA, however, noted the likelihood that some manufacturers will likely reduce the VOC content
of their coatings to levels significantly below the limits in the rule (EPA, 1996). The at-the-limit
assumption, therefore, likely results in emission reductions being understated. In its cost analysis,
insufficient data were available for EPA to distinguish reformulation costs between different coating
types (i.e., the reformulation cost for flat paints is equal to the reformulation cost for all other affected
paint types). The EPA noted the likelihood of reformulation costs varying from product to product
(EPA, 1995).
References:
Ducey, 1997: E. Ducey, U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, personal communication with D. Crocker, E.H. Pechan & Associates, Inc., February 13,
1997.
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Economic Impact and Regulatory Flexibility Analysis of the Proposed Architectural Coatings Federal
Rule," Research Triangle Park, NC, March 1995.
EPA, 1996: U.S. Environmental Protection Agency, Emission Standards Division, Office of Air and
Radiation, "Architectural Coatings - Background for Proposed Standards, Draft Report," EPA-453/R-
95-009a, March 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Architectural Coatings
Control Measure Name: South Coast Phase I
Rule Name: South Coast AQMD Rule 1113 - Architectural Coatings
Pechan Measure Code: V22002	POD: 220
Application: The Phase I rule is an amendment to SCAQMD's existing architectural coatings rule
that establishes more stringent VOC content limits for flat, multi-color, traffic, and
lacquer coatings. These VOC limits in the SCAQMD for multi-color, traffic, and lacquer
coatings took effect on January 1, 1998, while the Phase I limits for flat coating took
effect on January 1, 2001.
Reductions in VOC emissions from these coatings are achieved through the use of
product reformulation and product substitution.
In AirControlNET this measure only affects architectural coatings VOC emissions.
Affected SCC:
2401001000 Architectural Coatings, Total: All Solvent Types
2401001999 Architectural Coatings, Solvents: NEC
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 34% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: For the Phase I amendment, a SCAQMD report documents cost per gallon, total
annual cost, emission reduction and cost-effectiveness values for each of the four
regulated coating types (SCAQMD, 1996).
The SCAQMD estimated that manufacturers would use an acetone formulation with
an associated cost of $2 per gallon to meet the proposed 550 grams per liter (g/L)
VOC limit for lacquers. For flats, South Coast estimated a zero cost for complying
with the near-term 100 g/L limit since most flats sold in California are already in
compliance with this limit. For traffic and multi-color coatings, the SCAQMD
estimated that a cost savings was likely to be associated with reformulation due to a
decrease in the cost of input materials. (The estimated magnitude of the savings is
not documented in the SCAQMD report.)
Costs were estimated by multiplying the cost per gallon data to total gallons sold.
The resulting weighted average cost effectiveness value was converted to 1990
dollars using the 1995:1990 producer price index for Standard Industrial Classification
(SIC) code 2851 (Paints and Allied Products).
Because capital cost information was not available, capital costs were not estimated
for this analysis.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Cost Effectiveness: Calculated cost-effectiveness values range from $3,300 to $4,600 per ton
depending on the specified limit and coating type. The cost effectiveness
range is attributable to the wide diversity of coatings.
AirControlNET uses a cost effectiveness of $1,443 per ton VOC reduction
based on a weighted average of national sales data by coating type (EPA,
1996) (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
References:
CARB, 1989: California Air Resources Board, Stationary Source Division, "ARB-CAPCOA
Suggested Control Measure for Architectural Coatings, Technical Support Document," July 1989.
EPA, 1996: U.S. Environmental Protection Agency, Emission Standards Division, Office of Air and
Radiation, "Architectural Coatings - Background for Proposed Standards, Draft Report," EPA-453/R-
95-009a, March 1996.
SCAQMD, 1996: South Coast Air Quality Management District, "Proposed Modifications to the
Appendices of the Draft 1997 Air Quality Management Plan," October 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Architectural Coatings
Control Measure Name: South Coast Phase II
Rule Name: South Coast AQMD Rule 1113 - Architectural Coatings
Pechan Measure Code: V22003	POD: 220
Application: Phase II represents an effort to lower the VOC content limits for non-flat industrial
maintenance primers and topcoats, sealers, undercoaters, and quick-dry enamels.
The rule requires manufacturers of the coatings sold in the SCAQMD to meet the VOC
limit requirements provided in the rule between 2002 and 2006.
Reductions in VOC emissions from these coatings are achieved through the use of
product reformulation and product substitution.
In AirControlNET this measure only affects architectural coatings VOC emissions.
Affected SCC:
2401001000 Architectural Coatings, Total: All Solvent Types
2401001999 Architectural Coatings, Solvents: NEC
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 47% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: For the Phase II amendments, the SCAQMD completed a socioeconomic impact
assessment (SCAQMD, 1999). SCAQMD assumed a 10 percent price increase per
gallon for compliant coatings meeting Phase II and estimated the cost based on the
number of gallons produced. Costs vary significantly among individual coatings
categories.
Because capital cost information was not available, capital costs were not estimated
for this analysis.
Cost Effectiveness: AirControlNET uses a cost effectiveness of $4,017 per ton VOC reduction
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
The South Coast notes that the process of collecting reformulation cost data for these categories is
very complex due to the resin technology used in lower-VOC, high-performance industrial
maintenance coatings (silicon-based resins, or polyurethanes) and the number of resin systems
involved (Berry, 1997).
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Berry, 1997: N. Berry, South Coast Air Quality Management District, personal communication with
D. Crocker, E.H. Pechan & Associates, Inc., March 4, 1997.
SCAQMD, 1999: South Coast Air Quality Management District, "Addendum to Staff Report: Final
Socioeconomic Impact Assessment, Proposed Amendments to Rule 1113," May 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Architectural Coatings
Control Measure Name: South Coast Phase III
Rule Name: South Coast AQMD Rule 1113 - Architectural Coatings
Pechan Measure Code: V22004	POD: 220
Application: Phase III applies to additional consumer products that are not affected by Phase I or
II. The rule requires manufacturers to limit VOC content of the specified coatings sold
in the SCAQMD using a phased-in approach specifying compliance dates that depend
on the coating type. Compliance dates range from 1/1/03 to 7/1/08.
Reductions in VOC emissions from these coatings are achieved through the use of
product reformulation and product substitution.
The measure only applies to VOC emissions from architectural coatings in
AirControlNET.
Affected SCC:
2401001000 Architectural Coatings, Total: All Solvent Types
2401001999 Architectural Coatings, Solvents: NEC
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 73% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: SCAQMD has not yet estimated the costs for implementing the Phase III limits. As
an estimate, Pechan uses the highest incremental cost effectiveness estimate for any
individual product for the Phase II amendments of $26,000 per ton (1998 dollars).
This value is about double the average of Phase II products. This cost estimate is
highly uncertain as no specific cost data are available (Pechan, 1999).
Because capital cost information was not available, capital costs were not estimated
for this analysis.
Cost Effectiveness: AirControlNET uses an overall cost effectiveness of $10,059 per ton VOC
reduction (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
The Phase III controls apply to additional consumer products that are not affected by the near-term
measures. These measures, which are expected to take effect between 2003 and 2008, are
expected to result in an additional 26 percent VOC reduction from Phase II rules.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Pechan documentation indicates that CARB is currently funding a study to examine zero-polluting
stains, waterproofing sealers, and clear wood finishes which will be used to comply with the third
phase emission reductions.
References:
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET) - Draft Report," prepared for
the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, NC, September1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Architectural Coatings
Control Measure Name: OTC AIM Coating Rule
Rule Name: OTC AIM Coating Rule
Pechan Measure Code: V24606
POD: 220
Application: This control requires manufacturers to reformulate coatings to meet specified VOC
contents limits, which are specified in grams per liter. The VOC content limits
contained in the AIM OTC Model Rule are based on the Suggested Control Measure
(SCM) adopted by ARB, and the State and Territorial Air Pollution Program
Administrators/Association of Local Air Pollution Control Officials (STAPPA/AI_APCO)
model rule for AIM Coatings.
Affected SCC:
2401001000: Solvent Utilization: Surface Coating: Architectural Coatings: Total: All Solvent
Types
2401001999: Solvent Utilization: Surface Coating: Architectural Coatings: Solvents: NEC
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: A cost $6,628 per ton VOC reduced was estimated on ARB's SCM cost analysis.
This average cost-effectiveness was weighted by emission reductions across all the
proposed limits. Details on the assumptions used for ARB's cost analysis are
provided in the "Staff Report for the Proposed Suggested Control Measures for
Architectural Coatings," (ARB, 2000)
Cost Effectiveness: The cost effectiveness used in AirControlNET is $6,628 per ton VOC reduced.
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
ARB, 2000: California Air Resources Board, "Staff Report for the Proposed Suggested Control
Measure for the Architectural Coatings, Volume II, Technical Support Document, Section VIII,
Economic Impacts," June 2000.
Pechan 2001: E.H. Pechan & Associates, Inc., "Control Measure Development Support-Analysis of
Ozone Transport Commission Model Rules," prepared for Ozone Transport Commission, March,
2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: AREA
Control Measure Name: OTC Solvent Cleaning Rule
Rule Name: OTC Solvent Cleaning Rule
Pechan Measure Code: V24604	POD: 241
Application: This control establishes hardware and operating requirements for specified vapor
cleaning machines, as well as solvent volatility limits and operating practices for cold
cleaners.
Affected SCC:
2415305000: Solvent Utilization: Degreasing: Furniture and Fixtures (SIC 25): Cold Cleaning
2415310000: Solvent Utilization: Degreasing: Primary Metal Industries (SIC 33): Cold Cleaning
2415320000: Solvent Utilization: Degreasing: Fabricated Metal Products (SIC 34): Cold Cleaning
2415325000: Solvent Utilization: Degreasing: Industrial Machinery and Equipment (SIC 35): Cold
Cleaning
2415330000: Solvent Utilization: Degreasing: Electronic and Other Elec. (SIC 36): Cold Cleaning
2415335000: Solvent Utilization: Degreasing: Transportation Equipment (SIC 37): Cold Cleaning
2415340000: Solvent Utilization: Degreasing: Instruments and Related Products (SIC 38): Cold
Cleaning
2415345000: Solvent Utilization: Degreasing: Miscellaneous Manufacturing (SIC 39): Cold Cleaning
2415355000 Solvent Utilization: Degreasing: Automotive Dealers (SIC 55): Cold Cleaning
2415360000 Solvent Utilization: Degreasing: Auto Repair Services (SIC 75): Cold Cleaning
2415365000 Solvent Utilization: Degreasing: Miscellaneous Repair Services (SIC 76): Cold
Cleaning
2415300000 Solvent Utilization: Degreasing: All Industries: Cold Cleaning
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 66% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis:
Cost Effectiveness:
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
SCAQMD, 1997: South Coast Air Quality Management District, "Final Staff Report for Proposed
Amendments to Rule 1122 - Solvent Degreasers," June 6, 1997.
Pechan 2001: E.H. Pechan & Associates, Inc., "Control Measure Development Support-Analysis of
Ozone Transport Commission Model Rules," prepared for Ozone Transport Commission, March,
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AT-A-GLANCE TABLE FOR AREA SOURCES
2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: AREA
Control Measure Name: OTC Consumer Products Rule
Rule Name: OTC Consumer Products Rule
Pechan Measure Code: V24607	POD: 249
Application: The OTC model rule regulates approximately 80 consumer product categories, and
uses more stringent VOC content limits then the Federal rule. Examples include
aerosol adhesives, floor wax strippers, dry cleaning fluids, and general purpose
cleaners. It also contains administrative requirements for labeling, reporting, code-
dating, and a "most restrictive limit" scenario. There is a reporting requirement, such
that manufacturers may be required to submit information to the State upon written
notice.
Affected SCC:
2465100000 Solvent Utilization: Miscellaneous Non-industrial: Consumer: Personal Care Products:
Total: All Solvent Types
2465200000 Solvent Utilization: Miscellaneous Non-industrial: Consumer: Household Products:
Total: All Solvent Types
2465400000 Solvent Utilization: Miscellaneous Non-industrial: Consumer: Automotive Aftermarket
Products: Total: All Solvent Types
2465000000 Solvent Utilization: Miscellaneous Non-industrial: Consumer: All Products/Processes:
Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 39.2% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: ARB has estimated the cost of their rule to be $1032 per ton (ARB, 1999). Since the
OTC model rule emissions limits are based on California's, this value should be
approximate costs that would be incurred to meet the same limits in the OTC States.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1032 per ton VOC reduced.
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
ARB, 1999: California Air Resources Board, "Initial Statement of Reasons for Proposed
Amendments to the California Consumer Products Regulation," Stationary Source Division,
September 1999.
Pechan 2001: E.H. Pechan & Associates, Inc., "Control Measure Development Support-Analysis of
Ozone Transport Commission Model Rules," prepared for Ozone Transport Commission, March,
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2001
Source Category: AREA
Control Measure Name: OTC Mobile Equipment Repair and Refinishing Rule
Rule Name: OTC MER Rule
Pechan Measure Code: V24608	POD: 251
Application: The rule includes VOC limits for paints used in the industry that are consistent with the
Federal limits for the mobile equipment refinishing materials. The rule also establishes
requirements for using improved transfer efficiency application equipment and
enclosed spray gun cleaning, and requires minimal training.
In addition to requiring that refinishing materials meet the Federal VOC limits, the
model rule proposes a number of pollution prevention initiatives. For example, the
coating application requirements specify using improved transfer efficiency spray
equipment such as high volume-low pressure (HVLP) equipment.
Affected SCC:
2401080000 Marine: SIC 373, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 61% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis:
A cost of $2,534 per ton of VOC reduced was estimated based on the use of HVLP
spray guns and a gun cleaning system, as estimated for Pennsylvania for Rule
129.75.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,534 per ton VOC reduced.
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
Pechan 2001: E.H. Pechan & Associates, Inc., "Control Measure Development Support-Analysis of
Ozone Transport Commission Model Rules," prepared for Ozone Transport Commission, March,
2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: AREA
Control Measure Name: OTC Mobile Equipment Repair and Refinishing Rule
Rule Name: OTC MER Rule
Pechan Measure Code: V24703
POD: 247
Application: The rule includes VOC limits for paints used in the industry that are consistent with the
Federal limits for the mobile equipment refinishing materials. The rule also establishes
requirements for using improved transfer efficiency application equipment and
enclosed spray gun cleaning, and requires minimal training.
In addition to requiring that refinishing materials meet the Federal VOC limits, the
model rule proposes a number of pollution prevention initiatives. For example, the
coating application requirements specify using improved transfer efficiency spray
equipment such as high volume-low pressure (HVLP) equipment.
Affected SCC:
2401055000 Machinery and Equipment: SIC 35, Total: All Solvent Types
2401085000 Railroad: SIC 374, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 61% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: A cost of $2,534 per ton of VOC reduced was estimated based on the use of HVLP
spray guns and a gun cleaning system, as estimated for Pennsylvania for Rule
129.75.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,534 per ton VOC reduced.
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
Pechan 2001: E.H. Pechan & Associates, Inc., "Control Measure Development Support-Analysis of
Ozone Transport Commission Model Rules," prepared for Ozone Transport Commission, March,
2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: AREA
Control Measure Name: OTC Mobile Equipment Repair and Refinishing Rule
Rule Name: OTC MER Rule
Pechan Measure Code: V25002	POD: 250
Application: The rule includes VOC limits for paints used in the industry that are consistent with the
Federal limits for the mobile equipment refinishing materials. The rule also establishes
requirements for using improved transfer efficiency application equipment and
enclosed spray gun cleaning, and requires minimal training.
In addition to requiring that refinishing materials meet the Federal VOC limits, the
model rule proposes a number of pollution prevention initiatives. For example, the
coating application requirements specify using improved transfer efficiency spray
equipment such as high volume-low pressure (HVLP) equipment.
Affected SCC:
2401075000: Aircraft: SIC 372, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 61% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis:
A cost of $2,534 per ton of VOC reduced was estimated based on the use of HVLP
spray guns and a gun cleaning system, as estimated for Pennsylvania for Rule
129.75.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,534 per ton VOC reduced.
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
Pechan 2001: E.H. Pechan & Associates, Inc., "Control Measure Development Support-Analysis of
Ozone Transport Commission Model Rules," prepared for Ozone Transport Commission, March,
2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: AREA
Control Measure Name: OTC Mobile Equipment Repair and Refinishing Rule
Rule Name: OTC MER Rule
Pechan Measure Code: V25403	POD: 246
Application: The rule includes VOC limits for paints used in the industry that are consistent with the
Federal limits for the mobile equipment refinishing materials. The rule also establishes
requirements for using improved transfer efficiency application equipment and
enclosed spray gun cleaning, and requires minimal training.
In addition to requiring that refinishing materials meet the Federal VOC limits, the
model rule proposes a number of pollution prevention initiatives. For example, the
coating application requirements specify using improved transfer efficiency spray
equipment such as high volume-low pressure (HVLP) equipment.
Affected SCC:
2401005000 Auto Refinishing: SIC 7532, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 61% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis:
A cost of $2,534 per ton of VOC reduced was estimated based on the use of HVLP
spray guns and a gun cleaning system, as estimated for Pennsylvania for Rule
129.75.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,534 per ton VOC reduced.
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
Pechan 2001: E.H. Pechan & Associates, Inc., "Control Measure Development Support-Analysis of
Ozone Transport Commission Model Rules," prepared for Ozone Transport Commission, March,
2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: AREA
Control Measure Name: OTC Consumer Products Rule
Rule Name: OTC Consumer Products Rule
Pechan Measure Code: V26904	POD: 269
Application: The OTC model rule regulates approximately 80 consumer product categories, and
uses more stringent VOC content limits then the Federal rule. Examples include
aerosol adhesives, floor wax strippers, dry cleaning fluids, and general purpose
cleaners. It also contains administrative requirements for labeling, reporting, code-
dating, and a "most restrictive limit" scenario. There is a reporting requirement, such
that manufacturers may be required to submit information to the State upon written
notice.
Affected SCC:
2465600000 Adhesives and Sealants, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 39.2% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: ARB has estimated the cost of their rule to be $1032 per ton (ARB, 1999). Since the
OTC model rule emissions limits are based on California's, this value should be
approximate costs that would be incurred to meet the same limits in the OTC States.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1032 per ton VOC reduced.
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
References:
ARB, 1999: California Air Resources Board, "Initial Statement of Reasons for Proposed
Amendments to the California Consumer Products Regulation," Stationary Source Division,
September 1999.
Pechan 2001: E.H. Pechan & Associates, Inc., "Control Measure Development Support-Analysis of
Ozone Transport Commission Model Rules," prepared for Ozone Transport Commission, March,
2001.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Automobile Refinishing
Control Measure Name: Federal Rule
Rule Name: Federal Rule
Pechan Measure Code: V24601	POD: 246
Application: This control is based on EPA proposed standards to reduce emissions of volatile
organic compounds (VOC) from the use of automobile refinish coatings.
This rule applies to automobile refinish coatings that are manufactured or imported for
sale or distribution in the United States. Coatings that are currently used for
automobile refinishing are also used outside the automobile refinish industry (Pechan,
1998).
Affected SCC:
2401005000 Auto Refinishing: SIC 7532, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 37% from uncontrolled
Equipment Life: Unavailable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: EPA calculated the total costs of the regulation as the sum of the costs for necessary
process modifications and employee training costs.
The total capital investment for process modifications is $10 million, including the
costs for pumping and mixing equipment capable of processing higher-solids
coatings. The costs for training personnel to use the new coatings was estimated
separately for coating manufacturers, distributors, and body shops. A training cost of
$425 per employee was applied to manufacturing employees, distributors, and
painters at body shops. Process modification and training costs were annualized
over 10 years at an interest rate of 7 percent for a total annual cost of $4.5 million
(EPA, 1995).
Cost Effectiveness: The cost effectiveness is $118 per ton VOC reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
EPA's documents acknowledge that research and development costs associated with formulating
low-VOC coatings were not considered, since these costs are assumed to have been incurred as the
result of state regulations (EPA, 1995).
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Volatile Organic Compound Emissions from Automobile Refinishing-Background Information for
Proposed Standards," Research Triangle Park, NC, EPA-453/D-95-005a, August 1995.
Pechan, 1998: E.H. Pechan & Associates, "Clean Air Act Section 812 Prospective Cost Analysis -
Draft Report" prepared for prepared for U.S. Environmental Protection Agency, September 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Automobile Refinishing
Control Measure Name: CARB BARCT Limits
Rule Name: California Air Resources Board Best Available Retrofit Control Technology
Pechan Measure Code: V24602	POD: 246
Application: The CARB BARCT rule establishes VOC content limits for automobile refinishing
coatings, the use of equipment that achieves a 65% transfer efficiency, cleanup of
spray equipment in an enclosed system, and specifies other housekeeping procedures.
These limits apply to any coating applied to motor vehicles. Emissions from auto body
refinishing can be classified in three categories (and percentage contribution): surface
preparation (1.6%), coating application (91.0%), and spray gun cleaning (7.4%).
Affected SCC:
2401005000 Auto Refinishing: SIC 7532, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 47% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost effectiveness was derived from BARCT limits using a weighted average of costs
from surface preparation product limits and spray gun cleaners (Pechan, 1994).
Costs for reformulating preparation products are estimated to be $900 per ton for
additional equipment to facilitate longer drying times needed for these coatings. A
savings of $900 per ton is documented for the use of spray gun cleaners due to the
reduction in solvent usage.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $750 per ton VOC reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1994
Additional Information:
The low-VOC coatings that meet the BARCT limits require significantly longer drying times, and may
require the purchase of additional equipment (e.g. heating lamps) in areas with weather conditions
unlike California's (Pechan, 1994).
Surface preparation emissions may be reduced through the use of low VOC-preparation products.
These products generally consist of more detergents (and less solvent) and must remain on the
surface longer and require additional rubbing for thorough removal of dirt, grease and old paint.
Emissions from coating applications can be reduced through low VOC content coatings (high solids
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AT-A-GLANCE TABLE FOR AREA SOURCES
or waterborne coatings) and/or increased transfer efficiency (e.g. high volume, low pressure spray
equipment).
Equipment cleaning emissions can be reduced through the use of gun cleaners which either
recirculate solvent or minimize evaporation.
References:
Pechan, 1994: E.H. Pechan & Associates, Inc., "Analysis of Incremental Emission Reductions and
Costs of VOC and NOx Control Measures - Draft Report," prepared for U.S. Environmental
Protection Agency, Ambient Standards Branch, Research Triangle Park, NC, September 1994.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Automobile Refinishing
Control Measure Name: California FIP Rule (VOC content & TE)
Rule Name: California Federal Implementation Plan Rule (VOC Content &TE)
Pechan Measure Code: V24603	POD: 246
Application: The Federal Implementation Plan (FIP) rule controls VOC emissions from automobile
refinishing operations. This FIP rule requires the use of low-VOC coatings or the use
of an emission control system, and a transfer efficiency for all coating application
equipment equivalent to that of high-volume, low-pressure (HVLP) spray equipment
(Radian, 1994).
The FIP rule applies to all facilities that apply coatings of any kind to motor vehicles
and mobile equipment for the purpose of on-site refinishing and modification. Affected
facilities include auto body repair/paint shops, production auto body paint shops, new
car dealer repair/paint shops, fleet operator repair/paint shops, custom-made car
fabrication facilities, and truck body builders (Radian, 1994).
Affected SCC:
2401005000 Auto Refinishing: SIC 7532, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 89% from uncontrolled
Equipment Life: Unavailable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost of implementing this FIP rule was estimated using data developed by the
SCAQMD for Rule 1151 (SCAQMD, 1991). The SCAQMD Rule 1151 regulates
emissions from solvent operations, however the FIP rule does not. To account for the
difference in regulations, the cost is calculated as the difference between the total
cost of SCAQMD Rule 1151 and the cost of solvent operations. The cost
effectiveness was calculated based on an estimate of 26.4 tpd VOC reduced (Radian,
1994).
Cost of Rule 1151: $201,100 per day
Cost of Solvent Operations: $11,500 per day
Difference = $189,600 per day
Cost Effectiveness = Difference / Tons Reduced Per Day = $7,200 per ton VOC
reduced
Note: All costs are in 1990 dollars.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $7,200 per ton VOC reduction.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Comments:
Status: Demonstrated
Last Reviewed: 1994
Additional Information:
CARB notes that the FIP rule is based largely on SCAQMD Rule 1151 and that portions of the FIP
rule are based on the CARB Determination of Reasonably Available Control Technology and Best
Available Retrofit Control Technology for Automotive Refinishing Operations (CARB, 1991).
References:
CARB, 1991: California Air Resources Board Criteria Pollutants Branch, Stationary Source Division,
"Determination of Reasonably Available Control Technology and Best Available Retrofit Control
Technology for Automotive Refinishing Operations," January 1991.
Radian, 1994: Radian Corporation, "Technical Support Document for Proposed FIP Automotive
Refinishing Operations Rule 52.961(c)," prepared for U.S. Environmental Protection Agency,
February 1994.
SCAQMD, 1991: South Coast Air Quality Management District, Rule Development Division,
"Supplemental Staff Report, Proposed Amended Rule 1151 - Motor Vehicle and Mobile Equipment
Non-Assembly Line Coating Operations," August 1991.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Bakery Products
Control Measure Name: Incineration >100,000 lbs bread
Rule Name: Not Applicable
Pechan Measure Code: V27102	POD: 271
Application: The control measure is based on the regulation adopted by the BAAQMD, which
assumes emissions reductions from the use of catalytic incinerators. These
incinerators use a catalyst to achieve very high control efficiencies at relatively low
operating temperatures (320 to 650 °C).
The BAAQMD control requirements affect only large, commercial bread bakeries,
classified under SCC 2302050000.
Affected SCC:
2302050000 Bakery Products, Total
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 40% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs for catalytic incinerators were developed using a spreadsheet cost model
provided by EPA. The spreadsheet model uses the procedures documented in the
OAQPS Control Cost Manual for developing costs for catalytic incinerators (EPA,
1990). Oven parameters that were used in the spreadsheet model to calculate
capital, operating and maintenance (O&M) costs, and cost effectiveness were
provided by EPA (1992).
Fixed annual costs for taxes, insurance, and administration were estimated as 4
percent of total installed capital costs. Capital recovery costs were estimated using a
factor of 0.1424 (based on a 7 percent interest rate and 10-year equipment life) times
total installed capital costs.
The spreadsheet model was used to estimate costs as follows:
Capital costs= $3,880 per ton VOC reduced
O&M costs= $800 per ton VOC reduced
The equipment costs in the spreadsheet model provided by EPA are in 1988 dollars.
The costs were indexed to 1990 dollars using the 1988-1990 equipment cost indices
for catalytic incinerators (M&S, 1991; EPA, 1995).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,470 per ton VOC reduced
(1990$).
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Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
The BAAQMD regulation was estimated to achieve an overall source category control level of 39.9
percent in 1993 (Schultz, 1997). The BAAQMD's regulation was selected as the basis for the control
measure because their regulation limits control requirements to large, commercial bread bakeries.
References:
EPA, 1990: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"OAQPS Control Cost Manual, Fourth Edition," EPA-450/3-90-006, Research Triangle Park, NC,
January 1990.
EPA, 1992: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Alternative Control Technology Document for Bakery Oven Emissions," Research Triangle Park,
NC, December 1992.
EPA, 1995: U.S. Environmental Protection Agency, "Office of Air Quality Planning and Standards,
Escalation Indices for Air Pollution Control Costs," EPA-452/R-95-006, Research Triangle Park, NC,
October 1995.
M&S, 1991: "Chemical Engineering, Marshall & Swift Equipment Cost Indices," February 1991.
Schultz, 1997: Schultz, S., BAAQMD, San Francisco, CA, personal communication with M. Cohen,
E.H. Pechan & Associates, Inc. February 20, 1997.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Commercial Adhesives
Control Measure Name: Federal Consumer Solvents Rule
Rule Name: Federal Consumer Solvents Rule
Pechan Measure Code: V26901	POD: 269
Application: This Federal rule provides uniformity over the state-level content limits that
commercial adhesives must meet. The rule sets maximum allowable VOC content
limits for 24 consumer product categories. The final rule was promulgated in 1998.
The proposed Federal rule covers those consumer products that EPA determined to
be most amenable to regulation, and were capable of achieving significant VOC
reductions without significant effects on product quality or price (EPA, 1995). Affected
adhesives are used in a wide variety of industrial applications, including product
manufacturing, packaging, construction, and installation of metal, wood and plastic
materials. For most adhesives, VOC emissions occur as the result of evaporation of
solvents during transfer, drying, surface preparation, and clean-up operations.
Affected SCC:
2465600000 Adhesives and Sealants, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost values are based upon the EPA's Economic Impact and Regulatory Flexibility
Analysis of the Regulation of VOCs from Consumer Products (EPA, 1996).
The cost estimate in the Federal rule was converted from 1991 dollars to 1990 dollars
using the producer price index for SIC code 284 (BLS, 1996).
Cost Effectiveness: An estimate of $232 (in 1990 dollars) per ton VOC reduced is used in
AirControlNET.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:

The Federal rule required companies to do what they (in most cases) had already done to comply
with CARB's and other states'
rules in existence before EPA's efforts.
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References:
BLS, 1996: Bureau of Labor Statistics, U.S. Department of Labor, "Producer Price Indices,"
Washington, DC, 1996.
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Study of Volatile Organic Compound Emissions from Consumer and Commercial Products, Report
to Congress," EPA-453/R-94-066-A, Research Triangle Park, NC, March 1995.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Economic Impact and Regulatory Flexibility Analysis of the Regulation of VOCs from Consumer
Products," EPA-453/R-96-014, Research Triangle Park, NC, October 1996.
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Source Category: Commercial Adhesives
Control Measure Name: CARB Mid-Term Limits
Rule Name: California Air Resources Board Mid-Term Limits (Based on SCAQMD Rule
1168)
Pechan Measure Code: V26902	POD: 269
Application: CARB rules included in this control are Phase I and Phase II Consumer Products and
Mid-Term I and Mid-Term II Consumer Products regulations. The CARB Mid-Term
(and Near-Term) limits set VOC content standards for various consumer products.
The regulations were implemented over a time period from 1993 to 2005. These
regulations assume that emissions will be reduced through product reformulation
(CARB, 1990).
Sources affected by these regulations include, but are not limited to, antiperspirants
and deodorants, aerosol coating products, and hairspray. Affected sources are
classified under SCC 2465600000.
Affected SCC:
2465600000 Adhesives and Sealants, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost effectiveness were estimated for CARB's consumer product regulations, and the
overall cost effectiveness for mid-term limits measure (includes all limits for near-term
and mid-term) were based on the emission reductions and costs for individual
regulations.
Average Cost Effectiveness for Individual Regulations:
Antiperspirants and Deodorants = $0.92 per pound
Phase I Consumer Products = $0.90 per pound
Phase II Consumer Produces = $0.55 per pound
Aerosol Coating Products = $3.03 per pound
Hairspray = $2.25 per pound
Mid-Term I Consumer Products = $0.25 per pound
Mid-Term II Consumer Products = $0.40 per pound
It should be noted that CARB expects costs to be incurred only through the first 15
years or so of regulation, due to research and development and changes to
production lines.
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Cost Effectiveness: The estimate used in AirControlNET is $2,192 (in 1990 dollars) per ton VOC
reduced, based on the individual average cost effectiveness estimates of CARB
regulations.
Comments:
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
The CARB plans to reduce VOC emissions from the consumer products category using three types
of control measures: near-term, mid-term, and long-term measures. Near-term measures include
VOC content limits for antiperspirants, Phase I consumer products, and Phase II consumer
products. The CARB is implementing the near-term measures as follows:
1)	Initial VOC limits for:
Antiperspirants by 1993,
Phase I consumer products by 1994,
Phase II consumer products by 1995;
2)	More stringent VOC content limits for:
Antiperspirants by 1999,
Selected Phase I products by 1996 and 1999,
Selected Phase II products by 1997 and 1998.
Some of CARB's standards were identified as technology-forcing because they cannot be met by
manufacturers at the time of rule adoption, but can be met within the time-frame provided by the
regulation.
The CARB's mid-term controls apply to additional consumer products that are not affected by the
near-term measures. These measures are to achieve an additional 25 percent reduction in overall
VOC emissions from consumer products by 2005.
References:
CARB, 1990: California Air Resources Board, Stationary Source Division, "Proposed Regulation to
Reduce Volatile Organic Compound Emissions from Consumer Products - Technical Support
Document," August 1990.
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Source Category: Commercial Adhesives
Control Measure Name: CARB Long-Term Limits
Rule Name: California Air Resources Board Long-Term Limits (Based on SCAQMD
Rule 1168)
Pechan Measure Code: V26903	POD: 269
Application: The CARB's long-term measures depend on future technological innovation and
market incentive methods that can be developed and implemented before 2010.
Sources affected by these regulations include, but are not limited to, antiperspirants
and deodorants, aerosol coating products, and hairspray. Affected sources are
classified under SCC 2465600000.
Affected SCC:
2465600000 Adhesives and Sealants, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 85% from uncontrolled
Equipment Life: Unavailable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: An incremental cost per ton of $4,680 is assumed, double the average cost through
the mid-term limits (Pechan, 1999). In 1990 dollars, this is $4,257 per ton. Overall
cost effectiveness for this measure (combining near-term, mid-term, and long-term) is
$2,880 per ton of VOC reduced.
Cost Effectiveness: The overall cost effectiveness used in AirControlNET is $2,880 per ton VOC
reduced (1990$).
Comments:
Status: Future
Last Reviewed: 1997
Additional Information:
References:
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET)," prepared for the U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle
Park, NC, September 1999.
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Source Category: Consumer Solvents
Control Measure Name: Federal Consumer Solvents Rule
Rule Name: Federal Consumer Solvents Rule
Pechan Measure Code: V24901
POD: 249
Application: This Federal rule provides uniformity over the state-level content limits that
commercial adhesive must meet. The rule sets maximum allowable VOC content
limits for 24 consumer product categories. The final rule was promulgated in 1998.
The proposed Federal rule covers those consumer products that EPA determined to
be most amenable to regulation, and were capable of achieving significant VOC
reductions without significant effects on product quality or price (EPA, 1995).
Consumer products include, but are not limited to, personal care products, household
cleaners and disinfectants, automotive aftermarket products, adhesives and sealants,
lawn and garden products, and household insecticides. (60 FR 15264, 1995).
Affected SCC:
2465000000 All Products/Processes, Total: All Solvent Types
2465100000 Personal Care Products, Total: All Solvent Types
2465200000 Household Products, Total: All Solvent Types
2465400000 Automotive Aftermarket Products, Total: All Solvent Types
2461600000 Miscellaneous Non-Industrial: Commercial - Adhesives and Sealants
2461850000 Miscellaneous Non-Industrial: Commercial - Pesticide Application
2465900000 Misc. Non-Industrial: Consumer - Misc. Products - Not Elsewhere Classified
2495000000 All Solvent User Groups
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 25% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost values are based upon the EPA's Economic Impact and Regulatory Flexibility
Analysis of the Regulation of VOCs from Consumer Products (EPA, 1996).
The cost estimate in the Federal rule was converted from 1991 dollars to 1990 dollars
using the producer price index for SIC code 284 (BLS, 1996).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $232 per ton VOC reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1999
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Additional Information:
The Federal rule required companies to do what they (in most cases) had already done to comply
with CARB's and other states' rules in existence before EPA's efforts.
References:
BLS, 1996: Bureau of Labor Statistics, U.S. Department of Labor, "Producer Price Indices,"
Washington, DC, 1996.
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Study of Volatile Organic Compound Emissions from Consumer and Commercial Products, Report
to Congress," EPA-453/R-94-066-A, Research Triangle Park, NC, March 1995.
61FR14531, 1996: Federal Register, "National Volatile Organic Compound Emission Standards for
Consumer Products, Proposed Rule," Volume 61, Number 64, April 2, 1996.
EPA, 1996: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Economic Impact and Regulatory Flexibility Analysis of the Regulation of VOCs from Consumer
Products, Draft Report, EPA-453/R-96-014, Research Triangle Park, NC, October 1996.
Moore, 1997: B. Moore, U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, personal communication with D. Crocker, E.H. Pechan & Associates, Inc., February 24,
1997.
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Source Category: Consumer Solvents
Control Measure Name: CARB Mid-Term Limits
Rule Name: California Air Resources Board Consumer Products Mid-Term Limits
Pechan Measure Code: V24902	POD: 249
Application: CARB rules included in this control are Phase I and Phase II Consumer Products and
Mid-Term I and Mid-Term II Consumer Products regulations. The CARB Mid-Term
(and Near-Term) limits set VOC content standards for various consumer products.
The regulations were implemented over a time period from 1993 to 2005. These
regulations assume that emissions will be reduced through product reformulation
(CARB, 1990).
Consumer products affected by this control measure include, but are not limited to,
personal care products, household cleaners and disinfectants, automotive aftermarket
products, adhesives and sealants, lawn and garden products, and household
insecticides.
Affected SCC:
2465000000 All Products/Processes, Total: All Solvent Types
2465100000 Personal Care Products, Total: All Solvent Types
2465200000 Household Products, Total: All Solvent Types
2465400000 Automotive Aftermarket Products, Total: All Solvent Types
2461600000 Miscellaneous Non-Industrial: Commercial - Adhesives and Sealants
2461850000 Miscellaneous Non-Industrial: Commercial - Pesticide Application
2465900000 Misc. Non-Industrial: Consumer - Misc. Products - Not Elsewhere Classified
2495000000 All Solvent User Groups
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost effectiveness were estimated for CARB's consumer product regulations, and the
overall cost effectiveness for mid-term limits measure (includes all limits for near-term
and mid-term) were based on the emission reductions and costs for individual
regulations.
Average Cost Effectiveness for Individual Regulations:
Antiperspirants and Deodorants = $0.92 per pound
Phase I Consumer Products = $0.90 per pound
Phase II Consumer Produces = $0.55 per pound
Aerosol Coating Products = $3.03 per pound
Hairspray = $2.25 per pound
Mid-Term I Consumer Products = $0.25 per pound
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Mid-Term II Consumer Products = $0.40 per pound
It should be noted that CARB expects costs to be incurred only through the first 15
years or so of regulation, due to research and development and changes to
production lines.
Cost Effectiveness: The estimate used in AirControlNET is $2,192 (in 1990 dollars) per ton VOC
reduced, based on the individual average cost effectiveness estimates of CARB
regulations.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
The CARB plans to reduce VOC emissions from the consumer products category using three types
of control measures: near-term, mid-term, and long-term measures. Near-term measures include
VOC content limits for antiperspirants, Phase I consumer products, and Phase II consumer
products. The CARB is implementing the near-term measures as follows:
1)	Initial VOC limits for:
Antiperspirants by 1993,
Phase I consumer products by 1994, and
Phase II consumer products by 1995;
2)	More stringent VOC content limits for:
Antiperspirants by 1999,
Selected Phase I products by 1996 and 1999, and
Selected Phase II products by 1997 and 1998.
Some of CARB's standards were identified as technology-forcing because they cannot be met by
manufacturers at the time of rule adoption, but can be met within the time-frame provided by the
regulation.
The CARB's mid-term controls (Phase III) apply to additional consumer products that are not
affected by the near-term measures. These measures are to achieve an additional 25 percent
reduction in overall VOC emissions from consumer products by 2005.
References:
CARB, 1990: California Air Resources Board, Stationary Source Division, "Proposed Regulation to
Reduce Volatile Organic Compound Emissions from Consumer Products - Technical Support
Document," August 1990.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Consumer Solvents
Control Measure Name: CARB Long-Term Limits
Rule Name: California Air Resources Board Consumer Products Long-Term Limits Rule
Pechan Measure Code: V24903
POD: 249
Application: The CARB's long-term measures depend on future technological innovation and
market incentive methods that can be developed and implemented before 2010.
Consumer products affected by this control measure include, but are not limited to,
personal care products, household cleaners and disinfectants, automotive aftermarket
products, adhesives and sealants, lawn and garden products, and household
insecticides.
Affected SCC:
2465000000 All Products/Processes, Total: All Solvent Types
2465100000 Personal Care Products, Total: All Solvent Types
2465200000 Household Products, Total: All Solvent Types
2465400000 Automotive Aftermarket Products, Total: All Solvent Types
2461600000 Miscellaneous Non-Industrial: Commercial - Adhesives and Sealants
2461850000 Miscellaneous Non-Industrial: Commercial - Pesticide Application
2465900000 Misc. Non-Industrial: Consumer - Misc. Products - Not Elsewhere Classified
2495000000 All Solvent User Groups
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 85% from uncontrolled
Equipment Life: Unavailable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: An incremental cost per ton of $4,680 is assumed, double the average cost through
the mid-term limits (Pechan, 1999). In 1990 dollars, this is $4,257 per ton. Overall
cost effectiveness for this measure (combining near-term, mid-term, and long-term) is
$2,880 per ton of VOC reduced.
Cost Effectiveness: The overall cost effectiveness used in AirControlNET is $2,880 per ton VOC
reduced (1990$).
Comments:
Status: Future
Last Reviewed: 1999
Additional Information:
References:
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET)," prepared for the U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle
Park, NC, September 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Cutback Asphalt
Control Measure Name: Switch to Emulsified Asphalts
Rule Name: Not Applicable
Pechan Measure Code: V27201
POD: 272
Application: Generic control measure replacing VOC-containing cutback asphalt with VOC-free
emulsified asphalt.
Affected SCC:
2461021000 Cutback Asphalt, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 100% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Pechan estimates that the cost effectiveness is $15 per ton to require driveways to be
paved with non-hydrocarbon asphalt (Pechan, 1997).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $15 per ton VOC reduced.
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
References:
Pechan, 1997: E.H. Pechan & Associates, Inc.," Control Measure Evaluations Prepared for
Southeast Pennsylvania Ozone Stakeholders Group."
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Electrical/Electronic Coating
Control Measure Name: MACT Standard
Rule Name: Maximum Achievable Control Technology for Electrical/Electronic Coating
Pechan Measure Code: V25301	POD: 253
Application: MACT control options for reducing VOC emissions from the manufacture of electronics
equipment include the use of low-VOC coatings and add-on control equipment (spray
guns, venting to emission control systems, and paint booth enclosures).
This control applies to the miscellaneous electronic equipment coating source
category, including VOC emissions resulting from the manufacture of circuit boards
and components, including resistors, transistors, semiconductors, coils, and
transformers. Emissions for this source category are classified under SCC
2401065000.
Affected SCC:
2401065000 Electronic and Other Electrical: SIC 36 - Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 36% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: At the time this was developed, the MACT for Miscellaneous Metal Parts and
Products Surface Coating Operations had not yet been promulgated. Pechan used
an estimate of $5,000 per ton VOC reduced based on a control efficiency of 36%
(Pechan, 1997).
Cost Effectiveness: The annual cost is $5,000 per ton VOC reduction (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
References:
E.H. Pechan & Associates, Inc., "Integrated Ozone, Particulate Matter, and Regional Haze Cost
Analysis - Methodology and Results," prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Office of Air Quality Planning and Standards, June 6,
1997.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Electrical/Electronic Coating
Control Measure Name: SCAQMD Rule
Rule Name: South Coast Air Quality Management District Rule 1164
Pechan Measure Code: V25302	POD: 253
Application: SCAQMD Rule 1116 requires: a fully covered area, low/no-VOC solvents, or an
approved emissions control system for solvent cleaning operations, photoresist
operations and solvent clean-up operations. An alternative emission control plan
pursuant to Rule 108 may be submitted in place of the measures listed above
(SCAQMD, 1995).
This control applies to the miscellaneous electronic equipment coating source
category, including VOC emissions resulting from the manufacture of circuit boards
and components, including resistors, transistors, semiconductors, coils, and
transformers. Emissions for this source category are classified under SCC
2401065000.
Affected SCC:
2401065000 Electronic and Other Electrical: SIC 36 - Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 70% from uncontrolled
Equipment Life: Unavailable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost inputs for achieving VOC reductions from this source category are based on
cost data from the SCAQMD. Factors affecting costs include product reformulations
(SCAQMD, 1996).
Cost Effectiveness: The annual cost for the South Coast measure used in AirControlNET is $5,976
(in 1990 dollars) per ton of VOC reduced (SCAQMD, 1996).
A cost range of $2,000 for reformulated coatings and $9,600 per ton for add-on
equipment is noted (Pechan, 1994).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
This control measure proposes to reduce VOC emissions from electronic components
manufacturing operations through the application of several control methods. These control methods
include installation of add-on control equipment, material reformulations, and improved operating
procedures. Such control methods are currently required for semiconductor manufacturing
operations and are also expected to be applicable to this source category due to the similarity in
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AT-A-GLANCE TABLE FOR AREA SOURCES
operations.
Add-on control devices such as carbon adsorption, and thermal and catalytic incinerators could be
used to capture and/or eliminate organic compound emissions from the operation exhaust streams.
In addition, development of low-VOC, high-solids content, and water-based formulations could
provide another alternative for reducing VOC emissions from this source category. Further emission
reductions could also be expected through adoption of improved procedures resulting in lower
solvent usage and/or evaporation (SCAQMD, 1988).
Assuming that the proposed control methods would have the same control efficiency as achieved in
semiconductor manufacturing operations, implementation of this control measure is expected to be
70 percent efficient in reducing VOC emissions from this source category.
References:
Pechan, 1994: E.H. Pechan & Associates, Inc., "Analysis of Incremental Emission Reductions and
Costs of VOC and NOx Control Measures - Draft Report," prepared for U.S. Environmental
Protection Agency, Ambient Standards Branch, Research Triangle Park, NC, September 1994.
Pechan , 1997: E.H. Pechan & Associates: "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air Quality
Standards, and Regional Haze Program," prepared for U.S. Environmental Protection Agency, July
1997.
SCAQMD, 1988: South Coast Air Quality Management District, Rule Development Division, "Staff
Report on the Proposed Rule 1164 - Semiconductor Manufacturing," April 1988.
SCAQMD, 1995: South Coast Air Quality Management District, "Rule 1164- Semiconductor
Manufacturing," January 1993.
SCAQMD, 1996: South Coast Air Quality Management District, "1997 Air Quality Management
Plan - Appendix IV-A - Stationary and Mobile Source Control Measures," August 1996.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Fabric Printing, Coating and Dyeing
Control Measure Name: Permanent Total Enclosure (PTE)
Rule Name: Not Applicable
Pechan Measure Code: V40202	POD: 202
Application: A PTE is an enclosure used to surround a source of emissions so that all, or nearly all,
emissions are captured and contained, usually for discharge to a control device.
Fabric printing, coating and dyeing is performed in the textile manufacturing industry in
order to:
~oprepare fiber and subsequently manufacture yarn, threads, braids, twine, and
cordage
~omanufacture broadwoven fabrics, narrow woven fabrics, knit fabrics, and carpets
and rugs from yarn
~odye and finish fiber, yarn, fabrics, and knit apparel
~ocoat, waterproof, or otherwise treat fabrics
~operform integrated manufacturing of knit apparel and other finished articles from
yarn
~omanufacture felt goods, lacegoods, nonwoven fabrics, and miscellaneous textiles.
The EPA evaluated VOC emission control options for the fabric printing, coating and
dyeing industry including the use of a PTE in conjunction with a thermal oxidizer in the
MACT standard-setting process for this source category.
Affected SCC:
40204001
40204002
40204003
40204004
40204010
40204011
40204012
40204013
40204020
40204021
40204022
40204023
40204121
40204130
40204140
40204150
40204151
40204152
40204160
40204161
40204162
40204221
40204230
40204240
40204250
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AT-A-GLANCE TABLE FOR POINT SOURCES
40204251
40204252
40204260
40204261
40204262
40204321
40204330
40204340
40204350
40204351
40204352
40204360
40204361
40204362
40204421
40204430
40204431
40204432
40204435
40204440
40204441
40204442
40204443
40204450
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 97% from uncontrolled
Equipment Life: 30 years (PTE); 15 years (thermal oxidizer)
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost analysis is based on an average of PTE and oxidizer capital and operating
and maintenance costs developed for four model fabric coating plants evaluated by
EPA for the Printing, Coating and Dyeing of other Fabrics and Textiles MACT
standard (40 CFR Part 63 Subpart OOOO). Consistent with the OAQPS Control Cost
Manual, an interest rate of 7% was used to determine the capital recovery factor.
Although the PTE is expected to have a life of 30 years, PTE costs were annualized
over a 15 year period, representing the expected catalytic oxidizer life. Each PTE
was assumed to capture 100% of all VOC emissions. All captured emissions were
assumed to be vented to a catalytic thermal oxidizer achieving a 97% control
efficiency. Therefore, the net VOC control efficiency is 97%. Year 1997 dollars were
specified for cost calculations in the EPA background document for the printing and
publishing industry. The EPA also evaluated costs based on the use of a thermal
(non-catalytic) oxidizer; the annualized costs were higher than for the use of a
catalytic oxidizer.
Cost Effectiveness: The cost effectiveness is $1,343 per ton VOC reduction (1997$). The cost
effectiveness is based on an annualized capital cost of $62,900 and an annual
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operation and maintenance (O&M) cost of $121,242 averaged over four model
textile manufacturing plants.
Comments:
Status:
Last Reviewed:
Additional Information:
Rule penetration estimated to be 100% in Air ControlNET, while state or local areas might choose to
require only sources above a certain size to comply with a regulation requiring PTEs. In such a
case, the rule penetration value would be less than 100 percent.
References:
EPA, 2002: U.S. Environmental Protection Agency, "Technical Support Document: Printing, Coating
and Dyeing of Fabrics and Other Textiles Proposed NESHAP", EPA 453/R-02-010, June 2002.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual", Sixth Edition, document EPA/452/B-02-001, January 2002.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Flexographic Printing
Control Measure Name: Permanent Total Enclosure (PTE)
Rule Name: Not Applicable
Pechan Measure Code: V40201	POD: 201
Application: A PTE is an enclosure used to surround a source of emissions so that all, or nearly all,
emissions are captured and contained, usually for discharge to a control device.
Flexographic printing is classified into two categories: wide-web and narrow-web
flexographic printing. Wide-web flexographic printing is used to print flexible and rigid
paper, plastic and aluminum foil packaging, newspapers, magazines, directories,
paper towels, etc., printed shower curtains and wallpaper. Flexographic newspaper
printing is also starting to replace older letterpress technology. Narrow-web
flexographic printing is primarily used for printing and adhesive application on paper,
foil and film tags and labels. The EPA evaluated VOC emission control options for the
flexographic printing industry including the use of a PTE in conjunction with a thermal
oxidizer in the MACT standard-setting process for this source category.
Affected SCC:
40500301
40500311
40500312
40500313
40500314
40500315
40500316
40500317
40500318
40500319
40500414
Printing/Publishing, General
Printing/Publishing, General
Printing/Publishing, General
Printing/Publishing, General
Printing/Publishing, General
Printing/Publishing, General
Printing/Publishing, General
Printing/Publishing, General
Printing/Publishing, General
Printing/Publishing, General
Printing/Publishing, General
Printing: Flexographic
Printing: Flexographic
Printing: Flexographic
Printing: Flexographic: Propyl Alcohol Cleanup
Printing: Flexographic: Propyl Alcohol Cleanup
Flexographic: Steam: Water-based
Flexographic: Steam: Water-based
Flexographic: Steam: Water-based
Flexographic: Steam: Water-based in Ink
Flexographic: Steam: Water-based Ink Storage
Flexographic: Propyl Alcohol Cleanup
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled
Equipment Life: 30 years (PTE); 15 years (thermal oxidizer)
Rule Effectiveness: 100% for point and area sources
Penetration: 100%
Cost Basis: The cost analysis is based on an average of PTE and oxidizer capital and operating
and maintenance costs developed for three model flexographic printing plants
evaluated by EPA for the Printing and Publishing MACT standard (40 CFR Part 63
Subpart KK). Consistent with the OAQPS Control Cost Manual, an interest rate of
7% was used to determine the capital recovery factor. Although the PTE is expected
to have a life of 30 years, PTE costs were annualized over 15 years (the expected life
of the thermal oxidizer). Each PTE was assumed to capture 100% of all VOC
emissions. All captured emissions were assumed to be vented to a thermal oxidizer
having a 95% control efficiency. Therefore, the net VOC control efficiency is 95%.
Year 1993 dollars were specified for cost calculations in the EPA background
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document for the printing and publishing industry.
Cost Effectiveness: The cost effectiveness is $9,947 per ton VOC reduction (1993$). The cost
effectiveness is based on an annualized capital cost of $97,120 and an annual
operation and maintenance (O&M) cost of $1,236,652 averaged over three
model flexographic printing plants
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
EPA, 1995: U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air
Pollutants: Printing and Publishing Industry Background Information for Proposed Standards",
February 1995.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual", Sixth Edition, document EPA/452/B-02-001, January 2002.
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Source Category: Graphic Arts
Control Measure Name: Use of Low or No VOC Materials
Rule Name: Not Applicable
Pechan Measure Code: V30301
POD: 303
Application: This control measure calls for the application of RACT-level controls to small graphic
arts sources. This control measure, based on one developed by STAPPA/ALAPCO,
requires the use of low or no-VOC materials to reduce VOC emissions from graphic
arts sources.
This control applies to lithography, letterpress, rotogravure, and flexography graphic,
and other graphic arts applications.
Affected SCC:
2425000000 All Processes, Total: All Solvent Types
2425010000 Lithography, Total: All Solvent Types
2425020000 Letterpress, Total: All Solvent Types
2425030000 Rotogravure, Total: All Solvent Types
2425040000 Flexography, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 65% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Pechan assumes an average cost effectiveness from the range given by
STAPPA/ALAPCO.
Cost Effectiveness: STAPPA/ALAPCO (1993) estimated a range of cost effectiveness from $3,500
to $4,800 per ton VOC reduced.
The cost effectiveness use in AirControlNET is $4,150 per ton VOC reduced.
(1993$)
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
References:
STAPPA/ALAPCO, 1993: "Meeting the 15 Percent Rate of Progress Requirement Under the Clean
Air Act: A Menu of Options," September 1993.
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
Source Category: Highway Vehicles - Gasoline Engine
Control Measure Name: Federal Reformulated Gasoline (RFG)
Rule Name: Federal Reformulated Gasoline
Pechan Measure Code: mOT2
POD: N/A
Application: This control measure represents the year round National use of Federal Reformulated
gasoline in light duty gasoline vehicles in counties currently not required to use this
fuel. Emission reduction benefits of NOx, CO, and VOC are estimated using EPA's
MOBILE6 model.
This control is applicable to all light duty gasoline vehicles, motor cycles, and trucks.
Affected SCC:
2201001000 Light Duty Gasoline Vehicles (LDGV), Total: All Road Types
2201020000 Light Duty Gasoline Trucks 1 (LDGT1), Total: All Road Types
2201040000 Light Duty Gasoline Trucks 2 (LDGT2), Total: All Road Types
2201070000 Heavy Duty Gasoline Vehicles (HDGV), Total: All Road Types
2201080000 Motorcycles (MC), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg




X
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency ranged from: NOx (-1.0 % to 1.1%; VOC (0.0 to 15.3%);
CO (3.8 to 16.3%)
Equipment Life: Not Applicable
Rule Effectiveness: Not applicable
Penetration: Not applicable
Cost Basis: The total annual cost of RFG was estimated using the number of vehicles and
amount of fuel consumed by county and vehicle type. Costs were estimated on a per-
vehicle basis in all counties with no RFG in the base case.
The number of vehicles was estimated by dividing the VMT by the average LDGV
annual mileage accumulation rate. The annual costs for RFG is estimated assuming
$0,043 per gallon (Pechan 2002) ($1997).
Cost Effectiveness: The cost effectiveness of RFG varies greatly by county. Cost effectiveness for
VOC ranged from $28,905,773 to $2,498 per ton. The average C-E for VOC is
$25,093 per ton of VOC reduced (median is $16,656 per ton). All costs are
$1997.
Comments: In some cases this control produces a slight NOx disbenefit. The median NOx control
efficiency is -0.02 percent.
Status: Demonstrated
Last Reviewed: 2002
Additional Information:
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AT-A-GLANCE TABLE FOR MOBILE SOURCES
References:
Pechan 2002: "AirControlNET Specifications and Methods for Mobile Source Controls" Memo
prepared for Larry Sorrels of the US EPA, December 2002.
Source Category: Highway Vehicles - Light Duty Gasoline Engines
Control Measure Name: Basic Inspection and Maintenance Program
Rule Name: Not Applicable
Pechan Measure Code: mOT9	POD: N/A
Application: Basic l/M control measure includes idle testing of light-duty gasoline vehicles (LDGVs)
for model years 1983 through 2001. Starting in 2002, all 1996 and later model year
LDGVs are tested with on-board diagnostics (OBD) and all pre-96 LDGVs continue to
receive the idle test. So, the NOx benefits are a result of the OBD testing.
Affected SCC:
2201001000 Light Duty Gasoline Vehicles (LDGV), Total: All Road Types
2201020000 Light Duty Gasoline Trucks 1 (LDGT1), Total: All Road Types
2201040000 Light Duty Gasoline Trucks 2 (LDGT2), Total: All Road Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
voc
S02
NH3
CO
Hg
V
V


V
V*
V
V
V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by model year and vehicle type.
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Costs are estimated on a per-vehicle basis. The number of vehicles was estimated
by dividing the VMT by the average LDGV annual mileage accumulation rate. The
costs are for basic l/M are estimated at $6.52 per vehicle.
Cost Effectiveness: The costs are for basic l/M are estimated at $6.52 per vehicle.
Comments:
Status: Demonstrated
Last Reviewed: 2005
Additional Information:
References:
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Maintenance Coating
Control Measure Name: AIM Coating Federal Rule
Rule Name: Architectural and Industrial Maintenance Coatings Federal Rule
Pechan Measure Code: V22201	POD: 222
Application: This federal rule provides uniformity over the state-level content limits that AIM coating
manufacturers must meet. The rule sets maximum allowable VOC content limits for 55
different categories of AIM coatings, and affects the manufacturers and importers of
the coating products. VOC content limits defined in the national rule took effect on
September 11, 1999. Manufacturers of FIFRA - regulated coatings had until March 10,
2000 to comply.
Sixty-four percent of the products included in the 1990 industry survey meet the VOC
content limits in this rule and, therefore, there will be no costs to reformulate these
products. The manufacturer of a product that does not meet the VOC content limits
will be required to reformulate the product if it will continue to be marketed, unless the
manufacturer chooses to use an alternative compliance option such as the
exceedance fee or tonnage exemption provision.
In AirControlNET, this specific control measure applies only to industrial maintenance
coatings.
Affected SCC:
2401100000 Industrial Maintenance Coatings, Total: All Solvent Types
2401990000 All Surface Coating Categories, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost estimates are based upon information provided to EPA by industry
representatives during the regulatory negotiation process. Industry representatives
estimated the level of effort required by a representative firm to research and develop
a new prototype coating to be 2.5 scientist-years over a 3-year time period. EPA
calculated an annualized cost of $17,772 per reformulation (1991 dollars) based on
an assumed cost of $100,000 per scientist-year as amortized over an assumed
repopulation cycle of 2.5 years.
The estimated average cost to reformulate a product was $87,000. The total
estimated national cost of the AIM Coating Federal rule is 25.6 million per year (1991
dollars).
Cost Effectiveness: EPA estimated emission reductions of 106,000 tons of VOC per year so that
the cost effectiveness is computed as $228 per ton VOC reduction (1990$)..
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AT-A-GLANCE TABLE FOR AREA SOURCES
Comments: The EPA did not account for potential cost differences for reformulating coatings to
various content limits. Instead, EPA assumed that a reformulation has a certain cost to
manufacturers regardless of the target content limit, or the anticipated VOC reduction
(Ducey, 1997).
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
In its analysis of the proposed federal rule, EPA assumed that the cost of product reformulation
would bring the VOC content limit for each noncompliant coating down to the level of the standards.
The EPA, however, noted the likelihood that some manufacturers will likely reduce the VOC content
of their coatings to levels significantly below the limits in the rule (EPA, 1996). The at-the-limit
assumption, therefore, likely results in emission reductions being understated. In its cost analysis,
insufficient data were available for EPA to distinguish reformulation costs between different coating
types (i.e., the reformulation cost for flat paints is equal to the reformulation cost for all other affected
paint types). The EPA noted the likelihood of reformulation costs varying from product to product
(EPA, 1995).
References:
Ducey, 1997: E. Ducey, U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, personal communication with D. Crocker, E.H. Pechan & Associates, Inc., February 13,
1997.
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Economic Impact and Regulatory Flexibility Analysis of the Proposed Architectural Coatings Federal
Rule," Research Triangle Park, NC. March 1995.
EPA, 1996: U.S. Environmental Protection Agency, Emission Standards Division, Office of Air and
Radiation, "Architectural Coatings - Background for Proposed Standards, Draft Report," March 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Maintenance Coating
Control Measure Name: South Coast Phase I
Rule Name: South Coast AQMD Rule 1113 - Architectural Coatings
Pechan Measure Code: V22202	POD: 222
Application: The Phase I rule is an amendment to SCAQMD's existing architectural coatings rule
that establishes more stringent VOC content limits for flat, multi-color, traffic, and
lacquer coatings. These VOC limits in the SCAQMD for multi-color, traffic, and lacquer
coatings took effect on January 1, 1998, while the Phase I limits for flat coating took
effect on January 1, 2001.
Reductions in VOC emissions from these coatings are achieved through the use of
product reformulation and product substitution.
Affected SCC:
2401100000 Industrial Maintenance Coatings, Total: All Solvent Types
2401990000 All Surface Coating Categories, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 34% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: For the Phase I amendment, a SCAQMD report documents cost per gallon, total
annual cost, emission reduction and cost-effectiveness values for each of the four
regulated coating types (SCAQMD, 1996).
The SCAQMD estimated that manufacturers would use an acetone formulation with
an associated cost of $2 per gallon to meet the proposed 550 grams per liter (g/L)
VOC limit for lacquers. For flats, South Coast estimated a zero cost for complying
with the near-term 100 g/L limit since most flats sold in California are already in
compliance with this limit. For traffic and multi-color coatings, the SCAQMD
estimated that a cost savings was likely to be associated with reformulation due to a
decrease in the cost of input materials. (The estimated magnitude of the savings is
not documented in the SCAQMD report.)
Costs were estimated by multiplying the cost per gallon data to total gallons sold.
The resulting weighted average cost effectiveness value was converted to 1990
dollars using the 1995:1990 producer price index for Standard Industrial Classification
(SIC) code 2851 (Paints and Allied Products).
Because capital cost information was not available, capital costs were not estimated
for this analysis.
Cost Effectiveness: Calculated cost-effectiveness values range from $3,300 to $4,600 per ton
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AT-A-GLANCE TABLE FOR AREA SOURCES
depending on the specified limit and coating type. The cost effectiveness
range is attributable to the wide diversity of coatings.
AirControlNET uses a cost effectiveness of $1,443 per ton VOC reduction
based on a weighted average of national sales data by coating type (EPA,
1996) (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
References:
CARB, 1989: California Air Resources Board, Stationary Source Division, "ARB-CAPCOA
Suggested Control Measure for Architectural Coatings, Technical Support Document," July 1989.
EPA, 1996: U.S. Environmental Protection Agency, Emission Standards Division, Office of Air and
Radiation, "Architectural Coatings - Background for Proposed Standards, Draft Report," EPA-453/R-
95-009a, March 1996.
SCAQMD, 1996: South Coast Air Quality Management District, "Proposed Modifications to the
Appendices of the Draft 1997 Air Quality Management Plan," October 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Maintenance Coating
Control Measure Name: South Coast Phase II
Rule Name: South Coast AQMD Rule 1113 - Architectural Coatings
Pechan Measure Code: V22203	POD: 222
Application: Phase II represents an effort to lower the VOC content limits for non-flat industrial
maintenance primers and topcoats, sealers, undercoaters, and quick-dry enamels.
The rule requires manufacturers of the coatings sold in the SCAQMD to meet the VOC
limit requirements provided in the rule between 2002 and 2006.
Reductions in VOC emissions from these coatings are achieved through the use of
product reformulation and product substitution.
Affected SCC:
2401100000 Industrial Maintenance Coatings, Total: All Solvent Types
2401990000 All Surface Coating Categories, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 47% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: For the Phase II amendments, the SCAQMD completed a socioeconomic impact
assessment (SCAQMD, 1999). SCAQMD assumed a 10 percent price increase per
gallon for compliant coatings meeting Phase II and estimated the cost based on the
number of gallons produced. Costs vary significantly among individual coatings
categories.
Because capital cost information was not available, capital costs were not estimated
for this analysis.
Cost Effectiveness: AirControlNET uses a cost effectiveness of $4,017 per ton VOC reduction
(1990$).
Comments: Cost data for Phase II controls are sparse and not well-documented.
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
The South Coast notes that the process of collecting reformulation cost data for these categories is
very complex due to the resin technology used in lower-VOC, high-performance industrial
maintenance coatings (silicon-based resins, or polyurethanes) and the number of resin systems
involved (Berry, 1997).
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Berry, 1997: N. Berry, South Coast Air Quality Management District, personal communication with
D. Crocker, E.H. Pechan & Associates, Inc., March 4, 1997.
SCAQMD, 1999: South Coast Air Quality Management District, "Addendum to Staff Report: Final
Socioeconomic Impact Assessment, Proposed Amendments to Rule 1113," May 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Industrial Maintenance Coating
Control Measure Name: South Coast Phase III
Rule Name: South Coast AQMD Rule 1113 - Architectural Coatings
Pechan Measure Code: V22204	POD: 222
Application: Phase III applies to additional consumer products that are not affected by Phase I or
II. The rule requires manufacturers to limit VOC content of the specified coatings sold
in the SCAQMD using a phased-in approach specifying compliance dates that depend
on the coating type. Compliance dates range from 1/1/03 to 7/1/08.
Reductions in VOC emissions from these coatings are achieved through the use of
product reformulation and product substitution.
Affected SCC:
2401100000 Industrial Maintenance Coatings, Total: All Solvent Types
2401990000 All Surface Coating Categories, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 73% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: SCAQMD has not yet estimated the costs for implementing the Phase III limits. As
an estimate, Pechan uses the highest incremental cost effectiveness estimate for any
individual product for the Phase II amendments of $26,000 per ton (1998 dollars).
This value is about double the average of Phase II products. This cost estimate is
highly uncertain as no specific cost data are available (Pechan, 1999).
Because capital cost information was not available, capital costs were not estimated
for this analysis.
Cost Effectiveness: AirControlNET uses an overall cost effectiveness of $10,059 per ton VOC
reduction (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
The Phase III controls apply to additional consumer products that are not affected by the near-term
measures. These measures, which are expected to take effect between 2000 and 2005, are
expected to result in an additional 25 percent VOC reduction from consumer products.
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET)," prepared for the U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle
Park, NC, 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Machinery, Equipment, and Railroad Coating
Control Measure Name: SCAQMD Limits
Rule Name: South Coast Air Quality Management District Rule 1107 - Coating of Metal
Parts and Products
Pechan Measure Code: V24702
POD: 247
Application: The SCAQMD amended rule 1107 sets stringent VOC emission limits for metal
coatings. VOC emissions can be reduced by using reformulated low-VOC content
compliant coatings, powder coating for both general and high gloss coatings, UV
curable coatings, high transfer efficiency coating applications, and increased
effectiveness of add-on control equipment (SCAQMD, 1996).
The metal coating source category classifies emissions that result from the coating of
metal parts and products including machinery and equipment (SCC 2401055000) and
railroad rolling stock (SCC 2401085000).
Affected SCC:
2401055000 Machinery and Equipment: SIC 35, Total: All Solvent Types
2401085000 Railroad: SIC 374, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost inputs for achieving VOC reductions from this source category were for this
analysis based on cost data from the SCAQMD Rule 1107. Factors affecting cost
include product reformulations (SCAQMD, 1996).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,027 per ton VOC reduction
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1994
Additional Information:
The SCAQMD originally adopted its Rule 1107 - Coating of Metal Parts and Products - in 1979, as
part of California's SIP. Since 1979, SCAQMD amended the rule several times to adjust the
compliance schedule, and to modify provisions due to delayed progress in the development and use
of compliant coatings.
The SCAQMD notes that add-on control equipment is considerably more expensive than low-VOC
coating reformulation.
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Pechan, 1994: E.H. Pechan & Associates, Inc., "Analysis of Incremental Emission Reductions and
Costs of VOC and NOx Control Measures," prepared for U.S. Environmental Protection Agency,
Ambient Standards Branch, Research Triangle Park, NC, September 1994.
SCAQMD, 1996: South Coast Air Quality Management District. "1997 Air Quality Management
Plan - Appendix IV-A. Stationary and Mobile Source Control Measures," August 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Marine Surface Coating (Shipbuilding)
Control Measure Name: MACT Standard
Rule Name: Maximum Achievable Control Technology for Marine Surface Coating
Pechan Measure Code: V25101	POD: 251
Application: The MACT standard requires the use of low-VOC coatings and work practices that
would minimize evaporative emissions from all affected marine coatings sources (EPA,
1992). The final rule was promulgated December 1995.
Sources affected by this control measure are all major facilities involved in shipbuilding
or ship repair (EPA, 1992).
Affected SCC:
2401080000 Marine: SIC 373, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 24% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs for model plants with emissions less than 100 tpy are used to estimate the
overall cost effectiveness (Pechan, 1998). EPA assumed that no additional
equipment is required for any facility and capital costs are therefore zero (EPA,
1994). Implementation of this regulation is expected to result in nationwide
annualized costs for existing shipyards of about $2 million (1992$), for a cost
effectiveness of $2,090 per ton of VOC reduced (1990$) (60FR64330, 1995). EPA
stated that since most of the sources are in NAAs, the costs for the NESHAP also
reflect costs associated with CTG compliance.
Cost Effectiveness: $2,090 per ton VOC reduced (1990$) is the cost effectiveness used in
AirControlNET (60FR64330, 1995).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
EPA, 1992: U.S. Environmental Protection Agency, "Fact Sheet - Proposed NESHAP BID for
Shipbuilding and Ship Repair Facilities (Surface Coating)," 1992. Retrieved August 1998 from
http://www.epa.gov/ttnatw01/shipb/shipbpg.html.
EPA, 1994: U.S. Environmental Protection Agency, "Alternative Control Techniques Document:
Surface Coating Operations at Shipbuilding and Ship Repair Facilities," Office of Air Quality
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AT-A-GLANCE TABLE FOR AREA SOURCES
Planning and Standards, Research Triangle Park, NC, April, 1994.
60FR64330, 1995: Federal Register "National Emission Standards for Hazardous Air Pollutants for
Shipbuilding and Ship Repair (surface coating) Operations," Vol. 60, December 1995.
Pechan, 1998: E.H. Pechan & Associates, "Clean Air Act Section 812 Prospective Cost Analysis -
Draft Report" prepared for prepared for U.S. Environmental Protection Agency, September 1998.
Source Category: Marine Surface Coating (Shipbuilding)
Control Measure Name: Add-On Controls
Rule Name: Not Applicable
Pechan Measure Code: V25102	POD: 251
Application: This control measure is generic in that it represents potential add-on controls available
for this source category. Add-on controls include thermal incinerators, catalytic
incinerators, and a combination of carbon absorbers and incinerators.
Affected SCC:
2401080000 Marine: SIC 373, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost is based on estimates for small industrial sources to install add on control
options. The highest costs for add-on controls are associated with specialized and
small plants (Pechan, 1999).
Cost Effectiveness: The cost effectiveness is $8,937 per ton VOC reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
References:
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET) - Draft Report," prepared for
the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research
Triangle Park, NC, September1999.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Metal Can Surface Coating Operations
Control Measure Name: Permanent Total Enclosure (PTE)
Rule Name: Not Applicable
Pechan Measure Code: V40203	POD: 203
Application: A PTE is an enclosure used to surround a source of emissions so that all, or nearly all,
emissions are captured and contained, usually for discharge to a control device. A
metal can is defined as a "usually cylindrical metal container", but governmental
agencies and industry groups use differing criteria to identify cans including shape,
materials, capacity, phase of product contained, and material thickness (gauge).
Decorative tins, bottle caps and jar lids are also included in the can coating category
since many of these items are coated on the same line where can coating takes place.
Cans consist of can bodies and can ends.
Metal can surface coating facilities include two-piece beverage can body facilities, two-
piece food can body facilities, one-piece aerosol can body facilities, sheetcoating
facilities, three-piece food can body assembly facilities, three-piece non-food can body
assembly facilities, and end lining facilities.
EPA evaluated VOC emission control options for the two-piece beverage can, two-
piece food can and sheetcoating facilities using a PTE in conjunction with a thermal
oxidizer in the MACT standard-setting process for this source category.
Affected SCC:
40201702	Surface Coating
40201703	Surface Coating
40201704	Surface Coating
40201705	Surface Coating
40201706	Surface Coating
40201721	Surface Coating
40201722	Surface Coating
40201723	Surface Coating
40201724	Surface Coating
40201725	Surface Coating
40201726	Surface Coating
40201736 &-37)
40201727	Surface Coating
40201728	Surface Coating
40201729	Surface Coating
40201731	Surface Coating
40201732	Surface Coating
Coating Line
40201733	Surface
Coating
40201734	Surface
Coating
40201735	Surface Coating
40201736	Surface Coating
40201737	Surface Coating
40201738	Surface Coating
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Coating Operations, Meta
Coating Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Operations, Meta
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Can Coating
Cleaning/Pretreatment
Coating Mixing
Coating Storage
Equipment Cleanup
Solvent Storage
Two Piece Exterior Base Coating
Interior Spray Coating
Sheet Base Coating (Interior)
Sheet Base Coating (Exterior)
Side Seam Spray Coating
End Sealing Compound (Also See
Lithography
Over Varnish
Exterior End Coating
Three-piece Can Sheet Base Coating
Three-piece Can Sheet Lithographic
Three-piece Can-side Seam Spray
Three-piece Can Interior Body Spray
Two-piece Can Coating Line
Two-piece Can End Sealing Compound
Three Piece Can End Sealing Compound
Two Piece Can Lithographic Coating
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AT-A-GLANCE TABLE FOR POINT SOURCES
Line
40201739 Surface Coating Operations, Metal Can Coating, Three Piece Can Coating Line (All
Coating Solvent Emission Points)
40201799 Surface Coating Operations, Metal Can Coating,Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: Expected to be 95% from uncontrolled.
Equipment Life: 30 years (PTE); 10 years (thermal oxidizer)
Rule Effectiveness: 100% for point and area sources
Penetration: 100%
Cost Basis: The cost analysis is based on an average of PTE and oxidizer capital and operating
and maintenance costs developed in an EPA background document for three model
metal can coating plants evaluated by EPA for the Metal Can Surface Coating MACT
standard (40 CFR Part 63 Subpart KKKK). Consistent with the OAQPS Control Cost
Manual, an interest rate of 7% was used to determine the capital recovery factor.
Although PTE costs were annualized over a 10 year period, PTE life is expected to be
30 years, also consistent with the OAQPS Control Cost Manual. Each PTE was
assumed to capture 100% of all VOC emissions. All captured emissions were
assumed to be vented to thermal oxidizer. The EPA background document does not
specify year dollars, so the cost basis is assumed to be in terms of 2002 dollars,
consistent with the year of issuance of the background document.
Cost Effectiveness: The cost effectiveness is $8,469 per ton HAP reduction (2002$). The cost
effectiveness is based on total annualized capital and operation/maintenance
(O&M) costs of $49,862,900 and total HAP reductions of 5,888 tons per year
for all three facilities combined.
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air
Pollutants (NESHAP) for Source Category Surface Coating of Metal Cans: Background Information
for Proposed Standards", November 2002.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual", Sixth Edition, document EPA/452/B-02-001, January 2002.
Document No. 05.09.009/9010.463
III-1407
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Metal Coil & Can Coating
Control Measure Name: MACT Standard
Rule Name: Maximum Achievable Control Technology for Metal Coil & Can Coating
Pechan Measure Code: V22301	POD: 223
Application: This control measure represents a 10-year MACT source category, also covered by a
CTG. Control methods for reducing VOC emissions from metal can and coil coating
operations include the use of low-VOC coatings and add-on control equipment.
Coatings are applied to metal cans and coils to improve appearance and prevent
corrosion. This rule is assumed to cover both two and three piece can and coil
coating. Area source VOC emissions for the metal can and coil coating source
category are classified under SCCs 2401040000 and 2401045000, respectively.
Affected SCC:
2401040000 Metal Cans: SIC 341, Total: All Solvent Types
2401045000 Metal Coils: SIC 3498, Total: All Solvent Types
2401050000 Miscellaneous Finished Metals: SIC 34 - (341 + 3498), Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 36% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: At the time this measure was developed the 10-year MACT had not been proposed,
thus control costs effectiveness was estimated to be $1,000 for a VOC emissions
reduction of 36% (Pechan, 1997).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,000 per ton VOC reduced
(1990$).

Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:

EPA promulgated a MACT standard for this category in June 2002.
References:
Pechan, 1997: E.H. Pechan & Associates, Inc., "Integrated Ozone, Particulate Matter, and Regional
Haze Cost Analysis - Methodology and Results," prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Office of Air Quality Planning and Standards,
June 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Metal Coil & Can Coating
Control Measure Name: BAAQMD Rule 11 Amended
Rule Name: Bay Area Air Quality Management District Rule 11 - Hazardous Pollutants
(Amended)
Pechan Measure Code: V22302	POD: 223
Application: The San Francisco Bay Area AQMD has adopted VOC content limits for body spray
coatings for both two and three piece cans and set VOC limits for end sealing
compounds for non-food products; and set limits for interior and exterior body sprays
used on drums, pails, and lids (BAAQMD, 1999). This control measure is based on the
1997 amendment to the rule.
Coatings are applied to metal cans and coils to improve appearance and prevent
corrosion. This rule is assumed to cover both two and three piece can and coil
coating. Area source VOC emissions for the metal can and coil coating source
category are classified under SCCs 2401040000 and 2401045000, respectively.
Affected SCC:
2401040000 Metal Cans: SIC 341, Total: All Solvent Types
2401045000 Metal Coils: SIC 3498, Total: All Solvent Types
2401050000 Miscellaneous Finished Metals: SIC 34 - (341 + 3498), Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 42% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost analysis is based up on the San Francisco Bay Area VOC content limits,
Rule 11 amendments. This amendment to Rule 11 is expected to further reduce
emissions by 9 percent from the original rule at a cost effectiveness of $8,400 per
ton. The year of dollars is not given in the control measure summary, so 1997 dollars
is assumed since this was the year of adoption of the regulation. In 1990 dollars, this
is $8,074 per ton, bringing the overall reduction to $2,007 per ton at 42 percent
reduction from uncontrolled emissions.
Cost Effectiveness: The cost effectiveness is $2,007 per ton VOC reduction (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
References:
BAAQMD, 1999: Bay Area Air Quality Management District, "San Francisco Bay Area Ozone
Attainment Plan for the 1-Hour National Ozone Standard, Appendix B - Control Measure
Descriptions," June 1999.
Document No. 05.09.009/9010.463	III-1409	Report

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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Metal Coil & Can Coating
Control Measure Name: Incineration
Rule Name: Not Applicable
Pechan Measure Code: V22303
POD: 223
Application: This is a generic control measure based on the use of incineration to reduce VOC
emissions from metal coil and can coating facilities.
Coatings are applied to metal cans and coils to improve appearance and prevent
corrosion. This rule is assumed to cover both two and three piece can and coil
coating. Area source VOC emissions for the metal can and coil coating source
category are classified under SCCs 2401040000 and 2401045000, respectively.
Affected SCC:
2401040000 Metal Cans: SIC 341, Total: All Solvent Types
2401045000 Metal Coils: SIC 3498, Total: All Solvent Types
2401050000 Miscellaneous Finished Metals: SIC 34 - (341 + 3498), Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Pechan estimates that the cost effectiveness is $8,937 per ton to require incineration
of VOC emissions from metal coil and can coating facilities (Pechan, 1998).
Cost Effectiveness: A cost effectiveness of $8,937 per ton VOC reduced is used in AirControlNET
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1998: E.H. Pechan & Associates: Clean Air Act Section 812 Prospective Cost Analysis -
Draft Report. Prepared for prepared for U.S. Environmental Protection Agency. September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Metal Furniture Surface Coating Operations
Control Measure Name: Permanent Total Enclosure (PTE)
Rule Name: Not Applicable
Pechan Measure Code: V40204	POD: 204
Application: A PTE is an enclosure used to surround a source of emissions so that all, or nearly all,
emissions are captured and contained, usually for discharge to a control device. Metal
furniture surface coating operations involve:
•Surface preparation of the metal furniture prior to coating application
•Preparation of a coating for application (e.g., mixing in additives, dissolving resins)
•Application of a coating to metal furniture
•Flashoff, drying, and curing following coating application
•Cleaning of equipment used in the coating application operation
•Storage of coatings, additives, and cleaning materials
•Conveyance of coatings, additives, and cleaning materials from storage areas to
mixing areas or to coating application areas, either manually or by automated means
•Handling and conveyance of waste materials generated by the surface coating
operation.
The EPA evaluated VOC emission control options for the metal furniture coating
industry including the use of a PTE in conjunction with a thermal oxidizer in the MACT
standard-setting process for this source category.
Affected SCC:
40202501 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202502 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202503 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202504 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202505 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202510 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202511 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
High Solids






40202512 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
Water-borne






40202515 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202520 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202521 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
Solids






40202522 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
Water-borne






40202523 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202524 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202525 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202531 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202532 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202533 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
40202534 Surface
Coating
Operations,
Miscel
aneous
Metal
Parts,
Spray






40202535 Surface
Coating
Operations,
Miscellaneous
Metal
Parts,
Coating Operation
Cleaning/Pretreatment
Coating Mixing
Coating Storage
Equipment Cleanup
Prime Coat Application
Prime Coat Application: Spray,
Prime Coat Application: Spray,
Prime Coat Application: Flashoff
Topcoat Application
Topcoat Application: Spray, High
Topcoat Application: Spray,
Topcoat Application: Dip
Topcoat Application: Flow Coat
Topcoat Application: Flashoff
Conveyor Single Flow
Conveyor Single Dip
Conveyor Single Spray
Conveyor Two Coat, Flow and
Conveyor Two Coat, Dip and
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Spray
40202536	Surface
40202537	Surface
Dry
40202542	Surface
High Solids
40202543	Surface
Water-borne
40202544	Surface
40202545	Surface
Coat
40202546	Surface
40202599 Surface
Coating
Coating
Operations,
Operations,
Miscellaneous
Miscellaneous
Metal
Metal
Parts,
Parts,
Coating
Operations,
Miscellaneous
Metal
Parts,
Coating
Operations,
Miscellaneous
Metal
Parts,
Coating
Coating
Operations,
Operations,
Miscellaneous
Miscellaneous
Metal
Metal
Parts,
Parts,
Coating
Coating
Operations,
Operations,
Miscellaneous
Miscellaneous
Metal
Metal
Parts,
Parts,
Conveyor Two Coat, Spray
Manual Two Coat, Spray and Air
Single Coat Application: Spray,
Single Coat Application: Spray,
Single Coat Application: Dip
Single Coat Application: Flow
Single Coat Application: Flashoff
Other Not Classified
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled
Equipment Life: 30 years (PTE); 10 years (thermal oxidizer)
Rule Effectiveness: 100% for point and area sources
Penetration: 100%
Cost Basis: The cost analysis is based on an average of PTE and oxidizer capital and operating
and maintenance costs developed for three model metal furniture manufacturing
plants evaluated by EPA for the Metal Furniture Surface Coating MACT standard (40
CFR Part 63 Subpart RRRR). Consistent with the OAQPS Control Cost Manual, an
interest rate of 7% was used to determine the capital recovery factor. Each PTE was
assumed to capture 100% of all VOC emissions. All captured emissions were
assumed to be vented to a regenerative thermal oxidizer having 95% heat recovery
and achieving a 95% control efficiency. Therefore, the net VOC control efficiency is
95%. Year 1998 dollars were specified for cost calculations in the EPA background
document for the printing and publishing industry.
Cost Effectiveness: The cost effectiveness is $19,321 per ton VOC reduction (1998$). The cost
effectiveness is based on an annualized capital cost of $625,266 and an annual
operation and maintenance (O&M) cost of $738,787 averaged over three model
metal furniture manufacturing plants.
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
EPA, 2001: U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air
Pollutants: Metal Furniture Surface Coating - Background Information for Proposed Standards",
October 2001.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual", Sixth Edition, document EPA/452/B-02-001, January 2002.
Document No. 05.09.009/9010.463
III-1412
Report

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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Metal Furniture, Appliances, Parts
Control Measure Name: MACT Standard
Rule Name: Maximum Achievable Control Technology for Metal Furniture, Appliances,
Parts
Pechan Measure Code: V24501
POD: 245
Application: The MACT for metal furniture, appliances and parts requires facilities to limit air toxic
emissions through low-VOC materials and pollution prevention techniques (EPA,
2002). The final rule was proposed April 2002, but has not yet been promulgated.
The metal coating source category classifies emissions that result from the coating of
metal parts and products including furniture (SCC 2401025000), appliances (SCC
2401060000), and miscellaneous manufacturing (SCC 2401090000).
Affected SCC:
2401025000 Metal Furniture: SIC 25, Total: All Solvent Types
2401060000 Large Appliances: SIC 363, Total: All Solvent Types
2401090000 Miscellaneous Manufacturing, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 36% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: At the time this control was developed the MACT for metal furniture, appliances and
parts had not been developed. Pechan estimated a cost effectiveness of $1,000 per
ton VOC reduced based on a 36% control efficiency (Pechan, 1997).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,000 per ton VOC reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, "Fact Sheet - Proposed Rule to Reduce Toxic
Air Pollutants From Surface Coating of Metal Furniture," March 2002. Retrieved April 28, 2003 from
http://www.epa.gov/ttn/atw/mfurn/mfurnpg.html
Pechan, 1997: E.H. Pechan & Associates, Inc., "Integrated Ozone, Particulate Matter, and Regional
Haze Cost Analysis - Methodology and Results," prepared for U.S. Environmental Protection
Agency, Innovative Strategies and Economics Group, Office of Air Quality Planning and Standards,
June 1997.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Metal Furniture, Appliances, Parts
Control Measure Name: SCAQMD Limits
Rule Name: South Coast Air Quality Management District Rule 1107 - Coating of Metal
Parts and Products
Pechan Measure Code: V24502	POD: 245
Application: SCAQMD Rule 1107 establishes VOC content limits for metal coatings along with
application procedures and equipment requirements. The rule also mentions several
options for reducing VOC emissions, including using reformulated low-VOC content
compliant coatings, powder coating for both general and high gloss coatings, UV
curable coatings, high transfer efficiency coating applications, and increased
effectiveness of add-on control equipment. The original rule was promulgated in 1979
and has been amended several times, most recently in November 2001.
This rule applies to emissions that result from the coating of metal parts and products
including furniture (SCC 2401025000), appliances (SCC 2401060000), and
miscellaneous manufacturing (SCC 2401090000).
Affected SCC:
2401025000 Metal Furniture: SIC 25, Total: All Solvent Types
2401060000 Large Appliances: SIC 363, Total: All Solvent Types
2401090000 Miscellaneous Manufacturing, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 55% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The costs of this control are based on cost effectiveness provided by SCAQMD staff
for the development of SCAQMD Rule 1107. Cost effectiveness is the average cost
per ton of the expected allocation of control measures to sources in the South Coast
Air Quality Basin. Factors affecting cost include product reformulations and level of
add-on controls required. SCAQMD notes that add-on control equipment is
considerably more expensive than low-VOC coating reformulation (SCAQMD, 1996).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $2,027 per ton VOC reduced
(1990$).
Comments: SCAQMD notes that powder coating is very effective in reducing VOC emissions
because in most cases it contains less than 3 percent VOC. Moreover, it is applied by
electrostatic attraction which has high transfer efficiency (SCAQMD, 1996).
Status: Demonstrated
Last Reviewed: 1996
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AT-A-GLANCE TABLE FOR AREA SOURCES
Additional Information:
Since its original adoption in 1979, SCAQMD Rule 1107 has been amended several times to adjust
the compliance schedule, and modify provisions due to delayed progress in the development and
use of compliant coatings (SCAQMD, 2001). This control measure represents requirements as they
stood in 1996.
Coating of metal parts and products are applied to prevent corrosion and to enhance appearance.
The metal parts or products undergo a cleaning process to remove grease, dust, mill scale, or
corrosion. Often they are also pretreated to improve coating adhesion. Commonly, the metal
substrate is washed through an alkaline, chromate, or non-caustic solution wash and is then rinsed
in water. After the final rinse, the metal normally passes through an oven to evaporate water before
the coating is applied (SCAQMD, 1996).
Coating is applied either by spraying, dipping, or flow coating. Conventional, high volume low
pressure (HVLP), or electrostatic spray guns are used for spraying (SCAQMD, 1996). After coating,
the parts are either baked in ovens or air-dried depending on the type of coating.
References:
SCAQMD, 1996: South Coast Air Quality Management District. "1997 Air Quality Management
Plan - Appendix IV-A. Stationary and Mobile Source Control Measures," August 1996.
SCAQMD, 2001: South Coast Air Quality Management District, "Rule 1107- Coating of Metal Parts
and Products," November 2001. Retrieved April 29, 2003 from www.aqmd.gov/rules/html/r1107.html.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Miscellaneous Metal Products Coatings
Control Measure Name: MACT Standard
Rule Name: Maximum Achievable Control Technology for Miscellaneous Metal Parts
and Products
Pechan Measure Code: V24701
POD: 247
Application: The 10 year MACT for Miscellaneous Metal Products Coatings sets VOC emissions
limits from the source category. The rule delineates compliance options, including low-
VOC coatings or an emissions capture system in conjunction with add-on controls
(67FR52799, 2002). The rule was proposed in August 2002.
This control affects the metal coating source category classified under the following
SCCs: railroad rolling stock (SCC 2401085000) and machinery (SCC 2401055000).
Affected SCC:
2401055000 Machinery and Equipment: SIC 35, Total: All Solvent Types
2401085000 Railroad: SIC 374, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 36% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: At the time this control measure was developed the MACT had not yet been
proposed. Pechan estimated the cost of the MACT requirements to be $1,000 based
on a 36% control efficiency (Pechan, 1997).
Cost Effectiveness: The cost effectiveness is $1,000 per ton VOC reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
References:
67FR52799, 2002: Federal Register, "National Emission Standards for Hazardous Air Pollutants:
Surface Coating of Miscellaneous Metal Parts and Products - Proposed Rule," Washington, DC,
August 2002.
Pechan, 1997: E.H. Pechan & Associates: "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997..
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Motor Vehicle Coating
Control Measure Name: MACT Standard
Rule Name: Maximum Achievable Control Technology for Motor Vehicle Coating
Pechan Measure Code: V25401	POD: 254
Application: The MACT regulation is based on best available controls, as defined under the Clean
Air Act, and sets specific VOC content limits on 7 categories of automobile refinish
coatings (generally classified as primers and topcoats). VOC limits would be met by
product reformulation, requiring the use of coatings with lower VOC content than the
coatings currently in use. Most manufacturers already produce low-VOC coatings.
EPA's rule would affect approximately 5 large automobile refinish coating component
manufacturers and importers and an additional 10-15 smaller manufacturers.
Affected SCC:
2401070000 Motor Vehicles: SIC 371, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 37% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: EPA calculated the total costs of the regulation as the sum of the costs for necessary
process modifications and employee training costs. The total capital investment for
process modifications is $10 million, the majority of which is for the purchase of
pumping and mixing equipment to process higher-solids coatings. The costs for
training personnel to use the new coatings was estimated separately for coating
manufacturers, distributors, and body shops. The total cost of the proposed rule
includes coating manufacturer process modification costs, and costs for training
coating manufacturer representatives, distributors, and body shop personnel.
A training cost of $425 per employee was applied to manufacturing employees,
distributors, and painters at body shops.
Process modification and training costs were annualized over 10 years at an interest
rate of 7 percent for a total annual cost of $4.5 million (EPA, 1995).
Cost Effectiveness: The cost effectiveness is $118 per ton VOC reduced (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR AREA SOURCES
Additional Information:
In April 1996, EPA proposed a national standard to reduce VOC emissions from the use of
automobile refinish coatings (61FR19005, 1996). EPA's regulation does not affect the application of
automobile refinish coatings, and therefore body shops nationwide are not directly affected by the
regulation's requirements. The rule is expected to reduce VOC emissions by 37 percent from
baseline levels.
Research and development costs associated with formulating low-VOC coatings were not
considered, since these costs are assumed to have been incurred as the result of state regulations
(EPA, 1995).
References:
EPA, 1995: U.S. Environmental Protection Agency, "Volatile Organic Compound Emissions from
Automobile Refinishing-Background Information for Proposed Standards," Office of Air Quality
Planning and Standards, Research Triangle Park, NC, EPA-453/D-95-005a, August 1995.
61FR19005, 1996: Federal Register, "National Volatile Organic Compound Emission Standards for
Automobile Refinish Coatings; Proposed Rule," Volume 61, Number 84, April 30, 1996.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Motor Vehicle Coating
Control Measure Name: Incineration
Rule Name: Not Applicable
Pechan Measure Code: V25402
POD: 254
Application: This is a generic control measure based on the use of incineration to reduce VOC
emissions from motor vehicle coating facilities.
Affected SCC:
2401070000 Motor Vehicles: SIC 371, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 90% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Pechan estimates that the cost effectiveness is $8,937 per ton to require incineration
of VOC emissions from motor vehicle coating facilities (Pechan, 1998).
Cost Effectiveness: A cost effectiveness of $8,937 per ton VOC reduced is used in AirControlNET
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1998: E.H. Pechan & Associates, "Clean Air Act Section 812 Prospective Cost Analysis -
Draft Report," prepared for prepared for U.S. Environmental Protection Agency, September 1998.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Municipal Solid Waste Landfill
Control Measure Name: Gas Collection (SCAQMD/BAAQMD)
Rule Name: Bay Area Air Quality Management District Regulation 8 - Rule 34 - Gas
Collection
Pechan Measure Code: V28402
POD: 284
Application: The rule is intended to limit Municipal Solid Waste (MSW) landfill emissions to prevent
public nuisance and possible detriment to public health caused by exposure to such
emissions. The rule, implemented in 1999, requires the installation of a gas collection
system and emission control system.
This control applies to all municipal solid waste landfills.
Affected SCC:
2620000000 All Categories, Total
2620030000 Municipal, Total
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 70% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: Cost effectiveness is based on information provided by the BAAQMD for the
installation of gas collection systems and emissions control systems. No additional
details were found in Bay Area documentation.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $700 per ton VOC reduced, in
1992 dollars (BAAQMD, 1999).
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
References:
BAAQMD, 1999: Bay Area Air Quality Management District, Regulation 8: Organic Compounds,
"Rule 34: Solid Waste Disposal Sites," Adopted May, 1984. Last Updated October, 1999.
Document No. 05.09.009/9010.463
III-1420
Report

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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Nonroad Gasoline Engines
Control Measure Name: Federal Reformulated Gasoline
Rule Name: Federal Reformulated Gasoline Standards (Phase II)
Pechan Measure Code: VNRFG	POD: N/A
Application: The federal rule provides expected emission reductions from the use of reformulated
gasoline as a fuel for all 2-stroke and 4-stroke nonroad gasoline engine categories.
Affected SCC:
2260001020 Recreational Equipment, Snowmobiles
2260001030 Recreational Equipment, Offroad Motorcycles/ATVs
2260001060 Recreational Equipment, Specialty Vehicles/Carts
2260002006 Construction and Mining Equipment, Tampers/Rammers
2260002009 Construction and Mining Equipment, Plate Compactors
2260002021 Construction and Mining Equipment, Paving Equipment
2260002039 Construction and Mining Equipment, Concrete/Industrial Saws
2260003030 Industrial Equipment, Sweepers/Scrubbers
2260004015	Lawn and Garden Equipment, Rotary Tillers < 6 HP (Residential)
2260004016	Lawn and Garden Equipment, Rotary Tillers < 6 HP (Commercial)
2260004020	Lawn and Garden Equipment, Chain Saws < 6 HP (Residential)
2260004021	Lawn and Garden Equipment, Chain Saws < 6 HP (Commercial)
2260004025	Lawn and Garden Equipment, Trimmers/Edgers/Brush Cutters (Residential)
2260004026	Lawn and Garden Equipment, Trimmers/Edgers/Brush Cutters (Commercial)
2260004030	Lawn and Garden Equipment, Vacuums/Vacuums (Residential)
2260004031	Lawn and Garden Equipment, Vacuums/Vacuums (Commercial)
2260004035	Lawn and Garden Equipment, Snow blowers (Residential)
2260004036	Lawn and Garden Equipment, Snow blowers (Commercial)
2260006005 Commercial Equipment, Generator Sets
2260006010 Commercial Equipment, Pumps
2260007005 Logging Equipment, Chain Saws > 6 HP
2265001030 Recreational Equipment, Offroad Motorcycles/ATVs
2265001050 Recreational Equipment, Golf Carts
2265001060 Recreational Equipment, Specialty Vehicles/Carts
2265002003 Construction and Mining Equipment, Pavers
2265002009 Construction and Mining Equipment, Plate Compactors
2265002015 Construction and Mining Equipment, Rollers
2265002021 Construction and Mining Equipment, Paving Equipment
2265002024 Construction and Mining Equipment, Surfacing Equipment
2265002030 Construction and Mining Equipment, Trenchers
2265002033 Construction and Mining Equipment, Bore/Drill Rigs
2265002039 Construction and Mining Equipment, Concrete/Industrial Saws
2265002042 Construction and Mining Equipment, Cement and Mortar Mixers
2265002060 Construction and Mining Equipment, Rubber Tire Loaders
2265002066 Construction and Mining Equipment, Tractors/Loaders/Backhoes
2265002072 Construction and Mining Equipment, Skid Steer Loaders
2265002078 Construction and Mining Equipment, Dumpers/Tenders
2265003010 Industrial Equipment, Aerial Lifts
2265003020 Industrial Equipment, Forklifts
2265003030 Industrial Equipment, Sweepers/Scrubbers
2265003040 Industrial Equipment, Other General Industrial Equipment
Document No. 05.09.009/9010.463
III-1421
Report

-------
AT-A-GLANCE TABLE FOR AREA SOURCES
2265003050 Industrial Equipment, Other Material Handling Equipment
2265003070 Industrial Equipment, Terminal Tractors
2265004010	Lawn and Garden Equipment, Lawn Mowers (Residential)
2265004011	Lawn and Garden Equipment, Lawn Mowers (Commercial)
2265004015	Lawn and Garden Equipment, Rotary Tillers < 6 HP (Residential)
2265004016	Lawn and Garden Equipment, Rotary Tillers < 6 HP (Commercial)
2265004025	Lawn and Garden Equipment, Trimmers/Edgers/Brush Cutters (Residential)
2265004026	Lawn and Garden Equipment, Trimmers/Edgers/Brush Cutters (Commercial)
2265004030	Lawn and Garden Equipment, Vacuums/Vacuums (Residential)
2265004031	Lawn and Garden Equipment, Vacuums/Vacuums (Commercial)
2265004035	Lawn and Garden Equipment, Snow blowers (Residential)
2265004036	Lawn and Garden Equipment, Snow blowers (Commercial)
2265004040	Lawn and Garden Equipment, Rear Engine Riding Mowers (Residential)
2265004041	Lawn and Garden Equipment, Rear Engine Riding Mowers (Commercial)
2265004046 Lawn and Garden Equipment, Front Mowers (Commercial)
2265004051 Lawn and Garden Equipment, Shredders < 6 HP (Commercial)
2265004055	Lawn and Garden Equipment, Lawn and Garden Tractors (Residential)
2265004056	Lawn and Garden Equipment, Lawn and Garden Tractors (Commercial)
2265004066 Lawn and Garden Equipment, Chippers/Stump Grinders (Commercial)
2265004071 Lawn and Garden Equipment, Turf Equipment (Commercial)
2265004075	Lawn and Garden Equipment, Other Lawn and Garden Equipment (Residential)
2265004076	Lawn and Garden Equipment, Other Lawn and Garden Equipment (Commercial)
2265005035 Agricultural Equipment, Sprayers
2265005040 Agricultural Equipment, Tillers > 6 HP
2265006005 Commercial Equipment, Generator Sets
2265006010 Commercial Equipment, Pumps
2265006015 Commercial Equipment, Air Compressors
2265006025 Commercial Equipment, Welders
2265006030 Commercial Equipment, Pressure Washers
2265007010 Logging Equipment, Shredders > 6 HP
2265008005 Airport Ground Support Equipment, Airport Ground Support Equipment
2282005010 Gasoline 2-Stroke, Outboard
2282005015 Gasoline 2-Stroke, Personal Water Craft
2282010005 Gasoline 4-Stroke, Inboard/Sterndrive
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 1.4% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: EPA's Office of Mobile Sources (OMS) estimated the VOC reductions and
corresponding cost effectiveness estimates resulting from the use of reformulated
gasoline in nonroad vehicles for exhaust and evaporative emissions.
Cost Effectiveness: Cost effectiveness (1990$) is based on SCC as follows (Pechan 1997):
2260001XXX $440/ton of VOC reduced
Document No. 05.09.009/9010.463
III-1422
Report

-------
AT-A-GLANCE TABLE FOR AREA SOURCES
2260002XXX
$1,030/ton of VOC reduced
2260003XXX
$2,500/ton of VOC reduced
2260004XXX
$1,140/ton of VOC reduced
2260006XXX
$2,225/ton of VOC reduced
2260007XXX
$1,285/ton of VOC reduced
2260008XXX
$8,850/ton of VOC reduced
2265001XXX
$1,400/ton of VOC reduced
2265002XXX
$9,250/ton of VOC reduced
2265003XXX
$8,000/ton of VOC reduced
2265004XXX
$5,000/ton of VOC reduced
2265005XXX
$4,750/ton of VOC reduced
2265006XXX
$1,8000/ton of VOC reduced
2265007XXX
$1,5250/ton of VOC reduced
2265008XXX
$5,750/ton of VOC reduced
2282005XXX
$440/ton of VOC reduced
2282010XXX
$1,400/ton of VOC reduced
Comments: This control measure is currently under review and is expected to soon be updated.
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
References:
Pechan, 1997: E.H. Pechan & Associates: "Additional Control Measure Evaluation for the Integrated
Implementation of the Ozone and Particulate Matter National Ambient Air Quality Standards, and
Regional Haze Program," prepared for U.S. Environmental Protection Agency, July 1997.
Document No. 05.09.009/9010.463
III-1423
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: All Terrain Vehicles (ATVs)
Control Measure Name: Recreational Gasoline ATV Standards
Rule Name: Recreational Gasoline ATV Standards
Pechan Measure Code: AT2010
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for ATV
engines for implementation year 2010.
Affected SCC:
2260001030 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; All Terrain Vehicles
2265001030 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; All Terrain Vehicles
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (0-34%); PM10 (0-
34%); NOX (Increase-16%); VOC (14-34%); CO (5-5%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline ATV standards, an estimate
was made of the number of affected engines for Phase 1 for each implementation
year (Pechan, 2003). Near-term costs per engine for Phase 1, obtained from EPA
2002, were then applied to the corresponding number of affected engines and
summed to obtain the total cost for this standard. The number of affected engines
was determined by subtracting out growth in engines, and using turnover data
compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of implementing these standards varies by engine type from $47 for 4-
stroke engines to $378 for 2-stroke engines ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-1424
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: All Terrain Vehicles (ATVs)
Control Measure Name: Recreational Gasoline ATV Standards
Rule Name: Recreational Gasoline ATV Standards
Pechan Measure Code: AT2015
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for ATV
engines for implementation year 2015.
Affected SCC:
2260001030 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; All Terrain Vehicles
2265001030 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; All Terrain Vehicles
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (0-73%); PM10 (0-
73%); NOX (lncrease-30%); VOC (27-73%); CO (9-14%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline ATV standards, an estimate
was made of the number of affected engines for Phase 1 for each implementation
year (Pechan, 2003). Near-term costs per engine for Phase 1, obtained from EPA
2002, were then applied to the corresponding number of affected engines and
summed to obtain the total cost for this standard. The number of affected engines
was determined by subtracting out growth in engines, and using turnover data
compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of implementing these standards varies by engine type from $47 for 4-
stroke engines to $378 for 2-stroke engines ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-1425
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: All Terrain Vehicles (ATVs)
Control Measure Name: Recreational Gasoline ATV Standards
Rule Name: Recreational Gasoline ATV Standards
Pechan Measure Code: AT2020
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for ATV
engines for implementation year 2020.
Affected SCC:
2260001030 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; All Terrain Vehicles
2265001030 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; All Terrain Vehicles
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (0-95%); PM10 (0-
95%); NOX (lncrease-36%); VOC (33-95%); CO (11-19%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline ATV standards, an estimate
was made of the number of affected engines for Phase 1 for each implementation
year (Pechan, 2003). Near-term costs per engine for Phase 1, obtained from EPA
2002, were then applied to the corresponding number of affected engines and
summed to obtain the total cost for this standard. The number of affected engines
was determined by subtracting out growth in engines, and using turnover data
compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of implementing these standards varies by engine type from $47 for 4-
stroke engines to $378 for 2-stroke engines ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-1426
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: All Terrain Vehicles (ATVs)
Control Measure Name: Recreational Gasoline ATV Standards
Rule Name: Recreational Gasoline ATV Standards
Pechan Measure Code: AT2030
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for ATV
engines for implementation year 2030.
Affected SCC:
2260001030 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; All Terrain Vehicles
2265001030 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; All Terrain Vehicles
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (0-97%); PM10 (0-
97%); NOX (lncrease-37%); VOC (33-97%); CO (12-20%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline ATV standards, an estimate
was made of the number of affected engines for Phase 1 for each implementation
year (Pechan, 2003). Near-term costs per engine for Phase 1, obtained from EPA
2002, were then applied to the corresponding number of affected engines and
summed to obtain the total cost for this standard. The number of affected engines
was determined by subtracting out growth in engines, and using turnover data
compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of implementing these standards varies by engine type from $47 for 4-
stroke engines to $378 for 2-stroke engines ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-1427
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: Motorcycles
Control Measure Name: Recreational Gasoline Off-Highway Motorcycle Standards
Rule Name: Recreational Gasoline Off-Highway Motorcycle Standards
Pechan Measure Code: MC2010
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for off-
highway motorcycle engines for implementation year 2010.
Motorcycles classified under SCCs 2260001010 and 2265001010 are affected by this
control.
Affected SCC:
2260001010 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Motorcycles: Off-road
2265001010 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; Motorcycles: Off-road
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (0-20%); PM10 (0-
20%); NOX (lncrease-7%); VOC (5-20%); CO (9-14%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline off-highway motorcycle
standards, an estimate was made of the number of affected engines for Phase 1 for
each implementation year (Pechan 2003). Near-term costs per engine for Phase 1,
obtained from EPA 2002, were then applied to the corresponding number of affected
engines and summed to obtain the total cost for this standard. The number of
affected engines was determined by subtracting out growth in engines, and using
turnover data compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost per engine ranges from $46 for 2-stroke engines to $296 for 4-stroke
engines ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022. September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
Document No. 05.09.009/9010.463
III-1428
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-1429
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: Motorcycles
Control Measure Name: Recreational Gasoline Off-Highway Motorcycle Standards
Rule Name: Recreational Gasoline Off-Highway Motorcycle Standards
Pechan Measure Code: MC2015
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for off-
highway motorcycle engines for implementation year 2015.
Motorcycles classified under SCCs 2260001010 and 2265001010 are affected by this
control.
Affected SCC:
2260001010 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Motorcycles: Off-road
2265001010 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; Motorcycles: Off-road
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (0-41%); PM10 (0-
41%); NOX (Increase-14%); VOC (10-40%); CO (18-29%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline off-highway motorcycle
standards, an estimate was made of the number of affected engines for Phase 1 for
each implementation year (Pechan 2003). Near-term costs per engine for Phase 1,
obtained from EPA 2002, were then applied to the corresponding number of affected
engines and summed to obtain the total cost for this standard. The number of
affected engines was determined by subtracting out growth in engines, and using
turnover data compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost per engine ranges from $46 for 2-stroke engines to $296 for 4-stroke
engines ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022. September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
Document No. 05.09.009/9010.463
III-1430
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-1431
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: Motorcycles
Control Measure Name: Recreational Gasoline Off-Highway Motorcycle Standards
Rule Name: Recreational Gasoline Off-Highway Motorcycle Standards
Pechan Measure Code: MC2020
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for off-
highway motorcycle engines for implementation year 2020.
Motorcycles classified under SCCs 2260001010 and 2265001010 are affected by this
control.
Affected SCC:
2260001010 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Motorcycles: Off-road
2265001010 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; Motorcycles: Off-road
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (0-51%); PM10 (0-
51%); NOX (Increase-17%); VOC (12-50%); CO (22-36%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline off-highway motorcycle
standards, an estimate was made of the number of affected engines for Phase 1 for
each implementation year (Pechan 2003). Near-term costs per engine for Phase 1,
obtained from EPA 2002, were then applied to the corresponding number of affected
engines and summed to obtain the total cost for this standard. The number of
affected engines was determined by subtracting out growth in engines, and using
turnover data compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost per engine ranges from $46 for 2-stroke engines to $296 for 4-stroke
engines ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022. September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
Document No. 05.09.009/9010.463
III-1432
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-143 3
Report

-------
AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: Motorcycles
Control Measure Name: Recreational Gasoline Off-Highway Motorcycle Standards
Rule Name: Recreational Gasoline Off-Highway Motorcycle Standards
Pechan Measure Code: MC2030
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for off-
highway motorcycle engines for implementation year 2030.
Motorcycles classified under SCCs 2260001010 and 2265001010 are affected by this
control.
Affected SCC:
2260001010 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Motorcycles: Off-road
2265001010 Off-highway Vehicle Gasoline, 4-Stroke; Recreational Equipment; Motorcycles: Off-road
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


V
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by equipment category: PM2.5 (0-52%); PM10 (0-
52%); NOX (Increase-17%); VOC (12-52%); CO (23-37%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline off-highway motorcycle
standards, an estimate was made of the number of affected engines for Phase 1 for
each implementation year (Pechan 2003). Near-term costs per engine for Phase 1,
obtained from EPA 2002, were then applied to the corresponding number of affected
engines and summed to obtain the total cost for this standard. The number of
affected engines was determined by subtracting out growth in engines, and using
turnover data compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost per engine ranges from $46 for 2-stroke engines to $296 for 4-stroke
engines ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022. September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
Document No. 05.09.009/9010.463
III-1434
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-143 5
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: Snowmobiles
Control Measure Name: Recreational Gasoline Snowmobile Standards
Rule Name: Recreational Gasoline Snowmobile Standards
Pechan Measure Code: SM2010
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for 2-
stroke gasoline snowmobile engines for implementation year 2010.
This control applies to snowmobiles classified under SCC 2260001020.
Affected SCC:
2260001020 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Snowmobiles
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


X
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by pollutant: PM2.5 (10%); PM10 (10%); NOX
(Increase); VOC (20%); CO (17%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline snowmobile standards, an
estimate was made of the number of affected engines by technology type for each
implementation year (Pechan, 2003). Near-term costs per engine by technology type,
obtained from EPA 2002, were then applied to the corresponding number of affected
engines and summed to obtain the total cost for this standard. The number of
affected engines was determined by subtracting out growth in engines, and using
turnover data compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of implementing these standards varies by technology type from $57
to $823 per engine ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Document No. 05.09.009/9010.463
III-143 6
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-143 7
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: Snowmobiles
Control Measure Name: Recreational Gasoline Snowmobile Standards
Rule Name: Recreational Gasoline Snowmobile Standards
Pechan Measure Code: SM2015
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for 2-
stroke gasoline snowmobile engines for implementation year 2015.
This control applies to snowmobiles classified under SCC 2260001020.
Affected SCC:
2260001020 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Snowmobiles
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


X
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by pollutant: PM2.5 (31%); PM10 (31%); NOX
(Increase); VOC (45%); CO (38%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline snowmobile standards, an
estimate was made of the number of affected engines by technology type for each
implementation year (Pechan, 2003). Near-term costs per engine by technology type,
obtained from EPA 2002, were then applied to the corresponding number of affected
engines and summed to obtain the total cost for this standard. The number of
affected engines was determined by subtracting out growth in engines, and using
turnover data compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of implementing these standards varies by technology type from $57
to $823 per engine ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Document No. 05.09.009/9010.463
III-143 8
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-143 9
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: Snowmobiles
Control Measure Name: Recreational Gasoline Snowmobile Standards
Rule Name: Recreational Gasoline Snowmobile Standards
Pechan Measure Code: SM2020
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for 2-
stroke gasoline snowmobile engines for implementation year 2020.
This control applies to snowmobiles classified under SCC 2260001020.
Affected SCC:
2260001020 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Snowmobiles
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


X
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by pollutant: PM2.5 (49%); PM10 (49%); NOX
(Increase); VOC (62%); CO (51%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline snowmobile standards, an
estimate was made of the number of affected engines by technology type for each
implementation year (Pechan, 2003). Near-term costs per engine by technology type,
obtained from EPA 2002, were then applied to the corresponding number of affected
engines and summed to obtain the total cost for this standard. The number of
affected engines was determined by subtracting out growth in engines, and using
turnover data compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of implementing these standards varies by technology type from $57
to $823 per engine ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Document No. 05.09.009/9010.463
III-1440
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Document No. 05.09.009/9010.463
III-1441
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Source Category: Off-Highway Vehicles: Snowmobiles
Control Measure Name: Recreational Gasoline Snowmobile Standards
Rule Name: Recreational Gasoline Snowmobile Standards
Pechan Measure Code: SM2030
POD: N/A
Application: This control measure is the application of EPA's Federal exhaust standards for 2-
stroke gasoline snowmobile engines for implementation year 2030.
This control applies to snowmobiles classified under SCC 2260001020.
Affected SCC:
2260001020 Off-highway Vehicle Gasoline, 2-Stroke; Recreational Equipment; Snowmobiles
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg
V
V


X
V*


V

V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: The control efficiency varies by pollutant: PM2.5 (58%); PM10 (58%); NOX
(Increase); VOC (69%); CO (56%).
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: To calculate costs for the nonroad recreational gasoline snowmobile standards, an
estimate was made of the number of affected engines by technology type for each
implementation year (Pechan, 2003). Near-term costs per engine by technology type,
obtained from EPA 2002, were then applied to the corresponding number of affected
engines and summed to obtain the total cost for this standard. The number of
affected engines was determined by subtracting out growth in engines, and using
turnover data compiled from EPA's NONROAD 2002 model.
All costs are in 2001 dollars.
Cost Effectiveness: The cost of implementing these standards varies by technology type from $57
to $823 per engine ($2001).
Comments:
Status: Demonstrated
Last Reviewed: 2003
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, Office of Air and Radiation, Office of
Transportation and Air Quality, "Final Regulatory Support Document: Control of Emissions from
Unregulated Nonroad Engines," EPA420-R-02-022, September 2002.
Pechan, 2003: E.H. Pechan & Associates, Inc., "AirControlNET Development Report," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
Document No. 05.09.009/9010.463
III-1442
Report

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AT-A-GLANCE TABLE FOR NONROAD SOURCES
Research Triangle Park, NC, Pechan Report No. 03.08.002/9010.242, August 2003.
Source Category: Oil and Natural Gas Production
Control Measure Name: Equipment and Maintenance
Rule Name: Not Applicable
Pechan Measure Code: V27901	POD: 279
Application:
Affected SCC:
2310000000 All Processes, Total: All Processes
2310010000 Crude Petroleum, Total: All Processes
2310020000 Natural Gas, Total: All Processes
2310030000 Natural Gas Liquids, Total: All Processes
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 37% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis:
Cost Effectiveness: The cost effectiveness is $317 per ton VOC reduced (1990$).
Comments: No description of this control measure was found in Pechan's Documentation.
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
References:
Document No. 05.09.009/9010.463
III-1443
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Open Top Degreasing
Control Measure Name: Title III MACT Standard
Rule Name: Maximum Achievable Control Technology for Open Top Degreasing
Pechan Measure Code: V23201	POD: 232
Application: The provisions of the MACT for open top degreasing apply to individual batch vapor, in-
line vapor, in-line cold, and batch cold solvent cleaning machines. VOC emissions
from degreasing operations can be reduced by the use of low-VOC content solvents,
and by changes in operating practices (EPA, 1993). The original MACT was
promulgated in 1994.
Degreasing operations are associated with VOC emissions as a result of using
solvents to clean contaminants from parts, products, tools, machinery, and equipment.
This control measure is applicable to several area source SCCs beginning with "2415".
Affected SCC:
2415100000 All Industries: Open Top Degreasing, Total: All Solvent Types
2415105000 Furniture and Fixtures (SIC 25): Open Top Degreasing, Total: All Solvent Types
2415110000 Primary Metal Industries (SIC 33): Open Top Degreasing, Total: All Solvent Types
2415120000 Fabricated Metal Products (SIC 34): Open Top Degreasing, Total: All Solvent Types
2415125000 Industrial Machinery & Equipment (SIC 35)-Open Top Degreasing, Total- All Solvents
2415130000 Electronic and Other Elec. (SIC 36): Open Top Degreasing, Total: All Solvent Types
2415135000 Transportation Equipment (SIC 37): Open Top Degreasing, Total: All Solvent Types
2415140000 Instruments & Related Products (SIC 38)-Open Top Degreasing, Total-All Solvents
2415145000 Miscellaneous Manufacturing (SIC 39): Open Top Degreasing, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 31% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In the cost analysis for the halogenated solvent NESHAP, EPA estimated costs by
cleaner size (small, medium, large, very large, and in-line). The cost effectiveness
used to estimate costs reflect a weighted average across all model facility sizes.
Costs reflects distribution of emissions by model plant size.
The range of cost effectiveness is from a SAVINGS of $148 for in-line cleaners to a
cost of $128 for small cleaners (Pechan, 1998).
Cost Effectiveness: The cost effectiveness used in AirControlNET is a SAVINGS of $69 per ton
VOC reduction (1990$). (Pechan, 1998).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Document No. 05.09.009/9010.463
III-1444
Report

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AT-A-GLANCE TABLE FOR AREA SOURCES
Additional Information:
There are two basic types of solvent cleaning equipment: batch cleaners, and in-line or continuous
cleaners. Batch vapor cleaners heat the solvent to boiling and create a solvent vapor zone within
the machine in which parts are cleaned. In-line cleaners are enclosed devices distinguished by a
conveyor system to continuously supply a stream of parts for cleaning. Batch cold cleaning
machines use non-boiling solvent to clean parts. The halogenated solvent cleaning NESHAP
reflects the application of the maximum achievable control technology (MACT) for all batch vapor
and in-line units. For area source batch cold cleaning machines, the standard reflects the GACT
(59FR61801, 1994).
References:
Pechan, 1998: E.H. Pechan & Associates, "Clean Air Act Section 812 Prospective Cost Analysis -
Draft Report" prepared for U.S. Environmental Protection Agency, September 1998.
EPA, 1993: U.S. Environmental Protection Agency, "Halogenated Solvent Cleaning National
Emission standards for Hazardous Air Pollutants: Background Information Document," Research
Triangle Park, NC, November 4, 1993.
59FR61801, 1994: Federal Register, "National Emission Standards for Hazardous Air Pollutants:
Halogenated Solvent Cleaning; Final Rule," December 2, 1994.
Document No. 05.09.009/9010.463
III-1445
Report

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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Open Top Degreasing
Control Measure Name: SCAQMD 1122 (VOC content limit)
Rule Name: South Coast Air Quality Management District Rule 1122 - Solvent
Degreasers (VOC Content Limit)
Pechan Measure Code: V23202	POD: 232
Application: VOC emissions from degreasing operations can be reduced by the use of low-VOC
content solvents, and by changes in operating practices. This rule was originally
adopted in 1979, but has since been amended to specify maximum ventilating
conditions, minimize drag-out losses, eliminate some rule exemptions, expand the rule
to smaller cold degreasers, and further limit the solvent content of waste materials.
This rule was most recently amended in 1997.
This control measure is applicable to several area source SCCs beginning with "2415"
Affected SCC:
2415100000 All Industries: Open Top Degreasing, Total: All Solvent Types
2415105000 Furniture and Fixtures (SIC 25): Open Top Degreasing, Total: All Solvent Types
2415110000 Primary Metal Industries (SIC 33): Open Top Degreasing, Total: All Solvent Types
2415120000 Fabricated Metal Products (SIC 34): Open Top Degreasing, Total: All Solvent Types
2415125000 Industrial Machinery & Equipment (SIC 35)-Open Top Degreasing, Total- All Solvents
2415130000 Electronic and Other Elec. (SIC 36): Open Top Degreasing, Total: All Solvent Types
2415135000 Transportation Equipment (SIC 37): Open Top Degreasing, Total: All Solvent Types
2415140000 Instruments & Related Products (SIC 38)-Open Top Degreasing, Total-All Solvents
2415145000 Miscellaneous Manufacturing (SIC 39): Open Top Degreasing, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 76% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost estimates are based on studies done in the development and amendment of
the SCAQMD Rule 1122. (SCAQMD, 1996; SCAQMD, 1997) The amendments are
estimated to reduce emissions from solvent degreasing tanks (as opposed to hand-
held cleaning) by 76 percent by using widely available no- or low-VOC solvents. The
expected cost is $1,391 per ton of VOC reduced (1997 dollars) (SCAQMD, 1997).
Cost Effectiveness: The cost effectiveness is estimated to be $1,248 per ton VOC reduced (1990$)
(SCAQMD, 1997).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR AREA SOURCES
Additional Information:
Rule 1122 applies to both batch and conveyorized degreasing. The latest amendments, from 1997,
set lower VOC limits for batch loaded and conveyorized cold cleaners at 50 grams of VOC per liter
of material (SCAQMD, 1997).
Open-top vapor degreasers include a tank for holding the solvent and a heating system to heat and
vaporize the liquid solvent. As the liquid solvent vaporizes, a vapor layer is formed above the liquid
solvent. The cleaning action is provided by the solvent vapor condensing on the cooler (dirty) parts
and either dissolving or flushing contaminants from the parts. The cleaning operation is complete
when the temperature of the parts reaches that of the vapor, thereby ending the condensation
process (SCAQMD, 1996). The soiled solvent is periodically removed and replaced with fresh
solvent.
References:
SCAQMD, 1996: South Coast Air Quality Management District, "1997 Air Quality Management
Plan - Appendix IV-A: Stationary and Mobile Source Control Measures," August 1996.
SCAQMD, 1997: South Coast Air Quality Management District, Draft Staff Report for Proposed
Amendments to Rule 1122 - Solvent Degreasers, June 3, 1997.
Document No. 05.09.009/9010.463
III-1447
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Open Top Degreasing
Control Measure Name: Airtight Degreasing System
Rule Name: Not Applicable
Pechan Measure Code: V23203	POD: 232
Application: An airtight degreasing unit provides an enclosed environment from which no VOCs can
escape.
Emissions for this source category are classified under several area source SCCs
beginning with "2415".
Affected SCC:
2415100000 All Industries: Open Top Degreasing, Total: All Solvent Types
2415105000 Furniture and Fixtures (SIC 25): Open Top Degreasing, Total: All Solvent Types
2415110000 Primary Metal Industries (SIC 33): Open Top Degreasing, Total: All Solvent Types
2415120000 Fabricated Metal Products (SIC 34): Open Top Degreasing, Total: All Solvent Types
2415125000 Industrial Machinery & Equipment (SIC 35)-Open Top Degreasing, Total- All Solvents
2415130000 Electronic and Other Elec. (SIC 36): Open Top Degreasing, Total: All Solvent Types
2415135000 Transportation Equipment (SIC 37): Open Top Degreasing, Total: All Solvent Types
2415140000 Instruments & Related Products (SIC 38)-Open Top Degreasing, Total-All Solvents
2415145000 Miscellaneous Manufacturing (SIC 39): Open Top Degreasing, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 98% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: In the study to amend Rule 1122, the SCAQMD examined this more stringent control
option that requires airless batch cleaning systems or air-tight cleaning systems.
This would reduce emissions by a total of 98 percent. The incremental cost
effectiveness was taken from the study to amend SCAQMD Rule 1122, estimated to
be $53,360 per ton (beyond the amended rule). (SCAQMD, 1997)
Note: All costs are in 1990 dollars.
Cost Effectiveness: The cost effectiveness is estimated to be $9,789 per ton VOC reduced (1990$)
(SCAQMD, 1997).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
Additional research is needed to determine the fixed versus recurring cost breakout for open top
degreasing control regulations. In general, if new degreasing agents are used, little or no capital
expenditures would be required. For the more stringent options such as this one, new equipment is
Document No. 05.09.009/9010.463	JJI-1448	Report

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AT-A-GLANCE TABLE FOR AREA SOURCES
required.
Open-top vapor degreasers include a tank for holding the solvent and a heating system to heat and
vaporize the liquid solvent. As the liquid solvent vaporizes, a vapor layer is formed above the liquid
solvent. The cleaning action is provided by the solvent vapor condensing on the cooler (dirty) parts
and either dissolving or flushing contaminants from the parts. The cleaning operation is complete
when the temperature of the parts reaches that of the vapor, thereby ending the condensation
process (SCAQMD, 1996). The soiled solvent is periodically removed and replaced with fresh
solvent.
References:
SCAQMD, 1996: South Coast Air Quality Management District. "1997 Air Quality Management
Plan - Appendix IV-A. Stationary and Mobile Source Control Measures," August 1996.
SCAQMD, 1997: South Coast Air Quality Management District, "Draft Staff Report for Proposed
Amendments to Rule 1122 - Solvent Degreasers," June 1997.
Document No. 05.09.009/9010.463
III-1449
Report

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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Paper and other Web Coating Operations
Control Measure Name: Permanent Total Enclosure (PTE)
Rule Name: Not Applicable
Pechan Measure Code: V40205	POD: 205
Application: A PTE is an enclosure used to surround a source of emissions so that all, or nearly all,
emissions are captured and contained, usually for discharge to a control device. The
paper and other web coating category includes the surface coating of pressure-
sensitive tapes and labels, photographic film, industrial and decorative laminates,
flexible vinyl products, flexible packaging, abrasive products and folding paperboard
boxes. The EPA evaluated VOC emission control options for the paper and other web
coating industry including the use of a PTE in conjunction with a regenerative thermal
oxidizer in the MACT standard-setting process for this source category.
Affected SCC:
30701199 Pulp and Paper and Wood Products, Paper Coating and Glazing, Extrusion Coating Line
with Solvent Free Resin/Wax
40201301 Surface Coati
40201303	Surface Coat
40201304	Surface Coat
40201305	Surface Coat
40201310 Surface Coat
40201320 Surface Coat
40201330 Surface Coat
40201399 Surface Coat
40202201	Surface Coat
40202202	Surface Coat
40202203	Surface Coat
40202204	Surface Coat
40202205	Surface Coat
40202206	Surface Coat
40202207	Surface Coat
40202208	Surface Coat
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
ng Operations
Coating
40202209	Surface Coating Operations
40202210	Surface Coating Operations
(40% Efficiency)
40202211	Surface Coating Operations
40202212	Surface Coating Operations
Shielding Coating
40202213	Surface Coating Operations
EMI/RFI Shielding Coating
40202214	Surface Coating Operations
Coating
40202215	Surface Coating Operations
40202220 Surface Coating Operations
40202229	Surface Coating Operations
40202230	Surface Coating Operations
40202239	Surface Coating Operations
40202240	Surface Coating Operations
Knife Coater
Reverse Roll Coater
Rotogravure Printer
Paper Coating, Coating Operation
Paper Coating, Coating Mixing
Paper Coating, Coating Storage
Paper Coating, Equipment Cleanup
Paper Coating, Coating Application:
Paper Coating, Coating Application:
Paper Coating, Coating Application:
Paper Coating, Other Not Classified
Plastic Parts, Coating Operation
Cleaning/Pretreatment
Coating Mixing
Coating Storage
Equipment Cleanup
Business: Baseline Coating Mix
Business: Low Solids Solvent-borne Coating
Business: Medium Solids Solvent-borne
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic Parts
Plastic
Plastic
Plastic
Plastic
Plastic
Plastic
Parts
Parts
Parts
Parts
Parts
Parts
Business: High Solids Coating (25% Efficiency)
Business: High Solids Solvent-borne Coating
Business: Water-borne Coating
Business: Low Solids Solvent-borne EMI/RFI
Business: Higher Solids Solvent-borne
Business: Water-borne EMI/RFI Shielding
Business: Zinc Arc Spray
Prime Coat Application
Prime Coat Flashoff
Color Coat Application
Color Coat Flashoff
Topcoat/Texture Coat Application
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
40202249	Surface Coating Operations, Plastic Parts, Topcoat/Texture Coat Flashoff
40202250	Surface Coating Operations, Plastic Parts, EMI/RFI Shielding Coat Application
40202259 Surface Coating Operations, Plastic Parts, EMI/RFI Shielding Coat Flashoff
40202270 Surface Coating Operations, Plastic Parts, Sanding/Grit Blasting Prior to EMI/RFI
Shielding Coat Application
40202280 Surface Coating Operations, Plastic Parts, Maskant Application
40202299 Surface Coating Operations, Plastic Parts, Other Not Classified
31605001 Photographic Film Manufacturing, Product Manufacturing - Surface Treatments, Surface
Coating Operations
31616004 Photographic Film Manufacturing, Support Activities - Other Operations, Paint Spraying
Operations
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled
Equipment Life: 30 years (PTE); 10 years (thermal oxidizer)
Rule Effectiveness: 100% for point and area sources
Penetration: 100%
Cost Basis: The cost analysis is based on an average of PTE and oxidizer capital and operating
and maintenance costs developed for five model rotogravure printing plants evaluated
by EPA for the Paper and Other Web Coating MACT standard (40 CFR Part 63
Subpart JJJJ). Consistent with the OAQPS Control Cost Manual, an interest rate of
7% was used to determine the capital recovery factor. Although the PTE is expected
to have a life of 30 years, PTE costs were annualized over a 10 year period (the
expected life of the thermal oxidizer). Each PTE was assumed to capture 100% of all
VOC emissions. All captured emissions were assumed to be vented to a
regenerative thermal oxidizer having a 95% control efficiency. Therefore, the net
VOC control efficiency is 95%. Year 1998 dollars were specified for cost calculations
in the EPA background document for the paper and other web coating industry.
Cost Effectiveness: The cost effectiveness is $1,503 per ton VOC reduction (1998$). The cost
effectiveness is based on an annualized capital cost of $659,351 and an annual
operation and maintenance (O&M) cost of $671,167 averaged over two model
paper and other web printing plants.
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
EPA, 2000: U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air
Pollutants for Source Categories: Paper and Other Web Coating Operations - Background
Information for Proposed Standards", April 2000.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual", Sixth Edition, document EPA/452/B-02-001, January 2002.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Paper Surface Coating
Control Measure Name: Incineration
Rule Name: Not Applicable
Pechan Measure Code: V24001
POD: 240
Application: This is a generic control measure based on the use of incineration to reduce VOC
emissions from paper coating processes
Area source VOC emissions for the paper coating source category are classified under
SCCs 2401030000.
Affected SCC:
2401030000 Paper: SIC 26, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 78% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 80%
Penetration: 100%
Cost Basis: Pechan estimated the costs based on estimates for VOC reduction under the Post-
CAAA scenarios (Pechan, 1998).
Cost Effectiveness: A cost effectiveness of $4,776 per ton VOC reduced is used in AirControlNET
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1998
Additional Information:
References:
Pechan, 1998: E.H. Pechan & Associates, "Clean Air Act Section 812 Prospective Cost Analysis -
Draft Report," prepared for U.S. Environmental Protection Agency, September 1998.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Pesticide Application
Control Measure Name: Reformulation - FIP Rule
Rule Name: California Federal Implementation Plan Rule (Reformulation)
Pechan Measure Code: V29502	POD: 295
Application: The California Federal Implementation Plan (FIP) rule intends to reach the VOC limits
by switching to and/or encouraging the use of low-VOC pesticides and better
Integrated Pest Management (IPM) practices.
All types of pesticide applications are affected by this rule.
Affected SCC:
2461800000 Pesticide Application: All Processes, Total: All Solvent Types
2461850000 Pesticide Application: Agricultural, All Processes
2465800000 Pesticide Application, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The California Federal Implementation Plan (FIP) Rule is the basis for estimating
emission reductions and costs for pesticide application.
Annualized costs resulting from this rule include those associated with:
VOC content analysis required of all pesticide producers = $6,000,000,
New studies to support reformulation of restricted pesticides = $408,000,000
Registration fees of reformulated products = $556,000,000
The CA FIP estimated the cost effectiveness for a 20 percent reduction to be $9,300
per ton based on the above annualized costs and an emissions reduction of 157 tons
per day (Radian, 1994). This cost is likely overestimated given the information
available from California's Department of Pesticide Regulation; however, no new cost
effectiveness estimates are available to date.
Cost Effectiveness: The cost effectiveness per ton VOC reduced is $9,300 (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
CARB formed the Department of Pesticide Regulation (DPR) in 1991 to regulate all aspects of
pesticide sales and use. The DPR has implemented a faster registration process so that new
pesticide products can be more quickly integrated. The DPR also encourages better IPM practices
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AT-A-GLANCE TABLE FOR AREA SOURCES
by working with local agricultural agencies and rewarding those who demonstrate good practice or
innovation.
No new regulations have been developed for pesticides as the DPR believes that the reduction
goals will be met through reformulation (which is occurring without specific air regulations) and better
IPM practices (CDPR, 1999).
References:
CDPR, 1999: California Department of Pesticide Regulation website: www.cdpr.ca.gov.
Radian, 1994: Radian Corporation, "Technical Support Document: Proposed FIP Pesticides
Measure 52.2960," prepared for the U.S. Environmental Protection Agency, February 1994.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Portable Gasoline Containers
Control Measure Name: OTC Portable Gas Container Rule
Rule Name: OTC Portable Gas Container Rule
Pechan Measure Code: V24605	POD: 305
Application: The rule specifies performance standards for portable fuel containers and/or spouts
which are intended to reduce emissions from storage, transport and refueling
activities. The rule states that any portable fuel container and/or spout must provide
the following:
•~Only one opening for both filling and pouring;
•~An automatic shut-off to prevent overfill during refueling;
•~Automatic closing and sealing of the container and/or spout when not dispensing
fuel;
•~A fuel flow rate and fill level as specified in the rule;
•~A permeation rate of less than or equal to 0.4 grams per gallon per day; and
•~A warranty by the manufacturer as specified in the rule.
Affected SCC:
2501000120: Storage and Transport: Petroleum and Petroleum Product Storage: All Storage Types:
Breathing Loss: Gasoline
2501010120: Storage and Transport: Petroleum and Petroleum Product Storage:
Commercial/Industrial: Breathing Loss: Gasoline
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 33% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The annual gas can population turnover and the estimated sales process for each
container are used to calculate the incremental cost of the draft model rule on an
annual basis. The total VOC reductions for 2007 and the annual incremental cost
were used to calculate cost of compliance in dollars per ton.
Cost Effectiveness: The cost effectiveness used in AirControlNET is $581 per ton VOC reduced
(1999$).
Comments:
Status:
Last Reviewed: 2005
Additional Information:
References:
Pechan 2001: E.H. Pechan & Associates, Inc., "Control Measure Development Support-Analysis of
Ozone Transport Commission Model Rules," prepared for Ozone Transport Commission, March,
2001.
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Product and Packaging Rotogravure and Screen Printing
Control Measure Name: Permanent Total Enclosure (PTE)
Rule Name: Not Applicable
Pechan Measure Code: V40206	POD: 206
Application: A PTE is an enclosure used to surround a source of emissions so that all, or nearly all,
emissions are captured and contained, usually for discharge to a control device.
Product and packaging rotogravure includes folding cartons, flexible packaging, labels
and wrappers, gift wraps, wall coverings, vinyl printing, decorative laminates, floor
coverings, tissue products and miscellaneous specialty products such as cigarette
tipping paper. The EPA evaluated VOC emission control options for the publication
rotogravure printing industry including the use of a PTE in conjunction with a solvent
concentrator in the MACT standard-setting process for this source category. Rotary
screen printing is sometimes used in combination with product and packaging
rotogravure printing.
Affected SCC:
2425030000 Graphic Arts, Rotogravure, Total: All Solvent Types
40201330 Surface Coating Operations, Paper Coating, Coating Application: Rotogravure Printer
40500801 Printing/Publishing, General, Screen Printing
40500811 Printing/Publishing, General, Screen Printing
40500811 Printing/Publishing, General, Screen Printing
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 96.4% from uncontrolled
Equipment Life: 30 years (PTE); 15 years (thermal oxidizer)
Rule Effectiveness: 100% for point and area sources
Penetration: 100%
Cost Basis: The cost analysis is based on an average of PTE and oxidizer capital and operating
and maintenance costs developed for five model product and packaging rotogravure
printing plants evaluated by EPA for the Printing and Publishing MACT standard (40
CFR Part 63 Subpart KK). Consistent with the OAQPS Control Cost Manual, an
interest rate of 7% was used to determine the capital recovery factor. Each PTE was
assumed to capture 100% of all VOC emissions. All captured emissions were
assumed to be vented to a thermal oxidizer having an average 96.4% control
efficiency (average for all five model plants evaluated). Therefore, the net VOC
control efficiency is 96.4%. Year 1993 dollars were specified for cost calculations in
the EPA background document for the printing and publishing industry. In many
cases, catalytic incineration is appropriate for solvents used in product and packaging
rotogravure; in these cases, catalytic incineration systems would have lower operating
costs.
Cost Effectiveness: The cost effectiveness is $12,770 per ton VOC reduction (1993$). The cost
effectiveness is based on an annualized capital cost of $93,552 and an annual
operation and maintenance (O&M) cost of $999,932 averaged over five model
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AT-A-GLANCE TABLE FOR POINT SOURCES
packaging and product rotogravure printing plants.
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
References:
EPA, 1995: U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air
Pollutants: Printing and Publishing Industry Background Information for Proposed Standards",
February 1995.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual", Sixth Edition, document EPA/452/B-02-001, January 2002.
Document No. 05.09.009/9010.463
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AT-A-GLANCE TABLE FOR POINT SOURCES
Source Category: Publication Rotogravure Printing
Control Measure Name: Permanent Total Enclosure (PTE)
Rule Name: Not Applicable
Pechan Measure Code: V40207	POD: 207
Application: A PTE is an enclosure used to surround a source of emissions so that all, or nearly all,
emissions are captured and contained, usually for discharge to a control device.
Publication rotogravure primarily involves the printing of newspapers, magazines, and
advertisement inserts. The EPA evaluated VOC emission control options for the
rotogravure printing industry, including the use of a PTE in conjunction with a solvent
concentrator in the MACT standard-setting process for this source category.
Affected SCC:
2425030000 Graphic Arts, Rotogravure, Total: All Solvent Types
40201330 Surface Coating Operations, Paper Coating, Coating Application: Rotogravure Printer
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 95% from uncontrolled
Equipment Life: 30 years (PTE); 15 years (thermal oxidizer)
Rule Effectiveness: 100% for point and area sources
Penetration: 100%
Cost Basis: The cost analysis is based on an average of PTE and oxidizer capital and operating
and maintenance costs developed for five model publication rotogravure printing
plants evaluated by EPA for the Printing and Publishing MACT standard (40 CFR Part
63 Subpart KK). Consistent with the OAQPS Control Cost Manual, an interest rate of
7% was used to determine the capital recovery factor. Although the PTE is expected
to have a life of 30 years, PTE costs were annualized over a 15 year life (the
expected life of the solvent concentrator). Each PTE was assumed to capture 100%
of all VOC emissions. All captured emissions were assumed to be vented to a
solvent concentrator having a 95% control efficiency (average for all five
concentrators evaluated). Therefore, the net VOC control efficiency is 95%. Year
1993 dollars were specified for cost calculations in the EPA background document for
the printing and publishing industry.
Cost Effectiveness: The cost effectiveness is $2,422 per ton VOC reduction (1993$). The cost
effectiveness is based on an annualized capital cost of $520,781 and an annual
operation and maintenance (O&M) cost of $603,344 averaged over five model
publication rotogravure printing plants.
Comments:
Status: Demonstrated
Last Reviewed: 2004
Additional Information:
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AT-A-GLANCE TABLE FOR POINT SOURCES
References:
EPA, 1995: U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air
Pollutants: Printing and Publishing Industry Background Information for Proposed Standards",
February 1995.
EPA, 2002: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"EPA Air Pollution Control Cost Manual", Sixth Edition, document EPA/452/B-02-001, January 2002
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Rubber and Plastics Manufacturing
Control Measure Name: SCAQMD - Low VOC
Rule Name: South Coast Air Quality Management District Rule 1145 - Plastic, Rubber
and Glass Coatings
Pechan Measure Code: V24401	POD: 244
Application: SCAQMD Rule 1145 - Plastic, Rubber, and Glass Coatings was adopted to reduce
VOC emissions from plastic, rubber, and glass operations. Since its adoption, this
rule has been amended numerous times incorporating more stringent VOC limits as
the technology and low VOC coatings have become available. The last amendment in
March 1996 was to exempt aerosol coatings and to provide rule consistency with the
recently adopted ARB Aerosol Coating Products Rule.
There are a variety of control methods to reduce VOCs from plastic, rubber, and glass
coatings operations. VOC emissions can be reduced by using reformulated low-VOC
content compliant coatings, UV curable coatings, high transfer efficiency coating
applications and increased effectiveness of add-on control equipment.
Affected SCC:
2430000000 All Processes, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 60% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost estimates are based on studies done in the development and amendment of
the SCAQMD Rule 1145 (SCAQMD, 1996). The rule is estimated to reduce
emissions from rubber and plastics manufacturing by 60%, with an expected cost
effectiveness of $1,020 per ton VOC reduced (1990 dollars) (SCAQMD, 1996).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $1,020 per ton VOC reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
The majority of VOC emissions from this source category are generated from coating, cleaning, and
other manufacturing operations used in the production of plastic, rubber and glass substrates.
Glass products manufactured in the South Coast Basin are primarily mirrors (SCAQMD, 1996).
During the coating application process for mirrors, glass is passed under a flow coater or roll coater.
The coating or product is either forced-dried or air-dried. Molded or formed glass objects can be
either dipped or sprayed.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Rubber products are typically spray painted. Artistic designs are applied to the substrate through a
mask or by using transfer decals. Adding pigment to the rubber during its manufacturing can avoid
the need for painting.
Plastic products use the widest variety of coating application techniques. The majority of coatings
are sprayed, but dip coating, flow coating, and roller coating are also used. Coatings are typically air-
dried or forced-dried, because excess heat can cause them to melt and deform. Masks are used to
manufacture toys and multicolored products. Coatings may be eliminated by using colored plastic or
transfer decals. Letters, numbers, and designs may be transferred to an object by a process similar
to a letter press.
References:
SCAQMD, 1996: South Coast Air Quality Management District. "1997 Air Quality Management
Plan - Appendix IV-A. Stationary and Mobile Source Control Measures," August 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Stage II Service Stations
Control Measure Name: Low Pressure/Vacuum Relief Valve
Rule Name: Not Applicable
Pechan Measure Code: V30101	POD: 301
Application: This control measure is the addition of low pressure/vacuum (LP/V) relief valves to
gasoline storage tanks at service stations with Stage II control systems. LP/V relief
valves prevent breathing emissions from gasoline storage tank vent pipes.
This control measure applies to all gasoline service stations with Stage II control
systems, classified under SCC 2501060100.
Affected SCC:
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 92% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost for this rule were estimated by the SCAQMD. They estimated the cost
effectiveness based on the following assumptions:
6% of stations already have LP/V valves;
stations without LP/V valves need an average of 3 valves;
the valves can be installed with one hour of labor;
each valve costs $57; and
the installation is paid for over 10 years at 4% interest (SCAQMD, 1995).
Note: All costs are in 1994 dollars.
Cost Effectiveness: The annual cost per ton VOC reduced used in AirControlNET is $1,080.
(1991$)
EPA estimated the cost effectiveness to range from $930 to $1,230 per ton
VOC removed depending on whether or not small service stations were
exempted (EPA, 1995).
Comments:
Status: Demonstrated
Last Reviewed: 1999
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AT-A-GLANCE TABLE FOR AREA SOURCES
Additional Information:
Stage II vapor recovery systems utilize a dispensing nozzle and attached hose to collect and return
the displaced gasoline vapors from the vehicle fuel tank back to the storage tank. Stage II systems
work effectively with a variety of vehicle fill pipes, unlike Stage I systems. The Stage II system will
have either a tubular bellows, or "boot," or a face cone to recover VOC emissions from the fueling
process (SCAQMD, 1995).
References:
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stage II Comparability Study for the Northeast Ozone Transport Region," Research Triangle Park,
NC, January 1995.
SCAQMD, 1995: South Coast Air Quality Management District, "Staff Report for: Proposed
Amendments to Rule 461 - Gasoline Transfer and Dispensing," August 1995.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Stage II Service Stations - Underground Tanks
Control Measure Name: Low Pressure/Vacuum Relief Valve
Rule Name: Not Applicable
Pechan Measure Code: V30201	POD: 302
Application: This control measure is the addition of low pressure/vacuum (LP/V) relief valves to
underground gasoline storage tanks at service stations with Stage II control systems.
LP/V relief valves prevent breathing emissions from gasoline storage tank vent pipes.
This control measure applies to all gasoline service stations with underground gasoline
storage tanks, classified under SCC 2501060201.
Affected SCC:
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 73% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost for this rule were estimated by the SCAQMD. They estimated the cost
effectiveness based on the following assumptions:
6% of stations already have LP/V valves;
stations without LP/V valves need an average of 3 valves;
the valves can be installed with one hour of labor;
each valve costs $57; and
the installation is paid for over 10 years at 4% interest (SCAQMD, 1995).
Note: All costs are in 1994 dollars.
Cost Effectiveness: The annual cost per ton VOC reduced used in AirControlNET is $1,080.
(1991$)
EPA estimated the cost effectiveness to range from $930 to $1,230 per ton
VOC removed depending on whether or not small service stations were
exempted (EPA, 1995).
Comments:
Status: Demonstrated
Last Reviewed: 1999
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AT-A-GLANCE TABLE FOR AREA SOURCES
Additional Information:
Stage II vapor recovery systems utilize a dispensing nozzle and attached hose to collect and return
the displaced gasoline vapors from the vehicle fuel tank back to the storage tank. Stage II systems
work effectively with a variety of vehicle fill pipes, unlike Stage I systems. The Stage II system will
have either a tubular bellows, or "boot," or a face cone to recover VOC emissions from the fueling
process (SCAQMD, 1995).
References:
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Stage II Comparability Study for the Northeast Ozone Transport Region," Research Triangle Park,
NC, January 1995.
SCAQMD, 1995: South Coast Air Quality Management District, "Staff Report for: Proposed
Amendments to Rule 461 - Gasoline Transfer and Dispensing," August 1995.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Traffic Markings
Control Measure Name: AIM Coating Federal Rule
Rule Name: Architectural and Industrial Maintenance Coatings Federal Rule
Pechan Measure Code: V22101	POD: 221
Application: This federal rule provides uniformity over the state-level content limits that AIM coating
manufacturers must meet. The rule sets maximum allowable VOC content limits for 55
different categories of AIM coatings, and affects the manufacturers and importers of
the coating products. VOC content limits defined in the national rule took effect on
September 11, 1999. Manufacturers of FIFRA - regulated coatings had until March 10,
2000 to comply.
Sixty-four percent of the products included in the 1990 industry survey meet the VOC
content limits in this rule and, therefore, there will be no costs to reformulate these
products. The manufacturer of a product that does not meet the VOC content limits
will be required to reformulate the product if it will continue to be marketed, unless the
manufacturer chooses to use an alternative compliance option such as the
exceedance fee or tonnage exemption provision.
In AirControlNET, this specific control measure applies only to traffic markings.
Affected SCC:
2401008000 Traffic Markings, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 20% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost estimates are based upon information provided to EPA by industry
representatives during the regulatory negotiation process. Industry representatives
estimated the level of effort required by a representative firm to research and develop
a new prototype coating to be 2.5 scientist-years over a 3-year time period. EPA
calculated an annualized cost of $17,772 per reformulation (1991 dollars) based on
an assumed cost of $100,000 per scientist-year as amortized over an assumed
repopulation cycle of 2.5 years.
The estimated average cost to reformulate a product was $87,000. The total
estimated national cost of the AIM Coating Federal rule is 25.6 million per year (1991
dollars).
Cost Effectiveness: EPA estimated emission reductions of 106,000 tons of VOC per year so that
the cost effectiveness is computed as $228 per ton VOC reduction (1990$)..
Comments: The EPA did not account for potential cost differences for reformulating coatings to
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AT-A-GLANCE TABLE FOR AREA SOURCES
various content limits. Instead, EPA assumed that a reformulation has a certain cost to
manufacturers regardless of the target content limit, or the anticipated VOC reduction
(Ducey, 1997).
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
In its analysis of the proposed federal rule, EPA assumed that the cost of product reformulation
would bring the VOC content limit for each noncompliant coating down to the level of the standards.
The EPA, however, noted the likelihood that some manufacturers will likely reduce the VOC content
of their coatings to levels significantly below the limits in the rule (EPA, 1996). The at-the-limit
assumption, therefore, likely results in emission reductions being understated. In its cost analysis,
insufficient data were available for EPA to distinguish reformulation costs between different coating
types (i.e., the reformulation cost for flat paints is equal to the reformulation cost for all other affected
paint types). The EPA noted the likelihood of reformulation costs varying from product to product
(EPA, 1995).
References:
Ducey, 1997: E. Ducey, U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, personal communication with D. Crocker, E.H. Pechan & Associates, Inc., February 13,
1997.
EPA, 1995: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards,
"Economic Impact and Regulatory Flexibility Analysis of the Proposed Architectural Coatings Federal
Rule," Research Triangle Park, NC, March 1995.
EPA, 1996: U.S. Environmental Protection Agency, Emission Standards Division, Office of Air and
Radiation, "Architectural Coatings - Background for Proposed Standards, Draft Report," March 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Traffic Markings
Control Measure Name: South Coast Phase I
Rule Name: South Coast AQMD Rule 1113 - Architectural Coatings
Pechan Measure Code: V22102	POD: 221
Application: The Phase I rule is an amendment to SCAQMD's existing architectural coatings rule
that establishes more stringent VOC content limits for flat, multi-color, traffic, and
lacquer coatings. These VOC limits in the SCAQMD for multi-color, traffic, and lacquer
coatings took effect on January 1, 1998, while the Phase I limits for flat coating took
effect on January 1, 2001.
Reductions in VOC emissions from these coatings are achieved through the use of
product reformulation and product substitution.
Affected SCC:
2401008000 Traffic Markings, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 34% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: For the Phase I amendment, a SCAQMD report documents cost per gallon, total
annual cost, emission reduction and cost-effectiveness values for each of the four
regulated coating types (SCAQMD, 1996).
The SCAQMD estimated that manufacturers would use an acetone formulation with
an associated cost of $2 per gallon to meet the proposed 550 grams per liter (g/L)
VOC limit for lacquers. For flats, South Coast estimated a zero cost for complying
with the near-term 100 g/L limit since most flats sold in California are already in
compliance with this limit. For traffic and multi-color coatings, the SCAQMD
estimated that a cost savings was likely to be associated with reformulation due to a
decrease in the cost of input materials. (The estimated magnitude of the savings is
not documented in the SCAQMD report.)
Costs were estimated by multiplying the cost per gallon data to total gallons sold.
The resulting weighted average cost effectiveness value was converted to 1990
dollars using the 1995:1990 producer price index for Standard Industrial Classification
(SIC) code 2851 (Paints and Allied Products).
Because capital cost information was not available, capital costs were not estimated
for this analysis.
Cost Effectiveness: CARB indicated that costs ranged from a savings of $8,600 per ton (for pool
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AT-A-GLANCE TABLE FOR AREA SOURCES
finishes) to cost of $12,800 per ton of VOC reduced (for specialty enamels)
(CARB, 1989). The cost effectiveness range is attributable to the wide diversity
of coatings.
AirControlNET uses a cost effectiveness of $1,443 per ton VOC reduction
based on a weighted average of national sales data by coating type (EPA,
1996) (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
References:
CARB, 1989: California Air Resources Board, Stationary Source Division, "ARB-CAPCOA
Suggested Control Measure for Architectural Coatings, Technical Support Document," July 1989.
EPA, 1996: U.S. Environmental Protection Agency, Emission Standards Division, Office of Air and
Radiation, "Architectural Coatings - Background for Proposed Standards, Draft Report," EPA-453/R-
95-009a, March 1996.
SCAQMD, 1996: South Coast Air Quality Management District, "Proposed Modifications to the
Appendices of the Draft 1997 Air Quality Management Plan," October 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Traffic Markings
Control Measure Name: South Coast Phase II
Rule Name: South Coast AQMD Rule 1113 - Architectural Coatings
Pechan Measure Code: V22103	POD: 221
Application: Phase II represents an effort to lower the VOC content limits for non-flat industrial
maintenance primers and topcoats, sealers, undercoaters, and quick-dry enamels.
The rule requires manufacturers of the coatings sold in the SCAQMD to meet the VOC
limit requirements provided in the rule between 2002 and 2006.
Reductions in VOC emissions from these coatings are achieved through the use of
product reformulation and product substitution.
Affected SCC:
2401008000 Traffic Markings, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 47% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: For the Phase II amendments, the SCAQMD completed a socioeconomic impact
assessment (SCAQMD, 1999). SCAQMD assumed a 10 percent price increase per
gallon for compliant coatings meeting Phase II and estimated the cost based on the
number of gallons produced. Costs vary significantly among individual coatings
categories.
Because capital cost information was not available, capital costs were not estimated
for this analysis.
Cost Effectiveness: AirControlNET uses a cost effectiveness of $4,017 per ton VOC reduction
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
The South Coast notes that the process of collecting reformulation cost data for these categories is
very complex due to the resin technology used in lower-VOC, high-performance industrial
maintenance coatings (silicon-based resins, or polyurethanes) and the number of resin systems
involved (Berry, 1997).
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Berry, 1997: N. Berry, South Coast Air Quality Management District, personal communication with
D. Crocker, E.H. Pechan & Associates, Inc., March 4, 1997.
SCAQMD, 1999: South Coast Air Quality Management District, "Addendum to Staff Report: Final
Socioeconomic Impact Assessment, Proposed Amendments to Rule 1113," May 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Traffic Markings
Control Measure Name: South Coast Phase III
Rule Name: South Coast AQMD Rule 1113 - Architectural Coatings
Pechan Measure Code: V22104	POD: 221
Application: Phase III applies to additional consumer products that are not affected by Phase I or
II. The rule requires manufacturers to limit VOC content of the specified coatings sold
in the SCAQMD using a phased-in approach specifying compliance dates that depend
on the coating type. Compliance dates range from 1/1/03 to 7/1/08.
Reductions in VOC emissions from these coatings are achieved through the use of
product reformulation and product substitution.
In AirControlNET this measure only applies to traffic markings.
Affected SCC:
2401008000 Traffic Markings, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 73% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: SCAQMD has not yet estimated the costs for implementing the Phase III limits at the
time this control was developed. As an estimate, Pechan uses the highest
incremental cost effectiveness estimate for any individual product for the Phase II
amendments of $26,000 per ton (1998 dollars). This value is about double the
average of Phase II products. This cost estimate is highly uncertain as no specific
cost data are available (Pechan, 1999).
Because capital cost information was not available, capital costs were not estimated
for this analysis.
Cost Effectiveness: AirControlNET uses an overall cost effectiveness of $10,059 per ton VOC
reduction (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1996
Additional Information:
The Phase III controls apply to additional consumer products that are not affected by the near-term
measures. These measures, which are expected to take effect between 2000 and 2005, are
expected to result in an additional 25 percent VOC reduction from consumer products.
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET)," prepared for the U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle
Park, NC, 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Wood Furniture Surface Coating
Control Measure Name: MACT Standard
Rule Name: Maximum Achievable Control Technology for Wood Furniture Surface
Coating
Pechan Measure Code: V22501	POD: 225
Application: The MACT establishes emission limits for finishing materials, adhesives, and strippable
spray booth coatings. It also specifies work practices that minimize evaporative
emissions from the storage, transfer, and application of coatings and solvents. The
MACT standard for wood furniture surface coatings allows facilities to use one of the
following methods to demonstrate compliance: compliant coatings; averaging; an add-
on control device; a combination of compliant coatings and an add-on control device;
or a combination of an add-on control device and averaging.
The rule affects the production of the following products and their components: wood
kitchen cabinets; wood residential furniture, upholstered residential and office furniture;
wood television, ratio, phonograph, and sewing machine cabinets; wood office furniture
and fixtures; partitions, shelving and lockers; and other wood furniture.
Affected SCC:
2401020000 Wood Furniture: SIC 25, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 30% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: EPA estimates the costs using a model plant approach. The total cost estimate
includes the costs of incineration, spray guns, and carbon adsorption as control
options. For gluing operations, capital costs include the cost for drying ovens and
delivery systems. (Pechan, 1998)
For application to the area sources, the cost-effectiveness is an average of the costs
associated with the two smallest model plant size categories:
Small = $150 per ton VOC reduced
Medium = $704 per ton VOC reduced
Cost Effectiveness: The cost effectiveness is $446 per ton VOC reduction (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
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AT-A-GLANCE TABLE FOR AREA SOURCES
References:
Pechan, 1998: E. H. Pechan & Associates, "Emission Projections for the Clean Air Act Section 812
Prospective Analysis," June 1998..
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Wood Furniture Surface Coating
Control Measure Name: New CTG
Rule Name: Not Applicable
Pechan Measure Code: V22502	POD: 225
Application: The new CTG, published in 1996, applies to ozone nonattainment areas and the
Ozone Transport Region (OTR). This will affect facilities emitting 25 tons per year or
more.
The Wood furniture coating industry covers 10 SIC codes including: Wood Kitchen
Cabinets; Wood Household Furniture (except upholstered); Wood Household Furniture
(upholstered); Wood Television, Radios, Phonograph, and Sewing Machine Cabinets;
Household Furniture Not Classified Elsewhere; Wood Office Furniture; Public Building
and Related Furniture; Wood Office and Store Fixtures; Furniture and Fixtures Not
Elsewhere Classified; and Custom Kitchen Cabinets. Area source emissions would
typically account for the smaller facilities that are not covered in the point source
inventory.
Affected SCC:
2401020000 Wood Furniture: SIC 25, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 47% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: EPA (1996) estimated the cost effectiveness using a model plant technique for 16
plants. The cost estimates include low-VOC coating costs, application equipment
costs, and operator training costs (EPA, 1996).
Cost Effectiveness: The cost effectiveness used in AirControlNET is $967 per ton VOC reduction
(1990$).
The CTG examined several controls and an overall range from a savings of
$462 to a cost of $22,100 per ton VOC reduced was estimated.
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
References:
EPA, 1996: U.S. Environmental Protection Agency, "Control of Volatile Organic Compound
Emissions from Wood Furniture Manufacturing Operations," April 1996.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Wood Furniture Surface Coating
Control Measure Name: Add-On Controls
Rule Name: Not Applicable
Pechan Measure Code: V22503	POD: 225
Application: This control measure is generic in that it represents potential add-on controls available
for this source category. Add-on controls include hybrid waterborne systems, full
waterborne systems, other alternative coatings, thermal incinerators, catalytic
incinerators, and a combination of carbon absorbers and catalytic incinerators.
This control applies to all wood furniture coating applications.
Affected SCC:
2401020000 Wood Furniture: SIC 25, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 75% from uncontrolled
Equipment Life: 10 years
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost is based on estimates for small industrial sources to install add-on control
options. The highest costs for add-on controls are associated with specialized and
small plants (Pechan, 1999).
The industry sponsored study whose information was included in the guideline
document used a 10 percent discount rate in the computation of a capital recovery
factor (EPA, 1996).
Cost Effectiveness: Depending on the control, a cost effectiveness range of $468 per ton to more
than $22,100 per ton VOC reduced is estimated. Emissions reductions range
from 67 to 98 percent (Pechan, 1999).
The cost effectiveness used in AirControlNET is $20,000 per ton VOC reduced
(1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
Where facilities can achieve comparable reductions through the use of hybrid waterborne systems,
full waterborne systems or other alternative coatings, reductions may be higher and costs may be
lower than those estimated based on this add-on control measure. For some of the smallest
facilities, add-on controls may not be feasible (Pechan, 1999).
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AT-A-GLANCE TABLE FOR AREA SOURCES
There are control options that were evaluated, but not selected, in EPA's estimates op preemptive
RACT requirements for this source category.
References:
EPA, 1996: U.S. Environmental Protection Agency, Emission Standards Division, "Control of
Volatile Organic Compound Emissions from Wood Furniture Coating Operations," Guideline Series,
Research Triangle Park, NC, April, 1996.
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control Measure
Data Base For the National Emission Trends Inventory (AirControlNET)," prepared for the U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle
Park, 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Wood Product Surface Coating
Control Measure Name: MACT Standard
Rule Name: Maximum Achievable Control Technology for Wood Product Surface
Coating
Pechan Measure Code: V22401	POD: 224
Application: The Wood Product Surface Coating MACT sets emissions limits from wood product
surface coating facilities. The proposed rule allows for several compliance options
including the use of coatings that have been reformulated to reduce air toxics content,
upgrading or installation of new capture-and-control systems to reduce air toxics
emissions, or a combination of the two. The final rule was proposed February 2003.
The MACT applies to new, reconstructed, or existing wood building product facilities
that use more than 4,170 liters (1,100 gallons) of coatings per year and that are
"major" sources of air toxics emissions (EPA, 2002).
Affected SCC:
2401015000 Factory Finished Wood: SIC 2426 thru 242, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 30% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: At the time the control measure was developed the MACT had not yet been
proposed. Pechan assumed a cost effectiveness of $446 per ton corresponding to a
control efficiency of 30% (Pechan, 1997)
Cost Effectiveness: The cost effectiveness is $446 per ton VOC reduction (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1997
Additional Information:
References:
EPA, 2002: U.S. Environmental Protection Agency, "Fact Sheet - Proposed Rule to Reduce Toxic
Air Pollutants From Surface Coating of Wood Building Products," May 2002. Retrieved April 29,
2003 from http://www.epa.gov/ttn/atw/wbldg/wbldgpg.html.
E.H. Pechan & Associates, Inc., "Integrated Ozone, Particulate Matter, and Regional Haze Cost
Analysis - Methodology and Results," prepared for U.S. Environmental Protection Agency,
Innovative Strategies and Economics Group, Office of Air Quality Planning and Standards, June 6,
1997.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Wood Product Surface Coating
Control Measure Name: SCAQMD Rule 1104
Rule Name: South Coast Air Quality Management District Rule 1104 - Wood Flat Stock
Coatings Operations
Pechan Measure Code: V22402	POD: 224
Application: The SCAQMD rule 1104 sets VOC content limits for wood product surface coatings.
This rule establishes specifications for application and solvent cleaning requirements
(SCAQMD, 1999). The amendments to this rule also sets stringent VOC limits for inks
and exterior siding coatings.
This rule applies to factory finished wood coatings.
Affected SCC:
2401015000 Factory Finished Wood: SIC 2426 thru 242, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 53% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: SCAQMD estimated costs for this control when developing amendments to rule
1104. Factors affecting cost include product reformulations (SCAQMD, 1996).
The amendments are expected to reduce emissions by 17 percent over current
baseline levels at a cost-effectiveness of $1,802 per ton of VOC reduced (1999
dollars) (SCAQMD, 1999). This results in an overall reduction of 53 percent at an
incremental cost of $1,429 per ton (1990 dollars) for an overall cost per ton VOC
reduced of $881.
Cost Effectiveness: The cost effectiveness is $881 per ton VOC reduction (1990$).
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
References:
SCAQMD, 1996: South Coast Air Quality Management District, "Proposed Modifications to the
Appendices of the Draft 1997 Air Quality Management Plan," October 1996.
SCAQMD, 1999: South Coast Air Quality Management District, "Staff Report: Proposed Amended
Rule 1104 - Wood Flat Stock Coating Operations," August 1999.
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AT-A-GLANCE TABLE FOR AREA SOURCES
Source Category: Wood Product Surface Coating
Control Measure Name: Incineration
Rule Name: Not Applicable
Pechan Measure Code: V22403
POD: 224
Application: This is a generic control measure based on the use of incineration to reduce VOC
emissions from wood coating facilities.
This control measure applies to sources classified as factory finished wood producers,
SCC 2401015000.
Affected SCC:
2401015000 Factory Finished Wood: SIC 2426 thru 242, Total: All Solvent Types
Pollutant(s)
PM10
PM2.5
EC
OC
NOx
VOC
S02
NH3
CO
Hg





V*




V = pollutant reduction; X = pollutant increase, * = major pollutant
Control Efficiency: 86% from uncontrolled
Equipment Life: Not Applicable
Rule Effectiveness: 100%
Penetration: 100%
Cost Basis: The cost analysis is based on SCAQMD alternative control techniques data. For the
one facility examined (which has coatings above the proposed limits), cost
effectiveness is estimated at $4,202 per ton reduced (1999 dollars) for a reductions of
86 percent.
Cost Effectiveness: A cost effectiveness of $4,202 per ton VOC reduced is used in AirControlNET.
(1999$)
Comments:
Status: Demonstrated
Last Reviewed: 1999
Additional Information:
References:
No reference found in Pechan's documentation.
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PECHAN
September 2005
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PECHAN
September 2005
CHAPTER IV. REFERENCES
Pechan, 1995: E.H. Pechan & Associates, Inc., "Regional Particulate Strategies," Draft Report,
prepared for U.S. Environmental Protection Agency, Office of Policy Planning and
Evaluation, Washington, DC, Pechan Report No. 95.09.005/1754, September 29, 1995.
Pechan, 1997: E.H. Pechan & Associates, Inc., "Additional Control Measure Evaluation for the
Integrated Implementation of the Ozone and Particulate Matter National Ambient Air
Quality Standards, and Regional Haze Program," prepared for U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards, Research Triangle
Park, NC, Pechan Report No. 97.03.001/1800 (Rev.), July 17, 1997.
Pechan, 1999: E.H. Pechan & Associates, Inc., "Control Measure Evaluations: The Control
Measure Data Base for the National Emission Trends Inventory (AirControlNET)," Draft
Report, prepared for U.S. Environmental Protection Agency, Office of Air Quality
Planning and Standards, Research Triangle Park, NC, Pechan Report No.
99.09.001/9004.112, September 1999.
Pechan, 2001a: E.H. Pechan & Associates, Inc., "Revisions to AirControlNET, and Particulate
Matter Control Strategies and Cost Analyses," Revised Report, prepared for U.S.
Environmental Protection Agency, Innovative Strategies and Economics Group, Research
Triangle Park, NC, September 28, 2001.
Pechan, 2001b: E.H. Pechan & Associates, Inc., "Control Measure Development Support
Analysis of Ozone Transport Commission Model Rules," Draft Report, prepared for the
Ozone Transport Commission, Washington, DC, Pechan Report No. 01.02.001/9408.000,
February 5, 2001.
Pechan, 2002: E.H. Pechan & Associates, Inc., "VOC and NOx Control Measures Adopted by
States and Nonattainment Areas for 1999 NEI Base Case Emissions Projection
Calculations," Draft Report, prepared for U.S. Environmental Protection Agency,
Research Triangle Park, NC, Pechan Report No. 02.09.002/9010.122, September 2002.
Pechan, 2005a: E.H. Pechan & Associates, Inc., "AirControlNET User's Guide, Version 4,"
Draft Report, prepared for U.S. Environmental Protection Agency, Research Triangle
Park, NC, Pechan Report No. 03.05/9010.463,August 2005.
Pechan, 2005b: E.H. Pechan & Associates, Inc., "AirControlNET Tool Development Report,
Version 4, prepared for U.S. Environmental Protection Agency, Research Triangle Park,
NC, Pechan Report No. 03.05/9010.463, August 2005.
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PECHAN	September 2005
APPENDIX A: CONTROL MEASURE SUMMARY LIST - BY
SOURCE
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September 2005
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Appendix A Control Measure Summary List by Source Category - Sorted alphabetically by Source Category and SCC
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Adhesives - Industrial
SCAQMD Rule 1168





-V*





73%


2,202

Agricultural Burning
Bale Stack/Propane Burning
V
V*
¦V
•V






49%
63%
63%

2,591

Agricultural Burning
Seasonal Ban (Ozone Season Daily)




¦V*






100%


N/A

Agricultural Tilling
Soil Conservation Plans
V
V
¦V
¦V







11.7%


138

Aircraft Surface Coating
MACT Standard





¦V*





60%


165

Ammonia - Natural Gas - Fired
Reformers - Small Sources
Low NOx Burner




-V*






50%


820

Ammonia - Natural Gas - Fired
Reformers - Small Sources
Low NOx Burner (LNB) + Flue Gas
Recirculation (FGR)




¦V*






60%

2,470
2,560
2,560
Ammonia - Natural Gas - Fired
Reformers - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

2,900
3,870
3,870
Ammonia - Natural Gas - Fired
Reformers - Small Sources
Selective Catalytic Reduction (SCR)




-V*


X



80%

2,230
2,230
2,860
Ammonia - Natural Gas - Fired
Reformers - Small Sources
Oxygen Trim + Water Injection




¦V*






65%


680

Ammonia Products; Feedstock
Desulfurization - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
A-1

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
Drimary po
Typical
il Cost
ss
I utant)
High
Architectural Coatings
OTC AIM Coating Rule





-V*





55%


6,628

Architectural Coatings
AIM Coating Federal Rule





¦V*





20%


228

Architectural Coatings
South Coast Phase III





¦V*





73%


10,059

Architectural Coatings
South Coast Phase II





-V*





47%


4,017

Architectural Coatings
South Coast Phase 1





¦V*





34%

3,300
1,443
4,600
AREA
OTC Mobile Equipment Repair and
Refinishing Rule





¦V*





61%


2,534

AREA
OTC Consumer Products Rule





¦V*





39.2%


1,032

AREA
OTC Mobile Equipment Repair and
Refinishing Rule





¦V*





61%


2,534

AREA
OTC Mobile Equipment Repair and
Refinishing Rule





¦V*





61%


2,534

AREA
OTC Consumer Products Rule





¦V*





39.2%


1,032

AREA
OTC Mobile Equipment Repair and
Refinishing Rule





¦V*





61%


2,534

A-2

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Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
VOC
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
AREA
OTC Solvent Cleaning Rule





-V*





66%


1,400

Asphalt Manufacture
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Asphalt Manufacture
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Asphalt Manufacture
Paper/Nonwoven Filters - Cartridge
Collector Type
¦V
¦V*
¦V
V







99%

85
147
256
Asphalt Manufacture
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V
•V







99%

42
117
266
Asphalt Manufacture
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
¦V







99%

37
126
303
Asphalt Manufacture
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
¦V







99%

53
148
337
Asphaltic Cone; Rotary Dryer;
Conv Plant - Small Sources
Low NOx Burner




V*






50%


2,200

Automobile Refinishing
Federal Rule





¦V*





37%


118

Automobile Refinishing
CARB BARCT Limits





V*





47%


750

Automobile Refinishing
California FIP Rule (VOC content &
TE)





¦V*





89%


7,200

A-3

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
ed
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Bakery Products
Incineration >100,000 lbs bread





V*





39.9%


1,470

Beef Cattle Feedlots
Watering
V
V*
V
V







50%


307

Bituminous/Subbituminous Coal
Flue Gas Desulfurization






¦V*




90%


N/A

Bituminous/Subbituminous Coal
Flue Gas Desulfurization






¦V*




90%


N/A

Bituminous/Subbituminous
Coal (Industrial Boilers)
In-duct Dry Sorbent Injection






¦V*




40%

1,111
1,526
2,107
Bituminous/Subbituminous
Coal (Industrial Boilers)
Wet Flue Gas Desulfurization






¦V*




90%

1,027
1,536
1,980
Bituminous/Subbituminous
Coal (Industrial Boilers)
Spray Dryer Abosrber






-V*




90%

804
1,341
1,973
By-Product Coke Manufacturing
Vacuum Carbonate Plus Sulfur
Recovery Plant






¦V*




82%


N/A

By-Product Coke
Manufacturing; Oven
Underfiring
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


1,640

Cattle Feedlots
Chemical Additives to Waste







-V*



50%


228

Cement Kilns
Biosolid Injection




¦V*






23%


310

A-4

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Cement Manufacturing - Dry
Selective Catalytic Reduction (SCR)




-V*


X



80%


3,370

Cement Manufacturing - Dry
Selective Non-Catalytic Reduction
(SNCR) Ammonia Based




¦V*


X



50%


850

Cement Manufacturing - Dry
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



50%


770

Cement Manufacturing - Dry
Mid-Kiln Firing




-V*






25%

-460
55
730
Cement Manufacturing - Dry
Low NOx Burner




¦V*






25%

300
440
620
Cement Manufacturing - Wet
Low NOx Burner




¦V*






25%

300
440
620
Cement Manufacturing - Wet
Mid-Kiln Firing




¦V*






25%

-460
55
730
Cement Manufacturing - Wet -
Large Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%


2,880

Cement Manufacturing - Wet -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%


2,880

Ceramic Clay Manufacturing;
Drying - Small Sources
Low NOx Burner




¦V*






50%


2,200

Chemical Manufacture
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

A-5

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Chemical Manufacture
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Chemical Manufacture
Wet ESP - Wire Plate Type
V
V*
V
V







99%

55
220
550
Coal Cleaning-Thrml Dryer;
Fluidized Bed - Small Sources
Low NOx Burner




¦V*






50%


1,460

Coal-fired Plants with
Production Capacities>100MW
Combustion Optimization




-V*






20%


-25

Combustion Turbines - Jet
Fuel - Small Sources
Water Injection




¦V*






68%


1,290

Combustion Turbines - Jet
Fuel - Small Sources
Selective Catalytic Reduction (SCR)
+ Water Injection




¦V*






90%


2,300

Combustion Turbines - Natural
Gas - Large Sources
Dry Low NOx Combustors




¦V*






50%

100
100
140
Combustion Turbines - Natural
Gas - Small Sources
Selective Catalytic Reduction (SCR)
+ Water Injection




¦V*






95%


2,730

Combustion Turbines - Natural
Gas - Small Sources
Water Injection




¦V*






76%


1,510

Combustion Turbines - Natural
Gas - Small Sources
Steam Injection




¦V*






80%


1,040

Combustion Turbines - Natural
Gas - Small Sources
Dry Low NOx Combustors




¦V*






84%

490
490
540
A-6

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Combustion Turbines - Natural
Gas - Small Sources
Selective Catalytic Reduction (SCR)
+ Low NOx Burner (LNB)




-V*


X



94%

2,570
2,570
19,120
Combustion Turbines - Natural
Gas - Small Sources
Selective Catalytic Reduction (SCR)
+ Steam Injection




¦V*


X



95%

2,010
2,010
8,960
Combustion Turbines - Oil -
Small Sources
Selective Catalytic Reduction (SCR)
+ Water Injection




¦V*






90%


2,300

Combustion Turbines - Oil -
Small Sources
Water Injection




-V*






68%


1,290

Commercial Adhesives
CARB Long-Term Limits





¦V*





85%


2,880

Commercial Adhesives
CARB Mid-Term Limits





¦V*





55%


2,192

Commercial Adhesives
Federal Consumer Solvents Rule





¦V*





25%


232

Commercial Institutional
Boilers - Coal
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Commercial Institutional
Boilers - Coal
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Commercial Institutional
Boilers - Coal
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
¦V







99%

53
148
337
Commercial Institutional
Boilers - Coal
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
•V







98%

40
110
250
A-7

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Commercial Institutional
Boilers - Coal
Fabric Filter (Pulse Jet Type)
V
V*
¦V
V







99%

42
117
266
Commercial Institutional
Boilers - Liquid Waste
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Commercial Institutional
Boilers - Liquid Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Commercial Institutional
Boilers - LPG
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Commercial Institutional
Boilers - LPG
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Commercial Institutional
Boilers - Natural Gas
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Commercial Institutional
Boilers - Natural Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Commercial Institutional
Boilers - Oil
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Commercial Institutional
Boilers - Oil
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Commercial Institutional
Boilers - Oil
Dry ESP-Wire Plate Type
V
V*
¦V
¦V







98%

40
110
250
Commercial Institutional
Boilers - Process Gas
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

A-8

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Commercial Institutional
Boilers - Process Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Commercial Institutional
Boilers - Solid Waste
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Commercial Institutional
Boilers - Solid Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Commercial Institutional
Boilers - Wood
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Commercial Institutional
Boilers - Wood
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Commercial Institutional
Boilers - Wood/Bark
Dry ESP-Wire Plate Type
-V
¦V*
-V
¦V







98%

40
110
250
Commercial Institutional
Boilers - Wood/Bark
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
¦V







99%

53
148
337
Commercial Institutional
Boilers - Wood/Bark
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V
¦V







99%

42
117
266
Commercial/Institutional -
Natural Gas
Water Heater Replacement




¦V*






7%


N/A

Commercial/Institutional -
Natural Gas
Water Heaters + LNB Space Heaters




¦V*






7%


1,230

Commercial/Institutional
Incinerators
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



45%


1,130

A-9

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Construction Activities
Dust Control Plan
V
V*
V
V







62.5%


3,600

Consumer Solvents
Federal Consumer Solvents Rule





¦V*





25%


232

Consumer Solvents
CARB Mid-Term Limits





¦V*





55%


2,192

Consumer Solvents
CARB Long-Term Limits





-V*





85%


2,880

Conv Coating of Prod; Acid
Cleaning Bath - Small Sources
Low NOx Burner




¦V*






50%


2,200

Conveyorized Charbroilers
Catalytic Oxidizer
V*
V*



¦V




80%
83%
90%

2,966

Cutback Asphalt
Switch to Emulsified Asphalts





¦V*





100%


15

Diesel Locomotives
Selective Catalytic Reduction (SCR)




¦V*






72%


1,400

Distillate Oil (Industrial Boiler)
Wet Flue Gas Desulfurization






V*




90%

2,295
3,489
4,524
Electric Generation - Coke
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Coke
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

A-10

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Electric Generation - Bagasse
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Bagasse
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Coal
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Coal
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Liquid
Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Liquid
Waste
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - LPG
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - LPG
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Natural
Gas
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Natural
Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Oil
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

A-11

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Electric Generation - Oil
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Solid
Waste
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Solid
Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Wood
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Wood
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electrical/Electronic Coating
MACT Standard





¦V*





36%


5,000

Electrical/Electronic Coating
SCAQMD Rule





¦V*





70%


5,976

Fabric Printing, Coating and
Dyeing
Permanent Total Enclosure (PTE)





¦V*








N/A

Fabricated Metal Products -
Abrasive Blasting
Paper/Nonwoven Filters - Cartridge
Collector Type
V
V*
-V
¦V







99%

85
142
256
Fabricated Metal Products -
Welding
Paper/Nonwoven Filters - Cartridge
Collector Type
V
V*
¦V
¦V







99%

85
142
256
Ferrous Metals Processing -
Coke
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

A-12

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Ferrous Metals Processing -
Coke
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Ferrous Metals Processing -
Coke
Fabric Filter (Mech. Shaker Type)
¦V
-V*
¦V
¦V







99%

37
126
303
Ferrous Metals Processing -
Coke
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
¦V







99%

53
148
337
Ferrous Metals Processing -
Coke
Venturi Scrubber
¦V
¦V*
¦V
V







93%

75
751
2,100
Ferrous Metals Processing -
Ferroalloy Production
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Ferrous Metals Processing -
Ferroalloy Production
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Ferrous Metals Processing -
Ferroalloy Production
Fabric Filter (Mech. Shaker Type)
¦V
-V*
¦V
V







99%

37
126
303
Ferrous Metals Processing -
Ferroalloy Production
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
Ferrous Metals Processing -
Ferroalloy Production
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
V







99%

53
148
337
Ferrous Metals Processing -
Gray Iron Foundries
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Ferrous Metals Processing -
Gray Iron Foundries
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

A-13

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Ferrous Metals Processing -
Gray Iron Foundries
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Ferrous Metals Processing -
Gray Iron Foundries
Dry ESP-Wire Plate Type
¦V
-V*
¦V
V







98%

40
110
250
Ferrous Metals Processing -
Gray Iron Foundries
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
V







99%

53
148
337
Ferrous Metals Processing -
Gray Iron Foundries
Impingement-Plate Scrubber
¦V
¦V*
¦V
V







64%

46
431
1,200
Ferrous Metals Processing -
Gray Iron Foundries
Venturi Scrubber
¦V
¦V*
¦V
V







94%

76
751
2,100
Ferrous Metals Processing -
Iron & Steel Production
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Ferrous Metals Processing -
Iron & Steel Production
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Ferrous Metals Processing -
Iron and Steel Production
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
V







99%

53
148
337
Ferrous Metals Processing -
Iron and Steel Production
Wet ESP - Wire Plate Type
-V
¦V*
-V
V







99%

55
220
550
Ferrous Metals Processing -
Iron and Steel Production
Fabric Filter (Pulse Jet Type)
¦V
-V*
¦V
V







99%

42
117
266
Ferrous Metals Processing -
Iron and Steel Production
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
A-14

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Ferrous Metals Processing -
Iron and Steel Production
Venturi Scrubber
¦V
¦V*
¦V
V







73%

76
751
2,100
Ferrous Metals Processing -
Iron and Steel Production
Fabric Filter (Mech. Shaker Type)
¦V
-V*
¦V
¦V







99%

37
126
303
Ferrous Metals Processing -
Other
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Ferrous Metals Processing -
Other
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Ferrous Metals Processing -
Steel Foundries
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Ferrous Metals Processing -
Steel Foundries
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Ferrous Metals Processing -
Steel Foundries
Venturi Scrubber
¦V
-V*
¦V
V







73%

76
751
2,100
Ferrous Metals Processing -
Steel Foundries
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V
V







99%

42
117
266
Ferrous Metals Processing -
Steel Foundries
Wet ESP - Wire Plate Type
-V
¦V*
-V
V







99%

55
220
550
Ferrous Metals Processing -
Steel Foundries
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Ferrous Metals Processing -
Steel Foundries
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
A-15

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Ferrous Metals Processing -
Steel Foundries
Fabric Filter (Mech. Shaker Type)
V
V*
V
V







99%

37
126
303
Fiberglass Manufacture; Textile-
Type; Recuperative Furnaces
Low NOx Burner




V*






40%


1,690

Flexographic Printing
Permanent Total Enclosure (PTE)





V*





95


9,947

Fluid Catalytic Cracking Units -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




-V*






55%

1,430
3,190
3,190
Fuel Fired Equipment -
Process Heaters
Low Nox Burner + Flue Gas
Recirculation




¦V*






50%


570

Fuel Fired Equipment;
Furnaces; Natural Gas
Low NOx Burner




¦V*






50%


570

Glass Manufacturing -
Containers
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


1,770

Glass Manufacturing -
Containers
Selective Catalytic Reduction (SCR)




¦V*


X



75%


2,200

Glass Manufacturing -
Containers
Low NOx Burner




¦V*






40%


1,690

Glass Manufacturing -
Containers
Cullet Preheat




¦V*






25%


940

Glass Manufacturing -
Containers
Electric Boost




¦V*






10%


7,150

A-16

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Glass Manufacturing -
Containers
OXY-Firing




-V*






85%


4,590

Glass Manufacturing - Flat
OXY-Firing




¦V*






85%


1,900

Glass Manufacturing - Flat
Electric Boost




¦V*






10%


2,320

Glass Manufacturing - Flat
Low NOx Burner




-V*






40%


700

Glass Manufacturing - Flat -
Large Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


740

Glass Manufacturing - Flat -
Large Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


710

Glass Manufacturing - Flat -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


740

Glass Manufacturing - Flat -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


710

Glass Manufacturing - Pressed
Low NOx Burner




¦V*






40%


1,500

Glass Manufacturing - Pressed
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


1,640

Glass Manufacturing - Pressed
Selective Catalytic Reduction (SCR)




¦V*


X



75%


2,530

A-17

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
VOC
fecti
rease,
S02
ed
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Glass Manufacturing - Pressed
OXY-Firing




-V*






85%


3,900

Glass Manufacturing - Pressed
Cullet Preheat




¦V*






25%


810

Glass Manufacturing - Pressed
Electric Boost




¦V*






10%


8,760

Grain Milling
Fabric Filter (Pulse Jet Type)
V
V*
¦V
V







99%

42
117
266
Grain Milling
Fabric Filter (Reverse-Air Cleaned
Type)
V
V*
¦V
•V







99%

53
148
337
Grain Milling
Paper/Nonwoven Filters - Cartridge
Collector Type
V
V*
-V
¦V







99%

85
142
256
Graphic Arts
Use of Low or No VOC Materials





¦V*





65%

3,500
4,150
4,800
Highway Vehicles - Gasoline
Engine
Federal Reformulated Gasoline
(RFG)




X
¦V*


V

0%
7.65%
15.3%
2,498
25,093

Highway Vehicles - Gasoline
Engine
Low Reid Vapor Pressure (RVP)
Limit in Ozone Season




¦V
¦V*


V

0.1%
5.5%
11.1%
125
1,548
25,671
Highway Vehicles - Gasoline
Engine
RFG and High Enhanced l/M
Program




¦V
-V*


V

-9.1%
11.4%
31.9%
484
16,164

Highway Vehicles - Heavy Duty
and Diesel-Fueled Vehicles
Heavy Duty Engine and Vehicle
Standards and Highway Diesel Fuel
Sulfur Controls
V
V


¦V*

¦V

V


61%


10,561

A-18

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Highway Vehicles - Heavy Duty
and Diesel-Fueled Vehicles
Heavy Duty Engine and Vehicle
Standards and Highway Diesel Fuel
Sulfur Controls
V
V


¦V*
¦V
V

V


76%


10,561

Highway Vehicles - Heavy Duty
and Diesel-Fueled Vehicles
Heavy Duty Engine and Vehicle
Standards and Highway Diesel Fuel
Sulfur Controls
V
V


-V*
¦V
V

V


19%


9,301

Highway Vehicles - Heavy Duty
and Diesel-Fueled Vehicles
Heavy Duty Engine and Vehicle
Standards and Highway Diesel Fuel
Sulfur Controls
V
V


¦V*
¦V
-V

-V


44%


10,561

Highway Vehicles - Heavy Duty
Diesel Engines
Voluntary Diesel Retrofit Program:
Selective Catalytic Reduction
V
V


¦V*
¦V


V


19.26%


50,442

Highway Vehicles - Heavy Duty
Diesel Engines
Voluntary Diesel Retrofit Program:
Biodiesel Fuel
V
V*



V


V


7%


209,913

Highway Vehicles - Heavy Duty
Diesel Engines
Voluntary Diesel Retrofit Program:
Diesel Particulate Filter
V
V*



V
-V

-V


61.99%


727,689

Highway Vehicles - Heavy Duty
Diesel Engines
Voluntary Diesel Retrofit Program:
Diesel Oxidation Catalyst
V
V*



V
V

V


24.01%


167,640

Highway Vehicles - Light Duty
and Gasoline-Fueled Vehicles
Tier 2 Motor Vehicle Emissions and
Gasoline Sulfur Controls
V
V


¦V*
V
V

V

28%
34%
40%

6,297

Highway Vehicles - Light Duty
and Gasoline-Fueled Vehicles
Tier 2 Motor Vehicle Emissions and
Gasoline Sulfur Controls
V
V


¦V*
V
-V

-V

43%
54.5%
66%

6,297

Highway Vehicles - Light Duty
and Gasoline-Fueled Vehicles
Tier 2 Motor Vehicle Emissions and
Gasoline Sulfur Controls
V
V


-V*
V
V

V

74%
83%
92%

6,297

Highway Vehicles - Light Duty
and Gasoline-Fueled Vehicles
Tier 2 Motor Vehicle Emissions and
Gasoline Sulfur Controls
V
V


¦V*
V
V

V

52%
64.5%
77%

6,297

A-19

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
ed
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Highway Vehicles - Light Duty
Gasoline Engines
Basic Inspection and Maintenance
Program
V
V


¦V
¦V*
¦V
¦V
¦V





N/A

Highway Vehicles - Light Duty
Gasoline Engines
High Enhanced Inspection and
Maintenance (l/M) Program




¦V*
¦V


-V

0.4%
6.5%
13.4%
3,900
7,949
218,369
Hog Operations
Chemical Additives to Waste







¦V*



50%


73

IC Engines - Gas
L-E (Low Speed)




-V*






87%


176

IC Engines - Gas - Small
Sources
Selective Catalytic Reduction (SCR)




¦V*






90%


2,769

IC Engines - Gas, Diesel,
LPG - Small Sources
Selective Catalytic Reduction (SCR)




¦V*






80%


2,340

IC Engines - Gas, Diesel,
LPG - Small Sources
Ignition Retard




¦V*






25%


770

ICI Boilers - Coal/Cyclone -
Large Sources
Coal Reburn




¦V*






50%


300

ICI Boilers - Coal/Cyclone -
Small Sources
Natural Gas Reburn (NGR)




¦V*






55%


1,570

ICI Boilers - Coal/Cyclone -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*






80%


820

ICI Boilers - Coal/Cyclone -
Small Sources
Coal Reburn




¦V*






50%


1,570

A-20

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
ICI Boilers - Coal/Cyclone -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



35%


840

ICI Boilers - Coal/FBC - Large
Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



40%


670

ICI Boilers - Coal/FBC - Small
Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



75%


900

ICI Boilers - Coal/Stoker -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



40%

873
1,015
1,015
ICI Boilers - Coal/Stoker -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


817

ICI Boilers - Coal/Wall - Large
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


840

ICI Boilers - Coal/Wall - Large
Sources
Selective Catalytic Reduction (SCR)




¦V*


X



70%


1,070

ICI Boilers - Coal/Wall - Large
Sources
Low NOx Burner




¦V*






50%


1,090

ICI Boilers - Coal/Wall - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%

400
1,040
1,040
ICI Boilers - Coal/Wall - Small
Sources
Selective Catalytic Reduction (SCR)




¦V*






70%


1,260

ICI Boilers - Coal/Wall - Small
Sources
Low NOx Burner




¦V*






50%


1,460

A-21

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
ICI Boilers - Coke - Small
Sources
Selective Catalytic Reduction (SCR)




-V*


X



70%


1,260

ICI Boilers - Coke - Small
Sources
Low NOx Burner




¦V*






50%


1,460

ICI Boilers - Coke - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%

400
1,040
1,040
ICI Boilers - Distillate Oil -
Large Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



50%


1,890

ICI Boilers - Distillate Oil -
Small Sources
Low NOx Burner




¦V*






50%


1,180

ICI Boilers - Distillate Oil -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

1,090
2,490
2,490
ICI Boilers - Distillate Oil -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,780
2,780
3,570
ICI Boilers - Distillate Oil -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

3,470
4,640
4,640
ICI Boilers - Liquid Waste
Selective Catalytic Reduction (SCR)




¦V*


X



80%

1,480
1,480
1,910
ICI Boilers - Liquid Waste -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

1,120
1,120
1,080
ICI Boilers - Liquid Waste -
Small Sources
Low NOx Burner




¦V*






50%


400

A-22

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
ICI Boilers - Liquid Waste -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



50%

1,940
2,580
2,580
ICI Boilers - LPG - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

3,470
4,640
4,640
ICI Boilers - LPG - Small
Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,780
2,780
3,570
ICI Boilers - LPG - Small
Sources
Low NOx Burner + Flue Gas
Recirculation




-V*






60%

1,090
2,490
2,490
ICI Boilers - LPG - Small
Sources
Low NOx Burner




¦V*






50%


1,180

ICI Boilers - MSW/Stoker-
Small Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



55%


1,690

ICI Boilers - Natural Gas -
Large Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%


1,570

ICI Boilers - Natural Gas -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,230
2,230
2,860
ICI Boilers - Natural Gas -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

2,900
3,870
3,870
ICI Boilers - Natural Gas -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
ICI Boilers - Natural Gas -
Small Sources
Oxygen Trim + Water Injection




¦V*






65%


680

A-23

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
ICI Boilers - Natural Gas -
Small Sources
Low NOx Burner




-V*






50%


820

ICI Boilers - Process Gas -
Small Sources
Oxygen Trim + Water Injection




¦V*






65%


680

ICI Boilers - Process Gas -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
ICI Boilers - Process Gas -
Small Sources
Low NOx Burner




-V*






50%


820

ICI Boilers - Process Gas -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,230
2,230
2,860
ICI Boilers - Residual Oil -
Large Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%


1,050

ICI Boilers - Residual Oil -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

1,480
1,480
1,910
ICI Boilers - Residual Oil -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

1,120
1,120
1,080
ICI Boilers - Residual Oil -
Small Sources
Low NOx Burner




¦V*






50%


400

ICI Boilers - Residual Oil -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

1,940
2,580
2,580
ICI Boilers -
Wood/Bark/Stoker - Large
Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



55%


1,190

A-24

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
ICI Boilers -
Wood/Bark/Stoker - Small
Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




V*


X



55%


1,440

Industrial Boilers - Coal
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Industrial Boilers - Coal
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Industrial Boilers - Coal
Venturi Scrubber
¦V
¦V*
¦V
V







82%

76
751
2,100
Industrial Boilers - Coal
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
•V







98%

40
110
250
Industrial Boilers - Coal
Fabric Filter (Pulse Jet Type)
-V
¦V*
-V
¦V







99%

42
117
266
Industrial Boilers - Coal
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
¦V







99%

53
148
337
Industrial Boilers - Coke
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Industrial Boilers - Coke
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Industrial Boilers - Liquid Waste
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Industrial Boilers - Liquid Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

A-25

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Industrial Boilers - Liquid Waste
Dry ESP-Wire Plate Type
V
V*
¦V
V







98%

40
110
250
Industrial Boilers - LPG
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Industrial Boilers - LPG
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Industrial Boilers - Natural Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Industrial Boilers - Natural Gas
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Industrial Boilers - Oil
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Industrial Boilers - Oil
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Industrial Boilers - Oil
Venturi Scrubber
V
V*
¦V
¦V







92%

76
751
2,100
Industrial Boilers - Oil
Dry ESP-Wire Plate Type
V
V*
-V
¦V







98%

40
110
250
Industrial Boilers - Process Gas
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Industrial Boilers - Process Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

A-26

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Industrial Boilers - Solid Waste
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Industrial Boilers - Solid Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Industrial Boilers - Wood
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Industrial Boilers - Wood
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Industrial Boilers - Wood
Venturi Scrubber
¦V
¦V*
¦V
•V







93%

76
751
2,100
Industrial Boilers - Wood
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
¦V







99%

53
148
337
Industrial Boilers - Wood
Dry ESP-Wire Plate Type
¦V
-V*
¦V
¦V







98%

40
110
250
Industrial Boilers - Wood
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V








99%

42
117
266
Industrial Coal Combustion
RACT to 50 tpy (LNB)




¦V*






21%


1,350

Industrial Coal Combustion
RACT to 25 tpy (LNB)




¦V*






21%


1,350

Industrial Incinerators
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



45%


1,130

A-27

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Industrial Maintenance Coating
AIM Coating Federal Rule





-V*





20%


228

Industrial Maintenance Coating
South Coast Phase III





¦V*





73%


10,059

Industrial Maintenance Coating
South Coast Phase 1





¦V*





34%

3,300
1,443
4,600
Industrial Maintenance Coating
South Coast Phase II





-V*





47%


4,017

Industrial Natural Gas
Combustion
RACT to 25 tpy (LNB)




¦V*






31%


770

Industrial Natural Gas
Combustion
RACT to 50 tpy (LNB)




¦V*






31%


770

Industrial Oil Combustion
RACT to 50 tpy (LNB)




¦V*






36%


1,180

Industrial Oil Combustion
RACT to 25 tpy (LNB)




¦V*






36%


1,180

Inorganic Chemical
Manufacture
Flue Gas Desulfurization






V*




90%


N/A

In-Proc; Process Gas; Coke
Oven/Blast Ovens
Low NOx Burner + Flue Gas
Recirculation




¦V*






55%

1,430
3,190
3,190
In-process Fuel Use -
Bituminous Coal
Flue Gas Desulfurization






V*




90%


N/A

A-28

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
In-Process Fuel Use -
Bituminous Coal - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



40%


1,260

In-Process Fuel Use; Natural
Gas - Small Sources
Low NOx Burner




¦V*






50%


2,200

In-Process Fuel Use; Residual
Oil - Small Sources
Low NOx Burner




¦V*






37%


2,520

In-Process; Bituminous Coal;
Cement Kilns
Selective Non-Catalytic Reduction
(SNCR) Urea Based




-V*


X



50%


770

In-Process; Bituminous Coal;
Lime Kilns
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



50%


770

In-Process; Process Gas;
Coke Oven Gas
Low NOx Burner




¦V*






50%


2,200

Internal Combustion Engines -
Gas
L-E (Medium Speed)




¦V*






87%


380

Internal Combustion Engines -
Gas - Large Sources
Air/Fuel + Ignition Retard




¦V*






30%

150
460
460
Internal Combustion Engines -
Gas - Large Sources
Air/Fuel Ratio Adjustment




¦V*






20%


380

Internal Combustion Engines -
Gas - Large Sources
Ignition Retard




¦V*






20%


550

Internal Combustion Engines -
Gas - Small Sources
Air/Fuel + Ignition Retard




¦V*






30%

270
1,440
1,440
A-29

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Internal Combustion Engines -
Gas - Small Sources
Air/Fuel Ratio Adjustment




-V*






20%


1,570

Internal Combustion Engines -
Gas - Small Sources
Ignition Retard




¦V*






20%


1,020

Internal Combustion Engines -
Oil - Small Sources
Ignition Retard




¦V*






25%


770

Internal Combustion Engines -
Oil - Small Sources
Selective Catalytic Reduction (SCR)




-V*


X



80%


2,340

Iron & Steel Mills - Annealing
Low NOx Burner (LNB) + SCR




¦V*


X



80%

1,320
1,720
1,720
Iron & Steel Mills - Annealing
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

250
750
750
Iron & Steel Mills - Annealing
Low NOx Burner




¦V*






50%


570

Iron & Steel Mills - Annealing
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


1,640

Iron & Steel Mills - Annealing -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



85%


3,830

Iron & Steel Mills - Annealing -
Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



90%

3,720
4,080
4,080
Iron & Steel Mills - Galvanizing
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

190
580
580
A-30

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
ed
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Iron & Steel Mills - Galvanizing
Low NOx Burner




-V*






50%


490

Iron & Steel Mills - Reheating
Low Excess Air (LEA)




¦V*






13%


1,320

Iron & Steel Mills - Reheating
Low NOx Burner




¦V*






66%


300

Iron & Steel Mills - Reheating
Low NOx Burner + Flue Gas
Recirculation




-V*






77%

150
380
380
Iron Production; Blast
Furnaces; Blast Heating Stoves
Low NOx Burner + Flue Gas
Recirculation




¦V*






77%


380

Lignite (Industrial Boiler)
In-duct Dry Sorbent Injection






¦V*




40%

1,111
1,526
2,107
Lignite (Industrial Boiler)
Spray Dryer Abosrber






-V*




90%

804
1,341
1,973
Lignite (Industrial Boiler)
Wet Flue Gas Desulfurization






¦V*




90%

1,027
1,536
1,980
Lignite (Industrial Boilers)
Flue Gas Desulfurization






¦V*




90%


N/A

Lime Kilns
Low NOx Burner




¦V*






30%


560

Lime Kilns
Mid-Kiln Firing




¦V*






30%


460

A-31

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Lime Kilns
Selective Non-Catalytic Reduction
(SNCR) Urea Based




-V*


X



50%


770

Lime Kilns
Selective Non-Catalytic Reduction
(SNCR) Ammonia Based




¦V*


X



50%


850

Lime Kilns
Selective Catalytic Reduction (SCR)




¦V*


X



80%


3,370

Machinery, Equipment, and
Railroad Coating
SCAQMD Limits





-V*





55.2%


2,027

Marine Surface Coating
(Shipbuilding)
Add-On Controls





¦V*





90%


8,937

Marine Surface Coating
(Shipbuilding)
MACT Standard





¦V*





24%


2,090

Medical Waste Incinerators
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



45%


4,510

Metal Can Surface Coating
Operations
Permanent Total Enclosure (PTE)





¦V*





95


8,469

Metal Coil & Can Coating
Incineration





¦V*





90%


8,937

Metal Coil & Can Coating
BAAQMD Rule 11 Amended





¦V*





42%


2,007

Metal Coil & Can Coating
MACT Standard





¦V*





36%


1,000

A-32

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Metal Furniture Surface
Coating Operations
Permanent Total Enclosure (PTE)





-V*





95


19,321

Metal Furniture, Appliances,
Parts
SCAQMD Limits





V*





55.2%


2,027

Metal Furniture, Appliances,
Parts
MACT Standard





V*





36%


1,000

Mineral Products - Cement
Manufacture
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Mineral Products - Cement
Manufacture
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Mineral Products - Cement
Manufacture
Fabric Filter (Pulse Jet Type)
-V
¦V*
-V
¦V







99%

42
117
266
Mineral Products - Cement
Manufacture
Fabric Filter (Mech. Shaker Type)
¦V
-V*
¦V
¦V







99%

37
126
303
Mineral Products - Cement
Manufacture
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
¦V







98%

40
110
250
Mineral Products - Cement
Manufacture
Paper/Nonwoven Filters - Cartridge
Collector Type
-V
¦V*
-V
¦V







99%

85
142
256
Mineral Products - Cement
Manufacture
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
¦V







99%

53
148
337
Mineral Products - Coal
Cleaning
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

A-33

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Mineral Products - Coal
Cleaning
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Mineral Products - Coal
Cleaning
Venturi Scrubber
¦V
-V*
¦V
V







99%

76
751
2,100
Mineral Products - Coal
Cleaning
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
V







99%

53
148
337
Mineral Products - Coal
Cleaning
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V
V







99%

42
117
266
Mineral Products - Coal
Cleaning
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Mineral Products - Coal
Cleaning
Paper/Nonwoven Filters - Cartridge
Collector Type
-V
¦V*
-V
V







99%

85
142
256
Mineral Products - Other
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Mineral Products - Other
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Mineral Products - Other
Fabric Filter (Pulse Jet Type)
-V
¦V*
-V
V







99%

42
117
266
Mineral Products - Other
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Mineral Products - Other
Dry ESP-Wire Plate Type
¦V
¦V*

V







98%

40
110
250
A-34

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Mineral Products - Other
Wet ESP - Wire Plate Type
¦V
¦V*
¦V
V







99%

55
220
550
Mineral Products - Other
Paper/Nonwoven Filters - Cartridge
Collector Type
¦V
-V*
¦V
V







99%

85
145
256
Mineral Products - Other
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
V







99%

37
126
303
Mineral Products - Stone
Quarrying & Processing
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Mineral Products - Stone
Quarrying & Processing
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Mineral Products - Stone
Quarrying and Processing
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
V







99%

37
126
303
Mineral Products - Stone
Quarrying and Processing
Fabric Filter (Pulse Jet Type)
¦V
-V*
¦V
V







99%

42
117
266
Mineral Products - Stone
Quarrying and Processing
Wet ESP - Wire Plate Type
¦V
¦V*
¦V
V







99%

55
220
550
Mineral Products - Stone
Quarrying and Processing
Dry ESP-Wire Plate Type
-V
¦V*
-V
V







98%

40
110
250
Mineral Products - Stone
Quarrying and Processing
Paper/Nonwoven Filters - Cartridge
Collector Type
¦V
-V*
¦V
V







99%

85
142
256
Mineral Products - Stone
Quarrying and Processing
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*

V







99%

53
148
337
A-35

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Mineral Products - Stone
Quarrying and Processing
Venturi Scrubber
V
V*
¦V
V







95%

76
751
2,100
Mineral Products Industry
Flue Gas Desulfurization






V*




90%


N/A

Miscellaneous Metal Products
Coatings
MACT Standard





¦V*





36%


1,000

Motor Vehicle Coating
Incineration





-V*





90%


8,937

Motor Vehicle Coating
MACT Standard





¦V*





36%


118

Municipal Solid Waste Landfill
Gas Collection (SCAQMD/BAAQMD)





¦V*





70%


700

Municipal Waste Combustors
Selective Non-Catalytic Reduction
(SNCR)




V*


X



45%


1,130

Municipal Waste Incineration
Dry ESP-Wire Plate Type
V
V*
¦V








98%

40
110
250
Natural Gas Production;
Compressors - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



20%


1,651

Nitric Acid Manufacturing -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



97%


590

Nitric Acid Manufacturing -
Small Sources
Non-Selective Catalytic Reduction
(NSCR)




¦V*


X



98%

510
550
710
A-36

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Nitric Acid Manufacturing -
Small Sources
Extended Absorption




V*






95%


480

Non-Ferrous Metals
Processing - Aluminum
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Non-Ferrous Metals
Processing - Aluminum
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Non-Ferrous Metals
Processing - Aluminum
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Non-Ferrous Metals
Processing - Aluminum
Wet ESP - Wire Plate Type
¦V
¦V*
¦V
•V







99%

55
220
550
Non-Ferrous Metals
Processing - Aluminum
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
¦V







99%

53
148
337
Non-Ferrous Metals
Processing - Aluminum
Dry ESP-Wire Plate Type
¦V
-V*
¦V
V







98%

40
110
250
Non-Ferrous Metals
Processing - Copper
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Non-Ferrous Metals
Processing - Copper
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Non-Ferrous Metals
Processing - Copper
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Non-Ferrous Metals
Processing - Copper
Wet ESP - Wire Plate Type
¦V
¦V*
¦V
V







99%

55
220
550
A-37

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Non-Ferrous Metals
Processing - Copper
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Non-Ferrous Metals
Processing - Copper
Dry ESP-Wire Plate Type
¦V
-V*
¦V
V







98%

40
110
250
Non-Ferrous Metals
Processing - Lead
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Non-Ferrous Metals
Processing - Lead
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Non-Ferrous Metals
Processing - Lead
Wet ESP - Wire Plate Type
¦V
¦V*
¦V
V







99%

55
220
550
Non-Ferrous Metals
Processing - Lead
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
V







99%

53
148
337
Non-Ferrous Metals
Processing - Lead
Dry ESP-Wire Plate Type
¦V
-V*
¦V
V







98%

40
110
250
Non-Ferrous Metals
Processing - Lead
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Non-Ferrous Metals
Processing - Other
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Non-Ferrous Metals
Processing - Other
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Non-Ferrous Metals
Processing - Other
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
A-38

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Non-Ferrous Metals
Processing - Other
Wet ESP - Wire Plate Type
¦V
¦V*
¦V
V







99%

55
220
550
Non-Ferrous Metals
Processing - Other
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Non-Ferrous Metals
Processing - Other
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
V







99%

37
1,260
303
Non-Ferrous Metals
Processing - Zinc
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Non-Ferrous Metals
Processing - Zinc
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Non-Ferrous Metals
Processing - Zinc
Wet ESP - Wire Plate Type
-V
¦V*
-V
V







99%

55
220
550
Non-Ferrous Metals
Processing - Zinc
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Non-Ferrous Metals
Processing - Zinc
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
Non-Ferrous Metals
Processing - Zinc
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
V







99%

37
126
303
Nonroad Diesel Engines
Heavy Duty Retrofit Program
¦V
-V*
¦V
V







1%


9,500

Nonroad Gasoline Engines
Federal Reformulated Gasoline





V*





1.4%

440
4,854
9,250
A-39

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Off-Highway Diesel Vehicles
Final Compression-Ignition (C-l)
Engine Standards
V
V


¦V*
¦V


¦V

34%
45.5%
57%

N/A

Off-Highway Diesel Vehicles
Final Compression-Ignition (C-l)
Engine Standards
V
V


-V*
¦V


-V

49%
62%
75%

N/A

Off-Highway Diesel Vehicles
Final Compression-Ignition (C-l)
Engine Standards
V
V


¦V*
¦V


-V

65%
72%
79%

N/A

Off-Highway Diesel Vehicles
Final Compression-Ignition (C-l)
Engine Standards
V
V


¦V*
¦V


¦V

21%
30%
59%

N/A

Off-Highway Gasoline Vehicles
Large Spark-Ignition (S-l) Engine
Standards
V
V


¦V*



¦V

-26%
35.5%
77%

N/A

Off-Highway Gasoline Vehicles
Large Spark-Ignition (S-l) Engine
Standards
V
V


¦V*
¦V


-V

-32%
33.5%
91%

N/A

Off-Highway Gasoline Vehicles
Large Spark-Ignition (S-l) Engine
Standards
V
V


-V*
¦V


¦V

-31%
29%
95%

N/A

Off-Highway Gasoline Vehicles
Large Spark-Ignition (S-l) Engine
Standards
V
V


¦V*



¦V

-26%
33.5%
93%

N/A

Off-Highway Vehicles: All
Terrain Vehicles (ATVs)
Recreational Gasoline ATV
Standards
V
V


¦V
¦V*


¦V

33%
65%
97%

N/A

Off-Highway Vehicles: All
Terrain Vehicles (ATVs)
Recreational Gasoline ATV
Standards
V
V


¦V
-V*


¦V

33%
64%
95%

N/A

Off-Highway Vehicles: All
Terrain Vehicles (ATVs)
Recreational Gasoline ATV
Standards
V
V



¦V*




27%
40%
73%

N/A

A-40

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Off-Highway Vehicles: All
Terrain Vehicles (ATVs)
Recreational Gasoline ATV
Standards
V
V


¦V
¦V*


¦V

14%
24%
34%

N/A

Off-Highway Vehicles:
Motorcycles
Recreational Gasoline Off-Highway
Motorcycle Standards
V
V


¦V
-V*


¦V

5%
12.5%
20%

N/A

Off-Highway Vehicles:
Motorcycles
Recreational Gasoline Off-Highway
Motorcycle Standards
V
V


¦V
¦V*


¦V

10%
25%
40%

N/A

Off-Highway Vehicles:
Motorcycles
Recreational Gasoline Off-Highway
Motorcycle Standards
V
V


¦V
¦V*


¦V

12%
31%
50%

N/A

Off-Highway Vehicles:
Motorcycles
Recreational Gasoline Off-Highway
Motorcycle Standards
V
V


V
¦V*




12%
32%
52%

N/A

Off-Highway Vehicles:
Snowmobiles
Recreational Gasoline Snowmobile
Standards
V
V


X
¦V*


¦V


20%


N/A

Off-Highway Vehicles:
Snowmobiles
Recreational Gasoline Snowmobile
Standards
V
V


X
¦V*


¦V


45%


N/A

Off-Highway Vehicles:
Snowmobiles
Recreational Gasoline Snowmobile
Standards
V
V


X
¦V*





69%


N/A

Off-Highway Vehicles:
Snowmobiles
Recreational Gasoline Snowmobile
Standards
V
V


X
¦V*


¦V


62%


N/A

Oil and Natural Gas Production
Equipment and Maintenance





¦V*





37%


317

Open Burning
Episodic Ban (Daily Only)




¦V*






100%


N/A

A-41

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
VOC
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Open Top Degreasing
SCAQMD 1122 (VOC content limit)





-V*





76%


1,248

Open Top Degreasing
Title III MACT Standard





¦V*





31%


-69

Open Top Degreasing
Airtight Degreasing System





¦V*





98%


9,789

Paper and other Web Coating
Operations
Permanent Total Enclosure (PTE)





-V*





95


1,503

Paper Surface Coating
Incineration





¦V*





78%


4,776

Paved Roads
Vacuum Sweeping
V
V*
V
V







50.5%


485

Pesticide Application
Reformulation - FIP Rule





¦V*





20%


9,300

Petroleum Industry
Flue Gas Desulfurization (FGD)






V*




90%


N/A

Plastics Prod-Specific; (ABS) -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




V*






55%

1,430
3,190
3,190
Portable Gasoline Containers
OTC Portable Gas Container Rule





¦V*





33%


581

Poultry Operations
Chemical Additives to Waste







V*



75%


1,014

A-42

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Prescribed Burning
Increase Fuel Moisture
V
V*
V
V







50%


2,617

Primary Lead Smelters -
Sintering
Dual Absorption






V*




99%


N/A

Primary Metals Industry
Flue Gas Desulfurization






V*




90%


N/A

Primary Zinc Smelters -
Sintering
Dual Absorption






V*




99%


N/A

Process Heaters - Distillate
Oil - Small Sources
Ultra Low NOx Burner




¦V*






74%


2,140

Process Heaters - Distillate
Oil - Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



92%

9,120
9,120
15,350
Process Heaters - Distillate
Oil - Small Sources
Low NOx Burner - Selective Non-
Catalytic Reduction (SNCR)




¦V*


X



78%

3,620
3,620
3,830
Process Heaters - Distillate
Oil - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


9,230

Process Heaters - Distillate
Oil - Small Sources
Low NOx Burner




¦V*






45%


3,470

Process Heaters - Distillate
Oil - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






48%

4,250
4,250
19,540
Process Heaters - Distillate
Oil - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


3,180

A-43

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Process Heaters - LPG - Small
Sources
Selective Catalytic Reduction (SCR)




-V*


X



75%


9,230

Process Heaters - LPG - Small
Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



92%

9,120
9,120
15,350
Process Heaters - LPG - Small
Sources
Low NOx Burner




¦V*






45%


3,470

Process Heaters - LPG - Small
Sources
Low NOx Burner (LNB) + SNCR




-V*


X



78%

3,620
3,620
3,830
Process Heaters - LPG - Small
Sources
Ultra Low NOx Burner




¦V*






74%


2,140

Process Heaters - LPG - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


3,180

Process Heaters - LPG - Small
Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






48%

4,250
4,250
19,540
Process Heaters - Natural
Gas - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


2,850

Process Heaters - Natural
Gas - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






55%

3,190
3,190
15,580
Process Heaters - Natural
Gas - Small Sources
Low NOx Burner




¦V*






50%


2,200

Process Heaters - Natural
Gas - Small Sources
Low NOx Burner (LNB) + SNCR




¦V*


X



80%

3,520
3,520
6,600
A-44

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Process Heaters - Natural
Gas - Small Sources
Selective Catalytic Reduction (SCR)




-V*


X



75%


12,040

Process Heaters - Natural
Gas - Small Sources
Ultra Low NOx Burner




¦V*






75%


1,500

Process Heaters - Natural
Gas - Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



88%

11,560
11,560
27,910
Process Heaters - Other Fuel -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



60%


1,930

Process Heaters - Other Fuel -
Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



91%

5,420
5,420
7,680
Process Heaters - Other Fuel -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


5,350

Process Heaters - Other Fuel -
Small Sources
Low NOx Burner (LNB) + SNCR




¦V*


X



75%

2,230
2,300
2,860
Process Heaters - Other Fuel -
Small Sources
Ultra Low NOx Burner




¦V*






73%


1,290

Process Heaters - Other Fuel -
Small Sources
Low NOx Burner




¦V*






37%


2,520

Process Heaters - Other Fuel -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






34%


3,490

Process Heaters - Process
Gas - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






55%

1,430
3,190
3,190
A-45

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Process Heaters - Process
Gas - Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




-V*


X



88%

11,560
11,560
27,910
Process Heaters - Process
Gas - Small Sources
Low NOx Burner (LNB) +Selective
Reduction SNCR




¦V*


X



80%

3,520
3,520
6,600
Process Heaters - Process
Gas - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


12,040

Process Heaters - Process
Gas - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



60%


2,850

Process Heaters - Process
Gas - Small Sources
Low NOx Burner




¦V*






50%


2,200

Process Heaters - Process
Gas - Small Sources
Ultra Low NOx Burner




¦V*






75%


1,500

Process Heaters - Residual
Oil - Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



91%

5,420
5,420
7,680
Process Heaters - Residual
Oil - Small Sources
Ultra Low NOx Burner




¦V*






73%


1,290

Process Heaters - Residual
Oil - Small Sources
Low NOx Burner




¦V*






37%


2,520

Process Heaters - Residual
Oil - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






34%


3,490

Process Heaters - Residual
Oil - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


1,930

A-46

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Process Heaters - Residual
Oil - Small Sources
Selective Catalytic Reduction (SCR)




-V*


X



75%


5,350

Process Heaters - Residual
Oil - Small Sources
Low NOx Burner (LNB) + SCR




¦V*


X



75%

2,230
2,300
2,860
Process Heaters (Oil and Gas
Production)
Flue Gas Desulfurization






V*




90%


N/A

Product and Packaging
Rotogravure and Screen
Printing
Permanent Total Enclosure (PTE)





-V*





95


12,770

Publication Rotogravure
Printing
Permanent Total Enclosure (PTE)





¦V*





95


2,422

Pulp and Paper Industry
(Sulfate Pulping)
Flue Gas Desulfurization






V*




90%


N/A

Residential Natural Gas
Water Heater Replacement




¦V*






7%


N/A

Residential Natural Gas
Water Heater + LNB Space Heaters




¦V*






7%


1,230

Residential Wood Combustion
Education and Advisory Program
V
V*
V
V







50%


1,320

Residential Wood Stoves
NSPS compliant Wood Stoves
V*
V*









98%


2,000

Residual Oil
(Commercial/Institutional
Boilers)
Wet Flue Gas Desulfurization






V*




90%

2,295
3,489
4,524
A-47

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
VOC
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Residual Oil
(Commercial/Institutional
Boilers)
Flue Gas Desulfurization






V*




90%


N/A

Residual Oil (Industrial Boilers
Flue Gas Desulfurization






V*




90%


N/A

Rich-Burn Stationary
Reciprocating Internal
Combustion Engines
Non-selective catalytic reduction




¦V*






90%


342

Rich-Burn Stationary
Reciprocating Internal
Combustion Engines
Non-selective catalytic reduction




-V*






90%


342

Rich-Burn Stationary
Reciprocating Internal
Combustion Engines (RICE)
Non-selective catalytic reduction
(NSCR)




¦V*
V


V


90%


342

Rubber and Plastics
Manufacturing
SCAQMD - Low VOC





¦V*





60%


1,020

Sand/Gravel; Dryer - Small
Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






55%

1,430
3,190
3,190
Secondary Aluminum
Production; Smelting Furnaces
Low NOx Burner




¦V*






50%


570

Secondary Metal Production
Flue Gas Desulfurization






V*




90%


N/A

Solid Waste Disposal;
Government; Other
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



45%


1,130

Space Heaters - Distillate Oil -
Small Sources
Low NOx Burner




¦V*






50%


1,180

A-48

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Space Heaters - Distillate Oil -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




-V*






60%

1,090
2,490
2,490
Space Heaters - Distillate Oil -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,780
2,780
3,570
Space Heaters - Distillate Oil -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

3,470
4,640
4,640
Space Heaters - Natural Gas -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



50%

2,900
3,870
3,870
Space Heaters - Natural Gas -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,230
2,230
2,860
Space Heaters - Natural Gas -
Small Sources
Low NOx Burner




¦V*






50%


820

Space Heaters - Natural Gas -
Small Sources
Oxygen Trim + Water Injection




¦V*






65%


680

Space Heaters - Natural Gas -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
Stage II Service Stations
Low Pressure/Vacuum Relief Valve





¦V*





91.6%

930
1,080
1,230
Stage II Service Stations -
Underground Tanks
Low Pressure/Vacuum Relief Valve





¦V*





73%

930
1,080
1,230
Starch Manufacturing;
Combined Operation - Small
Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






55%

1,430
3,190
3,190
A-49

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Steam Generating Unit-Coal/Oil
Flue Gas Desulfurization






V*




90%


N/A

Steel Foundries; Heat Treating
Low NOx Burner




V*






50%


570

Steel Production; Soaking Pits
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

250
750
750
Sulfate Pulping - Recovery
Furnaces - Small Sources
Low NOx Burner




-V*






50%


820

Sulfate Pulping - Recovery
Furnaces - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

2,900
3,870
3,870
Sulfate Pulping - Recovery
Furnaces - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,230
2,230
2,860
Sulfate Pulping - Recovery
Furnaces - Small Sources
Oxygen Trim + Water Injection




¦V*






65%


680

Sulfate Pulping - Recovery
Furnaces - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing + Flue Gas
Desulfurization






V*




99.8%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing + Flue Gas
Desulfurization






V*




99.7%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing






V*




98.4%


N/A

A-50

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
ed
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing






¦V*




97.8%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing






-V*




97.1%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Flue Gas Desulfurization






¦V*




90%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing + Flue Gas
Desulfurization






¦V*




99.8%


N/A

Sulfur Recovery Plants - Sulfur
Removal
Flue Gas Desulfurization






¦V*




90%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%) +
Flue Gas Desulfurization






¦V*




95%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%)






-V*




75%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Flue Gas Desulfurization






¦V*




90%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%) +
Flue Gas Desulfurization






¦V*




85%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%)






-V*




90%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%) +
Flue Gas Desulfurization






¦V*




90%


N/A

A-51

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%)






V*




95%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%) +
Flue Gas Desulfurization






V*




75%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%)






V*




85%


N/A

Surface Coat Oper; Coating
Oven Htr; Nat Gas - Small
Sources
Low NOx Burner




-V*


X



50%


2,200

Traffic Markings
South Coast Phase II





¦V*





47%


4,017

Traffic Markings
AIM Coating Federal Rule





¦V*





20%


228

Traffic Markings
South Coast Phase III





¦V*





73%


1,059

Traffic Markings
South Coast Phase 1





¦V*





34%

8,600
1,443
12,800
Unpaved Roads
Chemical Stabilization
V
V*
-V








37.5%


2,753

Unpaved Roads
Hot Asphalt Paving
V
V*
¦V
V







67.5%


537

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
cross-Coupled Overfire Air (LNC1)




¦V*






33%


N/A

A-52

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
separated Overfire Air (LNC2)




-V*






48%


N/A

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
Close-Coupled and Separated
Overfire Air (LNC3)




¦V*






58%


N/A

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
cross-Coupled Overfire Air (LNC1)




¦V*






43%


N/A

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
separated Overfire Air (LNC2)




-V*






38%


N/A

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
Close-Coupled and Separated
Overfire Air (LNC3)




¦V*






53%


N/A

Utility Boiler - Coal/Tangential
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



35%


N/A

Utility Boiler - Coal/Tangential
Selective Catalytic Reduction (SCR)




¦V*


X

V

90%
(Hg 95%)


N/A

Utility Boiler - Coal/Tangential
Natural Gas Reburn (NGR)




¦V*






50%


N/A

Utility Boiler - Coal/Wall
Low Nox Burner with Overfire Air




¦V*






56%


N/A

Utility Boiler - Coal/Wall
Low Nox Burner without Overfire Air




¦V*






41


N/A

Utility Boiler - Coal/Wall
Low Nox Burner without Overfire Air




¦V*






40%


N/A

A-53

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Utility Boiler - Coal/Wall
Low Nox Burner with Overfire Air




-V*






55%


N/A

Utility Boiler - Coal/Wall
Selective Catalytic Reduction (SCR)




¦V*


X



90%


N/A

Utility Boiler - Coal/Wall
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



35%


N/A

Utility Boiler - Coal/Wall
Natural Gas Reburn (NGR)




-V*






50%


N/A

Utility Boiler - Cyclone
Natural Gas Reburn (NGR)




¦V*






50%


N/A

Utility Boiler - Cyclone
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



35%


N/A

Utility Boiler - Cyclone
Selective Catalytic Reduction (SCR)




¦V*


X



80%


N/A

Utility Boiler - Oil-
Gas/Tangential
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%


N/A

Utility Boiler - Oil-
Gas/Tangential
Selective Catalytic Reduction (SCR)




¦V*


X



80%


N/A

Utility Boiler - Oil-
Gas/Tangential
Natural Gas Reburn (NGR)




¦V*






50%


N/A

Utility Boiler - Oil-Gas/Wall
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%


N/A

A-54

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficients
from base I
Typical
/
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Utility Boiler - Oil-Gas/Wall
Natural Gas Reburn (NGR)




-V*






50%


N/A

Utility Boiler - Oil-Gas/Wall
Selective Catalytic Reduction (SCR)




V*


X



80%


N/A

Utility Boilers - Coal
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
¦V





V

99.5%

37
126
303
Utility Boilers - Coal
Fabric Filter
¦V
¦V*
¦V






V

95%
(Hg 80%)


N/A

Utility Boilers - Coal
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
•V





V

99%

53
148
337
Utility Boilers - Coal
Dry ESP-Wire Plate Type
-V
¦V*
-V
¦V





V
(Hg 3%)
98%
(Hg 20%)
Hg 36%)
40
110
250
Utility Boilers - Coal
Fabric Filter (Pulse Jet Type)
¦V
-V*
¦V
¦V





-V

99%

42
117
266
Utility Boilers - Coal-Fired
Fuel Switching - High-Sulfur Coal to
Low-Sulfur Coal
¦V
¦V




V*




60%

113
140
167
Utility Boilers - Coal-Fired
Repowering to IGCC




V

V*




99%


N/A

Utility Boilers - Coal-Fired
Coal Washing
¦V
¦V




V*


-V

40%

70
320
563
Utility Boilers - Gas/Oil
Fabric Filter
¦V
¦V*
¦V
•V







95%


N/A

A-55

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficient
from base I
Typical
/
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Utility Boilers - High Sulfur
Content
Flue Gas Desulfurization (Wet
Scrubber Type)






V*


V
(Hg 29%)
90%
(Hg 64%)
Hg 98%)

N/A

Utility Boilers - Medium Sulfur
Content
Flue Gas Desulfurization (Wet
Scrubber Type)






V*


V
(Hg 29%)
90%
(Hg 64%)
Hg 98%)

N/A

Utility Boilers - Very High Sulfur
Content
Flue Gas Desulfurization (Wet
Scrubber Type)






V*


V

90%


N/A

Wood Furniture Surface
Coating
MACT Standard





-V*





30%


446

Wood Furniture Surface
Coating
New CTG





¦V*





47%

462
967
22,100
Wood Furniture Surface
Coating
Add-On Controls





¦V*




67%
75%
98%
468
20,000
22,100
Wood Product Surface Coating
SCAQMD Rule 1104





¦V*





53%


881

Wood Product Surface Coating
Incineration





¦V*





86%


4,202

Wood Product Surface Coating
MACT Standard





¦V*





30%


446

Wood Pulp & Paper
Wet ESP - Wire Plate Type
V
V*
¦V
¦V







99%

55
220
550
Wood Pulp & Paper
Dry ESP-Wire Plate Type
V
V*
¦V
•V







98%

40
110
250
A-56

-------
PECHAN	September 2005
APPENDIX B: CONTROL MEASURE SUMMARY LIST - BY
POLLUTANT
Document No. 05.09.009/9010.463
Report

-------
PECHAN
September 2005
[This page intentionally left blank.]
Document No. 05.09.009/9010.463	Report

-------
Appendix B Control Measure Summary List by Source Category (1999 Baseline) - Sorted alphabetically by Pollutant and Source Category
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Cattle Feedlots
Chemical Additives to Waste







V*



50%


228

Hog Operations
Chemical Additives to Waste







V*



50%


73

Poultry Operations
Chemical Additives to Waste







V*



75%


1,014

Agricultural Burning
Seasonal Ban (Ozone Season Daily)




V*






100%


N/A

Ammonia - Natural Gas - Fired
Reformers - Small Sources
Oxygen Trim + Water Injection




¦V*






65%


680

Ammonia - Natural Gas - Fired
Reformers - Small Sources
Low NOx Burner




-V*






50%


820

Ammonia - Natural Gas - Fired
Reformers - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

2,900
3,870
3,870
Ammonia - Natural Gas - Fired
Reformers - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,230
2,230
2,860
Ammonia - Natural Gas - Fired
Reformers - Small Sources
Low NOx Burner (LNB) + Flue Gas
Recirculation (FGR)




-V*






60%

2,470
2,560
2,560
Ammonia Products; Feedstock
Desulfurization - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
Asphaltic Cone; Rotary Dryer;
Conv Plant - Small Sources
Low NOx Burner




¦V*






50%


2,200

B-1

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
By-Product Coke
Manufacturing; Oven
Underfiring
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



60%


1,640

Cement Kilns
Biosolid Injection




¦V*






23%


310

Cement Manufacturing - Dry
Low NOx Burner




¦V*






25%

300
440
620
Cement Manufacturing - Dry
Mid-Kiln Firing




-V*






25%

-460
55
730
Cement Manufacturing - Dry
Selective Catalytic Reduction (SCR)




¦V*


X



80%


3,370

Cement Manufacturing - Dry
Selective Non-Catalytic Reduction
(SNCR) Ammonia Based




¦V*


X



50%


850

Cement Manufacturing - Dry
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



50%


770

Cement Manufacturing - Wet
Low NOx Burner




¦V*






25%

300
440
620
Cement Manufacturing - Wet
Mid-Kiln Firing




¦V*






25%

-460
55
730
Cement Manufacturing - Wet -
Large Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%


2,880

Cement Manufacturing - Wet -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%


2,880

B-2

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Ceramic Clay Manufacturing;
Drying - Small Sources
Low NOx Burner




-V*






50%


2,200

Coal Cleaning-Thrml Dryer;
Fluidized Bed - Small Sources
Low NOx Burner




¦V*






50%


1,460

Coal-fired Plants with
Production Capacities>100MW
Combustion Optimization




¦V*






20%


-25

Combustion Turbines - Jet
Fuel - Small Sources
Selective Catalytic Reduction (SCR)
+ Water Injection




-V*






90%


2,300

Combustion Turbines - Jet
Fuel - Small Sources
Water Injection




¦V*






68%


1,290

Combustion Turbines - Natural
Gas - Large Sources
Dry Low NOx Combustors




¦V*






50%

100
100
140
Combustion Turbines - Natural
Gas - Small Sources
Water Injection




¦V*






76%


1,510

Combustion Turbines - Natural
Gas - Small Sources
Selective Catalytic Reduction (SCR)
+ Steam Injection




¦V*


X



95%

2,010
2,010
8,960
Combustion Turbines - Natural
Gas - Small Sources
Selective Catalytic Reduction (SCR)
+ Low NOx Burner (LNB)




¦V*


X



94%

2,570
2,570
19,120
Combustion Turbines - Natural
Gas - Small Sources
Dry Low NOx Combustors




¦V*






84%

490
490
540
Combustion Turbines - Natural
Gas - Small Sources
Steam Injection




¦V*






80%


1,040

B-3

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Combustion Turbines - Natural
Gas - Small Sources
Selective Catalytic Reduction (SCR)
+ Water Injection




-V*






95%


2,730

Combustion Turbines - Oil -
Small Sources
Selective Catalytic Reduction (SCR)
+ Water Injection




¦V*






90%


2,300

Combustion Turbines - Oil -
Small Sources
Water Injection




¦V*






68%


1,290

Commercial/Institutional -
Natural Gas
Water Heaters + LNB Space Heaters




-V*






7%


1,230

Commercial/Institutional -
Natural Gas
Water Heater Replacement




¦V*






7%


N/A

Commercial/Institutional
Incinerators
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



45%


1,130

Conv Coating of Prod; Acid
Cleaning Bath - Small Sources
Low NOx Burner




¦V*






50%


2,200

Diesel Locomotives
Selective Catalytic Reduction (SCR)




¦V*






72%


1,400

Fiberglass Manufacture; Textile-
Type; Recuperative Furnaces
Low NOx Burner




¦V*






40%


1,690

Fluid Catalytic Cracking Units -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






55%

1,430
3,190
3,190
Fuel Fired Equipment -
Process Heaters
Low Nox Burner + Flue Gas
Recirculation




¦V*






50%


570

B-4

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Fuel Fired Equipment;
Furnaces; Natural Gas
Low NOx Burner




-V*






50%


570

Glass Manufacturing -
Containers
Selective Catalytic Reduction (SCR)




¦V*


X



75%


2,200

Glass Manufacturing -
Containers
Electric Boost




¦V*






10%


7,150

Glass Manufacturing -
Containers
Cullet Preheat




-V*






25%


940

Glass Manufacturing -
Containers
Low NOx Burner




¦V*






40%


1,690

Glass Manufacturing -
Containers
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


1,770

Glass Manufacturing -
Containers
OXY-Firing




¦V*






85%


4,590

Glass Manufacturing - Flat
Low NOx Burner




¦V*






40%


700

Glass Manufacturing - Flat
OXY-Firing




¦V*






85%


1,900

Glass Manufacturing - Flat
Electric Boost




¦V*






10%


2,320

Glass Manufacturing - Flat -
Large Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


740

B-5

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Glass Manufacturing - Flat -
Large Sources
Selective Catalytic Reduction (SCR)




-V*


X



75%


710

Glass Manufacturing - Flat -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


710

Glass Manufacturing - Flat -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


740

Glass Manufacturing - Pressed
OXY-Firing




-V*






85%


3,900

Glass Manufacturing - Pressed
Selective Catalytic Reduction (SCR)




¦V*


X



75%


2,530

Glass Manufacturing - Pressed
Low NOx Burner




¦V*






40%


1,500

Glass Manufacturing - Pressed
Cullet Preheat




¦V*






25%


810

Glass Manufacturing - Pressed
Electric Boost




¦V*






10%


8,760

Glass Manufacturing - Pressed
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


1,640

Highway Vehicles - Gasoline
Engine
Low Reid Vapor Pressure (RVP)
Limit in Ozone Season




¦V
-V*


V

0.1%
5.5%
11.1%
125
1,548
25,671
Highway Vehicles - Heavy Duty
and Diesel-Fueled Vehicles
Heavy Duty Engine and Vehicle
Standards and Highway Diesel Fuel
Sulfur Controls
V
V


¦V*

V

V


76%


10,561

B-6

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Highway Vehicles - Heavy Duty
and Diesel-Fueled Vehicles
Heavy Duty Engine and Vehicle
Standards and Highway Diesel Fuel
Sulfur Controls
V
V


¦V*
¦V
V

V


19%


9,301

Highway Vehicles - Heavy Duty
and Diesel-Fueled Vehicles
Heavy Duty Engine and Vehicle
Standards and Highway Diesel Fuel
Sulfur Controls
V
V


-V*
¦V
V

V


44%


10,561

Highway Vehicles - Heavy Duty
and Diesel-Fueled Vehicles
Heavy Duty Engine and Vehicle
Standards and Highway Diesel Fuel
Sulfur Controls
V
V


¦V*
¦V
-V

-V


61%


10,561

Highway Vehicles - Heavy Duty
Diesel Engines
Voluntary Diesel Retrofit Program:
Selective Catalytic Reduction
V
V


¦V*
¦V
V

V


19.26%


50,442

Highway Vehicles - Light Duty
and Gasoline-Fueled Vehicles
Tier 2 Motor Vehicle Emissions and
Gasoline Sulfur Controls
V
V


¦V*

V

V

28%
34%
40%

6,297

Highway Vehicles - Light Duty
and Gasoline-Fueled Vehicles
Tier 2 Motor Vehicle Emissions and
Gasoline Sulfur Controls
V
V


¦V*
¦V
-V

-V

74%
83%
92%

6,297

Highway Vehicles - Light Duty
and Gasoline-Fueled Vehicles
Tier 2 Motor Vehicle Emissions and
Gasoline Sulfur Controls
V
V


-V*
V
V

V

52%
64.5%
77%

6,297

Highway Vehicles - Light Duty
and Gasoline-Fueled Vehicles
Tier 2 Motor Vehicle Emissions and
Gasoline Sulfur Controls
V
V


¦V*
V
V

V

43%
54.5%
66%

6,297

Highway Vehicles - Light Duty
Gasoline Engines
High Enhanced Inspection and
Maintenance (l/M) Program




¦V*
V


-V

0.4%
6.5%
13.4%
3,900
7,949
218,369
IC Engines - Gas
L-E (Low Speed)




¦V*






87%


176

IC Engines - Gas - Small
Sources
Selective Catalytic Reduction (SCR)




¦V*






90%


2,769

B-7

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
IC Engines - Gas, Diesel,
LPG - Small Sources
Ignition Retard




-V*






25%


770

IC Engines - Gas, Diesel,
LPG - Small Sources
Selective Catalytic Reduction (SCR)




¦V*






80%


2,340

ICI Boilers - Coal/Cyclone -
Large Sources
Coal Reburn




¦V*






50%


300

ICI Boilers - Coal/Cyclone -
Small Sources
Natural Gas Reburn (NGR)




-V*






55%


1,570

ICI Boilers - Coal/Cyclone -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



35%


840

ICI Boilers - Coal/Cyclone -
Small Sources
Coal Reburn




¦V*






50%


1,570

ICI Boilers - Coal/Cyclone -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*






80%


820

ICI Boilers - Coal/FBC - Large
Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



40%


670

ICI Boilers - Coal/FBC - Small
Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



75%


900

ICI Boilers - Coal/Stoker -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


817

ICI Boilers - Coal/Stoker -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%

873
1,015
1,015
B-8

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
ICI Boilers - Coal/Wall - Large
Sources
Low NOx Burner




-V*






50%


1,090

ICI Boilers - Coal/Wall - Large
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


840

ICI Boilers - Coal/Wall - Large
Sources
Selective Catalytic Reduction (SCR)




¦V*


X



70%


1,070

ICI Boilers - Coal/Wall - Small
Sources
Low NOx Burner




-V*






50%


1,460

ICI Boilers - Coal/Wall - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%

400
1,040
1,040
ICI Boilers - Coal/Wall - Small
Sources
Selective Catalytic Reduction (SCR)




¦V*






70%


1,260

ICI Boilers - Coke - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%

400
1,040
1,040
ICI Boilers - Coke - Small
Sources
Selective Catalytic Reduction (SCR)




¦V*


X



70%


1,260

ICI Boilers - Coke - Small
Sources
Low NOx Burner




¦V*






50%


1,460

ICI Boilers - Distillate Oil -
Large Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%


1,890

ICI Boilers - Distillate Oil -
Small Sources
Low NOx Burner




¦V*






50%


1,180

B-9

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
ICI Boilers - Distillate Oil -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




-V*






60%

1,090
2,490
2,490
ICI Boilers - Distillate Oil -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

3,470
4,640
4,640
ICI Boilers - Distillate Oil -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,780
2,780
3,570
ICI Boilers - Liquid Waste
Selective Catalytic Reduction (SCR)




-V*


X



80%

1,480
1,480
1,910
ICI Boilers - Liquid Waste -
Small Sources
Low NOx Burner




¦V*






50%


400

ICI Boilers - Liquid Waste -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

1,120
1,120
1,080
ICI Boilers - Liquid Waste -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

1,940
2,580
2,580
ICI Boilers - LPG - Small
Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,780
2,780
3,570
ICI Boilers - LPG - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

3,470
4,640
4,640
ICI Boilers - LPG - Small
Sources
Low NOx Burner




¦V*






50%


1,180

ICI Boilers - LPG - Small
Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

1,090
2,490
2,490
B-10

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
ICI Boilers - MSW/Stoker-
Small Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




-V*


X



55%


1,690

ICI Boilers - Natural Gas -
Large Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%


1,570

ICI Boilers - Natural Gas -
Small Sources
Oxygen Trim + Water Injection




¦V*






65%


680

ICI Boilers - Natural Gas -
Small Sources
Selective Catalytic Reduction (SCR)




-V*


X



80%

2,230
2,230
2,860
ICI Boilers - Natural Gas -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

2,900
3,870
3,870
ICI Boilers - Natural Gas -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
ICI Boilers - Natural Gas -
Small Sources
Low NOx Burner




¦V*






50%


820

ICI Boilers - Process Gas -
Small Sources
Low NOx Burner




¦V*






50%


820

ICI Boilers - Process Gas -
Small Sources
Oxygen Trim + Water Injection




¦V*






65%


680

ICI Boilers - Process Gas -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,230
2,230
2,860
ICI Boilers - Process Gas -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
B-11

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
ICI Boilers - Residual Oil -
Large Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



50%


1,050

ICI Boilers - Residual Oil -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

1,480
1,480
1,910
ICI Boilers - Residual Oil -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

1,120
1,120
1,080
ICI Boilers - Residual Oil -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



50%

1,940
2,580
2,580
ICI Boilers - Residual Oil -
Small Sources
Low NOx Burner




¦V*






50%


400

ICI Boilers -
Wood/Bark/Stoker - Large
Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



55%


1,190

ICI Boilers -
Wood/Bark/Stoker - Small
Sources
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



55%


1,440

Industrial Coal Combustion
RACT to 50 tpy (LNB)




¦V*






21%


1,350

Industrial Coal Combustion
RACT to 25 tpy (LNB)




¦V*






21%


1,350

Industrial Incinerators
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



45%


1,130

Industrial Natural Gas
Combustion
RACT to 50 tpy (LNB)




¦V*






31%


770

B-12

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Industrial Natural Gas
Combustion
RACT to 25 tpy (LNB)




-V*






31%


770

Industrial Oil Combustion
RACT to 50 tpy (LNB)




¦V*






36%


1,180

Industrial Oil Combustion
RACT to 25 tpy (LNB)




¦V*






36%


1,180

In-Proc; Process Gas; Coke
Oven/Blast Ovens
Low NOx Burner + Flue Gas
Recirculation




-V*






55%

1,430
3,190
3,190
In-Process Fuel Use -
Bituminous Coal - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



40%


1,260

In-Process Fuel Use; Natural
Gas - Small Sources
Low NOx Burner




¦V*






50%


2,200

In-Process Fuel Use; Residual
Oil - Small Sources
Low NOx Burner




¦V*






37%


2,520

In-Process; Bituminous Coal;
Cement Kilns
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



50%


770

In-Process; Bituminous Coal;
Lime Kilns
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



50%


770

In-Process; Process Gas;
Coke Oven Gas
Low NOx Burner




¦V*






50%


2,200

Internal Combustion Engines -
Gas
L-E (Medium Speed)




¦V*






87%


380

B-13

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Internal Combustion Engines -
Gas - Large Sources
Air/Fuel + Ignition Retard




-V*






30%

150
460
460
Internal Combustion Engines -
Gas - Large Sources
Air/Fuel Ratio Adjustment




¦V*






20%


380

Internal Combustion Engines -
Gas - Large Sources
Ignition Retard




¦V*






20%


550

Internal Combustion Engines -
Gas - Small Sources
Air/Fuel + Ignition Retard




-V*






30%

270
1,440
1,440
Internal Combustion Engines -
Gas - Small Sources
Air/Fuel Ratio Adjustment




¦V*






20%


1,570

Internal Combustion Engines -
Gas - Small Sources
Ignition Retard




¦V*






20%


1,020

Internal Combustion Engines -
Oil - Small Sources
Ignition Retard




¦V*






25%


770

Internal Combustion Engines -
Oil - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%


2,340

Iron & Steel Mills - Annealing
Low NOx Burner (LNB) + SCR




¦V*


X



80%

1,320
1,720
1,720
Iron & Steel Mills - Annealing
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


1,640

Iron & Steel Mills - Annealing
Low NOx Burner




¦V*






50%


570

B-14

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Iron & Steel Mills - Annealing
Low NOx Burner + Flue Gas
Recirculation




-V*






60%

250
750
750
Iron & Steel Mills - Annealing -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



85%


3,830

Iron & Steel Mills - Annealing -
Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



90%

3,720
4,080
4,080
Iron & Steel Mills - Galvanizing
Low NOx Burner




-V*






50%


490

Iron & Steel Mills - Galvanizing
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

190
580
580
Iron & Steel Mills - Reheating
Low NOx Burner + Flue Gas
Recirculation




¦V*






77%

150
380
380
Iron & Steel Mills - Reheating
Low NOx Burner




¦V*






66%


300

Iron & Steel Mills - Reheating
Low Excess Air (LEA)




¦V*






13%


1,320

Iron Production; Blast
Furnaces; Blast Heating Stoves
Low NOx Burner + Flue Gas
Recirculation




¦V*






77%


380

Lime Kilns
Selective Non-Catalytic Reduction
(SNCR) Urea Based




¦V*


X



50%


770

Lime Kilns
Selective Catalytic Reduction (SCR)




¦V*


X



80%


3,370

B-15

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Lime Kilns
Selective Non-Catalytic Reduction
(SNCR) Ammonia Based




-V*


X



50%


850

Lime Kilns
Mid-Kiln Firing




¦V*






30%


460

Lime Kilns
Low NOx Burner




¦V*






30%


560

Medical Waste Incinerators
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



45%


4,510

Municipal Waste Combustors
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



45%


1,130

Natural Gas Production;
Compressors - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



20%


1,651

Nitric Acid Manufacturing -
Small Sources
Extended Absorption




¦V*






95%


480

Nitric Acid Manufacturing -
Small Sources
Non-Selective Catalytic Reduction
(NSCR)




¦V*


X



98%

510
550
710
Nitric Acid Manufacturing -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



97%


590

Off-Highway Diesel Vehicles
Final Compression-Ignition (C-l)
Engine Standards
V
V


-V*
¦V


V

65%
72%
79%

N/A

Off-Highway Diesel Vehicles
Final Compression-Ignition (C-l)
Engine Standards
V
V


¦V*



V

21%
30%
59%

N/A

B-16

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Off-Highway Diesel Vehicles
Final Compression-Ignition (C-l)
Engine Standards
V
V


¦V*
¦V


V

34%
45.5%
57%

N/A

Off-Highway Diesel Vehicles
Final Compression-Ignition (C-l)
Engine Standards
V
V


-V*
¦V


V

49%
62%
75%

N/A

Off-Highway Gasoline Vehicles
Large Spark-Ignition (S-l) Engine
Standards
V
V


¦V*
¦V


V

-26%
35.5%
77%

N/A

Off-Highway Gasoline Vehicles
Large Spark-Ignition (S-l) Engine
Standards
V
V


¦V*
V


V

-26%
33.5%
93%

N/A

Off-Highway Gasoline Vehicles
Large Spark-Ignition (S-l) Engine
Standards
V
V


¦V*
V


V

-32%
33.5%
91%

N/A

Off-Highway Gasoline Vehicles
Large Spark-Ignition (S-l) Engine
Standards
V
V


¦V*
V


-V

-31%
29%
95%

N/A

Open Burning
Episodic Ban (Daily Only)




¦V*






100%


N/A

Plastics Prod-Specific; (ABS) -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






55%

1,430
3,190
3,190
Process Heaters - Distillate
Oil - Small Sources
Ultra Low NOx Burner




¦V*






74%


2,140

Process Heaters - Distillate
Oil - Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



92%

9,120
9,120
15,350
Process Heaters - Distillate
Oil - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


9,230

B-17

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Process Heaters - Distillate
Oil - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



60%


3,180

Process Heaters - Distillate
Oil - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






48%

4,250
4,250
19,540
Process Heaters - Distillate
Oil - Small Sources
Low NOx Burner - Selective Non-
Catalytic Reduction (SNCR)




¦V*


X



78%

3,620
3,620
3,830
Process Heaters - Distillate
Oil - Small Sources
Low NOx Burner




-V*






45%


3,470

Process Heaters - LPG - Small
Sources
Low NOx Burner (LNB) + SNCR




¦V*


X



78%

3,620
3,620
3,830
Process Heaters - LPG - Small
Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


3,180

Process Heaters - LPG - Small
Sources
Ultra Low NOx Burner




¦V*






74%


2,140

Process Heaters - LPG - Small
Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



92%

9,120
9,120
15,350
Process Heaters - LPG - Small
Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






48%

4,250
4,250
19,540
Process Heaters - LPG - Small
Sources
Low NOx Burner




¦V*






45%


3,470

Process Heaters - LPG - Small
Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


9,230

B-18

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Process Heaters - Natural
Gas - Small Sources
Ultra Low NOx Burner




-V*






75%


1,500

Process Heaters - Natural
Gas - Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



88%

11,560
11,560
27,910
Process Heaters - Natural
Gas - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


2,850

Process Heaters - Natural
Gas - Small Sources
Low NOx Burner + Flue Gas
Recirculation




-V*






55%

3,190
3,190
15,580
Process Heaters - Natural
Gas - Small Sources
Low NOx Burner




¦V*






50%


2,200

Process Heaters - Natural
Gas - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


12,040

Process Heaters - Natural
Gas - Small Sources
Low NOx Burner (LNB) + SNCR




¦V*


X



80%

3,520
3,520
6,600
Process Heaters - Other Fuel -
Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



91%

5,420
5,420
7,680
Process Heaters - Other Fuel -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


5,350

Process Heaters - Other Fuel -
Small Sources
Low NOx Burner (LNB) + SNCR




¦V*


X



75%

2,230
2,300
2,860
Process Heaters - Other Fuel -
Small Sources
Ultra Low NOx Burner




¦V*






73%


1,290

B-19

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Process Heaters - Other Fuel -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




-V*


X



60%


1,930

Process Heaters - Other Fuel -
Small Sources
Low NOx Burner




¦V*






37%


2,520

Process Heaters - Other Fuel -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






34%


3,490

Process Heaters - Process
Gas - Small Sources
Low NOx Burner




-V*






50%


2,200

Process Heaters - Process
Gas - Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




¦V*


X



88%

11,560
11,560
27,910
Process Heaters - Process
Gas - Small Sources
Low NOx Burner (LNB) +Selective
Reduction SNCR




¦V*


X



80%

3,520
3,520
6,600
Process Heaters - Process
Gas - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


12,040

Process Heaters - Process
Gas - Small Sources
Ultra Low NOx Burner




¦V*






75%


1,500

Process Heaters - Process
Gas - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


2,850

Process Heaters - Process
Gas - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






55%

1,430
3,190
3,190
Process Heaters - Residual
Oil - Small Sources
Ultra Low NOx Burner




¦V*






73%


1,290

B-20

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Process Heaters - Residual
Oil - Small Sources
Low NOx Burner + Flue Gas
Recirculation




-V*






34%


3,490

Process Heaters - Residual
Oil - Small Sources
Low NOx Burner




¦V*






37%


2,520

Process Heaters - Residual
Oil - Small Sources
Low NOx Burner (LNB) + SCR




¦V*


X



75%

2,230
2,300
2,860
Process Heaters - Residual
Oil - Small Sources
Low NOx Burner (LNB) + Selective
Catalytic Reduction (SCR)




-V*


X



91%

5,420
5,420
7,680
Process Heaters - Residual
Oil - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



60%


1,930

Process Heaters - Residual
Oil - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



75%


5,350

Residential Natural Gas
Water Heater Replacement




¦V*






7%


N/A

Residential Natural Gas
Water Heater + LNB Space Heaters




¦V*






7%


1,230

Rich-Burn Stationary
Reciprocating Internal
Combustion Engines
Non-selective catalytic reduction




¦V*






90%


342

Rich-Burn Stationary
Reciprocating Internal
Combustion Engines
Non-selective catalytic reduction




¦V*






90%


342

Rich-Burn Stationary
Reciprocating Internal
Combustion Engines (RICE)
Non-selective catalytic reduction
(NSCR)




¦V*
V


V


90%


342

B-21

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Sand/Gravel; Dryer - Small
Sources
Low NOx Burner + Flue Gas
Recirculation




-V*






55%

1,430
3,190
3,190
Secondary Aluminum
Production; Smelting Furnaces
Low NOx Burner




¦V*






50%


570

Solid Waste Disposal;
Government; Other
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



45%


1,130

Space Heaters - Distillate Oil -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




-V*






60%

1,090
2,490
2,490
Space Heaters - Distillate Oil -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,780
2,780
3,570
Space Heaters - Distillate Oil -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

3,470
4,640
4,640
Space Heaters - Distillate Oil -
Small Sources
Low NOx Burner




¦V*






50%


1,180

Space Heaters - Natural Gas -
Small Sources
Low NOx Burner




¦V*






50%


820

Space Heaters - Natural Gas -
Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

2,900
3,870
3,870
Space Heaters - Natural Gas -
Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,230
2,230
2,860
Space Heaters - Natural Gas -
Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
B-22

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Space Heaters - Natural Gas -
Small Sources
Oxygen Trim + Water Injection




-V*






65%


680

Starch Manufacturing;
Combined Operation - Small
Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






55%

1,430
3,190
3,190
Steel Foundries; Heat Treating
Low NOx Burner




¦V*






50%


570

Steel Production; Soaking Pits
Low NOx Burner + Flue Gas
Recirculation




-V*






60%

250
750
750
Sulfate Pulping - Recovery
Furnaces - Small Sources
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%

2,900
3,870
3,870
Sulfate Pulping - Recovery
Furnaces - Small Sources
Low NOx Burner




¦V*






50%


820

Sulfate Pulping - Recovery
Furnaces - Small Sources
Oxygen Trim + Water Injection




¦V*






65%


680

Sulfate Pulping - Recovery
Furnaces - Small Sources
Selective Catalytic Reduction (SCR)




¦V*


X



80%

2,230
2,230
2,860
Sulfate Pulping - Recovery
Furnaces - Small Sources
Low NOx Burner + Flue Gas
Recirculation




¦V*






60%

2,470
2,560
2,560
Surface Coat Oper; Coating
Oven Htr; Nat Gas - Small
Sources
Low NOx Burner




¦V*


X



50%


2,200

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
separated Overfire Air (LNC2)




¦V*






48%


N/A

B-23

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
cross-Coupled Overfire Air (LNC1)




-V*






33%


N/A

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
separated Overfire Air (LNC2)




¦V*






38%


N/A

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
Close-Coupled and Separated
Overfire Air (LNC3)




¦V*






53%


N/A

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
cross-Coupled Overfire Air (LNC1)




-V*






43%


N/A

Utility Boiler - Coal/Tangential
Low Nox Coal-and-Air Nozzles with
Close-Coupled and Separated
Overfire Air (LNC3)




¦V*






58%


N/A

Utility Boiler - Coal/Tangential
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



35%


N/A

Utility Boiler - Coal/Tangential
Selective Catalytic Reduction (SCR)




¦V*


X

V

90%
(Hg 95%)


N/A

Utility Boiler - Coal/Tangential
Natural Gas Reburn (NGR)




¦V*






50%


N/A

Utility Boiler - Coal/Wall
Low Nox Burner without Overfire Air




¦V*






41


N/A

Utility Boiler - Coal/Wall
Low Nox Burner with Overfire Air




¦V*






56%


N/A

Utility Boiler - Coal/Wall
Low Nox Burner with Overfire Air




¦V*






55%


N/A

B-24

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Utility Boiler - Coal/Wall
Low Nox Burner without Overfire Air




-V*






40%


N/A

Utility Boiler - Coal/Wall
Selective Catalytic Reduction (SCR)




¦V*


X



90%


N/A

Utility Boiler - Coal/Wall
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



35%


N/A

Utility Boiler - Coal/Wall
Natural Gas Reburn (NGR)




-V*






50%


N/A

Utility Boiler - Cyclone
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



35%


N/A

Utility Boiler - Cyclone
Natural Gas Reburn (NGR)




¦V*






50%


N/A

Utility Boiler - Cyclone
Selective Catalytic Reduction (SCR)




¦V*


X



80%


N/A

Utility Boiler - Oil-
Gas/Tangential
Natural Gas Reburn (NGR)




¦V*






50%


N/A

Utility Boiler - Oil-
Gas/Tangential
Selective Catalytic Reduction (SCR)




¦V*


X



80%


N/A

Utility Boiler - Oil-
Gas/Tangential
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%


N/A

Utility Boiler - Oil-Gas/Wall
Selective Non-Catalytic Reduction
(SNCR)




¦V*


X



50%


N/A

B-25

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Utility Boiler - Oil-Gas/Wall
Natural Gas Reburn (NGR)




-V*






50%


N/A

Utility Boiler - Oil-Gas/Wall
Selective Catalytic Reduction (SCR)




V*


X



80%


N/A

Agricultural Burning
Bale Stack/Propane Burning
-V
¦V*
-V
¦V






49%
63%
63%

2,591

Agricultural Tilling
Soil Conservation Plans
¦V
¦V
¦V
V







11.7%


138

Asphalt Manufacture
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Asphalt Manufacture
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Asphalt Manufacture
Paper/Nonwoven Filters - Cartridge
Collector Type
¦V
-V*
¦V
V







99%

85
147
256
Asphalt Manufacture
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Asphalt Manufacture
Fabric Filter (Pulse Jet Type)
-V
¦V*
-V
V







99%

42
117
266
Asphalt Manufacture
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Beef Cattle Feedlots
Watering
¦V
¦V*
¦V
V







50%


307

B-26

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Chemical Manufacture
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Chemical Manufacture
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Chemical Manufacture
Wet ESP - Wire Plate Type
-V
¦V*
-V
¦V







99%

55
220
550
Commercial Institutional
Boilers - Coal
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Commercial Institutional
Boilers - Coal
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Commercial Institutional
Boilers - Coal
Dry ESP-Wire Plate Type
-V
¦V*
-V
¦V







98%

40
110
250
Commercial Institutional
Boilers - Coal
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Commercial Institutional
Boilers - Coal
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V
V







99%

42
117
266
Commercial Institutional
Boilers - Liquid Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Commercial Institutional
Boilers - Liquid Waste
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Commercial Institutional
Boilers - LPG
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

B-27

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Commercial Institutional
Boilers - LPG
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Commercial Institutional
Boilers - Natural Gas
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Commercial Institutional
Boilers - Natural Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Commercial Institutional
Boilers - Oil
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Commercial Institutional
Boilers - Oil
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Commercial Institutional
Boilers - Oil
Dry ESP-Wire Plate Type
V
V*
V
V







98%

40
110
250
Commercial Institutional
Boilers - Process Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Commercial Institutional
Boilers - Process Gas
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Commercial Institutional
Boilers - Solid Waste
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Commercial Institutional
Boilers - Solid Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Commercial Institutional
Boilers - Wood
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

B-28

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Commercial Institutional
Boilers - Wood
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Commercial Institutional
Boilers - Wood/Bark
Fabric Filter (Pulse Jet Type)
¦V
-V*
¦V
¦V







99%

42
117
266
Commercial Institutional
Boilers - Wood/Bark
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
¦V







99%

53
148
337
Commercial Institutional
Boilers - Wood/Bark
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
Construction Activities
Dust Control Plan
¦V
¦V*
¦V
V







62.5%


3,600

Conveyorized Charbroilers
Catalytic Oxidizer
¦V*
¦V*



V




80%
83%
90%

2,966

Electric Generation - Coke
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Electric Generation - Coke
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Electric Generation - Bagasse
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Electric Generation - Bagasse
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Electric Generation - Coal
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

B-29

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Electric Generation - Coal
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Liquid
Waste
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Liquid
Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - LPG
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - LPG
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Natural
Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Natural
Gas
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Oil
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Electric Generation - Oil
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Solid
Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Electric Generation - Solid
Waste
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

B-30

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Electric Generation - Wood
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Electric Generation - Wood
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Fabricated Metal Products -
Abrasive Blasting
Paper/Nonwoven Filters - Cartridge
Collector Type
-V
¦V*
-V
¦V







99%

85
142
256
Fabricated Metal Products -
Welding
Paper/Nonwoven Filters - Cartridge
Collector Type
¦V
¦V*
¦V








99%

85
142
256
Ferrous Metals Processing -
Coke
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Ferrous Metals Processing -
Coke
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Ferrous Metals Processing -
Coke
Fabric Filter (Mech. Shaker Type)
¦V
-V*
¦V
¦V







99%

37
126
303
Ferrous Metals Processing -
Coke
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
V







99%

53
148
337
Ferrous Metals Processing -
Coke
Venturi Scrubber
-V
¦V*
-V
V







93%

75
751
2,100
Ferrous Metals Processing -
Ferroalloy Production
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Ferrous Metals Processing -
Ferroalloy Production
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

B-31

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Ferrous Metals Processing -
Ferroalloy Production
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
V







99%

53
148
337
Ferrous Metals Processing -
Ferroalloy Production
Dry ESP-Wire Plate Type
¦V
-V*
¦V
V







98%

40
110
250
Ferrous Metals Processing -
Ferroalloy Production
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
V







99%

37
126
303
Ferrous Metals Processing -
Gray Iron Foundries
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Ferrous Metals Processing -
Gray Iron Foundries
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Ferrous Metals Processing -
Gray Iron Foundries
Impingement-Plate Scrubber
-V
¦V*
-V
V







64%

46
431
1,200
Ferrous Metals Processing -
Gray Iron Foundries
Venturi Scrubber
¦V
-V*
¦V
V







94%

76
751
2,100
Ferrous Metals Processing -
Gray Iron Foundries
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Ferrous Metals Processing -
Gray Iron Foundries
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
V







99%

53
148
337
Ferrous Metals Processing -
Gray Iron Foundries
Dry ESP-Wire Plate Type
¦V
-V*
¦V
V







98%

40
110
250
Ferrous Metals Processing -
Iron & Steel Production
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

B-32

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Ferrous Metals Processing -
Iron & Steel Production
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Ferrous Metals Processing -
Iron and Steel Production
Venturi Scrubber
¦V
-V*
¦V
¦V







73%

76
751
2,100
Ferrous Metals Processing -
Iron and Steel Production
Fabric Filter (Pulse Jet Type)
-V
¦V*
-V
¦V







99%

42
117
266
Ferrous Metals Processing -
Iron and Steel Production
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Ferrous Metals Processing -
Iron and Steel Production
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
Ferrous Metals Processing -
Iron and Steel Production
Wet ESP - Wire Plate Type
-V
¦V*
-V
V







99%

55
220
550
Ferrous Metals Processing -
Iron and Steel Production
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Ferrous Metals Processing -
Other
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Ferrous Metals Processing -
Other
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Ferrous Metals Processing -
Steel Foundries
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Ferrous Metals Processing -
Steel Foundries
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

B-33

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Ferrous Metals Processing -
Steel Foundries
Venturi Scrubber
¦V
¦V*
¦V
V







73%

76
751
2,100
Ferrous Metals Processing -
Steel Foundries
Fabric Filter (Mech. Shaker Type)
¦V
-V*
¦V
¦V







99%

37
126
303
Ferrous Metals Processing -
Steel Foundries
Wet ESP - Wire Plate Type
-V
¦V*
-V
V







99%

55
220
550
Ferrous Metals Processing -
Steel Foundries
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
Ferrous Metals Processing -
Steel Foundries
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
V







99%

53
148
337
Ferrous Metals Processing -
Steel Foundries
Fabric Filter (Pulse Jet Type)
-V
¦V*
-V
V







99%

42
117
266
Grain Milling
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Grain Milling
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V
V







99%

42
117
266
Grain Milling
Paper/Nonwoven Filters - Cartridge
Collector Type
-V
¦V*
-V
V







99%

85
142
256
Highway Vehicles - Gasoline
Engine
RFG and High Enhanced l/M
Program




V
-V*


V

-9.1%
11.4%
31.9%
484
16,164

Highway Vehicles - Heavy Duty
Diesel Engines
Voluntary Diesel Retrofit Program:
Diesel Particulate Filter
¦V
¦V*




V

V


61.99%


727,689

B-34

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Highway Vehicles - Heavy Duty
Diesel Engines
Voluntary Diesel Retrofit Program:
Biodiesel Fuel
¦V
¦V*



V


V


7%


209,913

Highway Vehicles - Heavy Duty
Diesel Engines
Voluntary Diesel Retrofit Program:
Diesel Oxidation Catalyst
¦V
-V*



V
V

V


24.01%


167,640

Industrial Boilers - Coal
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Industrial Boilers - Coal
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Industrial Boilers - Coal
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V
•V







99%

42
117
266
Industrial Boilers - Coal
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
¦V







99%

53
148
337
Industrial Boilers - Coal
Venturi Scrubber
¦V
-V*
¦V
¦V







82%

76
751
2,100
Industrial Boilers - Coal
Dry ESP-Wire Plate Type
¦V
¦V*
¦V








98%

40
110
250
Industrial Boilers - Coke
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Industrial Boilers - Coke
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Industrial Boilers - Liquid Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

B-35

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Industrial Boilers - Liquid Waste
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Industrial Boilers - Liquid Waste
Dry ESP-Wire Plate Type
V
V*
¦V
¦V







98%

40
110
250
Industrial Boilers - LPG
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Industrial Boilers - LPG
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Industrial Boilers - Natural Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Industrial Boilers - Natural Gas
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Industrial Boilers - Oil
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

Industrial Boilers - Oil
Increased Monitoring Frequency
(IMF) of PM Controls
V*
V*









6.5%


620

Industrial Boilers - Oil
Venturi Scrubber
V
V*
-V
¦V







92%

76
751
2,100
Industrial Boilers - Oil
Dry ESP-Wire Plate Type
V
V*
¦V
¦V







98%

40
110
250
Industrial Boilers - Process Gas
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
V*
V*









7.7%


5,200

B-36

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Industrial Boilers - Process Gas
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Industrial Boilers - Solid Waste
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Industrial Boilers - Solid Waste
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Industrial Boilers - Wood
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Industrial Boilers - Wood
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Industrial Boilers - Wood
Venturi Scrubber
-V
¦V*
-V
¦V







93%

76
751
2,100
Industrial Boilers - Wood
Dry ESP-Wire Plate Type
¦V
-V*
¦V
¦V







98%

40
110
250
Industrial Boilers - Wood
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
¦V







99%

53
148
337
Industrial Boilers - Wood
Fabric Filter (Pulse Jet Type)
-V
¦V*
-V








99%

42
117
266
Mineral Products - Cement
Manufacture
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Mineral Products - Cement
Manufacture
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

B-37

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Mineral Products - Cement
Manufacture
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Mineral Products - Cement
Manufacture
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Mineral Products - Cement
Manufacture
Paper/Nonwoven Filters - Cartridge
Collector Type
-V
¦V*
-V
V







99%

85
142
256
Mineral Products - Cement
Manufacture
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
Mineral Products - Cement
Manufacture
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V
V







99%

42
117
266
Mineral Products - Coal
Cleaning
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Mineral Products - Coal
Cleaning
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Mineral Products - Coal
Cleaning
Venturi Scrubber
¦V
¦V*
¦V
V







99%

76
751
2,100
Mineral Products - Coal
Cleaning
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
V







99%

37
126
303
Mineral Products - Coal
Cleaning
Fabric Filter (Pulse Jet Type)
¦V
-V*
¦V
V







99%

42
117
266
Mineral Products - Coal
Cleaning
Paper/Nonwoven Filters - Cartridge
Collector Type
¦V
¦V*

V







99%

85
142
256
B-38

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Mineral Products - Coal
Cleaning
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
V







99%

53
148
337
Mineral Products - Other
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Mineral Products - Other
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Mineral Products - Other
Paper/Nonwoven Filters - Cartridge
Collector Type
¦V
¦V*
¦V
V







99%

85
145
256
Mineral Products - Other
Wet ESP - Wire Plate Type
¦V
¦V*
¦V
V







99%

55
220
550
Mineral Products - Other
Dry ESP-Wire Plate Type
-V
¦V*
-V
V







98%

40
110
250
Mineral Products - Other
Fabric Filter (Pulse Jet Type)
¦V
-V*
¦V
V







99%

42
117
266
Mineral Products - Other
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
V







99%

53
148
337
Mineral Products - Other
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
V







99%

37
126
303
Mineral Products - Stone
Quarrying & Processing
Increased Monitoring Frequency
(IMF) of PM Controls
-V*
-V*









6.5%


620

Mineral Products - Stone
Quarrying & Processing
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

B-39

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Mineral Products - Stone
Quarrying and Processing
Fabric Filter (Pulse Jet Type)
¦V
¦V*
¦V
V







99%

42
117
266
Mineral Products - Stone
Quarrying and Processing
Dry ESP-Wire Plate Type
¦V
-V*
¦V
V







98%

40
110
250
Mineral Products - Stone
Quarrying and Processing
Venturi Scrubber
-V
¦V*
-V
V







95%

76
751
2,100
Mineral Products - Stone
Quarrying and Processing
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
V







99%

53
148
337
Mineral Products - Stone
Quarrying and Processing
Paper/Nonwoven Filters - Cartridge
Collector Type
¦V
¦V*
¦V
V







99%

85
142
256
Mineral Products - Stone
Quarrying and Processing
Wet ESP-Wire Plate Type
-V
¦V*
-V
V







99%

55
220
550
Mineral Products - Stone
Quarrying and Processing
Fabric Filter (Mech. Shaker Type)
¦V
-V*
¦V
V







99%

37
126
303
Municipal Waste Incineration
Dry ESP-Wire Plate Type
¦V
¦V*
¦V








98%

40
110
250
Non-Ferrous Metals
Processing - Aluminum
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Non-Ferrous Metals
Processing - Aluminum
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Non-Ferrous Metals
Processing - Aluminum
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
B-40

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Non-Ferrous Metals
Processing - Aluminum
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
V







99%

53
148
337
Non-Ferrous Metals
Processing - Aluminum
Wet ESP - Wire Plate Type
¦V
-V*
¦V
V







99%

55
220
550
Non-Ferrous Metals
Processing - Aluminum
Dry ESP-Wire Plate Type
-V
¦V*
-V
V







98%

40
110
250
Non-Ferrous Metals
Processing - Copper
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Non-Ferrous Metals
Processing - Copper
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Non-Ferrous Metals
Processing - Copper
Fabric Filter (Mech. Shaker Type)
-V
¦V*
-V
V







99%

37
126
303
Non-Ferrous Metals
Processing - Copper
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Non-Ferrous Metals
Processing - Copper
Dry ESP-Wire Plate Type
¦V
¦V*
¦V
V







98%

40
110
250
Non-Ferrous Metals
Processing - Copper
Wet ESP-Wire Plate Type
-V
¦V*
-V
V







99%

55
220
550
Non-Ferrous Metals
Processing - Lead
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
-V*
-V*









7.7%


5,200

Non-Ferrous Metals
Processing - Lead
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

B-41

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Non-Ferrous Metals
Processing - Lead
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*
¦V
V







99%

53
148
337
Non-Ferrous Metals
Processing - Lead
Wet ESP - Wire Plate Type
¦V
-V*
¦V
V







99%

55
220
550
Non-Ferrous Metals
Processing - Lead
Dry ESP-Wire Plate Type
-V
¦V*
-V
V







98%

40
110
250
Non-Ferrous Metals
Processing - Lead
Fabric Filter (Mech. Shaker Type)
¦V
¦V*
¦V
V







99%

37
126
303
Non-Ferrous Metals
Processing - Other
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

Non-Ferrous Metals
Processing - Other
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Non-Ferrous Metals
Processing - Other
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
-V*
¦V
V







99%

53
148
337
Non-Ferrous Metals
Processing - Other
Wet ESP - Wire Plate Type
¦V
¦V*
¦V
V







99%

55
220
550
Non-Ferrous Metals
Processing - Other
Dry ESP-Wire Plate Type
-V
¦V*
-V
V







98%

40
110
250
Non-Ferrous Metals
Processing - Other
Fabric Filter (Mech. Shaker Type)
¦V
-V*

V







99%

37
1,260
303
Non-Ferrous Metals
Processing - Zinc
Increased Monitoring Frequency
(IMF) of PM Controls
¦V*
¦V*









6.5%


620

B-42

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Non-Ferrous Metals
Processing - Zinc
CEM Upgrade and Increased
Monitoring Frequency of PM
Controls
¦V*
¦V*









7.7%


5,200

Non-Ferrous Metals
Processing - Zinc
Fabric Filter (Mech. Shaker Type)
¦V
-V*
¦V
V







99%

37
126
303
Non-Ferrous Metals
Processing - Zinc
Dry ESP-Wire Plate Type
-V
¦V*
-V
V







98%

40
110
250
Non-Ferrous Metals
Processing - Zinc
Wet ESP - Wire Plate Type
¦V
¦V*
¦V
V







99%

55
220
550
Non-Ferrous Metals
Processing - Zinc
Fabric Filter (Reverse-Air Cleaned
Type)
¦V
¦V*

V







99%

53
148
337
Nonroad Diesel Engines
Heavy Duty Retrofit Program
-V
¦V*
-V
V







1%


9,500

Paved Roads
Vacuum Sweeping
¦V
-V*
V
V







50.5%


485

Prescribed Burning
Increase Fuel Moisture
¦V
¦V*
V
V







50%


2,617

Residential Wood Combustion
Education and Advisory Program
-V
¦V*
-V
V







50%


1,320

Residential Wood Stoves
NSPS compliant Wood Stoves
-V*
-V*









98%


2,000

Unpaved Roads
Chemical Stabilization
¦V
¦V*









37.5%


2,753

B-43

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
>l I ut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficient
from base I
Typical
/
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Unpaved Roads
Hot Asphalt Paving
¦V
¦V*
¦V
V







67.5%


537

Utility Boilers - Coal
Fabric Filter (Mech. Shaker Type)
¦V
-V*
¦V
¦V





V

99.5%

37
126
303
Utility Boilers - Coal
Dry ESP-Wire Plate Type
-V
¦V*
-V
V





V
(Hg 3%)
98%
(Hg 20%)
Hg 36%)
40
110
250
Utility Boilers - Coal
Fabric Filter
¦V
¦V*
V
V





V

95%
(Hg 80%)


N/A

Utility Boilers - Coal
Fabric Filter (Pulse Jet Type)
¦V
¦V*
V
V





V

99%

42
117
266
Utility Boilers - Coal
Fabric Filter (Reverse-Air Cleaned
Type)
-V
¦V*
-V
V





V

99%

53
148
337
Utility Boilers - Gas/Oil
Fabric Filter
¦V
-V*
¦V
¦V





V

95%


N/A

Wood Pulp & Paper
Wet ESP-Wire Plate Type
¦V
¦V*

V







99%

55
220
550
Wood Pulp & Paper
Dry ESP-Wire Plate Type
-V
¦V*
-V
V







98%

40
110
250
Bituminous/Subbituminous Coal
Flue Gas Desulfurization






V*




90%


N/A

Bituminous/Subbituminous Coal
Flue Gas Desulfurization






V*




90%


N/A

B-44

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
ed
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Bituminous/Subbituminous
Coal (Industrial Boilers)
Wet Flue Gas Desulfurization






¦V*




90%

1,027
1,536
1,980
Bituminous/Subbituminous
Coal (Industrial Boilers)
Spray Dryer Abosrber






-V*




90%

804
1,341
1,973
Bituminous/Subbituminous
Coal (Industrial Boilers)
In-duct Dry Sorbent Injection






¦V*




40%

1,111
1,526
2,107
By-Product Coke Manufacturing
Vacuum Carbonate Plus Sulfur
Recovery Plant






¦V*




82%


N/A

Distillate Oil (Industrial Boiler)
Wet Flue Gas Desulfurization






¦V*




90%

2,295
3,489
4,524
Inorganic Chemical
Manufacture
Flue Gas Desulfurization






¦V*




90%


N/A

In-process Fuel Use -
Bituminous Coal
Flue Gas Desulfurization






-V*




90%


N/A

Lignite (Industrial Boiler)
Wet Flue Gas Desulfurization






¦V*




90%

1,027
1,536
1,980
Lignite (Industrial Boiler)
Spray Dryer Abosrber






¦V*




90%

804
1,341
1,973
Lignite (Industrial Boiler)
In-duct Dry Sorbent Injection






-V*




40%

1,111
1,526
2,107
Lignite (Industrial Boilers)
Flue Gas Desulfurization






¦V*




90%


N/A

B-45

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
ed
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Mineral Products Industry
Flue Gas Desulfurization






¦V*




90%


N/A

Petroleum Industry
Flue Gas Desulfurization (FGD)






-V*




90%


N/A

Primary Lead Smelters -
Sintering
Dual Absorption






¦V*




99%


N/A

Primary Metals Industry
Flue Gas Desulfurization






¦V*




90%


N/A

Primary Zinc Smelters -
Sintering
Dual Absorption






¦V*




99%


N/A

Process Heaters (Oil and Gas
Production)
Flue Gas Desulfurization






¦V*




90%


N/A

Pulp and Paper Industry
(Sulfate Pulping)
Flue Gas Desulfurization






-V*




90%


N/A

Residual Oil
(Commercial/Institutional
Boilers)
Wet Flue Gas Desulfurization






¦V*




90%

2,295
3,489
4,524
Residual Oil
(Commercial/Institutional
Boilers)
Flue Gas Desulfurization






¦V*




90%


N/A

Residual Oil (Industrial Boilers
Flue Gas Desulfurization






-V*




90%


N/A

Secondary Metal Production
Flue Gas Desulfurization






¦V*




90%


N/A

B-46

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
ed
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Steam Generating Unit-Coal/Oil
Flue Gas Desulfurization






¦V*




90%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing + Flue Gas
Desulfurization






-V*




99.7%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing






¦V*




97.8%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing + Flue Gas
Desulfurization






¦V*




99.8%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing + Flue Gas
Desulfurization






¦V*




99.8%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing






¦V*




97.1%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Amine Scrubbing






-V*




98.4%


N/A

Sulfur Recovery Plants -
Elemental Sulfur
Flue Gas Desulfurization






¦V*




90%


N/A

Sulfur Recovery Plants - Sulfur
Removal
Flue Gas Desulfurization






¦V*




90%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%) +
Flue Gas Desulfurization






-V*




85%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%)






¦V*




75%


N/A

B-47

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
ed
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficient
from base I
Typical
/
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%) +
Flue Gas Desulfurization






¦V*




75%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%)






-V*




95%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%)






¦V*




85%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%) +
Flue Gas Desulfurization






¦V*




95%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Flue Gas Desulfurization






¦V*




90%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%)






¦V*




90%


N/A

Sulfuric Acid Plants - Contact
Absorbers
Increase Absorption Efficiency from
Existing to NSPS Level (99.7%) +
Flue Gas Desulfurization






-V*




90%


N/A

Utility Boilers - Coal-Fired
Fuel Switching - High-Sulfur Coal to
Low-Sulfur Coal
V
V




¦V*




60%

113
140
167
Utility Boilers - Coal-Fired
Coal Washing
V
V




¦V*


V

40%

70
320
563
Utility Boilers - Coal-Fired
Repowering to IGCC




V

-V*


V

99%


N/A

Utility Boilers - High Sulfur
Content
Flue Gas Desulfurization (Wet
Scrubber Type)






¦V*


V
(Hg 29%)
90%
(Hg 64%)
Hg 98%)

N/A

B-48

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficient
from base I
Typical
/
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Utility Boilers - Medium Sulfur
Content
Flue Gas Desulfurization (Wet
Scrubber Type)






V*


V
(Hg 29%)
90%
(Hg 64%)
Hg 98%)

N/A

Utility Boilers - Very High Sulfur
Content
Flue Gas Desulfurization (Wet
Scrubber Type)






V*


V

90%


N/A

Adhesives - Industrial
SCAQMD Rule 1168





¦V*





73%


2,202

Aircraft Surface Coating
MACT Standard





-V*





60%


165

Architectural Coatings
OTC AIM Coating Rule





¦V*





55%


6,628

Architectural Coatings
South Coast Phase I





¦V*





34%

3,300
1,443
4,600
Architectural Coatings
South Coast Phase III





¦V*





73%


10,059

Architectural Coatings
AIM Coating Federal Rule





¦V*





20%


228

Architectural Coatings
South Coast Phase II





¦V*





47%


4,017

AREA
OTC Mobile Equipment Repair and
Refinishing Rule





¦V*





61%


2,534

AREA
OTC Solvent Cleaning Rule





¦V*





66%


1,400

B-49

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
VOC
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
Drimary po
Typical
il Cost
ss
I utant)
High
AREA
OTC Consumer Products Rule





-V*





39.2%


1,032

AREA
OTC Mobile Equipment Repair and
Refinishing Rule





¦V*





61%


2,534

AREA
OTC Mobile Equipment Repair and
Refinishing Rule





¦V*





61%


2,534

AREA
OTC Consumer Products Rule





-V*





39.2%


1,032

AREA
OTC Mobile Equipment Repair and
Refinishing Rule





¦V*





61%


2,534

Automobile Refinishing
Federal Rule





¦V*





37%


118

Automobile Refinishing
California FIP Rule (VOC content &
TE)





¦V*





89%


7,200

Automobile Refinishing
CARB BARCT Limits





¦V*





47%


750

Bakery Products
Incineration >100,000 lbs bread





¦V*





39.9%


1,470

Commercial Adhesives
CARB Long-Term Limits





¦V*





85%


2,880

Commercial Adhesives
CARB Mid-Term Limits





¦V*





55%


2,192

B-50

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
VOC
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Commercial Adhesives
Federal Consumer Solvents Rule





-V*





25%


232

Consumer Solvents
CARB Long-Term Limits





¦V*





85%


2,880

Consumer Solvents
CARB Mid-Term Limits





¦V*





55%


2,192

Consumer Solvents
Federal Consumer Solvents Rule





-V*





25%


232

Cutback Asphalt
Switch to Emulsified Asphalts





¦V*





100%


15

Electrical/Electronic Coating
SCAQMD Rule





¦V*





70%


5,976

Electrical/Electronic Coating
MACT Standard





¦V*





36%


5,000

Fabric Printing, Coating and
Dyeing
Permanent Total Enclosure (PTE)





¦V*








N/A

Flexographic Printing
Permanent Total Enclosure (PTE)





¦V*





95


9,947

Graphic Arts
Use of Low or No VOC Materials





¦V*





65%

3,500
4,150
4,800
Highway Vehicles - Gasoline
Engine
Federal Reformulated Gasoline
(RFG)




X
¦V*


V

0%
7.65%
15.3%
2,498
25,093

B-51

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Highway Vehicles - Light Duty
Gasoline Engines
Basic Inspection and Maintenance
Program
V
V


V
¦V*
V
V
V





N/A

Industrial Maintenance Coating
South Coast Phase III





¦V*





73%


10,059

Industrial Maintenance Coating
AIM Coating Federal Rule





¦V*





20%


228

Industrial Maintenance Coating
South Coast Phase II





-V*





47%


4,017

Industrial Maintenance Coating
South Coast Phase 1





¦V*





34%

3,300
1,443
4,600
Machinery, Equipment, and
Railroad Coating
SCAQMD Limits





¦V*





55.2%


2,027

Marine Surface Coating
(Shipbuilding)
Add-On Controls





¦V*





90%


8,937

Marine Surface Coating
(Shipbuilding)
MACT Standard





¦V*





24%


2,090

Metal Can Surface Coating
Operations
Permanent Total Enclosure (PTE)





¦V*





95


8,469

Metal Coil & Can Coating
Incineration





¦V*





90%


8,937

Metal Coil & Can Coating
BAAQMD Rule 11 Amended





¦V*





42%


2,007

B-52

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Metal Coil & Can Coating
MACT Standard





-V*





36%


1,000

Metal Furniture Surface
Coating Operations
Permanent Total Enclosure (PTE)





¦V*





95


19,321

Metal Furniture, Appliances,
Parts
MACT Standard





¦V*





36%


1,000

Metal Furniture, Appliances,
Parts
SCAQMD Limits





-V*





55.2%


2,027

Miscellaneous Metal Products
Coatings
MACT Standard





¦V*





36%


1,000

Motor Vehicle Coating
Incineration





¦V*





90%


8,937

Motor Vehicle Coating
MACT Standard





¦V*





36%


118

Municipal Solid Waste Landfill
Gas Collection (SCAQMD/BAAQMD)





¦V*





70%


700

Nonroad Gasoline Engines
Federal Reformulated Gasoline





¦V*





1.4%

440
4,854
9,250
Off-Highway Vehicles: All
Terrain Vehicles (ATVs)
Recreational Gasoline ATV
Standards
V
V


¦V
-V*


V

27%
40%
73%

N/A

Off-Highway Vehicles: All
Terrain Vehicles (ATVs)
Recreational Gasoline ATV
Standards
V
V



¦V*


V

33%
64%
95%

N/A

B-53

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
Pc
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
primary po
Typical
il Cost
ss
I utant)
High
Off-Highway Vehicles: All
Terrain Vehicles (ATVs)
Recreational Gasoline ATV
Standards
V
V


¦V
¦V*


¦V

14%
24%
34%

N/A

Off-Highway Vehicles: All
Terrain Vehicles (ATVs)
Recreational Gasoline ATV
Standards
V
V


¦V
-V*


¦V

33%
65%
97%

N/A

Off-Highway Vehicles:
Motorcycles
Recreational Gasoline Off-Highway
Motorcycle Standards
V
V


¦V
¦V*


¦V

10%
25%
40%

N/A

Off-Highway Vehicles:
Motorcycles
Recreational Gasoline Off-Highway
Motorcycle Standards
V
V


¦V
¦V*


¦V

5%
12.5%
20%

N/A

Off-Highway Vehicles:
Motorcycles
Recreational Gasoline Off-Highway
Motorcycle Standards
V
V



¦V*




12%
31%
50%

N/A

Off-Highway Vehicles:
Motorcycles
Recreational Gasoline Off-Highway
Motorcycle Standards
V
V


¦V
¦V*


¦V

12%
32%
52%

N/A

Off-Highway Vehicles:
Snowmobiles
Recreational Gasoline Snowmobile
Standards
V
V


X
¦V*


¦V


45%


N/A

Off-Highway Vehicles:
Snowmobiles
Recreational Gasoline Snowmobile
Standards
V
V


X
¦V*





69%


N/A

Off-Highway Vehicles:
Snowmobiles
Recreational Gasoline Snowmobile
Standards
V
V


X
¦V*


¦V


62%


N/A

Off-Highway Vehicles:
Snowmobiles
Recreational Gasoline Snowmobile
Standards
V
V


X
¦V*


¦V


20%


N/A

Oil and Natural Gas Production
Equipment and Maintenance





¦V*





37%


317

B-54

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
VOC
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
Drimary po
Typical
il Cost
ss
I utant)
High
Open Top Degreasing
Title III MACT Standard





-V*





31%


-69

Open Top Degreasing
SCAQMD 1122 (VOC content limit)





¦V*





76%


1,248

Open Top Degreasing
Airtight Degreasing System





¦V*





98%


9,789

Paper and other Web Coating
Operations
Permanent Total Enclosure (PTE)





-V*





95


1,503

Paper Surface Coating
Incineration





¦V*





78%


4,776

Pesticide Application
Reformulation - FIP Rule





¦V*





20%


9,300

Portable Gasoline Containers
OTC Portable Gas Container Rule





¦V*





33%


581

Product and Packaging
Rotogravure and Screen
Printing
Permanent Total Enclosure (PTE)





¦V*





95


12,770

Publication Rotogravure
Printing
Permanent Total Enclosure (PTE)





¦V*





95


2,422

Rubber and Plastics
Manufacturing
SCAQMD - Low VOC





¦V*





60%


1,020

Stage II Service Stations
Low Pressure/Vacuum Relief Valve





¦V*





91.6%

930
1,080
1,230
B-55

-------
Source Category
Control Measure Name
V = po
PM2.5
Mutant
PM10
PC
reduc
EC
)llut
io, X
oc
ant(
= pollut
NOx
s) Af
ant inc
voc
fecti
rease,
S02
sd
* = ma
NH3
jor pol
CO
utant
Hg
E
(%
Low
Control
Efficienc
from base I
Typical
y
ne)
High
Averac
Eff
($/ton
Low
je Annuc
ectivene
Drimary po
Typical
il Cost
ss
I utant)
High
Stage II Service Stations -
Underground Tanks
Low Pressure/Vacuum Relief Valve





-V*





73%

930
1,080
1,230
Traffic Markings
South Coast Phase III





¦V*





73%


1,059

Traffic Markings
AIM Coating Federal Rule





¦V*





20%


228

Traffic Markings
South Coast Phase 1





-V*





34%

8,600
1,443
12,800
Traffic Markings
South Coast Phase II





¦V*





47%


4,017

Wood Furniture Surface
Coating
Add-On Controls





¦V*




67%
75%
98%
468
20,000
22,100
Wood Furniture Surface
Coating
New CTG





¦V*





47%

462
967
22,100
Wood Furniture Surface
Coating
MACT Standard





¦V*





30%


446

Wood Product Surface Coating
Incineration





¦V*





86%


4,202

Wood Product Surface Coating
SCAQMD Rule 1104





¦V*





53%


881

Wood Product Surface Coating
MACT Standard





¦V*





30%


446

B-56

-------
PECHAN	September 2005
APPENDIX C: SCC / SIC / NAICS CROSSWALK
Document No. 05.09.009/9010.463
Report

-------
PECHAN
September 2005
[This page intentionally left blank.]
Document No. 05.09.009/9010.463	Report

-------
Appendix C SCC-SIC-NAICS Crosswalk



see
SCC Name
SIC

NAICS
30500313
Mineral Products, Brick Manufacture, Curing and Firing:
Coal-fired Tunnel Kilns
3251
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500314
Mineral Products, Brick Manufacture, Curing and Firing: Gas-
fired Periodic Kilns
3255
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500398
Mineral Products, Brick Manufacture, Other Not Classified
3251
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500402
Mineral Products, Calcium Carbide, Coke Dryer
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30500406
Mineral Products, Calcium Carbide, Circular Charging:
Conveyor
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30500499
Mineral Products, Calcium Carbide, Other Not Classified
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30500606
Mineral Products, Cement Manufacturing (Dry Process),
Kilns
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500609
Mineral Products, Cement Manufacturing (Dry Process),
Primary Crushing
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500610
Mineral Products, Cement Manufacturing (Dry Process),
Secondary Crushing
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500611
Mineral Products, Cement Manufacturing (Dry Process),
Screening
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500612
Mineral Products, Cement Manufacturing (Dry Process),
Raw Material Transfer
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500613
Mineral Products, Cement Manufacturing (Dry Process),
Raw Material Grinding and Drying
3295
Stone, Clay, and Glass Products
212 Mining; Mining (except Oil and Gas)
30500614
Mineral Products, Cement Manufacturing (Dry Process),
Clinker Cooler
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
C-1

-------
SCC SCC Name
SIC
NAICS
30500616
Mineral Products, Cement Manufacturing (Dry Process),
Clinker Transfer
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500617
Mineral Products, Cement Manufacturing (Dry Process),
Clinker Grinding
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500618
Mineral Products, Cement Manufacturing (Dry Process),
Cement Silos
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500619
Mineral Products, Cement Manufacturing (Dry Process),
Cement Load Out
3295
Stone, Clay, and Glass Products
212 Mining; Mining (except Oil and Gas)
30500706
Mineral Products, Cement Manufacturing (Wet Process),
Kilns
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
10100202
Electric Generation, Bituminous/Subbituminous Coal,
Pulverized Coal: Dry Bottom (Bituminous Coal)
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
10100203
Electric Generation, Bituminous/Subbituminous Coal,
Cyclone Furnace (Bituminous Coal)
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
10100212
Electric Generation, Bituminous/Subbituminous Coal,
Pulverized Coal: Dry Bottom (Tangential) (Bituminous Coal)
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
10100401
Electric Generation, Residual Oil, Grade 6 Oil: Normal Firing
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
10100404
Electric Generation, Residual Oil, Grade 6 Oil: Tangential
Firing
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
10100501
Electric Generation, Distillate Oil, Grades 1 and 2 Oil
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
10100504
Electric Generation, Distillate Oil, Grade 4 Oil: Normal Firing
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
10100505
Electric Generation, Distillate Oil, Grade 4 Oil: Tangential
Firing
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
C-2

-------
SCC SCC Name
SIC
NAICS
10100601
Electric Generation, Natural Gas, Boilers > 100 Million
Btu/hr except Tangential
4911
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10100602
Electric Generation, Natural Gas, Boilers < 100 Million
Btu/hr except Tangential
3674
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
10100604
Electric Generation, Natural Gas, Tangentially Fired Units
4911
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10100701
Electric Generation, Process Gas, Boilers > 100 Million
Btu/hr
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
10100702
Electric Generation, Process Gas, Boilers < 100 Million
Btu/hr
4952
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10100902
Electric Generation, Wood/Bark Waste, Wood/Bark Fired
Boiler
9223
Justice, Public Order, and Safety
922
Public Administration; Justice, Public
Order, and Safety Activities
10100903
Electric Generation, Wood/Bark Waste, Wood-fired Boiler
2511
Furniture and Fixtures
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
10101201
Electric Generation, Solid Waste, Specify Waste Material in
Comments
2511
Furniture and Fixtures
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
10200201
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal:
Wet Bottom
4961
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10200202
Industrial, Bituminous/Subbituminous Coal, Pulverized Coal:
Dry Bottom
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
10200203
Industrial, Bituminous/Subbituminous Coal, Cyclone Furnace
3679
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
10200204
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
2511
Furniture and Fixtures
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
10200205
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
8221
Educational Services
611
Educational Services; Educational
Services
C-3

-------
SCC SCC Name
SIC
NAICS
10200206
Industrial, Bituminous/Subbituminous Coal, Underfeed
Stoker
4961
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10200210
Industrial, Bituminous/Subbituminous Coal, Overfeed Stoker
2435
Lumber and Wood Products
321
Wood Product Manufacturing; Wood
Product Manufacturing
10200224
Industrial, Bituminous/Subbituminous Coal, Spreader Stoker
(Subbituminous Coal)
2511
Furniture and Fixtures
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
10200401
Industrial, Residual Oil, Grade 6 Oil
4961
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10200404
Industrial, Residual Oil, Grade 5 Oil
2731
Printing and Publishing
512
Information; Motion Picture and Sound
Recording Industries
10200501
Industrial, Distillate Oil, Grades 1 and 2 Oil
4911
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10200504
Industrial, Distillate Oil, Grade 4 Oil
4911
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10200505
Industrial, Distillate Oil, Cogeneration
3519
Industrial Machinery and Equipment
333
Primary Metal Manufacturing; Machinery
Manufacturing
10200601
Industrial, Natural Gas, > 100 Million Btu/hr
4961
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10200602
Industrial, Natural Gas, 10-100 Million Btu/hr
4961
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10200603
Industrial, Natural Gas, < 10 Million Btu/hr
3732
Transportation Equipment
811
Other Services (except Public
Administration); Repair and Maintenance
10200701
Industrial, Process Gas, Petroleum Refinery Gas
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
10200707
Industrial, Process Gas, Coke Oven Gas
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
C-4

-------
SCC SCC Name
SIC
NAICS
10200901
Industrial, Wood/Bark Waste, Bark-fired Boiler (> 50,000 Lb
Steam)
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
10200902
Industrial, Wood/Bark Waste, Wood/Bark-fired Boiler (>
50,000 Lb Steam)
2421
Lumber and Wood Products
321
Wood Product Manufacturing; Wood
Product Manufacturing
10200903
Industrial, Wood/Bark Waste, Wood-fired Boiler (> 50,000
Lb Steam)
2511
Furniture and Fixtures
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
10200906
Industrial, Wood/Bark Waste, Wood-fired Boiler (< 50,000
Lb Steam)
2511
Furniture and Fixtures
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
10201002
Industrial, Liquified Petroleum Gas (LPG), Propane
2657
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
10201201
Industrial, Solid Waste, Specify Waste Material in Comments
4953
Electric, Gas, and Sanitary Services
562 Administrative and Support and Waste
Management and Remediation
Services; Waste Management and
10201301
Industrial, Liquid Waste, Specify Waste Material in
Comments
2512
Furniture and Fixtures
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
10201302
Industrial, Liquid Waste, Waste Oil
2048
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
10300206
Commercial/Institutional, Bituminous/Subbituminous Coal,
Pulverized Coal: Dry Bottom (Bituminous Coal)
9711
National Security and Intl. Affairs
928
Public Administration; National Security
and International Affairs
10300207
Commercial/Institutional, Bituminous/Subbituminous Coal,
Overfeed Stoker (Bituminous Coal)
8221
Educational Services
611
Educational Services; Educational
Services
10300208
Commercial/Institutional, Bituminous/Subbituminous Coal,
Underfeed Stoker (Bituminous Coal)
9223
Justice, Public Order, and Safety
922
Public Administration; Justice, Public
Order, and Safety Activities
10300209
Commercial/Institutional, Bituminous/Subbituminous Coal,
Spreader Stoker (Bituminous Coal)
4961
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
10300211
Commercial/Institutional, Bituminous/Subbituminous Coal,
Overfeed Stoker **
9223
Justice, Public Order, and Safety
922
Public Administration; Justice, Public
Order, and Safety Activities
C-5

-------
SCC SCC Name
SIC
NAICS
10300217
Commercial/Institutional, Bituminous/Subbituminous Coal,
Atmospheric Fluidized Bed Combustion: Bubbling Bed
(Bituminous Coal)
8221
Educational Services
611 Educational Services; Educational
Services
10300401
Commercial/Institutional, Residual Oil, Grade 6 Oil
4961
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
10300402
Commercial/Institutional, Residual Oil, 10-100 Million Btu/hr
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
10300404
Commercial/Institutional, Residual Oil, Grade 5 Oil
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
10300501
Commercial/Institutional, Distillate Oil, Grades 1 and 2 Oil
8733
Engineering & Management Services
541 Professional, Scientific, and Technical
Services; Professional, Scientific, and
Technical Services
10300502
Commercial/Institutional, Distillate Oil, 10-100 Million Btu/hr
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
10300503
Commercial/Institutional, Distillate Oil, < 10 Million Btu/hr**
3273
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
10300601
Commercial/Institutional, Natural Gas, > 100 Million Btu/hr
8221
Educational Services
611 Educational Services; Educational
Services
10300602
Commercial/Institutional, Natural Gas, 10-100 Million Btu/hr
8733
Engineering & Management Services
541 Professional, Scientific, and Technical
Services; Professional, Scientific, and
Technical Services
10300603
Commercial/Institutional, Natural Gas, < 10 Million Btu/hr
7216
Personal Services
812 Other Services (except Public
Administration); Personal and Laundry
Services
10300701
Commercial/Institutional, Process Gas, POTW Digester Gas-
fired Boiler
4952
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
10300799
Commercial/Institutional, Process Gas, Other Not Classified
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
10300903
Commercial/Institutional, Wood/Bark Waste, Wood-fired
Boiler
2511
Furniture and Fixtures
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
C-6

-------
SCC SCC Name
SIC
NAICS
10301002
Commercial/Institutional, Liquified Petroleum Gas (LPG),
Propane
3585
Industrial Machinery and Equipment
333 Primary Metal Manufacturing; Machinery
Manufacturing
10500105
Space Heaters, Industrial, Distillate Oil
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
10500106
Space Heaters, Industrial, Natural Gas
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
10500110
Space Heaters, Industrial, Liquified Petroleum Gas (LPG)
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
10500210
Space Heaters, Commercial/Institutional, Liquified
Petroleum Gas (LPG)
4931
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
20100101
Electric Generation, Distillate Oil (Diesel), Turbine
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
20100102
Electric Generation, Distillate Oil (Diesel), Reciprocating
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
20100201
Electric Generation, Natural Gas, Turbine
4931
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
20100702
Electric Generation, Process Gas, Reciprocating
4953
Electric, Gas, and Sanitary Services
562 Administrative and Support and Waste
Management and Remediation
Services; Waste Management and
20200104
Industrial, Distillate Oil (Diesel), Reciprocating: Cogeneration
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
20200202
Industrial, Natural Gas, Reciprocating
4922
Electric, Gas, and Sanitary Services
486 Air Transportation; Pipeline
Transportation
20200401
Industrial, Large Bore Engine, Diesel
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
20300101
Commercial/Institutional, Distillate Oil (Diesel), Reciprocating
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
C-7

-------
SCC SCC Name
SIC
NAICS
20300102
Commercial/Institutional, Distillate Oil (Diesel), Turbine
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
30100101
Chemical Manufacturing, Adipic Acid, General
2869
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30100601
Chemical Manufacturing, Charcoal Manufacturing, General
2499
Lumber and Wood Products
339 Primary Metal Manufacturing;
Miscellaneous Manufacturing
30100699
Chemical Manufacturing, Charcoal Manufacturing, Other
Not Classified
2062
Food and Kindred Products
311 Food Manufacturing; Food
Manufacturing
30100901
Chemical Manufacturing, Cleaning Chemicals, Spray Drying:
Soaps and Detergents
2844
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30100902
Chemical Manufacturing, Cleaning Chemicals, Specialty
Cleaners
2842
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30100999
Chemical Manufacturing, Cleaning Chemicals, Other Not
Classified
2841
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30101011
Chemical Manufacturing, Explosives (Trinitrotoluene), Batch
Process: Nitration Reactors Fume Recovery
2892
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30101301
Chemical Manufacturing, Nitric Acid, Absorber Tail Gas (Pre-
1970 Facilities)
2892
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30101302
Chemical Manufacturing, Nitric Acid, Absorber Tail Gas
(Post-1970 Facilities)
2892
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30101401
Chemical Manufacturing, Paint Manufacture, General Mixing
and Handling
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30101402
Chemical Manufacturing, Paint Manufacture, Pigment
Handling
2851
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30101503
Chemical Manufacturing, Varnish Manufacturing, Alkyd
2851
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
C-8

-------
SCC SCC Name
SIC
NAICS
30101599
Chemical Manufacturing, Varnish Manufacturing, Other Not
Classified
2851
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30101805
Chemical Manufacturing, Plastics Production, Phenolic
Resins
3083
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30101817
Chemical Manufacturing, Plastics Production, General
3086
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30101842
Chemical Manufacturing, Plastics Production, Melamine
Resins
3083
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30101893
Chemical Manufacturing, Plastics Production, Raw Material
Storage
2865
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30101899
Chemical Manufacturing, Plastics Production, Others Not
Specified
2865
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30102001
Chemical Manufacturing, Printing Ink Manufacture, Vehicle
Cooking: General
2891
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30102005
Chemical Manufacturing, Printing Ink Manufacture, Pigment
Mixing
2893
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30102301
Chemical Manufacturing, Sulfuric Acid (Contact Process),
Absorber/@ 99.9% Conversion
2892
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30102399
Chemical Manufacturing, Sulfuric Acid (Contact Process),
Other Not Classified
2816
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30102599
Chemical Manufacturing, Cellulosic Fiber Production, Other
Not Classified
2823
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30103202
Chemical Manufacturing, Elemental Sulfur Production, Mod.
Claus: 3 Stage w/o Control (95-96% Removal)
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30103204
Chemical Manufacturing, Elemental Sulfur Production,
Sulfur Removal Process (99.9% Removal)
4925
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
C-9

-------
SCC SCC Name
SIC
NAICS
30103311
Chemical Manufacturing, Pesticides, General
2879
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30103501
Chemical Manufacturing, Inorganic Pigments, Ti02 Sulfate
Process: Calciner
2816
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30103553
Chemical Manufacturing, Inorganic Pigments, Pigment Dryer
2816
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30103554
Chemical Manufacturing, Inorganic Pigments,
Conveying/Storage/Packing
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30103599
Chemical Manufacturing, Inorganic Pigments, Other Not
Classified
2816
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30104101
Chemical Manufacturing, Nitrocellulose, Nitration Reactor
2892
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30104104
Chemical Manufacturing, Nitrocellulose, Nitric Acid
Concentrators
2892
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30104501
Chemical Manufacturing, Organic Fertilizer, General:
Mixing/Handling
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30106099
Chemical Manufacturing, Pharmaceutical Preparations,
Other Not Classified
2834
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30107002
Chemical Manufacturing, Inorganic Chemical Manufacturing
(General), Storage/Transfer
5085
Wholesale Trade - Durable Goods
421 Wholesale Trade; Wholesale Trade,
Durable Goods
30111299
Chemical Manufacturing, Elemental Phosphorous, Other
Not Classified
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30113701
Chemical Manufacturing, Esters Production, Ethyl Acrylate
2869
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30121101
Chemical Manufacturing, Linear Alkylbenzene, Olefin
Process: General
2841
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
C-10

-------
SCC SCC Name
SIC
NAICS
30125004
Chemical Manufacturing, Methanol/Alcohol Production,
Methanol: Fugitive Emissions
3546
Industrial Machinery and Equipment
333 Primary Metal Manufacturing; Machinery
Manufacturing
30125880
Chemical Manufacturing,
Benzene/Toluene/Aromatics/Xylenes, Aromatics: Fugitive
Emissions
2841
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30182001
Chemical Manufacturing, Wastewater Treatment,
Wastewater Stripper
2841
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30182002
Chemical Manufacturing, Wastewater Treatment,
Wastewater Treatment
2865
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30188801
Chemical Manufacturing, Fugitive Emissions, Specify in
Comments Field
2891
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30190011
Chemical Manufacturing, Fuel Fired Equipment, Distillate Oil
(No. 2): Incinerators
2879
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30199998
Chemical Manufacturing, Other Not Classified, Specify in
Comments Field
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30199999
Chemical Manufacturing, Other Not Classified, Specify in
Comments Field
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30200504
Food and Agriculture, Feed and Grain Terminal Elevators,
Drying
2851
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30200510
Food and Agriculture, Feed and Grain Terminal Elevators,
Removal from Bins (Tunnel Belt)
3412
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30200604
Food and Agriculture, Feed and Grain Country Elevators,
Drying
0254
Agricultural Production - Livestock
112 Agriculture, Forestry, Fishing and
Hunting; Animal Production
30200742
Food and Agriculture, Grain Millings, Dry Corn Milling: Grain
Drying
2048
Food and Kindred Products
311 Food Manufacturing; Food
Manufacturing
30200743
Food and Agriculture, Grain Millings, Dry Corn Milling:
Precleaning/Handling
2048
Food and Kindred Products
311 Food Manufacturing; Food
Manufacturing
C-11

-------
SCC SCC Name
SIC
NAICS
30200745
Food and Agriculture, Grain Millings, Dry Corn Milling:
Degerming and Milling
0254
Agricultural Production - Livestock
112 Agriculture, Forestry, Fishing and
Hunting; Animal Production
30200788
Food and Agriculture, Grain Millings, Soybean: Flaking
2075
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30200789
Food and Agriculture, Grain Millings, Soybean: Meal Dryer
2075
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30200790
Food and Agriculture, Grain Millings, Soybean: Meal Cooler
2075
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30200791
Food and Agriculture, Grain Millings, Soybean: Bulk Loading
2075
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30200805
Food and Agriculture, Feed Manufacture, Grinding
2048
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30200899
Food and Agriculture, Feed Manufacture, Not Classified **
3264
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30200903
Food and Agriculture, Beer Production, Brew Kettle ** (use
SCC 3-02-009-07)
2082
Food and Kindred Products
312
Food Manufacturing; Beverage and
Tobacco Product Manufacturing
30201003
Food and Agriculture, Distilled Spirits, Aging** (see 3-02-
010-17)
2085
Food and Kindred Products
312
Food Manufacturing; Beverage and
Tobacco Product Manufacturing
30201201
Food and Agriculture, Fish Processing, Cookers: Fresh Fish
Scrap
2077
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30201206
Food and Agriculture, Fish Processing, Direct Fired Dryer
2077
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30201301
Food and Agriculture, Meat Smokehouses, Combined
Operations **
2011
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30201501
Food and Agriculture, Sugar Cane Refining, General
2062
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
C-12

-------
SCC SCC Name
SIC
NAICS
30201599
Food and Agriculture, Sugar Cane Refining, Other Not
Classified
2062
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30201903
Food and Agriculture, Vegetable Oil Processing, Soybean
Oil: General **
2048
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30201918
Food and Agriculture, Vegetable Oil Processing, Oil Refining
2048
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30203001
Food and Agriculture, Dairy Products, Milk: Spray Dryer
2026
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30203104
Food and Agriculture, Export Grain Elevators, Drying
5153
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
30203105
Food and Agriculture, Export Grain Elevators, Unloading
0723
Agricultural Services
311
Food Manufacturing; Food
Manufacturing
30203106
Food and Agriculture, Export Grain Elevators, Loading
0723
Agricultural Services
311
Food Manufacturing; Food
Manufacturing
30203201
Food and Agriculture, Bakeries, Bread Baking: Sponge-
Dough Process
2051
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30203202
Food and Agriculture, Bakeries, Bread Baking: Straight-
Dough Process
2051
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30203299
Food and Agriculture, Bakeries, Other Not Classified
2051
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30203801
Food and Agriculture, Animal/Poultry Rendering, General
2077
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30288801
Food and Agriculture, Fugitive Emissions, Specify in
Comments Field
2099
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
30299998
Food and Agriculture, Other Not Specified, Other Not
Classified
2048
Food and Kindred Products
311
Food Manufacturing; Food
Manufacturing
C-13

-------
SCC SCC Name
SIC
NAICS
30299999
Food and Agriculture, Other Not Specified, Other Not
Classified
2099
Food and Kindred Products
311 Food Manufacturing; Food
Manufacturing
30300101
Primary Metal Production, Aluminum Ore (Electro-
reduction), Prebaked Reduction Cell
3334
Primary Metal Industries
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
39000489
In-process Fuel Use, Residual Oil, General
2077
Food and Kindred Products
311 Food Manufacturing; Food
Manufacturing
39000499
In-process Fuel Use, Residual Oil, General
2077
Food and Kindred Products
311 Food Manufacturing; Food
Manufacturing
39000503
In-process Fuel Use, Distillate Oil, Lime Kiln
3274
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
39000589
In-process Fuel Use, Distillate Oil, General
2077
Food and Kindred Products
311 Food Manufacturing; Food
Manufacturing
39000599
In-process Fuel Use, Distillate Oil, General
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
39000699
In-process Fuel Use, Natural Gas, General
2511
Furniture and Fixtures
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
39000701
In-process Fuel Use, Process Gas, Coke Oven or Blast
Furnace
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
40400116
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 13/10/7: Withdrawal Loss (67000 Bbl Cap.) -
Float RfTnk
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400117
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 13/10/7: Withdrawal Loss (250000 Bbl
Cap.)-Float RfTnk
5172
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400153
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Vapor Control Unit Losses
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400154
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Tank Truck Vapor Leaks
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
C-14

-------
SCC SCC Name
SIC
NAICS
30903005
Fabricated Metal Products, Machining Operations, Sawing:
Specify Material in Comments
3559
Industrial Machinery and Equipment
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30904001
Fabricated Metal Products, Metal Deposition Processes,
Metallizing: Wire Atomization and Spraying
3728
Transportation Equipment
541
Professional, Scientific, and Technical
Services; Professional, Scientific, and
Technical Services
30904010
Fabricated Metal Products, Metal Deposition Processes,
Thermal Spraying of Powdered Metal
3546
Industrial Machinery and Equipment
333
Primary Metal Manufacturing; Machinery
Manufacturing
30988801
Fabricated Metal Products, Fugitive Emissions, Specify in
Comments Field
3564
Industrial Machinery and Equipment
333
Primary Metal Manufacturing; Machinery
Manufacturing
30990001
Fabricated Metal Products, Fuel Fired Equipment, Distillate
Oil (No. 2): Process Heaters
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
39000899
In-process Fuel Use, Coke, General: Coke
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
39000989
In-process Fuel Use, Wood, General
3433
Fabricated Metal Products
333
Primary Metal Manufacturing; Machinery
Manufacturing
39000999
In-process Fuel Use, Wood, General: Wood
2421
Lumber and Wood Products
321
Wood Product Manufacturing; Wood
Product Manufacturing
39001089
In-process Fuel Use, Liquified Petroleum Gas, General
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
39001099
In-process Fuel Use, Liquified Petroleum Gas, General
3411
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
39001299
In-process Fuel Use, Solid Waste, General
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
39001399
In-process Fuel Use, Liquid Waste, General
3295
Stone, Clay, and Glass Products
212 Mining; Mining (except Oil and Gas)
39999993
Miscellaneous Manufacturing Industries, Miscellaneous
Industrial Processes, Other Not Classified
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
C-15

-------
SCC SCC Name
SIC
NAICS
30501522
Mineral Products, Gypsum Manufacture, End Sawing (12 Ft.)
3275
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501603
Mineral Products, Lime Manufacture, Calcining: Vertical Kiln
3274
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501604
Mineral Products, Lime Manufacture, Calcining: Rotary Kiln
** (See SCC Codes 3-05-016-18,-19,-20,-21)
3274
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501605
Mineral Products, Lime Manufacture, Calcining: Gas-fired
Calcimatic Kiln
3274
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501613
Mineral Products, Lime Manufacture, Lime Silos
3411
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30501905
Mineral Products, Phosphate Rock, Calcining
2048
Food and Kindred Products
311 Food Manufacturing; Food
Manufacturing
30502001
Mineral Products, Stone Quarrying - Processing (See also
305320), Primary Crushing
3273
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30502002
Mineral Products, Stone Quarrying - Processing (See also
305320), Secondary Crushing/Screening
3295
Stone, Clay, and Glass Products
212 Mining; Mining (except Oil and Gas)
30502003
Mineral Products, Stone Quarrying - Processing (See also
305320), Tertiary Crushing/Screening
3273
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30502006
Mineral Products, Stone Quarrying - Processing (See also
305320), Miscellaneous Operations:
Screen/Convey/Handling
3273
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30502012
Mineral Products, Stone Quarrying - Processing (See also
305320), Drying
3273
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30502510
Mineral Products, Construction Sand and Gravel, Crushing
2823
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30504021
Mineral Products, Mining and Quarrying of Nonmetallic
Minerals, Convey/Haul Material
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
C-16

-------
SCC SCC Name
SIC
NAICS
30504030
Mineral Products, Mining and Quarrying of Nonmetallic
Minerals, Primary Crusher
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
30504031
Mineral Products, Mining and Quarrying of Nonmetallic
Minerals, Secondary Crusher
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
30510196
Mineral Products, Bulk Materials Conveyors, Chemical:
Specify in Comments
3996
Miscellaneous Manufacturing Industries
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30510202
Mineral Products, Bulk Materials Storage Bins, Cement
2891
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30300104
Primary Metal Production, Aluminum Ore (Electro-
reduction), Materials Handling
3334
Primary Metal Industries
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30300105
Primary Metal Production, Aluminum Ore (Electro-
reduction), Anode Baking Furnace
3334
Primary Metal Industries
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30300302
Primary Metal Production, By-product Coke Manufacturing,
Oven Charging
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300315
Primary Metal Production, By-product Coke Manufacturing,
Gas By-product Plant
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300615
Primary Metal Production, Ferroalloy, Open Furnace,
Ferromanganese: Blast Furnace
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30300808
Primary Metal Production, Iron Production (See 3-03-015 for
Integrated Iron & Steel MACT), Slag Crushing and Sizing
3295
Stone, Clay, and Glass Products
212 Mining; Mining (except Oil and Gas)
30300819
Primary Metal Production, Iron Production (See 3-03-015 for
Integrated Iron & Steel MACT), Sinter Process (Combined
Code includes 15,16,17,18)
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300825
Primary Metal Production, Iron Production (See 3-03-015 for
Integrated Iron & Steel MACT), Cast House
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300841
Primary Metal Production, Iron Production (See 3-03-015 for
Integrated Iron & Steel MACT), Flue Dust Unloading
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
C-17

-------
SCC SCC Name
SIC
NAICS
30300901
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Open Hearth
Furnace: Stack
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300904
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Electric Arc Furnace:
Alloy Steel (Stack)
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300908
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Electric Arc Furnace:
Carbon Steel (Stack)
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300910
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Pickling
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300912
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Grinding
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300913
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Basic Oxygen
Furnace: Open Hood-Stack
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300922
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Continuous Casting
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300931
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Hot Rolling
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300933
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Reheat Furnaces
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300934
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Heat Treating
Furnaces: Annealing
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300935
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Cold Rolling
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300936
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Coating: Tin, Zinc,
etc.
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30300999
Primary Metal Production, Steel Manufacturing (See 3-03-
015 for Integrated Iron & Steel MACT), Other Not Classified
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
C-18

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SCC SCC Name
SIC
NAICS
30301201
Primary Metal Production, Titanium, Chlorination
2816
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30390003
Primary Metal Production, Fuel Fired Equipment, Natural
Gas: Process Heaters
3334
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30390014
Primary Metal Production, Fuel Fired Equipment, Process
Gas: Incinerators
3695
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
30400102
Secondary Metal Production, Aluminum, Smelting
Furnace/Crucible
3471
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30400103
Secondary Metal Production, Aluminum, Smelting
Furnace/Reverberatory
3334
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400120
Secondary Metal Production, Aluminum, Can Manufacture
3411
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30400220
Secondary Metal Production, Copper, Charge with Copper:
Electric Arc Furnace
3331
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400299
Secondary Metal Production, Copper, Other Not Classified
3331
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400301
Secondary Metal Production, Grey Iron Foundries, Cupola
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400303
Secondary Metal Production, Grey Iron Foundries, Electric
Induction Furnace
3334
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400310
Secondary Metal Production, Grey Iron Foundries,
Inoculation
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400320
Secondary Metal Production, Grey Iron Foundries,
Pouring/Casting
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400331
Secondary Metal Production, Grey Iron Foundries, Casting
Shakeout
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
C-19

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SCC SCC Name
SIC
NAICS
30400333
Secondary Metal Production, Grey Iron Foundries, Shakeout
Machine
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400340
Secondary Metal Production, Grey Iron Foundries,
Grinding/Cleaning
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400350
Secondary Metal Production, Grey Iron Foundries, Sand
Grinding/Handling
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400351
Secondary Metal Production, Grey Iron Foundries, Core
Ovens
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400352
Secondary Metal Production, Grey Iron Foundries, Sand
Grinding/Handling
3321
Primary Metal Industries
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30400527
Secondary Metal Production, Lead Battery Manufacture,
Small Parts Casting
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
30400701
Secondary Metal Production, Steel Foundries, Electric Arc
Furnace
4011
Railroad Transportation
482 Air Transportation; Rail Transportation
30400716
Secondary Metal Production, Steel Foundries, Sand
Grinding/Handling
3559
Industrial Machinery and Equipment
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30400731
Secondary Metal Production, Steel Foundries, Core
Machines/Other
3559
Industrial Machinery and Equipment
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30405001
Secondary Metal Production, Miscellaneous Casting
Fabricating, Other Not Classified
9711
National Security and Intl. Affairs
928
Public Administration; National Security
and International Affairs
30490013
Secondary Metal Production, Fuel Fired Equipment, Natural
Gas: Incinerators
5085
Wholesale Trade - Durable Goods
421
Wholesale Trade; Wholesale Trade,
Durable Goods
30499999
Secondary Metal Production, Other Not Classified, Specify
in Comments Field
2819
Chemicals and Allied Products
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
30500102
Mineral Products, Asphalt Roofing Manufacture, Asphalt
Blowing: Coating (Use 3-05-050-10 for MACT)
2952
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
C-20

-------
SCC SCC Name
SIC
NAICS
30500111
Mineral Products, Asphalt Roofing Manufacture, Dipping
Only
2952
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30500198
Mineral Products, Asphalt Roofing Manufacture, Other Not
Classified
2952
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30500201
Mineral Products, Asphalt Concrete, Rotary Dryer:
Conventional Plant (see 3-05-002-50 -51 -52 for subtypes
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
30500202
Mineral Products, Asphalt Concrete, Hot Elevators, Screens,
Bins and Mixer
2952
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30500203
Mineral Products, Asphalt Concrete, Storage Piles
2951
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30500204
Mineral Products, Asphalt Concrete, Cold Aggregate
Handling
2951
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30500205
Mineral Products, Asphalt Concrete, Drum Dryer: Hot
Asphalt Plants (see 3-05-002-55 & -58 for subtypes)
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
30500208
Mineral Products, Asphalt Concrete, Asphalt Heater:
Distillate Oil (Use 3-05-050-22 for MACT)
2951
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30500301
Mineral Products, Brick Manufacture, Raw Material Drying
3251
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500302
Mineral Products, Brick Manufacture, Raw Material Grinding
& Screening
3297
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500311
Mineral Products, Brick Manufacture, Curing and Firing: Gas-
fired Tunnel Kilns
3255
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500312
Mineral Products, Brick Manufacture, Curing and Firing: Oil-
fired Tunnel Kilns
3297
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500714
Mineral Products, Cement Manufacturing (Wet Process),
Clinker Cooler
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
C-21

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SCC SCC Name
SIC
NAICS
30500718
Mineral Products, Cement Manufacturing (Wet Process),
Cement Silos
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500719
Mineral Products, Cement Manufacturing (Wet Process),
Cement Load Out
3241
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500799
Mineral Products, Cement Manufacturing (Wet Process),
Other Not Classified
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
30500802
Mineral Products, Ceramic Clay/Tile Manufacture,
Comminution - Crushing, Grinding, & Milling
3264
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500899
Mineral Products, Ceramic Clay/Tile Manufacture, Other Not
Classified
3264
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30500999
Mineral Products, Clay and Fly Ash Sintering, Other Not
Classified
2952
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30501001
Mineral Products, Coal Mining, Cleaning, and Material
Handling (See 305310), Fluidized Bed
1221
Coal Mining
212 Mining; Mining (except Oil and Gas)
30501010
Mineral Products, Coal Mining, Cleaning, and Material
Handling (See 305310), Crushing
3295
Stone, Clay, and Glass Products
212 Mining; Mining (except Oil and Gas)
30501101
Mineral Products, Concrete Batching, General (Non-fugitive)
3531
Industrial Machinery and Equipment
336 Primary Metal Manufacturing;
Transportation Equipment Manufacturing
30501109
Mineral Products, Concrete Batching, Mixer Loading of
Cement/Sand/Aggregate
3295
Stone, Clay, and Glass Products
212 Mining; Mining (except Oil and Gas)
30501112
Mineral Products, Concrete Batching, Mixing: Wet
2951
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30990003
Fabricated Metal Products, Fuel Fired Equipment, Natural
Gas: Process Heaters
5085
Wholesale Trade - Durable Goods
421 Wholesale Trade; Wholesale Trade,
Durable Goods
30990013
Fabricated Metal Products, Fuel Fired Equipment, Natural
Gas: Incinerators
3586
Industrial Machinery and Equipment
333 Primary Metal Manufacturing; Machinery
Manufacturing
C-22

-------
SCC SCC Name
SIC
NAICS
30999999
Fabricated Metal Products, Other Not Classified, Other Not
Classified
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
31000404
Oil and Gas Production, Process Heaters, Natural Gas
4925
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
31299999
Machinery, Miscellaneous, Miscellaneous Machinery, Other
Not Classified
9711
National Security and Intl. Affairs
928
Public Administration; National Security
and International Affairs
31401002
Transportation Equipment, Brake Shoe Debonding, Multiple
Chamber Incinerator
3714
Transportation Equipment
336
Primary Metal Manufacturing;
Transportation Equipment Manufacturing
31499999
Transportation Equipment, Other Not Classified, Other Not
Classified
3728
Transportation Equipment
541
Professional, Scientific, and Technical
Services; Professional, Scientific, and
Technical Services
32099998
Leather and Leather Products, Other Not Classified, Other
Not Classified
3143
Leather and Leather Products
316
Food Manufacturing; Leather and Allied
Product Manufacturing
32099999
Leather and Leather Products, Other Not Classified, Other
Not Classified
3143
Leather and Leather Products
316
Food Manufacturing; Leather and Allied
Product Manufacturing
33000103
Textile Products, Miscellaneous, Polyester Thread
Production
3081
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
33000104
Textile Products, Miscellaneous, Tenter Frames: Heat
Setting
2241
Textile Mill Products
313
Food Manufacturing; Textile Mills
33000199
Textile Products, Miscellaneous, Other Not Classified
2221
Textile Mill Products
313
Food Manufacturing; Textile Mills
33000202
Textile Products, Rubberized Fabrics, Wet Coating: General
2823
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
33000212
Textile Products, Rubberized Fabrics, Wet Coating
3999
Miscellaneous Manufacturing Industries
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
33000298
Textile Products, Rubberized Fabrics, Other Not Classified
3143
Leather and Leather Products
316
Food Manufacturing; Leather and Allied
Product Manufacturing
C-23

-------
SCC SCC Name
SIC
NAICS
33000499
Textile Products, Fabric Finishing, Other Not Classified
3081
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
33088801
Textile Products, Fugitive Emissions, Specify in Comments
Field
3082
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
39000203
In-process Fuel Use, Bituminous Coal, Lime Kiln
(Bituminous)
3274
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
39999995
Miscellaneous Manufacturing Industries, Miscellaneous
Industrial Processes, Other Not Classified
3679
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
39999998
Miscellaneous Manufacturing Industries, Miscellaneous
Industrial Processes, Other Not Classified
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
39999999
Miscellaneous Manufacturing Industries, Miscellaneous
Industrial Processes, See Comment **
3674
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100101
Organic Solvent Evaporation, Dry Cleaning,
Perchloroethylene
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40100102
Organic Solvent Evaporation, Dry Cleaning, Stoddard
(Petroleum Solvent) ** (Use 4-10-001-01 or 4-10-002-01)
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
30800702
Rubber and Miscellaneous Plastics Products, Fiberglass
Resin Products, Mould Release
3086
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800703
Rubber and Miscellaneous Plastics Products, Fiberglass
Resin Products, Solvent Consumption
3083
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800704
Rubber and Miscellaneous Plastics Products, Fiberglass
Resin Products, Adhesive Consumption
3081
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800720
Rubber and Miscellaneous Plastics Products, Fiberglass
Resin Products, General
3083
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800722
Rubber and Miscellaneous Plastics Products, Fiberglass
Resin Products, Gel Coat: Spray On
3732
Transportation Equipment
811 Other Services (except Public
Administration); Repair and Maintenance
C-24

-------
SCC SCC Name
SIC
NAICS
30800723
Rubber and Miscellaneous Plastics Products, Fiberglass
Resin Products, Resin: General: Roll On
3732
Transportation Equipment
811 Other Services (except Public
Administration); Repair and Maintenance
30800724
Rubber and Miscellaneous Plastics Products, Fiberglass
Resin Products, Resin: General: Spray On ** (use 3-08-007-
30)
3732
Transportation Equipment
811 Other Services (except Public
Administration); Repair and Maintenance
30800799
Rubber and Miscellaneous Plastics Products, Fiberglass
Resin Products, Other Not Classified
3531
Industrial Machinery and Equipment
336 Primary Metal Manufacturing;
Transportation Equipment Manufacturing
30899999
Rubber and Miscellaneous Plastics Products, Other Not
Specified, Other Not Classified
7549
Auto Repair, Services, and Parking
488 Air Transportation; Support Activities for
Transportation
30900198
Fabricated Metal Products, General Processes, Other Not
Classified
3442
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30900199
Fabricated Metal Products, General Processes, Other Not
Classified
3479
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30900201
Fabricated Metal Products, Abrasive Blasting of Metal Parts,
General
3731
Transportation Equipment
336 Primary Metal Manufacturing;
Transportation Equipment Manufacturing
30900202
Fabricated Metal Products, Abrasive Blasting of Metal Parts,
Sand Abrasive
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
30900203
Fabricated Metal Products, Abrasive Blasting of Metal Parts,
Slag Abrasive
3731
Transportation Equipment
336 Primary Metal Manufacturing;
Transportation Equipment Manufacturing
30900205
Fabricated Metal Products, Abrasive Blasting of Metal Parts,
Steel Grit Abrasive
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
30900207
Fabricated Metal Products, Abrasive Blasting of Metal Parts,
Shotblast with Air
3264
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30900299
Fabricated Metal Products, Abrasive Blasting of Metal Parts,
General
3743
Transportation Equipment
333 Primary Metal Manufacturing; Machinery
Manufacturing
30900303
Fabricated Metal Products, Abrasive Cleaning of Metal
Parts, Polishing
3731
Transportation Equipment
336 Primary Metal Manufacturing;
Transportation Equipment Manufacturing
C-25

-------
SCC SCC Name
SIC
NAICS
30900304
Fabricated Metal Products, Abrasive Cleaning of Metal
Parts, Buffing
3589
Industrial Machinery and Equipment
333 Primary Metal Manufacturing; Machinery
Manufacturing
30901001
Fabricated Metal Products, Electroplating Operations, Entire
Process: General
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
30901098
Fabricated Metal Products, Electroplating Operations, Other
Not Classified
2754
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
30901101
Fabricated Metal Products, Conversion Coating of Metal
Products, Alkaline Cleaning Bath
3589
Industrial Machinery and Equipment
333 Primary Metal Manufacturing; Machinery
Manufacturing
30901102
Fabricated Metal Products, Conversion Coating of Metal
Products, Acid Cleaning Bath (Pickling)
3829
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
30901104
Fabricated Metal Products, Conversion Coating of Metal
Products, Rinsing/Finishing
3496
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
30902501
Fabricated Metal Products, Drum Cleaning/Reclamation,
Drum Burning Furnace
3412
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40100223
Organic Solvent Evaporation, Degreasing,
Perchloroethylene: Conveyorized Vapor Degreasing
3679
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100236
Organic Solvent Evaporation, Degreasing, Entire Unit: with
Non-boiling Solvent: Conveyorized Vapor Degreasing
3479
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40100252
Organic Solvent Evaporation, Degreasing, 1,1,1-
Trichloroethane (Methyl Chloroform): General Degreasing
Units
3469
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40100295
Organic Solvent Evaporation, Degreasing, Other Not
Classified: General Degreasing Units
3829
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100296
Organic Solvent Evaporation, Degreasing, Other Not
Classified: General Degreasing Units
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40400104
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 13: Breathing Loss (250000 Bbl Capacity)-
Fixed Roof Tank
5172
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
C-26

-------
SCC SCC Name
SIC
NAICS
40899999
Organic Chemical Transportation, Specific Liquid, Loading
Rack
2952
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
49000201
Organic Solvent Evaporation, Waste Solvent Recovery
Operations, Storage Tank Vent
3711
Transportation Equipment
336 Primary Metal Manufacturing;
Transportation Equipment Manufacturing
49000202
Organic Solvent Evaporation, Waste Solvent Recovery
Operations, Condenser Vent
3732
Transportation Equipment
811 Other Services (except Public
Administration); Repair and Maintenance
49090011
Organic Solvent Evaporation, Fuel Fired Equipment,
Distillate Oil (No. 2): Incinerators
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
49099998
Organic Solvent Evaporation, Miscellaneous Volatile
Organic Compound Evaporation, Identify the Process and
Solvent in Comments
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100103
Organic Solvent Evaporation, Dry Cleaning,
Perchloroethylene
7216
Personal Services
812 Other Services (except Public
Administration); Personal and Laundry
Services
40100104
Organic Solvent Evaporation, Dry Cleaning, Stoddard
(Petroleum Solvent) ** (Use 4-10-001 -02 or 4-10-002-02)
7216
Personal Services
812 Other Services (except Public
Administration); Personal and Laundry
Services
40100198
Organic Solvent Evaporation, Dry Cleaning, Other Not
Classified
7211
Personal Services
812 Other Services (except Public
Administration); Personal and Laundry
Services
40100201
Organic Solvent Evaporation, Degreasing, Stoddard
(Petroleum Solvent): Open-top Vapor Degreasing
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40100202
Organic Solvent Evaporation, Degreasing, 1,1,1-
Trichloroethane (Methyl Chloroform): Open-top Vapor
Degreasing
3672
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100203
Organic Solvent Evaporation, Degreasing,
Perchloroethylene: Open-top Vapor Degreasing
7216
Personal Services
812 Other Services (except Public
Administration); Personal and Laundry
Services
40100205
Organic Solvent Evaporation, Degreasing,
Trichloroethylene: Open-top Vapor Degreasing
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100222
Organic Solvent Evaporation, Degreasing, 1,1,1-
Trichloroethane (Methyl Chloroform):Conveyorized Vapor
Degreaser
3829
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
C-27

-------
SCC SCC Name
SIC
NAICS
40400202
Petroleum Liquids Storage (non-Refinery), Bulk Plants,
Gasoline RVP 10: Breathing Loss (67000 Bbl Capacity) -
Fixed Roof Tank
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400205
Petroleum Liquids Storage (non-Refinery), Bulk Plants,
Gasoline RVP 10: Working Loss (67000 Bbl. Capacity) -
Fixed Roof Tank
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400210
Petroleum Liquids Storage (non-Refinery), Bulk Plants,
Gasoline RVP 13/10/7: Withdrawal Loss (67000 Bbl Cap.) -
Float RfTnk
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400212
Petroleum Liquids Storage (non-Refinery), Bulk Plants,
Gasoline RVP 10: Filling Loss (10500 Bbl Cap.) - Variable
Vapor Space
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
30501199
Mineral Products, Concrete Batching, Other Not Classified
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
30501402
Mineral Products, Glass Manufacture, Container Glass:
Melting Furnace
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
30501403
Mineral Products, Glass Manufacture, Flat Glass: Melting
Furnace
3221
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501406
Mineral Products, Glass Manufacture, Container Glass:
Forming/Finishing
3221
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501413
Mineral Products, Glass Manufacture, Cullet:
Crushing/Grinding
3221
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501415
Mineral Products, Glass Manufacture, Glass Etching with
Hydrofluoric Acid Solution
3221
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501501
Mineral Products, Gypsum Manufacture, Rotary Ore Dryer
3275
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501502
Mineral Products, Gypsum Manufacture, Primary
Grinder/Roller Mills
3275
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501504
Mineral Products, Gypsum Manufacture, Conveying
3275
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
C-28

-------
SCC SCC Name
SIC
NAICS
30501508
Mineral Products, Gypsum Manufacture, Stockpile: Gypsum
Ore
3275
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501509
Mineral Products, Gypsum Manufacture, Storage Bins:
Gypsum Ore
3275
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501518
Mineral Products, Gypsum Manufacture, Mixers/Conveyors
3275
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501520
Mineral Products, Gypsum Manufacture, Drying Kiln
3275
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30501521
Mineral Products, Gypsum Manufacture, End Sawing (8 Ft.)
3275
Stone, Clay, and Glass Products
327 Wood Product Manufacturing;
Nonmetallic Mineral Product
Manufacturing
30510298
Mineral Products, Bulk Materials Storage Bins, Mineral:
Specify in Comments
2891
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
30510403
Mineral Products, Bulk Materials Unloading Operation, Coal
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30599999
Mineral Products, Other Not Defined, Specify in Comments
Field
3996
Miscellaneous Manufacturing Industries
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30600103
Petroleum Industry, Process Heaters, Oil-fired
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30600104
Petroleum Industry, Process Heaters, Gas-fired
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30600201
Petroleum Industry, Catalytic Cracking Units, Fluid Catalytic
Cracking Unit
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30600504
Petroleum Industry, Wastewater Treatment, Process Drains
and Wastewater Separators
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30600801
Petroleum Industry, Fugitive Emissions, Pipeline Valves and
Flanges
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
C-29

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SCC SCC Name
SIC
NAICS
30600802
Petroleum Industry, Fugitive Emissions, Vessel Relief Valves
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30600803
Petroleum Industry, Fugitive Emissions, Pump Seals w/o
Controls
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30600804
Petroleum Industry, Fugitive Emissions, Compressor Seals
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30600805
Petroleum Industry, Fugitive Emissions, Miscellaneous:
Sampling/Non-Asphalt Blowing/Purging/etc.
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
40200998
Surface Coating Operations, Thinning Solvents - General,
General: Specify in Comments
3444
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40201001
Surface Coating Operations, Coating Oven Heater, Natural
Gas
3669
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40201004
Surface Coating Operations, Coating Oven Heater, Liquified
Petroleum Gas (LPG)
9223
Justice, Public Order, and Safety
922 Public Administration; Justice, Public
Order, and Safety Activities
40201101
Surface Coating Operations, Fabric Coating/Printing,
Coating Operation (Also See Specific Coating Method
Codes 4-02-04X)
3999
Miscellaneous Manufacturing Industries
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
40201301
Surface Coating Operations, Paper Coating, Coating
Operation
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40201432
Surface Coating Operations, Large Appliances, Prime Air
Spray
3589
Industrial Machinery and Equipment
333 Primary Metal Manufacturing; Machinery
Manufacturing
40201599
Surface Coating Operations, Magnet Wire Surface Coating,
Other Not Classified
3669
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40201605
Surface Coating Operations, Automobiles and Light Trucks,
Equipment Cleanup
3711
Transportation Equipment
336 Primary Metal Manufacturing;
Transportation Equipment Manufacturing
40201620
Surface Coating Operations, Automobiles and Light Trucks,
Repair Topcoat Application Area
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
C-30

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SCC SCC Name
SIC
NAICS
40201621
Surface Coating Operations, Automobiles and Light Trucks,
Prime Coating: Solvent-borne - Automobiles
7549
Auto Repair, Services, and Parking
488 Air Transportation; Support Activities for
Transportation
40201625
Surface Coating Operations, Automobiles and Light Trucks,
Topcoat: Solvent-borne - Automobiles
5511
Automotive Dealers & Service Stations
441
Motor Vehicle and Parts Dealers; Motor
Vehicle and Parts Dealers
40201628
Surface Coating Operations, Automobiles and Light Trucks,
Prime Coating: Electro-deposition - Light Trucks
3711
Transportation Equipment
336
Primary Metal Manufacturing;
Transportation Equipment Manufacturing
40201631
Surface Coating Operations, Automobiles and Light Trucks,
Topcoat: Solvent-borne - Light Trucks
3711
Transportation Equipment
336
Primary Metal Manufacturing;
Transportation Equipment Manufacturing
40201632
Surface Coating Operations, Automobiles and Light Trucks,
Topcoat: Water-borne - Light Trucks
5411
Food Stores
452 Sporting Goods, Hobby, Book, and
Music Stores; General Merchandise
Stores
40201699
Surface Coating Operations, Automobiles and Light Trucks,
Other Not Classified
3711
Transportation Equipment
336
Primary Metal Manufacturing;
Transportation Equipment Manufacturing
40201724
Surface Coating Operations, Metal Can Coating, Sheet
Base Coating (Exterior)
3411
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40201726
Surface Coating Operations, Metal Can Coating, End
Sealing Compound (Also See 4-02-017-36 & -37)
3411
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40201727
Surface Coating Operations, Metal Can Coating, Lithography
3411
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40201731
Surface Coating Operations, Metal Can Coating, Three-
piece Can Sheet Base Coating
3411
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40201732
Surface Coating Operations, Metal Can Coating, Three-
piece Can Sheet Lithographic Coating Line
3411
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40201799
Surface Coating Operations, Metal Can Coating, Other Not
Classified
3411
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40201806
Surface Coating Operations, Metal Coil Coating, Finish
Coating
3479
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
C-31

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see
SCC Name
SIC

NAICS
40201901
Surface Coating Operations, Wood Furniture Surface
Coating, Coating Operation
2511
Furniture and Fixtures
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
40201999
Surface Coating Operations, Wood Furniture Surface
Coating, Other Not Classified
2511
Furniture and Fixtures
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
40202001
Surface Coating Operations, Metal Furniture Operations,
Coating Operation
9223
Justice, Public Order, and Safety
922 Public Administration; Justice, Public
Order, and Safety Activities
40202101
Surface Coating Operations, Flatwood Products, Base Coat
2434
Lumber and Wood Products
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
40202105
Surface Coating Operations, Flatwood Products, Equipment
Cleanup
2434
Lumber and Wood Products
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
40202106
Surface Coating Operations, Flatwood Products, Topcoat
2434
Lumber and Wood Products
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
40202108
Surface Coating Operations, Flatwood Products, Sealer
2434
Lumber and Wood Products
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
40202201
Surface Coating Operations, Plastic Parts, Coating
Operation
3089
Rubber and Misc. Plastics Products
337 Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
40202399
Surface Coating Operations, Large Ships, Other Not
Classified
3731
Transportation Equipment
336 Primary Metal Manufacturing;
Transportation Equipment Manufacturing
30601101
Petroleum Industry, Asphalt Blowing, General
2952
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
30700101
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping,
Digester Relief and Blow Tank
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
30700102
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping,
Washer/Screens
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
30700103
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping,
Multi-effect Evaporator
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
C-32

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SCC SCC Name
SIC
NAICS
30700104
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping,
Recovery Furnace/Direct Contact Evaporator
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
30700105
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping,
Smelt Dissolving Tank
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
30700106
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping,
Lime Kiln
2675
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
30700199
Pulp and Paper and Wood Products, Sulfate (Kraft) Pulping,
Other Not Classified
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
30700401
Pulp and Paper and Wood Products, Pulpboard
Manufacture, Paperboard: General
2675
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
30700501
Pulp and Paper and Wood Products, Wood Pressure
Treating, Creosote
2491
Lumber and Wood Products
321 Wood Product Manufacturing; Wood
Product Manufacturing
30700599
Pulp and Paper and Wood Products, Wood Pressure
Treating, Other Not Classified
2491
Lumber and Wood Products
321 Wood Product Manufacturing; Wood
Product Manufacturing
30700701
Pulp and Paper and Wood Products, Plywood Operations,
General: Not Classified **
2436
Lumber and Wood Products
321 Wood Product Manufacturing; Wood
Product Manufacturing
30700702
Pulp and Paper and Wood Products, Plywood Operations,
Sanding Operations
2499
Lumber and Wood Products
339 Primary Metal Manufacturing;
Miscellaneous Manufacturing
30700703
Pulp and Paper and Wood Products, Plywood Operations,
Particleboard Drying(See 3-07-006 For More Detailed
Particleboard SCC)
3083
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30700706
Pulp and Paper and Wood Products, Plywood Operations,
Hardboard: Predryer
2436
Lumber and Wood Products
321 Wood Product Manufacturing; Wood
Product Manufacturing
30700707
Pulp and Paper and Wood Products, Plywood Operations,
Hardboard: Pressing
2493
Lumber and Wood Products
321 Wood Product Manufacturing; Wood
Product Manufacturing
30700798
Pulp and Paper and Wood Products, Plywood Operations,
Other Not Classified
2491
Lumber and Wood Products
321 Wood Product Manufacturing; Wood
Product Manufacturing
C-33

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SCC SCC Name
SIC
NAICS
30700799
Pulp and Paper and Wood Products, Plywood Operations,
Other Not Classified
2436
Lumber and Wood Products
321
Wood Product Manufacturing; Wood
Product Manufacturing
30700897
Pulp and Paper and Wood Products, Sawmill Operations,
Other Not Classified
2426
Lumber and Wood Products
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
30700898
Pulp and Paper and Wood Products, Sawmill Operations,
Other Not Classified
2426
Lumber and Wood Products
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
30700899
Pulp and Paper and Wood Products, Sawmill Operations,
Other Not Classified
2426
Lumber and Wood Products
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
30702099
Pulp and Paper and Wood Products, Furniture Manufacture,
Other Not Classified
2511
Furniture and Fixtures
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
30703001
Pulp and Paper and Wood Products, Miscellaneous Wood
Working Operations, Wood Waste Storage Bin Vent
2499
Lumber and Wood Products
339
Primary Metal Manufacturing;
Miscellaneous Manufacturing
30703002
Pulp and Paper and Wood Products, Miscellaneous Wood
Working Operations, Wood Waste Storage Bin Loadout
2499
Lumber and Wood Products
339
Primary Metal Manufacturing;
Miscellaneous Manufacturing
30703097
Pulp and Paper and Wood Products, Miscellaneous Wood
Working Operations, Sanding/Planning Operations: Specify
2431
Lumber and Wood Products
321
Wood Product Manufacturing; Wood
Product Manufacturing
30703099
Pulp and Paper and Wood Products, Miscellaneous Wood
Working Operations, Sanding/Planning Operations: Specify
2426
Lumber and Wood Products
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
30790003
Pulp and Paper and Wood Products, Fuel Fired Equipment,
Natural Gas: Process Heaters
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
30800101
Rubber and Miscellaneous Plastics Products, Tire
Manufacture, Undertread and Sidewall Cementing
3011
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800102
Rubber and Miscellaneous Plastics Products, Tire
Manufacture, Bead Dipping
3011
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800104
Rubber and Miscellaneous Plastics Products, Tire
Manufacture, Tire Building
3011
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
C-34

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SCC SCC Name
SIC
NAICS
30800105
Rubber and Miscellaneous Plastics Products, Tire
Manufacture, Tread End Cementing
3011
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800106
Rubber and Miscellaneous Plastics Products, Tire
Manufacture, Green Tire Spraying
3011
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800107
Rubber and Miscellaneous Plastics Products, Tire
Manufacture, Tire Curing
3011
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800199
Rubber and Miscellaneous Plastics Products, Tire
Manufacture, Other Not Classified
7534
Auto Repair, Services, and Parking
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800501
Rubber and Miscellaneous Plastics Products, Tire
Retreading, Tire Buffing Machines
7534
Auto Repair, Services, and Parking
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800699
Rubber and Miscellaneous Plastics Products, Other
Fabricated Plastics, Other Not Classified
3082
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
30800701
Rubber and Miscellaneous Plastics Products, Fiberglass
Resin Products, Plastics Machining:
Drilling/Sanding/Sawing/etc.
3083
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
40400105
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 10: Breathing Loss (250000 Bbl Capacity)-
Fixed Roof Tank
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400108
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 10: Working Loss (Diameter Independent) -
Fixed Roof Tank
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400109
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 7: Working Loss (Diameter Independent) -
Fixed Roof Tank
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400110
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 13: Standing Loss (67000 Bbl Capacity)-
Floating Roof Tank
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400111
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 10: Standing Loss (67000 Bbl Capacity)-
Floating Roof Tank
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400113
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 13: Standing Loss (250000 Bbl Cap.) -
Floating Roof Tank
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
C-35

-------
SCC SCC Name
SIC
NAICS
40400114
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 10: Standing Loss (250000 Bbl Cap.) -
Floating Roof Tank
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400301
Petroleum Liquids Storage (non-Refinery), Oil and Gas Field
Storage and Working Tanks, Fixed Roof Tank: Breathing
Loss
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400302
Petroleum Liquids Storage (non-Refinery), Oil and Gas Field
Storage and Working Tanks, Fixed Roof Tank: Working Loss
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400402
Petroleum Liquids Storage (non-Refinery), Petroleum
Products - Underground Tanks, Gasoline RVP 13: Working
Loss
1611
Heavy Construction, Ex. Building
234 Construction; Heavy Construction
40400403
Petroleum Liquids Storage (non-Refinery), Petroleum
Products - Underground Tanks, Gasoline RVP 10: Breathing
Loss
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
40400404
Petroleum Liquids Storage (non-Refinery), Petroleum
Products - Underground Tanks, Gasoline RVP 10: Working
Loss
2711
Printing and Publishing
511 Information; Publishing Industries
40400410
Petroleum Liquids Storage (non-Refinery), Petroleum
Products - Underground Tanks, Jet Naphtha (JP-4):
Working Loss
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40400497
Petroleum Liquids Storage (non-Refinery), Petroleum
Products - Underground Tanks, Specify Liquid: Breathing
Loss
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40400498
Petroleum Liquids Storage (non-Refinery), Petroleum
Products - Underground Tanks, Specify Liquid: Working
Loss
2891
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
40500101
Printing/Publishing, Drying, Dryer
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500199
Printing/Publishing, Drying, Dryer
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500201
Printing/Publishing, General, Letter Press: 2751
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500301
Printing/Publishing, General, Printing: Flexographic
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
C-36

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SCC SCC Name
SIC
NAICS
40500305
Printing/Publishing, General, Ink Thinning Solvent (Isopropyl
Alcohol)
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500307
Printing/Publishing, General, Ink Thinning Solvent (Naphtha)
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500312
Printing/Publishing, General, Printing: Flexographic
2752
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500401
Printing/Publishing, General, Lithographic: 2752
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500411
Printing/Publishing, General, Lithographic: 2752
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40500412
Printing/Publishing, General, Lithographic: 2752
2711
Printing and Publishing
511 Information; Publishing Industries
40500501
Printing/Publishing, General, Gravure: 2754
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500512
Printing/Publishing, General, Gravure: 2754
2731
Printing and Publishing
512 Information; Motion Picture and Sound
Recording Industries
40500513
Printing/Publishing, General, Gravure: 2754
2754
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500598
Printing/Publishing, General, Ink Thinning Solvent: Other
Not Specified
2752
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500599
Printing/Publishing, General, Ink Thinning Solvent: Other
Not Specified
2752
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500701
Printing/Publishing, General, Solvent Storage
2754
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40500812
Printing/Publishing, General, Screen Printing
3829
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
C-37

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SCC SCC Name
SIC
NAICS
40588801
Printing/Publishing, Fugitive Emissions, Specify in
Comments Field
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40588802
Printing/Publishing, Fugitive Emissions, Specify in
Comments Field
2759
Printing and Publishing
323 Wood Product Manufacturing; Printing
and Related Support Activities
40100297
Organic Solvent Evaporation, Degreasing, Other Not
Classified: Open-top Vapor Degreasing
3674
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100298
Organic Solvent Evaporation, Degreasing, Other Not
Classified: Conveyorized Vapor Degreasing
3829
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100299
Organic Solvent Evaporation, Degreasing, Other Not
Classified: Open-top Vapor Degreasing
5065
Wholesale Trade - Durable Goods
421 Wholesale Trade; Wholesale Trade,
Durable Goods
40100302
Organic Solvent Evaporation, Cold Solvent
Cleaning/Stripping, Methylene Chloride
3672
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100305
Organic Solvent Evaporation, Cold Solvent
Cleaning/Stripping, 1,1,1-Trichloroethane (Methyl
Chloroform)
3672
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40100335
Organic Solvent Evaporation, Cold Solvent
Cleaning/Stripping, Entire Unit
3743
Transportation Equipment
333 Primary Metal Manufacturing; Machinery
Manufacturing
40100336
Organic Solvent Evaporation, Cold Solvent
Cleaning/Stripping, Degreaser: Entire Unit
7542
Auto Repair, Services, and Parking
811 Other Services (except Public
Administration); Repair and Maintenance
40100398
Organic Solvent Evaporation, Cold Solvent
Cleaning/Stripping, Other Not Classified
7532
Auto Repair, Services, and Parking
811 Other Services (except Public
Administration); Repair and Maintenance
40100399
Organic Solvent Evaporation, Cold Solvent
Cleaning/Stripping, Other Not Classified
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40188801
Organic Solvent Evaporation, Fugitive Emissions, Specify in
Comments Field
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40188898
Organic Solvent Evaporation, Fugitive Emissions, Specify in
Comments Field
5169
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
C-38

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SCC SCC Name
SIC
NAICS
40200101
Surface Coating Operations, Surface Coating Application -
General, Paint: Solvent-base
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
40200110
Surface Coating Operations, Surface Coating Application -
General, Paint: Solvent-base
2431
Lumber and Wood Products
321
Wood Product Manufacturing; Wood
Product Manufacturing
40200201
Surface Coating Operations, Surface Coating Application -
General, Paint: Water-base
3089
Rubber and Misc. Plastics Products
337
Primary Metal Manufacturing; Furniture
and Related Product Manufacturing
40200210
Surface Coating Operations, Surface Coating Application -
General, Paint: Water-base
3731
Transportation Equipment
336
Primary Metal Manufacturing;
Transportation Equipment Manufacturing
40200310
Surface Coating Operations, Surface Coating Application -
General, Varnish/Shellac
3479
Fabricated Metal Products
332
Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40200401
Surface Coating Operations, Surface Coating Application -
General, Lacquer
9711
National Security and Intl. Affairs
928
Public Administration; National Security
and International Affairs
40200410
Surface Coating Operations, Surface Coating Application -
General, Lacquer
3931
Miscellaneous Manufacturing Industries
339
Primary Metal Manufacturing;
Miscellaneous Manufacturing
40200501
Surface Coating Operations, Surface Coating Application -
General, Enamel
3443
Fabricated Metal Products
333
Primary Metal Manufacturing; Machinery
Manufacturing
40200510
Surface Coating Operations, Surface Coating Application -
General, Enamel
3674
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40200601
Surface Coating Operations, Surface Coating Application -
General, Primer
3993
Miscellaneous Manufacturing Industries
339
Primary Metal Manufacturing;
Miscellaneous Manufacturing
40200610
Surface Coating Operations, Surface Coating Application -
General, Primer
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40200701
Surface Coating Operations, Surface Coating Application -
General, Adhesive Application
3732
Transportation Equipment
811
Other Services (except Public
Administration); Repair and Maintenance
40200706
Surface Coating Operations, Surface Coating Application -
General, Adhesive: Solvent Mixing
2891
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
C-39

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SCC SCC Name
SIC
NAICS
40200710
Surface Coating Operations, Surface Coating Application -
General, Adhesive: General
3993
Miscellaneous Manufacturing Industries
339 Primary Metal Manufacturing;
Miscellaneous Manufacturing
40200801
Surface Coating Operations, Coating Oven - General,
General
3569
Industrial Machinery and Equipment
314 Food Manufacturing; Textile Product
Mills
40200802
Surface Coating Operations, Coating Oven - General, Dried
< 175F **
5085
Wholesale Trade - Durable Goods
421 Wholesale Trade; Wholesale Trade,
Durable Goods
40200810
Surface Coating Operations, Coating Oven - General,
General
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40200898
Surface Coating Operations, Coating Oven - General,
General
3669
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40200901
Surface Coating Operations, Thinning Solvents - General,
General: Specify in Comments
2435
Lumber and Wood Products
321 Wood Product Manufacturing; Wood
Product Manufacturing
40200911
Surface Coating Operations, Thinning Solvents - General,
Gasoline
3011
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
40200920
Surface Coating Operations, Thinning Solvents - General,
Mineral Spirits
3612
Electronic & Other Electric Equipment
335 Primary Metal Manufacturing; Electrical
Equipment, Appliance, and Component
Manufacturing
40200921
Surface Coating Operations, Thinning Solvents - General,
Naphtha
3053
Rubber and Misc. Plastics Products
339 Primary Metal Manufacturing;
Miscellaneous Manufacturing
40200922
Surface Coating Operations, Thinning Solvents - General,
Toluene
3479
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40200923
Surface Coating Operations, Thinning Solvents - General,
Varsol
2621
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
40200924
Surface Coating Operations, Thinning Solvents - General,
Xylene
3612
Electronic & Other Electric Equipment
335 Primary Metal Manufacturing; Electrical
Equipment, Appliance, and Component
Manufacturing
40202405
Surface Coating Operations, Large Aircraft, Equipment
Cleanup
3728
Transportation Equipment
541 Professional, Scientific, and Technical
Services; Professional, Scientific, and
Technical Services
C-40

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SCC SCC Name
SIC
NAICS
40202406
Surface Coating Operations, Large Aircraft, Topcoat
Operation
3728
Transportation Equipment
541 Professional, Scientific, and Technical
Services; Professional, Scientific, and
Technical Services
40202501
Surface Coating Operations, Miscellaneous Metal Parts,
Coating Operation
3496
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40202502
Surface Coating Operations, Miscellaneous Metal Parts,
Cleaning/Pretreatment
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40202537
Surface Coating Operations, Miscellaneous Metal Parts,
Manual Two Coat, Spray and Air Dry
3441
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40202599
Surface Coating Operations, Miscellaneous Metal Parts,
Other Not Classified
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40202601
Surface Coating Operations, Steel Drums, Coating Operation
5085
Wholesale Trade - Durable Goods
421 Wholesale Trade; Wholesale Trade,
Durable Goods
40202606
Surface Coating Operations, Steel Drums, Interior Coating
5085
Wholesale Trade - Durable Goods
421 Wholesale Trade; Wholesale Trade,
Durable Goods
40288801
Surface Coating Operations, Fugitive Emissions, Specify in
Comments Field
3812
Instruments and Related Products
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40299995
Surface Coating Operations, Miscellaneous, Specify in
Comments Field
3669
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40299998
Surface Coating Operations, Miscellaneous, Specify in
Comments Field
3669
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40301008
Petroleum Product Storage at Refineries, Fixed Roof Tanks
(Varying Sizes), Gasoline RVP 10: Working Loss (Tank
Diameter Independent)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301011
Petroleum Product Storage at Refineries, Fixed Roof Tanks
(Varying Sizes), Crude Oil RVP 5: Breathing Loss (250000
Bbl. Tank Size)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301016
Petroleum Product Storage at Refineries, Fixed Roof Tanks
(Varying Sizes), Jet Kerosene: Breathing Loss (67000 Bbl.
Tank Size)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
C-41

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SCC SCC Name
SIC
NAICS
40301018
Petroleum Product Storage at Refineries, Fixed Roof Tanks
(Varying Sizes), Jet Kerosene: Working Loss (Tank
Diameter Independent)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301019
Petroleum Product Storage at Refineries, Fixed Roof Tanks
(Varying Sizes), Distillate Fuel #2: Breathing Loss (67000
Bbl. Tank Size)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301021
Petroleum Product Storage at Refineries, Fixed Roof Tanks
(Varying Sizes), Distillate Fuel #2: Working Loss (Tank
Diameter Independent)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301097
Petroleum Product Storage at Refineries, Fixed Roof Tanks
(Varying Sizes), Specify Liquid: Breathing Loss (67000 Bbl.
Tank Size)
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
40301098
Petroleum Product Storage at Refineries, Fixed Roof Tanks
(Varying Sizes), Specify Liquid: Breathing Loss (250000 Bbl.
Tank Size)
5172
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301099
Petroleum Product Storage at Refineries, Fixed Roof Tanks
(Varying Sizes), Specify Liquid: Working Loss (Tank
Diameter Independent)
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
40301102
Petroleum Product Storage at Refineries, Floating Roof
Tanks (Varying Sizes), Gasoline RVP 10: Standing Loss
(67000 Bbl. Tank Size)
1422
Nonmetallic Minerals, Except Fuels
212 Mining; Mining (except Oil and Gas)
40301110
Petroleum Product Storage at Refineries, Floating Roof
Tanks (Varying Sizes), Crude Oil RVP 5: Standing Loss
(250000 Bbl. Tank Size)
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
40301111
Petroleum Product Storage at Refineries, Floating Roof
Tanks (Varying Sizes), Jet Naphtha (JP-4): Standing Loss
(67000 Bbl. Tank Size)
2911
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
40301113
Petroleum Product Storage at Refineries, Floating Roof
Tanks (Varying Sizes), Jet Kerosene: Standing Loss (67000
Bbl. Tank Size)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301115
Petroleum Product Storage at Refineries, Floating Roof
Tanks (Varying Sizes), Distillate Fuel #2: Standing Loss
(67000 Bbl. Tank Size)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301119
Petroleum Product Storage at Refineries, Floating Roof
Tanks (Varying Sizes), Jet Kerosene: Wthdrawal Loss
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301151
Petroleum Product Storage at Refineries, Floating Roof
Tanks (Varying Sizes), Gasoline: Standing Loss - Internal
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
C-42

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SCC SCC Name
SIC
NAICS
40301202
Petroleum Product Storage at Refineries, Variable Vapor
Space, Gasoline RVP 10: Filling Loss
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40301206
Petroleum Product Storage at Refineries, Variable Vapor
Space, Distillate Fuel #2: Filling Loss
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40388801
Petroleum Product Storage at Refineries, Fugitive
Emissions, Specify in Comments Field
2952
Petroleum and Coal Products
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
40400103
Petroleum Liquids Storage (non-Refinery), Bulk Terminals,
Gasoline RVP 7: Breathing Loss (67000 Bbl. Capacity) -
Fixed Roof Tank
5172
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600131
Transportation and Marketing of Petroleum Products, Tank
Cars and Trucks, Gasoline: Submerged Loading (Normal
Service)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600133
Transportation and Marketing of Petroleum Products, Tank
Cars and Trucks, Jet Naphtha: Submerged Loading (Normal
Service)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600134
Transportation and Marketing of Petroleum Products, Tank
Cars and Trucks, Kerosene: Submerged Loading (Normal
Services)
5172
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600135
Transportation and Marketing of Petroleum Products, Tank
Cars and Trucks, Distillate Oil: Submerged Loading (Normal
Service)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600136
Transportation and Marketing of Petroleum Products, Tank
Cars and Trucks, Gasoline: Splash Loading (Normal
Service)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600140
Transportation and Marketing of Petroleum Products, Tank
Cars and Trucks, Distillate Oil: Splash Loading (Normal
Service)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600141
Transportation and Marketing of Petroleum Products, Tank
Cars and Trucks, Gasoline: Submerged Loading (Balanced
Service)
5172
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600144
Transportation and Marketing of Petroleum Products, Tank
Cars and Trucks, Gasoline: Splash Loading (Balanced
Service)
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600147
Transportation and Marketing of Petroleum Products, Tank
Cars and Trucks, Gasoline: Submerged Loading (Clean
Tanks)
4952
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
C-43

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SCC SCC Name
SIC
NAICS
40600233
Transportation and Marketing of Petroleum Products,
Marine Vessels, Gasoline: Barge Loading - Cleaned and
Vapor Free Tanks
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600240
Transportation and Marketing of Petroleum Products,
Marine Vessels, Gasoline: Barge Loading - Average Tank
Condition
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600249
Transportation and Marketing of Petroleum Products,
Marine Vessels, Jet Fuel: Loading Barges
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600250
Transportation and Marketing of Petroleum Products,
Marine Vessels, Kerosene: Loading Barges
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600251
Transportation and Marketing of Petroleum Products,
Marine Vessels, Distillate Oil: Loading Barges
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600301
Transportation and Marketing of Petroleum Products,
Gasoline Retail Operations - Stage I, Splash Filling
5171
Wholesale Trade - Nondurable Goods
422 Wholesale Trade; Wholesale Trade,
Nondurable Goods
40600302
Transportation and Marketing of Petroleum Products,
Gasoline Retail Operations - Stage I, Submerged Filling w/o
Controls
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40600306
Transportation and Marketing of Petroleum Products,
Gasoline Retail Operations - Stage I, Balanced Submerged
Filling
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
40600307
Transportation and Marketing of Petroleum Products,
Gasoline Retail Operations - Stage I, Underground Tank
Breathing and Emptying
3312
Primary Metal Industries
324 Wood Product Manufacturing;
Petroleum and Coal Products
Manufacturing
40600401
Transportation and Marketing of Petroleum Products, Filling
Vehicle Gas Tanks - Stage II, Vapor Loss w/o Controls
3679
Electronic & Other Electric Equipment
334 Primary Metal Manufacturing; Computer
and Electronic Product Manufacturing
40600402
Transportation and Marketing of Petroleum Products, Filling
Vehicle Gas Tanks - Stage II, Liquid Spill Loss w/o Controls
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
40600403
Transportation and Marketing of Petroleum Products, Filling
Vehicle Gas Tanks - Stage II, Vapor Loss w/o Controls
2631
Paper and Allied Products
322 Wood Product Manufacturing; Paper
Manufacturing
40688801
Transportation and Marketing of Petroleum Products,
Fugitive Emissions, Specify in Comments Field
4925
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
C-44

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SCC SCC Name
SIC
NAICS
40688802
Transportation and Marketing of Petroleum Products,
Fugitive Emissions, Specify in Comments Field
4925
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
40688803
Transportation and Marketing of Petroleum Products,
Fugitive Emissions, Specify in Comments Field
4925
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
40688804
Transportation and Marketing of Petroleum Products,
Fugitive Emissions, Specify in Comments Field
4925
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
40700810
Organic Chemical Storage, Fixed Roof Tanks - Alcohols,
Ethyl Alcohol: Working Loss
2099
Food and Kindred Products
311 Food Manufacturing; Food
Manufacturing
40701612
Organic Chemical Storage, Fixed Roof Tanks - Alkanes
(Paraffins), Naphtha: Working Loss
4925
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
40703614
Organic Chemical Storage, Fixed Roof Tanks - Aromatics,
Styrene: Working Loss
2851
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
40703697
Organic Chemical Storage, Fixed Roof Tanks - Aromatics,
Specify Aromatic: Breathing Loss
2851
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
40706098
Organic Chemical Storage, Fixed Roof Tanks - Halogenated
Organics, Specify Halogenated Organic: Working Loss
3479
Fabricated Metal Products
332 Primary Metal Manufacturing; Fabricated
Metal Product Manufacturing
40799997
Organic Chemical Storage, Miscellaneous, Specify in
Comments
3711
Transportation Equipment
336 Primary Metal Manufacturing;
Transportation Equipment Manufacturing
49099999
Organic Solvent Evaporation, Miscellaneous Volatile
Organic Compound Evaporation, Identify the Process and
Solvent in Comments
4911
Electric, Gas, and Sanitary Services
221 Utilities; Utilities
50100101
Solid Waste Disposal - Government, Municipal Incineration,
Starved Air: Multiple Chamber
4953
Electric, Gas, and Sanitary Services
562 Administrative and Support and Waste
Management and Remediation
Services; Waste Management and
50100201
Solid Waste Disposal - Government, Open Burning Dump,
General Refuse
2892
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
50100505
Solid Waste Disposal - Government, Other Incineration,
Medical Waste Incinerator, unspecified type, Infectious
wastes only
9711
National Security and Intl. Affairs
928 Public Administration; National Security
and International Affairs
C-45

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SCC SCC Name
SIC
NAICS
50100701
Solid Waste Disposal - Government, Sewage Treatment,
Entire Plant
4952
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
50200101
Solid Waste Disposal - Commercial/Institutional,
Incineration, Multiple Chamber
8063
Health Services
622
Health Care and Social Assistance;
Hospitals
50200102
Solid Waste Disposal - Commercial/Institutional,
Incineration, Single Chamber
4953
Electric, Gas, and Sanitary Services
562 Administrative and Support and Waste
Management and Remediation
Services; Waste Management and
50200103
Solid Waste Disposal - Commercial/Institutional,
Incineration, Controlled Air
9711
National Security and Intl. Affairs
928
Public Administration; National Security
and International Affairs
50200505
Solid Waste Disposal - Commercial/Institutional,
Incineration: Special Purpose, Medical Waste Incinerator,
unspecified type, Infectious wastes only
8062
Health Services
622
Health Care and Social Assistance;
Hospitals
50200506
Solid Waste Disposal - Commercial/Institutional,
Incineration: Special Purpose, Sludge
4952
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
50200601
Solid Waste Disposal - Commercial/Institutional, Landfill
Dump, Waste Gas Flares ** (Use 5-01-004-10)
4952
Electric, Gas, and Sanitary Services
221
Utilities; Utilities
50290005
Solid Waste Disposal - Commercial/Institutional, Auxiliary
Fuel/No Emissions, Distillate Oil
8221
Educational Services
611
Educational Services; Educational
Services
50290006
Solid Waste Disposal - Commercial/Institutional, Auxiliary
Fuel/No Emissions, Natural Gas
3715
Transportation Equipment
336
Primary Metal Manufacturing;
Transportation Equipment Manufacturing
50290010
Solid Waste Disposal - Commercial/Institutional, Auxiliary
Fuel/No Emissions, Liquified Petroleum Gas (LPG)
3715
Transportation Equipment
336
Primary Metal Manufacturing;
Transportation Equipment Manufacturing
50300101
Solid Waste Disposal - Industrial, Incineration, Multiple
Chamber
3585
Industrial Machinery and Equipment
333
Primary Metal Manufacturing; Machinery
Manufacturing
50300102
Solid Waste Disposal - Industrial, Incineration, Single
Chamber
2819
Chemicals and Allied Products
331
Primary Metal Manufacturing; Primary
Metal Manufacturing
50300103
Solid Waste Disposal - Industrial, Incineration, Controlled Air
3711
Transportation Equipment
336
Primary Metal Manufacturing;
Transportation Equipment Manufacturing
C-46

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SCC SCC Name
SIC
NAICS
50300105
Solid Waste Disposal - Industrial, Incineration, Conical
Design (Tee Pee) Wood Refuse
2493
Lumber and Wood Products
321 Wood Product Manufacturing; Wood
Product Manufacturing
50300106
Solid Waste Disposal - Industrial, Incineration, Trench
Burner: Wood
2892
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
50300506
Solid Waste Disposal - Industrial, Incineration, Sludge
2834
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
50300701
Solid Waste Disposal - Industrial, Liquid Waste, General
2819
Chemicals and Allied Products
331 Primary Metal Manufacturing; Primary
Metal Manufacturing
50390005
Solid Waste Disposal - Industrial, Auxiliary Fuel/No
Emissions, Distillate Oil
2892
Chemicals and Allied Products
325 Wood Product Manufacturing; Chemical
Manufacturing
50390006
Solid Waste Disposal - Industrial, Auxiliary Fuel/No
Emissions, Natural Gas
3082
Rubber and Misc. Plastics Products
326 Wood Product Manufacturing; Plastics
and Rubber Products Manufacturing
C-47

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