Appendix G-5: Assessment of Control Technology Options for BART Eligible Sources

Appendix G-5: Assessment of Control Technology Options for BART Eligible Sources
Assessment of Control Technology
Options for BART-Eligible
Sources
Steam Electric Boilers, Industrial Boilers,
Cement Plants and Paper and Pulp Facilities
Prepared by
Northeast States for Coordinated Air Use Management
In Partnership with
The Mid-Atlantic/Northeast Visibility Union
March 2005
Members of Northeast States for Coordinated Air Use Management
Arthur N. Marin, Executive Director
Northeast States for Coordinated Air Use Management
Anne Gobin, Bureau Chief
Connecticut Department of Environmental Protection, Bureau of Air Management
James P. Brooks, Bureau Director
Maine Department of Environmental Protection, Bureau of Air Quality
Barbara Kwetz, Director
Massachusetts Department of Environmental Protection, Bureau of Waste Prevention
Robert Scott, Acting Director
New Hampshire Department of Environmental Services, Air Resources Division
William O’Sullivan, Director
New Jersey Department of Environmental Protection, Office of Air Quality Management
David Shaw, Director
New York Department of Environmental Conservation, Division of Air Recourses
Stephen Majkut, Chief
Rhode Island Department of Environmental Management, Office of Air Resources
Richard A. Valentinetti, Director
Vermont Department of Environmental Conservation, Air Pollution Control Division
ii
Assessment of Control Options for
BART-Eligible Sources
Steam Electric Boilers, Industrial Boilers,
Cement Plants and Paper and Pulp Facilities
Prepared by
Northeast States for Coordinated Air Use Management
In Partnership with
The Mid-Atlantic/Northeast Visibility Union
Submitted to the United States Environmental Protection Agency, Region III in partial
fulfillment of requirements for USEPA grant XA-983799-01-2 to the
Ozone Transport Commission
March 2005
iii
iv
ASSESSMENT OF CONTROL OPTIONS FOR
BART-ELIGIBLE SOURCES
STEAM ELECTRIC BOILERS, INDUSTRIAL BOILERS,
CEMENT PLANTS, AND PAPER AND PULP
FACILITIES
Project Director
Gary Kleiman, NESCAUM
Editors
Gary Kleiman, NESCAUM
Praveen Amar, NESCAUM
Principle Contributors
Praveen Amar, NESCAUM
Connie Senior, Reaction Engineering International
Rui Afonso, Energy and Environmental Strategies
Ingrid Ulbrich, NESCAUM
v
Acknowledgments
NESCAUM gratefully acknowledges the funding support provided by the United
States Environmental Protection Agency under USEPA grant XA-983799-01-2 to the
Ozone Transport Commission.
We also thank Glynn Rountree of the American Forest & Paper Association for
making us aware of John Pinkerton’s work at NCASI and providing us with Tables V-2
through V-5.
NESCAUM also thanks the following individuals for providing comments on this
report:
Doug Austin, Ozone Transport Commission
Mike Barden, Maine Paper and Pulp Association
John C. Buckley, NRG Energy
Bob Iwanchuck, ENSR on behalf of Dartmouth College
Wendy Jacobs, CT DEP
Roman Kramarchuk, U.S. EPA
Edward L. (Skip) Kropp, Jackson and Kelly on behalf of Midwest Ozone Group
Timothy Porter, Wheelabrator Technologies
Buzz Reynolds, CR Clean Air Technologies
Luc Robitaille, St. Lawrence Cement
Glynn Rountree, American Forest and Paper Association
Cathy Waxman, KeySpan
vi
Unit, Species, Acronyms
Acronyms
APCD – Air Pollution Control Device
BACT –Best Available Control Technology
BART – Best Available Retrofit Technology
CAA – Clean Air Act
CAAA – Clean Air Act Amendments
CKD – Cement Kiln Dust
CFBA – Circulating Fluidized-Bed Absorption
CFR – Code of Federal Regulations
DI – Dry Injection
DSI – Dry Sorbent Injection
EGU – Electricity Generating Unit
ESP – ElectroStatic Precipitator
ESFF – Electrostatic Stimulation of Fabric Filtration
FBC – Fluidized Bed Combustion
FF – Fabric Filters (also known as baghouses)
FGD – Flue Gas Desulfurization (also known as scrubbers)
FGR – Flue Gas Recirculation
FOM – Fixed Operating and Maintenance Costs
ICR – Information Collection Request
LAER – Lowest Achievable Emission Rate
LNB – Low NOX Burner
LSFO – Limestone Forced Oxidation
LSC – Low Sulfur Coal (also known as “compliance coal”)
MACT – Maximum Achievable Control Technology
MANE-VU – Mid-Atlantic/Northeast Visibility Union
MC – Mechanical Collector
NCG – Non Condensable Gases
NESCAUM – Northeast States for Coordinated Air Use Management
NSPS – New Source Performance Standard
NSR – New Source Review
OFA – Over Fire Air
PC – Pulverized Coal
PS – Particulate Scrubber
RACT – Reasonably Available Control Technology
RPO – Regional Planning Organization
SIP – State Implementation Plan
SCR – Selective Catalytic Reduction
SDA – Spray Dry Absorption
SNCR – Selective Non-Catalytic Reduction
SOG – Stripper Off Gases
TDF – Tire-Derived Fuel
US EPA – United States Environmental Protection Agency
vii
Chemical Species
EC – elemental carbon
HSO4 – bisulfate
H2SO4 – sulfuric acid
HNO3 – nitric acid
NOX – oxides of nitrogen ( NO and NO2)
NO – nitric oxide
NO2 – nitrogen dioxide
NO3 – nitrate
NH3 – ammonia
(NH4)3H(SO4)2 – letovicite
NH4HSO4 – ammonium bisulfate
(NH4)2SO4 – ammonium sulfate
NH4NO3 – ammonium nitrate
OC – organic carbon
PM2.5 – particle matter up to 2.5 µm in size
PM10 – particle matter up to 10?µm in size
PMcoarse – the difference: PM10 – PM2.5
S – sulfur
Se – selenium
SO2 – sulfur dioxide
SO4 – sulfate
VOC – volatile organic carbon
VOM – Variable Operating and Maintenance Costs
Units
Length
m – meter
µm – micrometer (0.000001m; 10-6 m)
km – kilometer (1000 x m; 103 m)
Mm – Megameter (1000000 x m; 106 m)
Flow Rate
ACFM – Actual Cubic Feet per Minute
Volume
L – liter
m3 – cubic meter
Mass
lb – pound
g – gram
µg – micrograms (0.000001 x g; 10-6 g)
kg – kilograms (1000 x g; 103 g)
viii
Power
W – watt (Joules/sec)
kW – kilowatt (1000 x W; 103 W)
MW – megawatt (1000000 x W; 106 W)
Energy
Btu – British Thermal Unit (= 1055 Joules)
mmBtu – million Btu
MWh – megawatt hour
kWh – kilowatt hour
Concentration
µg/m3 – micrograms per cubic meter
Visibility
dv – deciview
km – visual range in kilometers
Mm-1 – extinction in inverse megameters
ix
TABLE OF CONTENTS
Acknowledgments.......................................................................................................... vi
Unit, Species, Acronyms ............................................................................................... vii
Executive Summary ...................................................................................................... xii
1. INTRODUCTION................................................................................................1-1
2. STEAM ELECTRIC PLANTS (EGUs) ................................................................2-1
2.1. Description of generation process and typical technologies ...........................2-1
2.2. Review of BART-Eligible EGUs in the MANE-VU Region .........................2-2
2.3. Available Control Technologies....................................................................2-2
2.3.1. Emission Characteristics of Regional Haze Precursors from Coal
Combustion ..........................................................................................................2-4
2.3.2. Control Technologies used for Coal-fired EGUs ......................................2-5
2.3.3. Emission Control Configurations for Coal-fired Electric Utility Boilers .2-20
2.4. Costs and Availability of Technology .........................................................2-22
2.4.1. Detailed Capital Costs, Operating and Maintenance Costs, and Cost
Effectiveness ......................................................................................................2-22
3. INDUSTRIAL BOILERS.....................................................................................3-1
3.1. Description of Boiler Process........................................................................3-1
3.2. Review of BART-Eligible Industrial Boilers in the MANE-VU Region........3-2
3.3. Available Control Technologies....................................................................3-2
3.3.1. Emission Characteristics of Regional Haze Precursors from Industrial
Boilers ................................................................................................................3-3
3.3.2. Control Technologies used for Industrial Boilers......................................3-5
3.4. Costs of Technology...................................................................................3-12
3.4.1. NOX Technologies .................................................................................3-12
3.4.2. SO2 Technologies ..................................................................................3-13
3.4.3. PM Technologies ...................................................................................3-14
4. PORTLAND CEMENT KILNS ...........................................................................4-1
4.1. Description of Cement-Making Processes .....................................................4-1
4.2. Review of BART-Eligible Cement Kilns in the MANE-VU Region .............4-2
4.3. Available Control Technologies....................................................................4-3
4.3.1. SO2 Controls ............................................................................................4-3
4.3.2. NOX Controls...........................................................................................4-7
4.3.3. PM2.5 Controls .......................................................................................4-18
4.3.4. VOC Controls ........................................................................................4-20
4.4. Costs and Availability.................................................................................4-20
4.4.1. Sulfur Dioxide Control...........................................................................4-20
4.4.2. Nitrogen Oxides Control........................................................................4-22
4.4.3. PM2.5 Control.........................................................................................4-24
5. KRAFT PULP MILLS .........................................................................................5-1
5.1. Description of pulp and paper processes .......................................................5-1
5.2. Review of BART-Eligible Pulp and Paper facilities in the MANE-VU Region ..
.....................................................................................................................5-2
5.3. Available Control Technologies....................................................................5-2
x
5.3.1. SO2 Controls ............................................................................................5-3
5.3.2. NOX Controls...........................................................................................5-4
5.3.3. PM2.5 Controls .........................................................................................5-5
5.3.4. VOC Controls ..........................................................................................5-5
5.4. Costs and availability....................................................................................5-6
6. CONCLUSION ....................................................................................................6-1
6.1. EGUs............................................................................................................6-1
6.2. Industrial Boilers ..........................................................................................6-2
6.3. Cement Kilns................................................................................................6-2
6.4. Pulp Mills .....................................................................................................6-2
xi
Executive Summary
This report was prepared by the Northeast States for Coordinated Air Use
Management (NESCAUM) as part of an effort to assist states and tribes as they prepare
to comply with the Best Available Retrofit Technology Requirements (BART) of the
Regional Haze Rule. The Haze Rule requires states to determine the most stringent
technologically feasible system of controls that can reasonably be installed at each
facility eligible for BART. Criteria that determine whether a specific control technology
is deemed reasonable include: cost of the controls, other control technology in use at the
source, energy and other non-air quality environmental impacts, remaining useful life of
the source as well as the degree of visibility improvement anticipated to result from
installation of the controls.
This assessment provides information on available technology options, control
efficiency and typical installation costs for four important BART-eligible source
categories in the MANE-VU region. These categories include Fossil-fuel fired steam
electric plants of more than 250 million British thermal units per hour heat input, Fossilfuel boilers of more than 250 million British thermal units per hour heat input, Portland
cement plants, and Kraft pulp mills. While there are 22 other source categories covered
by the BART rule (with over 25 BART-Eligible facilities in at least 8 of these source
categories in the MANE-VU region), we have chosen to focus on these four categories
which include 75 of the 100 MANE-VU BART-Eligible sources identified at this time.
[Editors note: The addition of NY and PA non-EGU facilities will change these numbers]
These source sectors were chosen for a combination of factors including the number of
facilities, the typical emission level for these type of facilities and the availability of a
generic control technology characterizations for that sector. States will need to conduct
an individual analysis for each facility prior to making a BART determination. This
information is intended to facilitate that process by collecting available technology
information in a single reference document.
The report finds that significant emissions reductions can be achieved through a
variety of technologies that target different haze forming pollutants. While wet and dry
scrubbing techniques may be cost-effective means of removing SO2 at EGUs and large
industrial boilers, combustion modifications and process changes might be more effective
at cement plants and paper and pulp facilities. Similarly for NOX control, SCR and
SNCR are very efficient methods of post-combustion control that can be quite costeffective on large boilers, but combinations of combustion and post-controls as well as
combustion modification and process changes are also viable means of reducing a
facility’s total NOX emissions. These approaches need to be carefully considered on a
unit-by-unit basis, taking into account fuel used (coal, natural gas, oil, wood, etc.) and
capacity or use factors, to ensure that product quality and pollutant co-control issues are
handled appropriately. Particulate controls include a variety of technologies, but
electrostatic precipitators and fabric-filters (or baghouses) are viable options in different
configurations for EGUs, industrial boilers and cement plants. Paper and pulp facilities
may also consider demister pads, packed tower technologies and Venturi scrubbers.
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DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 1-1
1. INTRODUCTION
Under the U.S. Environmental Protection Agency’s (USEPA) 1999 “regional
haze rule” [64 Fed. Reg. 35714 (July 1, 1999)], certain emission sources that “may
reasonably be anticipated to cause or contribute” to visibility impairment in downwind
Class I areas are required to install Best Available Retrofit Technology (BART).1 These
requirements are intended to reduce emissions specifically from large sources that, due to
age, were exempted from other control requirements of the Clean Air Act (CAA).
BART requirements pertain to 26 specified major point source categories,
including power plants, industrial boilers, paper and pulp plants, cement kilns and other
large stationary sources. To be considered BART-eligible, sources from these specified
categories must have the potential to emit at least 250 tons per year of any haze forming
pollutant and must have commenced operation or come into existence in the fifteen year
period prior to August 7, 1977 (the date of passage of the 1977 Clean Air Act
Amendments (CAAA), which first required new source performance standards).
Because of the regional focus of the 1999 haze rule, it is likely that BART
requirements will be applied to a much larger number of sources across a broader
geographic region than has been the case historically (i.e. through reasonably attributable
visibility impairment requirements in the 1980 haze regulations). In addition, USEPA
has for the first time introduced the possibility that source-by-source, command and
control type BART implementation may be replaced by more flexible, market-based
approaches, provided such alternatives can be shown to achieve greater progress toward
visibility objectives than the standard BART approach.
In developing future haze state implementation plans (SIPs), states and tribes will
need to include an inventory of emissions from potentially BART-eligible facilities in
their jurisdictions and specify the timetable and stringency of controls to be applied at
those sources. In determining what level of control represents BART, states must address
the following considerations for each eligible source or group of eligible sources:
•
Compliance costs,
•
Energy and non-air quality environmental impacts,
•
Any existing pollution control technology in use at the source,
•
The remaining useful life of the source, and
•
The degree of visibility improvement that may reasonably be anticipated
to result from the imposition of BART.
In many respects, the strength of the BART program is dependent upon the
interpretation of these factors and in January 2001 USEPA proposed guidelines for the
interpretation and implementation of Best Available Retrofit Technology (BART)
requirements, including these factors. While no explicit threshold was established for
1
There are seven designated Class I areas in the Northeast and Mid-Atlantic States. They include Acadia
National Park and Moosehorn Wilderness Area in Maine; Roosevelt-Campobello International Park in New
Brunswick and Maine; the Lye Brook Wilderness Area in Vermont; the Great Gulf and Presidential RangeDry River Wilderness Areas in New Hampshire; and the Brigantine Wilderness Area in New Jersey.
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DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 1-2
any of these factors, the publication of the BART guidelines as a proposed rule in the
Federal Register [66 Fed. Reg. 38108 (July 20, 2001)] initiated a formal rulemaking
process to clarify BART requirements specifically.
BART is the primary mechanism identified for regulating haze-forming pollutants
from stationary sources for the first implementation period under the Haze Rule and the
final BART regulations, anticipated to be published on April 15, 2005, gives urgency to
understanding the implications of the final BART guidelines with respect to state
planning efforts. Depending on a host of factors, BART may be the primary component
of state haze plans or may be eliminated as a potential mechanism for state compliance.2
Amid such uncertainty, states must continue to plan for the implementation of BART.
To assist MANE-VU states and tribes with BART implementation efforts, MANE-VU
has developed a list of BART-eligible sources in the region (NESCAUM, 2001;
NESCAUM, 2003).3 The preliminary list developed in these documents has been
refined by state permitting staff to verify identifications and determine eligibility for
those sources for which incomplete information was available. The final, state-approved
(i.e. each state has approved the list of sources within that state) list is available here as
Appendix A. It should be noted that the review of the facilities for BART eligibility was
performed prior to the release of the draft BART rule in 2004. Determinations were
based upon the guidance provided in EPA draft rule released in 2001. It is anticipated
that EPA will release a final BART rule in April 2005 and at that time final BARTeligibility determinations will be made. It is likely that there will be changes to the
BART list based upon that final rule.
Once deemed BART-eligible, each source will undergo a BART engineering review to
determine what system of controls constitutes BART for each facility. This review will
examine impacts for all the BART pollutants. For example, if a facility triggeres BART
because it has VOC emissions over 250 tons per year for date-eligible units, the facility
will also have to examine the impacts of emissions of NOX, SO2, PM10 and ammonia,
even if emissions of these pollutants are less than 250 tons per year.
In addition, this review must take into account the statutory factors cited earlier including
remaining useful life of a source and controls already in place at a source. After review
of these criteria and control options, the level of required control will be established. It is
anticipated that the final rule will also address the specific aspects relating to the
completion of a BART engineering analysis.
2
A number of factors in the pending BART regulation may affect the strength of the program. Among
these are (1) a final decision on whether USEPA’s Clean Air Interstate Rule (CAIR) could serve as BART
for affected sources in states that choose this option, (2) final rules for how states may institute a source-bysource exemption test, (3) a decision on whether to aggregate emissions from multiple date-eligible boilers
at a facility when comparing to the 250 ton/year emission threshold. An additional factor to consider is a
provision contained in Senate Resolution 485 (the Clear Skies Act of 2003 which is expected to be reintroduced early in the 109th congress), which would act in place of the BART requirements of the regional
haze rule.
3
NESCAUM does not believe that there are any BART-eligible sources in the State of Vermont or any of
the member Tribes in MANE-VU and thus we have not developed lists for these jurisdictions. In addition,
Pennsylvania and the District of Columbia have developed BART-Eligible source lists following their own
methodology and the identified sources are contained in the final list in Appendix A.
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DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 1-3
As a next step in coordinating BART determinations for MANE-VU states and
tribes, we present here (in Chapters 3 through 6 of this report) a preliminary assessment
of available control technology options for states to consider as they undertake the
specific BART determinations for each of the eligible facilities in four major source
categories including EGUs, industrial boilers, cement plants and paper and pulp facilities.
These four categories cover 76 of the 101 BART-eligible facilities in MANE-VU.
While a facility specific review will need to be undertaken for each BARTeligibility (either to determine BART controls to be installed, or to determine the
magnitude of emissions reductions that must be considered in a BART trading program),
the information provided here will give states and tribes a foundation for conducting
these reviews.
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Page 2-1
2. STEAM ELECTRIC PLANTS (EGUs)
Electricity Generating Units or EGUs are the largest source category among the twenty six source categories covered by the Regional Haze Rule both in terms of total visibility
impairing emissions and in terms of number of facilities. Estimates of national emissions for
criteria air pollutants prepared by the USEPA show that electric utility power plants that burn
coal are significant sources of sulfur dioxide (SO2), nitrogen oxides (NOX), and particulate
matter (PM) (USEPA, 2000). Electric utility power plants are the nation’s largest source of SO2
emissions, contributing approximately 68 percent of the estimated total national SO2 emissions
in 1998 (most recent year for which national estimates are available). Over 90 percent of these
SO2 emissions are coal-fired electric utility boilers. Electric utilities contributed 25 percent of
total national NOX emissions in 1998. Again coal combustion is the predominant source of NOX
emissions from the electric utilities (almost 90 percent of the estimated NOX emissions). Coalfired electric utility power plants also are one of the largest industrial sources of PM emissions.
In general, the high combustion efficiencies achieved by coal-fired electric utility boilers result
in low emissions of CO and volatile organic compounds (a precursor for the photochemical
formation of ozone in the atmosphere). Although the emphasis of this Chapter is on coal-fired
utility boilers, many technologies described here are also applicable to gas and oil-fired units (for
example, SCR and SNCR technologies are equally applicable to coal and natural gas/oil units,
generally at much lower capital and operating costs; same is true for wet scrubbers for SO2
control and ESPs or baghouses for PM control for oil units).
All coal-fired electric utility power plants in the United States use control devices to
reduce PM emissions. Many coal-fired electric utility boilers also are required to use controls for
SO2 and NOX emissions depending on site-specific factors such as the properties of the coal
burned, when the power plant was built, and the area where the power plant is located. Though
there are other major stationary source sectors (for example, cement plants, paper and pulp
plants, large industrial boilers, combustion turbines, iron and steel industry), coal-fired boilers
are by far the largest contributor of all of these three precursors of regional haze.
2.1. Description of generation process and typical technologies
The USEPA ICR (Information Collection Request) of 1999 (the most recent and quite
detailed survey of coal-fired EGUs in the U.S. completed in connection with USEPA efforts to
develop MACT regulations for mercury from EGUs) indicates that there were about 1,140 coalfired units in the U.S. (with a maximum capacity to generate in excess of 300,000 MW of
power). This USEPA ICR data indicated that coal-fired steam electric generating units in the
U.S. burned 786 million tons of coal of which, approximately 52 percent was bituminous and 37
percent was sub-bituminous. Other fuels included lignite, anthracite coal, reclaimed waste coal,
mixtures of coal and petroleum coke (pet-coke), and mixtures of coal and tire-derived fuel
(TDF). Pulverized coal-fired (PC) boilers represent approximately 86 percent of the total
number and 90 percent of total utility boiler capacity. Based on capacity, other types of boilers
include cyclone-fired boilers (7.6 percent), fluidized-bed combustors (1.3 percent), and stokerfired boilers (1.0 percent).
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DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 2-2
2.2. Review of BART-Eligible EGUs in the MANE-VU Region
There are 53 BART-Eligible EGUs in the MANE-VU region. Table II-1 contains a
summary list of these sources by state. A complete list is presented in Appendix A. Both lists
are based on a previous NESCAUM report (2001) and follow-up review by state permitting
authorities. 4 An estimated 1.2 million tons of SO2 and three-hundred thousand tons of NOX are
emitted by these facilities and given the available control technology described in subsequent
sections of this chapter, BART-Eligible EGUs represent a significant emissions reduction
potential for consideration in the regional haze planning process.
Table II-1 BART-Eligible EGUs in the MANE-VU region. (NESCAUM, 2001).
Total
Number of
BART EGUs
Total SO2
Emissions
(1999 NEI)
Total NOX
Emissions
(1999 NEI)
Connecticut
5
30,787
8,217
Delaware
3
10,490
4,465
District of Columbia
1
1,432
447
Maryland
6
177,678
63,767
Massachusetts
7
97,854
27,350
Maine
1
6,406
879
New Hampshire
2
37,834
7,043
New Jersey
1
17,260
7,891
New York
13
73,164
31,392
Pennsylvania
14
744,165
151,992
Penobscot Tribe
0
N/A
N/A
Rhode Island
0
N/A
N/A
St. Regis Mohawk Tribe
0
N/A
N/A
Vermont
0
N/A
N/A
Region Total
53
1,197,070
303,443
State
2.3. Available Control Technologies
A variety of emission control technologies are employed to meet requirements for SO2,
NOX, and primary PM emissions; the three major precursors of observed regional haze in the
atmosphere (SO2 and NOX are mostly converted to ammonium sulfate and ammonium nitrate
4
NESCAUM does not believe that there are any BART-eligible sources in the State of Vermont or any of the
member Tribes in MANE-VU and thus we have not developed lists for these jurisdictions. In addition,
Pennsylvania and the District of Columbia have developed BART-Eligible source lists following their own
methodology and any identified sources are contained here and in the final list in Appendix A.
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Page 2-3
that are formed by the reactions of precursor gases with ammonia in the environment that is
emitted mostly from agricultural and cattle related activities). Most utilities control SO2 by the
use of either low-sulfur coal (generally less than 1 percent sulfur by weight) or by wet or dry
scrubbing (known as flue gas desulphurization, or FGD). Generally, NOX emissions are
controlled via combustion modification and, more recently, by more advanced post-combustion
controls, which are required by the 1990 Clean Air Act and state regulations ( “NOX Transport
SIP Call” and the Title IV of the 1990 CAAA are two major examples). Compared to these two
precursors, PM emissions are almost universally controlled in the U.S. (almost 100% of units
have either electrostatic precipitators (ESPs) or fabric filters (FF) (popularly known as “bag
houses”). Based on the 1999 USEPA’s ICR (Information Collection Request) data, for postcombustion controls, 77.4 percent of the units have PM control only, 18.6 percent have both PM
and SO2 controls, 2.5 percent have PM and NOX controls, and 1.3 percent have all three postcombustion control devices.
The different types of post-combustion control devices are briefly described below with
detailed descriptions given later in this section:
SO2 post-combustion control technologies are systems that are classified as wet flue gas
desulfurization (FGD) scrubbers, semi-dry scrubbers, or dry injection. Wet FGD scrubber
controls remove SO2 by dissolving it in a solution. A PM control device is always located
upstream of a wet scrubber. PM devices that may be used with wet FGD scrubbers include a
Particulate Scrubber (PS), Cold Side (CS)-ESP, Hot Side (HS)-ESP, or a fabric filter (FF) or a
baghouse. Semi-dry scrubbers include spray dryer absorption (SDA). Dry injection involves
injecting dry powdered lime or other suitable sorbent directly into the flue gas. A PM control
device (ESP or FF) is always installed downstream of a semi-dry scrubber or dry injection point
to remove the sorbent from the flue gas.
NOX post-combustion control technologies include selective non-catalytic reduction
(SNCR) and selective catalytic reduction (SCR) processes. With both of these methods, a
reducing agent such as ammonia or urea is injected into the duct to reduce NOX to N2. SCR
operates at lower temperatures than SNCR and is much more effective at reducing NOX, but it
has higher capital costs for installation.
Particulate matter (PM) control technologies include electrostatic precipitators (ESPs),
fabric filters (FFs) (also called “baghouses”), and particulate scrubbers (PS). ESPs and FFs may
be classified as either cold-side (CS) devices [installed upstream of the air heater where flue gas
temperatures range from 284 to 320 ºF (140 to 160 °C)] or hot-side [installed downstream of the
air heater and operate at temperatures ranging from 662 to 842 ºF (350 to 450 °C)].
For PM controls, ESPs are used on 84 percent of the existing electric utility coal-fired
boiler units, and fabric filters or baghouses are used on 14 percent of the utility units. Postcombustion SO2 controls are less common. Wet flue gas desulfurization (FGD) systems are used
on 15.1 percent of the units; and, dry scrubbers, predominantly spray dryer absorbers (SDA), are
used on 4.6 percent of units that were surveyed. However, since it is generally more cost
effective to install scrubbers on big units, the 20 percent of the units represent about 30% of the
installed U.S. capacity. In response to the “Section 110 Transport SIP call” and the
implementation of the Federal Title IV acid rain program, the application of post-combustion
NOX controls is becoming more prevalent. For example, based on the current status of electric
utility industry, it appears that one third of the coal-based capacity (about 100,000 MW out of the
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DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 2-4
installed base of about 300,000 MW) has been or is currently being retrofitted with the advanced
SCR technology .
2.3.1. Emission Characteristics of Regional Haze Precursors from Coal
Combustion
Sulfur Dioxide
SO2 emissions, mostly from the combustion of fossil fuels and by metallurgical
processes, are the result of oxidation of sulfur in the coal during the combustion process. Coal
deposits contain sulfur in amounts ranging from trace quantities to as high as eight percent or
more. Most of this sulfur is present as either pyritic sulfur (sulfur combined with iron in the
form of a mineral that occurs in the coal deposit) or organic sulfur (sulfur combined directly in
the coal structure). During combustion, sulfur compounds in coal are oxidized to gaseous SO2 or
SO3. When firing bituminous coal, almost all of the sulfur present in coal is emitted as gaseous
sulfur oxides (on average, ninety eight percent). The more alkaline nature of ash in some
subbituminous coals causes a portion of the sulfur in the coal to react to form various sulfate
salts; these salts are emitted as fly ash or retained in the boiler bottom ash. Generally, the
percentage of sulfur in the as-fired coal that is converted to sulfur oxides during combustion does
not vary with the utility boiler design or operation. (USEPA, 1982; Buonicore and Davis, 1992).
Nitrogen Oxides
The NOX formed during coal combustion by oxidation of molecular nitrogen (N2) in the
combustion air is referred to as “thermal NOX.” The oxidation reactions converting N2 to NO
and NO2 become very rapid once gas temperatures rise above 1,700°C (3,100°F). Formation of
thermal NOX in a coal-fired electric utility boiler is dependent on two conditions occurring
simultaneously in the combustion zone: high temperature and an excess of combustion air. A
boiler design feature or operating practice that increases the gas temperature above 1,700 °C, the
gas residence time at these temperatures and the quantity of excess combustion air affects
thermal NOX formation. The formation of NOX by oxidation of nitrogen compounds contained
in the coal is referred to as “fuel NOX.” The nitrogen content in most coals ranges from
approximately 0.5 to 2 percent. The amount of nitrogen available in the coal is relatively small
compared with the amount of nitrogen available in the combustion air. However, depending on
the combustion conditions, significant quantities of fuel NOX can be formed during coal
combustion. (USEPA, 1991; Buonicore and Davis, 1992).
Both NO and NO2 are formed during coal combustion by oxidation of molecular nitrogen
that is present in the combustion air or nitrogen compounds contained in the coal. Overall, total
NOX formed during combustion is composed predominantly of NO mixed with small quantities
of NO2 (typically less than 10 percent of the total NOX formed). However, when NO is formed
during coal combustion, the NO is oxidized to NO2 and is emitted to the atmosphere.
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Particulate Matter
Primary PM emissions from coal-fired electric utility boilers consist primarily of fly ash.
Ash is the unburned carbon char and the mineral portion of combusted coal. The amount of ash
in the coal, which ultimately exits the boiler unit as fly ash, is a complex function of the coal
properties, furnace-firing configuration, and boiler operation. For the dry-bottom, pulverizedcoal-fired boilers, approximately 80 percent of the total ash in the as-fired coal exits the boiler as
fly ash. Wet-bottom, pulverized-coal-fired boilers emit significantly less fly ash: on the order of
50 percent of the total ash exits the boiler as fly ash. In a cyclone furnace boiler, most of the ash
is retained as liquid slag; thus, the quantity of fly ash exiting the boiler is typically 20 to 30
percent of the total ash. However, the high operating temperatures unique to these designs may
also promote ash vaporization and larger fractions of submicron fly ash compared to dry bottom
designs. Fluidized-bed combustors emit high levels of fly ash since the coal is fired in
suspension and the ash is present in dry form. Spreader-stoker-fired boilers can also emit high
levels of fly ash. However, overfeed and underfeed stokers emit less fly ash than spreader
stokers, since combustion takes place in a relatively quiescent fuel bed.
In addition to the fly ash, PM emissions from coal-fired EGUs result from reactions of
the SO2 and NOX compounds as well as unburned carbon particles carried in the flue gas from
the boiler. The SO2 and NOX compounds are initially in the vapor phase following coal
combustion in the furnace chamber but can partially chemically transform in the stack, or near
plume, to form fine PM in the form of nitrates, sulfur trioxide (SO3), and sulfates. Firing
configuration and boiler operation can affect the fraction of carbon (from unburned coal)
contained in the fly ash. In general, the high combustion efficiencies achieved by pulverizedcoal-fired boilers and cyclone-fired boilers result in relatively small amounts of unburned carbon
particles in the exiting combustion gases. Those pulverized-coal-fired electric utility boilers that
use special burners for NOX control tend to burn coal less completely; consequently, these
furnaces tend to emit a higher fraction of unburned carbon in the combustion gases exiting the
furnace.
Another potential source of PM from coal-fired EGUs can be found in the flue gas and
the use of a dry sorbent-based control technology. Solid sorbent particles are injected into the
combustion gases to react with the air pollutants and then recaptured by a downstream control
device. Sorbent particles that escape capture by the control device are emitted as PM to the
atmosphere. (USEPA, 1982; Buonicore and Davis, 1992).
2.3.2. Control Technologies used for Coal-fired EGUs
In addition to BART requirements, all EGUs in the U.S. must comply with applicable
federal and state standards and programs that specifically regulate criteria air emissions from
coal-fired electric utility boilers. The federal regulations and programs include New Source
Performance Standards (NSPS), the CAA Title IV Acid Rain Program, the 1997 “Transport NOX
SIP call,” and the CAA Title V Operating Permits Program. The USEPA has delegated authority
to individual state and local agencies for implementing many of these regulatory requirements
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Additionally, some of the states in the Northeast, including Connecticut, Massachusetts, New
Hampshire, New Jersey, and New York, have recently implemented new regulations or
legislation that are more stringent than the federal requirements. Electric utility companies use
one or a combination of the following three control strategies to comply with the specific set of
requirements applicable to a given coal-fired boiler.
Pre-combustion Controls. Control measures in which fuel substitutions are made or fuel
pre-processing is performed to reduce pollutant formation in the combustion unit.
Combustion Controls. Control measures in which operating and equipment
modifications are made to reduce the amount of pollutants formed during the combustion
process; or in which a material is introduced into the combustion unit along with the fuel
to capture the pollutants formed before the combustion gases exit the unit.
Post-combustion Controls: Control measures in which one or more air pollution control
devices are used at a point downstream of the furnace combustion zone to remove the
pollutants from the post-combustion gases.
Table II-2 shows the national distribution of emissions control strategies for SO2, NOX,
and PM used for coal-fired electric utility boilers in 1999 as reported in the Part II USEPA ICR
data (USEPA, 2001). Approximately two-thirds of the total coal-fired electric utility boilers
use either a low-sulfur fuel or a post-combustion technology (a wet or a dry scrubber) to control
SO2 emissions. The methods used for controlling SO2 emissions from EGUs are discussed first.
All coal-fired electric utility boilers in the United States are controlled for PM emissions by
using some type of post-combustion controls. These particulate emission control types are
discussed next. Although approximately two-thirds of the coal-fired electric utility boilers are
controlled for NOX emissions, these units are not necessarily the same units controlled for SO2
emissions. The predominant strategy for controlling NOX emissions is to use combustion
controls. Later in this section, the application of NOX emission controls to coal-fired electric
utility boilers is described in detail.
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Table II-2 Criteria air pollutant emission control strategies as applied to coal-fired electric
utility boilers in the United States for the year 1999 (USEPA, 2001).
Percentage of Coal-fired Electric Utility Boilers Using Control
Strategy as Reported in Phase II USEPA ICR Data a,b
Meet
Applicable
Standards
Without
Additional
Controls
Precombustion
Controls
Combustion
Controls
Postcombustion
Controls
Particulate
Matter
0%
0%
0%
100 %
Sulfur
Dioxide
37 %
40 %
3%
20 %
Nitrogen
Oxides
40 %
0%
57 %
3%
Criteria
Air Pollutant
(a) Approximately 1.5 % of the boilers use a combination of pre-combustion and post-combustion SO2
controls.
(b) Approximately 1% of the boilers using post-combustion NOX controls also use some type of combustion
controls.
SO2 Emission Controls
Sulfur dioxide emissions from most coal-fired electric utility boilers are controlled using
either of two basic approaches. The first approach is to use pre-combustion measures, namely,
firing coal that contains lower amounts of sulfur. The low-sulfur coal may be naturally occurring
or the result of coal cleaning. The other approach is to remove the sulfur compounds from the
flue gas before the gas is discharged to the atmosphere. These post-combustion processes are
collectively called “flue gas desulfurization” or “FGD” systems. All FGD systems can be further
classified as wet or dry flue gas scrubbing systems. The SO2 control approaches include a
number of different technology subcategories that are now commercially used in the United
States, Europe, or Pacific Rim countries.
Table II-3 presents the 1999 nationwide distribution of SO2 controls used for coal-fired
electric utility boilers by total number of units and by percentage of nationwide electricity
generating capacity. For approximately one-third of the boilers, no SO2 controls were reported in
the Part II USEPA ICR data. The other two-thirds of the units reported using some type of
control to meet the SO2 emission standards applicable to the unit. Pre-combustion control by
burning a low-sulfur content coal was reported for approximately 40 percent of the boilers. Postcombustion control devices for SO2 removal are used for approximately 20 percent (representing
30% of the capacity in megawatts) of the boilers. Wet FGD systems are the most commonly used
post-combustion control technique. The newer technologies of spray dryer systems or dry
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injection are limited in their application to existing units. The remaining 3 percent of the boilers
use fluidized-bed combustion (FBC) with limestone.
Low-sulfur Coal
Coal with low sulfur content can be burned and meet applicable SO2 emission standards
without the use of additional controls is sometimes referred to as “compliance coal.” Coals
naturally low in sulfur content may be mined directly from the ground. Alternatively, the sulfur
content of coal fired in the boiler may be lowered first by cleaning the coal or blending coals
obtained from several sources. However, burning low-sulfur coal may not be a technically
feasible or economically practical SO2 control alternative for all boilers. In some cases, a coal
with the required sulfur content to meet the applicable standard may not be available or cannot
be fired satisfactorily in a given boiler unit design. Even if such a coal is available, use of the
low-sulfur coal that must be transported long distances from the mine may not be costcompetitive with burning higher sulfur coal supplied by closer mines and using a postcombustion control device.
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Table II-3 Nationwide distribution of existing SO2 emissions controls used for coal-fired
electric utility boilers for the year 1999 as reported in the Part II USEPA ICR data
(USEPA, 2001).
Phase II USEPA ICR Data
SO2 Control Type
Abbreviation
Code
Number
of Boilers
Percent of
Nationwide
Total
Number of
Units
Percent of
Nationwide
Electricity
Generating
Capacity
Burn low-sulfur coal
(“compliance coal”)
LSC
455
39.9 %
38.2 %
Wet FGD system
FGD
173 (a)
15.2 %
23.8 %
Spray dryer system
SDA
52 (b)
4.6%
3.4 %
Fluidized-bed coal
combustion with limestone
FBC
37 (a,c)
3.2%
1.1 %
Dry injection
DI
2
0.2 %
< 0.1 %
421
36.9 %
33.5 %
1,140 (e)
100 %
100 %
No controls reported (d)
Nationwide Total
(a) Includes one FBC boiler unit using a wet FGD system.
(b) Includes three FBC boilers using spray dryer systems.
(c) FBC boilers using no downstream post-combustion SO2 controls.
(d) Entry in ICR response indicated none or was left blank.
(e) Does not include the three IGCC units.
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Various coal cleaning processes may be used to reduce the sulfur content of the coal. A
significant portion of the pyritic sulfur minerals mixed with the mined coal can usually be
removed by physical gravity separation or surface property (flotation) methods. However,
physical coal cleaning methods are not effective for removing the organic sulfur bound in coal.
Another method of reducing the overall sulfur content of the coal burned in a given boiler unit is
to blend coals with different sulfur contents to meet a desired or target sulfur level.
Wet FGD Systems
The SO2 in flue gas can be removed by reacting the sulfur compounds with a solution of
water and an alkaline chemical to form insoluble salts that are removed in the scrubber effluent.
These processes are called “wet FGD systems” in this report. Most wet FGD systems for control
of SO2 emissions from coal-fired electric utility boilers are based on using either limestone or
lime as the alkaline source. At some of these facilities, fly ash is mixed with the limestone or
lime. Several other scrubber system designs (e.g., sodium carbonate, magnesium oxide, dual
alkali) are also used by a small percentage of the total number of boilers.
The basic wet limestone scrubbing process is simple and is the type most widely used for
control of SO2 emissions from coal-fired electric utility boilers. Limestone sorbent is
inexpensive and generally available throughout the United States. In a wet limestone scrubber,
the flue gas containing SO2 is brought into contact with limestone/water slurry. The SO2 is
absorbed into the slurry and reacts with limestone to form an insoluble sludge. The sludge,
mostly calcium sulfite hemihydrate and gypsum, is disposed of in a pond specifically constructed
for the purpose or is recovered as a salable byproduct.
The wet lime scrubber operates in a similar manner to the wet limestone scrubber. In a
wet lime scrubber, flue gas containing SO2 is contacted with hydrated lime/water slurry; the SO2
is absorbed into the slurry and reacts with hydrated lime to form an insoluble sludge. The
hydrated lime provides greater alkalinity (higher pH) and reactivity than limestone. However,
lime-scrubbing processes require appropriate disposal of large quantities of waste sludge.
The SO2 removal efficiencies of existing wet limestone scrubbers range from 31 to 97
percent, with an average of 78 percent. The SO2 removal efficiencies of existing wet lime
scrubbers range from 30 to 95 percent. For both types of wet scrubbers, operating parameters
affecting SO2 removal efficiency include liquid-to-gas ratio, pH of the scrubbing medium, and
the ratio of calcium sorbent to SO2. Periodic maintenance is needed because of scaling, erosion,
and plugging problems. Recent advancements include the use of additives or design changes to
promote SO2 absorption or to reduce scaling and precipitation problems.
Spray Dryer Absorber
A spray dryer absorber (sometimes referred to as wet-dry or semi-dry scrubbers) operates
by the same principle as wet lime scrubbing, except that the flue gas is contacted with a fine mist
of lime slurry instead of a bulk liquid (as in wet scrubbing). For the spray dryer absorber
process, the combustion gas containing SO2 is contacted with fine spray droplets of hydrated
lime slurry in a spray dryer vessel. This vessel is located downstream of the air heater outlet
where the gas temperatures are in the range of 120 to 180 °C (250 to 350 °F). The SO2 is
absorbed in the slurry and reacts with the hydrated lime reagent to form solid calcium sulfite and
calcium sulfate as in a wet lime scrubber. The water is evaporated by the hot flue gas and forms
dry, solid particles containing the reacted sulfur. These particles are entrained in the flue gas,
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along with fly ash, and are collected in a PM collection device. Most of the SO2 removal occurs
in the spray dryer vessel itself, although some additional SO2 capture has also been observed in
downstream particulate collection devices, especially fabric filters. This process produces dry
reaction waste products for easy disposal.
The primary operating parameters affecting SO2 removal are the calcium-reagent-tosulfur stoichiometric ratio and the approach to saturation in the spray dryer. To increase overall
sorbent use, the solids collected in the spray dryer and the PM collection device may be recycled.
The SO2 removal efficiencies of existing lime spray dryer systems range from 60 to 95 percent.
Dry Injection
For the dry injection process, dry powdered lime (or another suitable sorbent) is directly
injected into the ductwork upstream of a PM control device. Some systems use spray
humidification followed by dry injection. This dry process eliminates the slurry production and
handling equipment required for wet scrubbers and spray dryers, and produces dry reaction waste
products for easier disposal. The SO2 is adsorbed and reacts with the powdered sorbent. The dry
solids are entrained in the combustion gas stream, along with fly ash, and collected by the PM
control device. The SO2 removal efficiencies of existing dry injection systems range from 40 to
60 percent.
Circulating Fluidized-bed Absorber
In the circulating fluidized-bed absorber (CFBA), the flue gas flows upward through a
bed of sorbent particles to produce a fluid-like condition in the bed. This condition is obtained
by adjusting gas flow rate sufficiently to support the particles, but not carry them out of the
system. Characteristics of the bed are high heat and mass transfer, because of high mixing rates,
and particle-to-gas contact. These conditions allow the CFBA’s bed of sorbent particles to
remove a sorbate from the gas stream with high effectiveness. In a CFBA, material is withdrawn
from the bed for treatment (such as desorption) then re-injected into the bed. The SO2 removal
efficiencies for CFBA technologies range from 80 to 98 percent, providing a very effective
means of control.
NOX Emission Controls
Control techniques used to reduce NOX formation include combustion and postcombustion control measures. Combustion measures consist of operating and equipment
modifications that reduce the peak temperature and excess air in the furnace. Post-combustion
control involves converting the NOX in the flue gas to molecular nitrogen and water using either
a process that requires a catalyst (selective catalytic reduction) or a process that does not use a
catalyst (selective noncatalytic reduction).
Table II-4 presents the 1999 nationwide distribution of NOX controls used for coal-fired
electric utility boilers by total number of units and by percentage of nationwide electricity
generating capacity. Approximately one-third of the boilers do not use additional NOX controls.
The other two-thirds of the units use additional controls to meet the applicable NOX standards.
The predominant control NOX strategy is to use one or more combustion control techniques.
Post-combustion NOX reduction technologies (both catalytic and noncatalytic) accounted for
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only a small percentage of the NOX emission controls used in 1999 (approximately three percent
of the total units). However, a number of electric utilities have recently retrofitted are currently
actively retrofitting a large number of units with advanced SCR technology to meet the
requirements of the federal Title IV acid rain program or the Section 110 Transport SIP call.
Combustion Controls
A variety of combustion control practices can be used including low-NOX burners
(LNBs), overfire air, off-stoichiometric firing, selective or biased burner firing, reburning, and
burners-out-of-service. Control of NOX also can be achieved through staged combustion (also
called air staging). With staged combustion, the primary combustion zone is fired with most of
the air needed for complete combustion of the coal. The remaining air is introduced into the
products of the partial combustion in a secondary combustion zone. Air staging lowers the peak
flame temperature, thereby reducing thermal NOX, and lowering the production of fuel NOX by
reducing the oxygen available for combination with the fuel nitrogen. Staged combustion may
be achieved through methods that require modifying equipment or operating conditions so that a
fuel-rich condition exists near the burners (e.g., using specially designed low- NOX burners,
selectively removing burners from service, or diverting a portion of the combustion air). In
cyclone boilers and some other wet bottom designs, combustion occurs with a molten ash layer
and the combustion gases flow to the main furnace; this design precludes the use of low NOX
burners and air staging. Low-NOX burners may be used to lower NOX emissions by about 25 to
55 percent. Use of overfire air (OFA) as a single NOX control technique reduces NOX by 15 to
50 percent. When OFA is combined with low- NOX burners, reductions of up to 60 percent may
result. The actual NOX reduction achieved with a given combustion control technique may vary
from boiler to boiler.
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Table II-4 Nationwide distribution of existing NOX emissions controls used for coal-fired
electric utility boilers for the year 1999 as reported in the Part II USEPA ICR data
(USEPA, 2001).
Phase II USEPA ICR Data
NOX Control Type
Abbreviation
Code
Combustion controls low- NOX burners
Nationwide
Number
of
Boilers
Nationwide
Percentage
of
Boilers
Percent of
Nationwide
Electricity
Generating
Capacity
CC-LNB
404
35.4 %
43.0 %
Combustion controls low- NOX burners +
overfire air
CC-LNB/OFA
84
7.4 %
10.4 %
Combustion controls overfire air
CC-OFA
79
6.9 %
10.6 %
Other combustion
controls (a)
CC
83
7.3 %
5.6 %
Selective noncatalytic
reduction
SNCR
32
2.8 %
0.6 %
Selective catalytic
reduction
SCR
6
0.5 %
1.3 %
452
39.7%
28.5 %
1,140 (c)
100 %
100 %
No controls reported (b)
Nationwide Total
(a) Combustion controls other than low-NOX burners or overfire air. The controls include burners-out-of
service, flue gas recirculation, off-stoichiometric firing, and fluidized-bed combustion.
(b) Entry in ICR response indicated “none,” “not applicable,” or was left blank.
(c) Does not include the three IGCC units.
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Just as the combustion air to the primary combustion zone can be reduced, part of the fuel
may be diverted to create a secondary flame with fuel-rich conditions downstream of the primary
combustion zone. This combustion technique is termed reburning and involves injecting 10 to
20 percent of the fuel after the primary combustion zone and completing the combustion with
overfire air. The fuel injected downstream may not necessarily be the same as that used in the
primary combustion zone. In most applications of reburning, the primary fuel is coal and the
reburn fuel is natural gas (methane), and the technology is known as “gas reburn.”
Other ways to reduce NOX formation by reducing peak flame temperature include using
flue gas recirculation (FGR), reducing boiler load, injecting steam or water into the primary
combustion zone, and increasing spacing between burners. By using FGR to return part of the
flue gas to the primary combustion zone, the flame temperature and the concentration of oxygen
in the primary combustion zone are reduced. Increasing the space between burners provides
greater heat transfer to heat-absorbing surfaces. Another combustion control technique involves
reducing the boiler load. In this case, the formation of thermal NOX generally decreases directly
with decreases in heat release rate; however, reducing the load may cause poor air and fuel
mixing and increase CO and soot emissions.
Selective Catalytic Reduction
The selective catalytic reduction (SCR) process uses a catalyst with ammonia gas (NH3)
to reduce the NO and NO2 in the flue gas to molecular nitrogen and water. The ammonia gas is
diluted with air or steam, and this mixture is injected into the flue gas upstream of a metal
catalyst bed (composed of vanadium, titanium, platinum, or zeolite). In the reactor, the reduction
reactions occur at the catalyst surface. Typically some ammonia exits the catalyst, on the order
of 1-5 ppm in the flue gas; this is called “ammonia slip”. The SCR catalyst bed reactor is usually
located between the economizer outlet and air heater inlet, where temperatures range from 230 to
400 °C (450 to 750 °F). The catalyst modules take up a considerable amount of space; in
addition ductwork must be added for the ammonia injection section. There is not always room in
an existing boiler to retrofit an SCR system. As a consequence, fan capacity may have to be
increased, owing to the incremental pressure drop from the SCR and associated ductwork. In
some cases, the boiler must be modified to increase the economizer exit temperature to the
minimum and/or the air preheater must be modified. Installation of an SCR on a boiler is sitespecific and this results in a range of capital costs for SCR systems on boilers.
SCR catalysts in coal- and oil-fired boilers oxidize a small fraction of the SO2 in the flue
gas to produce SO3. The SO3 in the flue gas from an SCR may only be on the order of 10 ppm
(depending on the sulfur-content of the fuel), but it can have impacts on the downstream
equipment and emissions. The combination of ammonia slip and increased SO3 can form
deposits of ammonium bisulfate in the air preheater. SO can condense in the flue gas in the form
of a fine aerosol of sulfuric acid, which can cause a visible plume, the so-called “blue plume”.
Selective Noncatalytic Reduction
The selective noncatalytic reduction (SNCR) process is based on the same basic
chemistry of reducing the NO and NO2 in the flue gas to molecular nitrogen and water but does
not require the use of a catalyst to prompt these reactions. Instead, the reducing agent is injected
into the flue gas stream at a point where the flue gas temperature is within a very specific
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temperature range. Currently, two SNCR processes are commercially available: the THERMAL
DeNOX and the NOXOUT (USEPA, 1998). The THERMAL DeNOX uses ammonia gas as the
reagent and requires the gas be injected where the flue gas temperature is in the range of 870 to
1090 °C (1,600 to 2,000 °F). Consequently, the ammonia gas is injected at a location upstream
of the economizer. However, if the ammonia is injected above 1,090 °C (2,000 ºF), the ammonia
will oxidize and will result in the formation of excess NOX emissions. Once the flue gas
temperature drops below the optimum temperature range, the effectiveness of the process drops
significantly. By adding hydrogen gas or other chemical enhancers, the reduction reactions can
be sustained to temperatures down to approximately 700 °C (1,300 °F). The NOXOUT is a
similar process but uses an aqueous urea solution as the reagent in place of ammonia.
Using nitrogen-based reagents requires operators of SNCR systems to closely monitor
and control the rate of reagent injection. If injection rates are too high, NOX emissions may
increase, and stack emissions of ammonia in the range of 10 to 50 ppm may also result. A
portion (usually around 5 percent) of the NO reduction by SNCR systems results from
transformation of NO to N2O, which is a global warming gas.
Particulate Matter Emission Controls
Four types of control devices are used to collect PM emissions from coal-fired electric
utility boilers: electrostatic precipitators, fabric filters, mechanical collectors, and particle
scrubbers. Table II-5 presents the 1999 nationwide distribution of PM controls on coal-fired
electric utility boilers by total number of units and by percentage of nationwide electricity
generating capacity. Electrostatic precipitators are the predominant control type used on coalfired electric utility boilers both in terms of number of units (84 percent) and total generating
capacity (87 percent). The second most common control device type used is a fabric filter.
Fabric filters are used on about 14 percent of the coal-fired electric utility boilers. Particle
scrubbers are used on approximately three percent of the boilers. The least used control device
type is a mechanical collector. Less than one percent of the coal-fired electric utility boilers use
this type of control device as the sole PM control. Other boilers equipped with a mechanical
collector use this control device in combination with one of the other PM control device types.
Electrostatic Precipitators
Electrostatic precipitator (ESP) control devices have been used to control PM emissions
for over 80 years. These devices can be designed to achieve high PM collection efficiencies
(greater than 99 percent), but at the cost of increased unit size. An ESP operates by imparting an
electrical charge to incoming particles, and then attracting the particles to oppositely charged
metal plates for collection. Periodically, the particles collected on the plates are dislodged in
sheets or agglomerates (by rapping the plates) and fall into a collection hopper. The dust
collected in the ESP hopper is a solid waste that must be disposed of.
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Table II-5 Nationwide distribution of existing PM emission controls used for coal-fired
electric utility boilers for the year 1999 (USEPA, 2001).
Phase II USEPA ICR Data
PM
Control Type
Abbreviation
Code
Electrostatic precipitator
(Cold-side)
Number
of Boilers
Percent of
Nationwide
Total
Number of
Units
Percent of
Nationwide
Electricity
Generating
Capacity
CS- ESP
822 (a)
72.1 %
74.7 %
Electrostatic precipitator
(Hot-side)
HS-ESP
122
10.8 %
11.3 %
Fabric filter
FF
155 (b)
13.6 %
9.4 %
Particle scrubber
PS
23 (c)
2.0%
3.0 %
Mechanical collector (d)
MC
5
0.4 %
0.2 %
13
1.1 %
1.4 %
1,140 (f)
100 %
100 %
Multiple control device
combinations (e)
Nationwide Total
(a) Includes 10 boilers with cold-side ESP in combination with upstream mechanical collector.
(b) Includes eight boilers with baghouse in combination with upstream mechanical collector.
(c) Includes two boilers with particle scrubber in combination with upstream mechanical collector.
(d) Boilers using mechanical collector as only PM control device.
(e) Boilers using a combination of two or more different control device types other than mechanical
collectors. Includes two boilers that use a hot-side ESP in series with a cold-side ESP.
(f) Does not include the three IGCC units.
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The effectiveness of particle capture in an ESP depends largely on the electrical
resistance of the particles being collected. An optimum value exists for a given ash. Above and
below this value, particles become less effectively charged and collected. Table II-6 presents the
PM collection efficiency of an ESP compared with the other control device types. Coal that
contains a moderate to high amount of sulfur (more than approximately three percent) produces
an easily collected fly ash. Low-sulfur coal produces a high-resistivity fly ash that is more
difficult to collect. Resistivity of the fly ash can be changed by operating the boiler at a different
temperature or by conditioning the particles upstream of the ESP with sulfur trioxide, sulfuric
acid, water, sodium, or ammonia. In addition, collection efficiency is not uniform for all particle
sizes. For coal fly ash, particles larger than about 1 to 8 µm and smaller than about 0.3 µm (as
opposed to total PM) are typically collected with efficiencies from 95 to 99.9 percent. Particles
near the 0.3 µm size are in a poor charging region that reduces collection efficiency to 80 to 95
percent.
An ESP can be used at one of two locations in a coal-fired electric utility boiler system.
For many years, every ESP was installed downstream of the air heater where the temperature of
the flue gas is between 130 and 180 °C (270 and 350 °F). An ESP installed at this location is
referred is as a "cold-side" ESP. However, to meet SO2 emission requirements, many electric
utilities switched to burning low-sulfur coal (discussed in Section 2.3.2 under SO2 controls).
These coals have higher electrical ash resistivities, making the fly ash more difficult to capture
downstream of the air heater. Therefore, to take advantage of the lower fly-ash resistivities at
higher temperatures, some ESPs are installed upstream of the air heater, where the temperature
of the flue gas is in the range of 315 to 400 °C (600 to 750 °F). An ESP installed upstream of the
air heater is referred to as a "hot-side" ESP. (Buonicore and Davis, 1992; USEPA, 1998).
Fabric Filters
Fabric filters (FF) have been used for fly ash control from coal-fired electric utility
boilers for about 30 years. This type of control device collects fly ash in the combustion gas
stream by passing the gases through a porous fabric material. The buildup of solid particles on
the fabric surface forms a thin, porous layer of solids or a filter, which further acts as a filtration
medium. Gases pass through this cake/fabric filter, but the fly ash is trapped on the cake surface.
The fabric material used is typically fabricated in the shape of long, cylindrical bags. Hence,
fabric filters also are frequently referred to as "baghouses."
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Table II-6 Comparison of PM collection efficiencies for different
PM control device types (Buonicore and Davis, 1992).
PM
Control Type
Representative PM
Mass Collection Efficiency Range
Total
PM
PM
less than 0.3 µm
Electrostatic
precipitator
(Cold-side)
99 to 99.7 %
80 to 95 %
Electrostatic
precipitator
(Hot-side)
99 to 99.7 %
80 to 95 %
Fabric filter
99 to 99.9 %
99 to 99.8%
Particle scrubber
95 to 99 %
30 to 85 %
Mechanical collector
70 to 90 %
0 to 15 %
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DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 2-19
Gas flow through a FF becomes excessively restricted if the filter cake on the bags
becomes too thick. Therefore, the dust collected on the bags must be removed periodically. The
type of mechanism used to remove the filter cake classifies FF design types. Depending on the
FF design type, the dust particles will be collected either on the inside or outside of the bag. For
designs in which the dust is collected on the inside of the bags, the dust is removed by either
mechanically shaking the bag (called a "shaker type" FF) or by blowing air through the bag from
the opposite side (called a "reverse-air" FF). An alternate design mounts the bags over internal
frame structures, called "cages" to allow collection of the dust on the outside of the bags. A
pulsed jet of compressed air is used to cause a sudden stretching then contraction of the bag
fabric dislodging the filter cake from the bag. This design is referred to as a "pulse-jet" FF. The
dislodged dust particles fall into a hopper at the bottom of the baghouse. The dust collected in
the hopper is a solid waste that must be disposed of.
An FF must be designed and operated carefully to ensure that the bags inside the
collector are not damaged or destroyed by adverse operating conditions. The fabric material
must be compatible with the gas stream temperatures and chemical composition. Because of the
temperature limitations of the available bag fabrics, location of an FF for use in a coal-fired
electric utility boiler is restricted to downstream of the air heater. In general, fabric filtration is
the best commercially available PM control technology for high-efficiency collection of small
particles.
Electrostatic stimulation of fabric filtration (ESFF) involves a modified fabric filter that
uses electrostatic charging of incoming dust particles to increase collection efficiency and reduce
pressure drop compared to fabric filters without charging. Filter bags are specially made to
include wires or conductive threads, which produce an electrical field parallel to the fabric
surface. Conductors can also be placed as a single wire in the center of the bag. When the bags
are mounted in the baghouse, the conductors are attached to a wiring harness that supplies
electricity. As particles enter the field and are charged, they form a porous mass or cake of
agglomerates at the fabric surface. Greater porosity of the cake reduces pressure drop, while the
agglomeration increases efficiency of small particle collection. Cleaning is required less
frequently, resulting in longer bag life. For felted or nonwoven bags, the field promotes
collection on the outer surface of the fabric, which also promotes longer bag life. Filtration
velocity can be increased so that less fabric area is required in the baghouse. The amount of
reduction is based on an economic balance among desired performance, capital cost, and
operating costs. A number of variations exist on the ESFF idea of combining particle charging
with fabric filtration. (Buonicore and Davis, 1992; Turner and McKenna, 1989).
Particle Scrubbers and Mechanical Collectors
Particle scrubbers are generally much less efficient than ESPs and baghouses (especially
in collecting finer fraction of PM). For this reason and because they entail higher operating costs
associated with achieving high collection efficiency, they are not widely used in the industry.
Similarly, mechanical collectors have the least collection efficiency and are hardly used in the
industry. These two methods are not discussed further in this report. (Buonicore and Davis,
1992).
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2.3.3. Emission Control Configurations for Coal-fired Electric Utility Boilers
Table II-7 presents the 1999 nationwide distribution of post-combustion control device
configurations used for coal-fired electric utility boilers. For approximately 70 percent of the
boilers, the only control device used downstream of the furnace is an ESP. If the unit is subject
to SO2 and/or NOX emission limit standards, these units do burn low-sulfur coals to meet the SO2
emission limit and use some type of NOX combustion controls to meet the NOX emission limit.
Approximately 25 percent of the boilers use some combination of post-combustion control
devices. The most common configuration used is an ESP with a downstream wet scrubber for
SO2 control. Less than 2 percent of the units used a combination of PM, SO2, and NOX postcombustion control devices.
It is important to note that, for the case of PM, the data on PM control as shown for the
year 1999 should not have changed in any significant way. However, for SO2, the requirements
of Phase II ( starting in the Year 2000) of the Title IV (acid rain provisions) of the 1990 CAAA,
should have resulted in some boilers either switching to low -sulfur coal or the application of wet
or dry scrubbers. It appears that the SO2 scrubber retrofit activity in the U.S. has been rather
insignificant since 1999. The most active retrofits have involved the application of SCR, SNCR,
and gas reburn (in conjunction with low-NOX burners where appropriate) to significantly reduce
NOX emissions in the eastern U.S. These reductions, however, are only for ozone season (May 1
to September 30) since the NOX Transport SIP call applies to ozone season. As of 2003, more
than 50 applications of SCRs, SNCRs, or gas reburn have either been completed or are under
construction.
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Table II-7 Nationwide distribution of post-combustion emission control configurations
used for coal fired electric utility boilers for the year 1999 as reported in the Part II
USEPA ICR data (USEPA, 2001).
Post-Combustion Emission Control Device Configuration
Phase II USEPA ICR Data
PM control
Post-combustion
Control Strategy
E
S
P
SO2 control
NOX control
S
N
C
R
Number
of boilers
Percent of
nationwide
total number
791
69.4%
?
80
7.0%
?
6
0.5 %
?
5
0.4 %
?
4
0.4 %
2
0.2 %
2 (a)
0.2 %
133
11.7 %
38
3.3%
?
18
1.6 %
?
13
1.1 %
4
0.4 %
3
0.2 %
2
0.2 %
1
0.1 %
?
12
1.0 %
?
11
0.9 %
1
0.1 %
6
0.5 %
4
0.4 %
2
0.2%
1
0.1 %
1
0.1 %
1,140 (b)
100 %
F
F
P
S
M
C
W
S
S
D
A
D
I
S
C
R
?
?
Post-combustion
PM controls
only
?
?
?
?
?
?
?
?
Post-combustion
PM controls
and
SO2 controls
?
?
?
?
?
?
?
Post-combustion
PM controls
and
NOX controls
Post-combustion
PM controls,
SO2 controls,
and
NOX controls
?
?
?
?
?
?
?
?
?
?
?
?
?
?
?
?
?
?
?
?
?
?
Total
(a) Units using hot-side ESP in series with a cold-side ESP. Counted as a “multiple control device combination" in Table II-5
(b) Does not include the three IGCC units.
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Page 2-22
2.4. Costs and Availability of Technology
The technologies to control three of the precursors of regional haze are commercially
available. Since EGUs are the most significant stationary source of SO2, NOX, and PM, they
have been subject to extensive federal and state regulations to control all three pollutants. The
technical feasibility of control technologies has been successfully proven for a large number of
small (say, 100 MW) to very large boilers (over 1,000 MW) using different types of coal used.
Over the last few years, a large amount of cost data have also become available that clearly
indicate that many technologies provide substantial and extremely cost effective reductions.
2.4.1. Detailed Capital Costs, Operating and Maintenance Costs, and Cost
Effectiveness
Cost of Controlling SO2 Emissions
Both wet and dry scrubbers are in wide commercial use in the U.S. The capital costs for
new or retrofit wet or dry scrubbers are high when compared to the capital costs for NOX and PM
controls. The recent capital costs range from $180/kW for large units (larger than 600 MW) to
as high as $350 for small units (200 to 300 MW). However, the last few years has seen a general
trend of declining capital costs due to vendor competition and technology maturation. The cost
effectiveness (in dollars per ton) is very attractive, since these devices remove a very large
amount of SO2 (driven by high sulfur content of coal burned). The typical cost effectiveness is in
the range of 200 to 500 dollars per ton of SO2 removed though higher values are obtained for
small units operating at low capacity factors and burning low-sulfur coal. The cost effectiveness
is determined mostly by the baseline pre-controlled SO2 emisison rate (or sulfur content of fuel),
size and capacity factor of the unit, as well as the capital cost of FGDs (that generally ranges
from $150 to $200/kW).
Cost of Controlling NOX
A representative summary of range of costs associated with various technologies for NOX
control is provided below.
Gas Reburn
In general, the capital costs range from $15/kW to $30/kW for gas reburn and $30/kW to
$60/kW when using coal as the reburn fuel. Operating costs are mainly driven by fuel cost
differential (certainly gas vs. coal). For other fuels (e.g. coal/orimulsion reburning), fuel
preparation costs become more important (micronization, atomization) as there is little or no fuel
cost differential. The cost in dollars per ton of NOX removed is in the range of 500 to 2000
dollars.
Retrofit schedules are directly related to the scope of the retrofit requirements. In most
cases, 3-6 weeks are adequate for a reburn retrofit.
Low-NOX Burners
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In general, the capital costs for burners range from $10,000 to 50,000 per burner plus
installation. The lower end of this range applies when existing burners are modified instead of
replaced to achieve lower NOX. Operating costs are negligible unless increased unburned carbon
results in lost revenues from ash sales. An outage is generally required when implementing this
technology, but coal-flow sensors and adjustable orifices are best installed when a mill is out of
service. Low-NOX Burners provide moderate NOX reductions in the range of 30 to 60% at
moderate cost ($200 to 500 per ton of NOX removed).
Overfire Air (OFA)
OFA technologies have little or no impact on operating costs (other than the potential for
an increase in unburned carbon - efficiency loss -, and the resulting impact on ash disposal
options). Retrofit costs are site-specific. As such, the economics of these technologies are
driven by capital/retrofit costs which typically range from $5-$10/kW, with the lower range
reflecting easier application whereas the higher costs are typically associated with more difficult
and involved retrofits. The cost effectiveness is in the range of $250 to 600 per ton of NOX
removed.
From a schedule standpoint, OFA retrofit projects can require outages of 3 – 6 weeks,
depending on factors such as scope of work, integration with other plant outage requirements,
etc.
SCR
Capital costs for retrofit SCR systems to coal-fired power generation sources are specific
to the individual site, but have been documented to be within the range of $70/kW to about
$190/kW. The lower end of this range applies to retrofits with nominal difficulty. The high end
of the range would typically be associated with retrofits having significantly impeded
construction access, extensive relocations, and difficult ductwork transitions.
Capital costs for retrofit SCR systems on oil and gas-fired boilers are substantially lower
(about half to one third) than costs of coal-fired boiler retrofits. Lower volumes of catalyst are
required for gas-fired boilers because of the lack of ash and catalysts poisons like arsenic in the
flue gas. Capital costs for oil-fired retrofits are intermediate between coal- and gas-fired
retrofits. Oil combustion produces some particulate matter, which necessitates larger SCR
catalyst volume as compared to that for natural gas.
Operating costs are mainly driven by cost of reagent, energy penalty (pressure loss,
ammonia vaporization), catalyst replacement and dedicated O and M costs. SCR technology
offers very high NOX reductions (from 90 to 95%) and cost effectiveness (in the range of $1,000
to 1500 per ton of NOX removed).
SNCR
The capital costs for SNCR application are low making it an attractive option for
moderate NOX reductions (25 to 50%). Capital cots range from $10 to $20/kW for power
generation boilers.
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Operating costs are driven primarily by the consumption of the chemical reagent –
usually urea for SNCR - which in turn is dependent upon the efficiency of the control equipment
as well as the initial NOX level and the desired percent reduction. These are typically in the
range of $500-$700/ton of NOX.
An additional consideration important in the overall operating costs is the potential
contamination of fly ash by ammonia making it potentially unsalable.
Cost of Controlling PM
The costs associated with controlling PM from EGUs generally do not scale on the size
of the unit but on the volume of flue gases processed by the control devices (ESPs or fabric
filters). The representative costs are provided below.
ESPs
The following values represent typical costs for application of ESPs to units handling a
range of flue gas rates (these numbers reflect unit sizes ranging from utility-size units up to about
2,000,000 ACFM to smaller process down to about 10,000 ACFM):
•
•
•
Capital: $15 - $40/ACFM
Fixed O&M: Dry ESP’s - $0.25 - $0.65/yr-ACFM
Wet ESP’s - $0.15- $0.50/yr-ACFM
Variable O&M: Dry ESP’s - $0.45 - $0.60/yr-ACFM
Wet ESP’s - $0.25 - $0.50/yr-ACFM
Fabric Filters
Baghouses have been used extensively for many years in different industries. The EGU
sector, while predominantly dominated by ESP’s, has started to utilize FF’s in the last 20 years.
•
•
•
Capital: Reverse Air Fabric Filter - $17 - $40/ACFM
Pulse Jet Fabric Filter - $12 - $40/ACFM
Fixed O&M: Reverse Air Fabric Filter - $0.35 - $0.75/yr-ACFM
Pulse Jet Fabric Filter - $0.50 - $0.90/yr-ACFM
Variable O&M: Reverse Air Fabric Filter - $0.70 - $0.80/yr-ACFM
Pulse Jet Fabric Filter - $.90 - $1.1/yr-ACFM
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References
Buonicore, A.J., and W.T. Davis (eds.). Air Pollution Engineering Manual. Air & Waste
Management Association. Van Nostrand Reinhold, New York, NY. 1992.
NESCAUM, A Basis for Control of BART Eligible Sources, Northeast States for Coordinated Air
Use Management, Boston, MA, July, 2001.
Turner, J.H., and J.D. McKenna. Fabric Filter Baghouses I - Theory, Design, and Selection.
ETS, Inc., Roanoke, VA. 1989.
U.S. Environmental Protection Agency. Air Quality Criteria for Particulate Matter and Sulfur
Oxides, Volumes 1-3, EPA/600/8-82/029a-c. (NTIS PB84-156777). Office of Health and
Environmental Assessment, Environmental Criteria and Assessment Office, Research Triangle
Park, NC. 1982.
U.S. Environmental Protection Agency. Air Quality Criteria for Oxides of Nitrogen, Volumes 13, EPA/600/8-91/049a-c (NTIS PB92-176361; 95-124525; 95-124517), Office of Health and
Environment Assessment, Environmental Criteria and Assessment Office, Research Triangle
Park, NC. 1991.
U.S. Environmental Protection Agency, Stationary Source Control Techniques Document for
Fine Particulate Matter, Woodward, K., EPA/425/R-97-001 (NTIS PB99-116493). Office of
Air Quality Planning and Standards, Research Triangle Park, NC. October 1998.
U.S Environmental Protection Agency, National Air Pollutant Emissions Trends, 1900-1998,
U.S. EPA and the States: Working Together for Cleaner Air, Nizich, S.V., A.A. Pope, and L.M.
Driver. EPA-454/R-00-002 (NTIS PB2000-108054). Office of Air Quality Planning and
Standards, Research Triangle Park, NC. March 2000.
U.S. Environmental Protection Agency. Database of information collected in the Electric Utility
Steam Generating Unit Mercury Emissions Information Collection Effort. OMB Control No.
2060-0396. Office of Air Quality Planning and Standards. Research Triangle Park, NC. April
2001. Available at: <http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html>.
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3. INDUSTRIAL BOILERS
Industrial boilers are a significant source of emissions among the twenty-six
source categories covered under the Regional Haze Rule. Estimates of national emissions
for criteria air pollutants prepared by the USEPA (2000) show that industrial boilers
contributed approximately 12 percent of the estimated total national SO2 emissions and
23 percent of total national NOX emissions in 1998 (the most recent year for which
national estimates are available). Industrial boilers also are one of the largest industrial
sources of PM emissions, with 16 percent of the national PM10 emissions and 20 percent
of the national PM2.5 in 1998. Contrast this with the emissions of EGUs for which PM10
and PM2.5 emissions were 25 percent and 23 percent of national totals in 1998,
respectively. In general, the combustion efficiencies achieved by industrial boilers are
lower than those of EGUs, resulting in significant emissions of CO (18 percent of the
1998 emissions) and volatile organic compounds (6 percent of the 1998 emissions) from
industrial boilers. Industrial boilers also produced 16 percent of the ammonia emissions
in 1998. Ammonia is precursor of secondary PM in the atmosphere.
About 46 percent of the SO2 emissions from industrial boilers are from coal-fired
boilers (see Table III-1). The predominant sources of NOX emissions from industrial
boilers are gas-fired boilers (30 percent) and internal combustion boilers (34 percent);
coal-fired boilers were only responsible for 17 percent of NOX emissions from industrial
boilers. Although the emphasis of this Chapter is on coal-fired utility boilers, many
technologies described here are also applicable to gas and oil-fired units (for example,
SCR and SNCR technologies are equally applicable to coal and natural gas/oil units,
generally at much lower capital and operating costs; same is true for wet scrubbers for
SO2 control and ESPs or baghouses for PM control for oil units).
Table III-1 Distribution of emissions from industrial fuel boilers from 1998
National Emissions Inventory (USEPA, 2000)
Fuel/Source
NOX
SO2
PM10
PM2.5
Coal
17%
Oil
7%
Gas
39%
Other
4%
Internal Combustion 34%
46%
27%
21%
5%
1%
31%
18%
18%
25%
7%
16%
16%
26%
32%
10%
3.1. Description of Boiler Process
Typically, industrial boilers generate steam used for process heating or on-site
generation of electricity. Industrial boilers burn a wider variety of fuels than EGUs and
there are a larger number of boiler designs in use than in the electric power sector.
According to information contained in USEPA’s Docket on “National Emission
Standards for Hazardous Air Pollutants for Industrial/ Commercial/Institutional Boilers
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DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 3-2
and Process Heaters” (USEPA, 2004) in 1998 there were 63,767 fossil fuel-fired boilers,
1,100 wood-fired boilers and 998 boilers classified as non-fossil-fuel-fired. The fossil
fuels fired were natural gas, distillate oil, residual oil, coal and petroleum coke. The
majority (75 to 95 percent) of the boilers firing natural gas, residual oil and distillate oil
are fire tube boilers; the rest are water tube boilers. Coal-fired boilers include fluidized
bed boilers, stokers, cyclone boilers, and pulverized coal-fired boilers (wall-fired or
tangentially fired). Wood-fired boilers include fluidized bed boilers, cyclones, stokers
and dutch ovens.
3.2. Review of BART-Eligible Industrial Boilers in the MANE-VU
Region
There are 10 facilities with BART-Eligible industrial boilers in the MANE-VU
region. Table III-2 contains a list of these sources based on a previous NESCAUM report
(2003) and follow-up review by state permitting authorities. 5
Table III-2 BART-Eligible Facilities in the Industrial Boiler Category
State
Company/Facility
City/Town Category
Connecticut
Massachusetts
Versailles
Lynn
boilers
boilers
Massachusetts
Massachusetts
SPRAGUE PAPERBOARD INC
GENERAL ELECTRIC AIR (GE Aircraft Engines)
TRIGEN BOSTON ENERGY-KNEELAND
STATION
SOLUTIA INC. (MONSANTO CO.)
Boston
Springfield
boilers
boilers
Massachusetts
HARVARD UNIVERSITY CAMBRIDGE
Cambridge
boilers
Maine
International Paper - Bucksport
Bucksport
boilers
Maine
Katadhin - Mill W.
Millinocket boilers
New Hampshire Annheuser-Busch
Merrimack
boilers
New Hampshire Dartmouth College
Hanover
boilers
Rhode Island
Providence
boilers
BROWN UNIVERSITY
3.3. Available Control Technologies
A variety of emission control technologies are employed to meet requirements for
sulfur dioxide (SO2), nitrogen oxides (NOX), and primary PM emissions, the three major
precursors of observed regional haze in the atmosphere. SO2 and NOX are mostly
converted to ammonium sulfate and ammonium nitrate that are formed by the reactions
of precursor gases with ammonia, which is emitted mostly from agricultural and cattlerelated activities.
Pollutant emission controls are generally divided into three major types:
5
NESCAUM does not believe that there are any BART-eligible sources in the State of Vermont or any of
the member Tribes in MANE-VU and thus we have not developed lists for these jurisdictions. In addition,
Pennsylvania and the District of Columbia have developed BART-Eligible source lists following their own
methodology and any identified sources are contained here and in the final list in Appendix A.
3-2
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 3-3
•
Pre-combustion Controls. Control measures in which fuel substitutions are made
or fuel pre-processing is performed to reduce pollutant formation in the
combustion unit.
•
Combustion Controls. Control measures in which operating and equipment
modifications are made to reduce the amount of pollutants formed during the
combustion process; or in which a material is introduced into the combustion unit
along with the fuel to capture the pollutants formed before the combustion gases
exit the unit.
•
Post-combustion Controls: Control measures in which one or more air pollution
control devices are used at a point downstream of the furnace combustion zone to
remove the pollutants from the post-combustion gases.
3.3.1. Emission Characteristics of Regional Haze Precursors from
Industrial Boilers
Nitrogen Oxides
The formation of NOX is an unfortunate byproduct of the combustion of fossil
fuels. Both NO and NO2 (collectively called NOX) are formed during fossil fuel
combustion by oxidation of molecular nitrogen that is present in the combustion air or
nitrogen compounds contained in the fuel. The degree to which this conversion occurs is
dependent on many factors including both the combustion process itself and the
properties of the particular fuel being burned. This explains why similar boilers firing
different fuels or similar fuels burned in different boilers will yield different NOX
emissions. Overall, total NOX formed during combustion is composed predominantly of
NO mixed with small quantities of NO2 (typically less than 10 percent of the total NOX
formed). However, once NO formed during coal combustion is emitted to the
atmosphere, the NO is oxidized to NO2.
The NOX formed during combustion by oxidation of molecular nitrogen (N2) in
the combustion air is referred to as “thermal NOX.” The oxidation reactions converting
N2 to NO and NO2 become very rapid once gas temperatures rise above 1,700°C
(3,100°F). Formation of thermal NOX in a boiler is dependent on two conditions
occurring simultaneously in the combustion zone: high temperature and an excess of
combustion air. A boiler design feature or operating practice that increases the gas
temperature above 1,700 °C, the gas residence time at these temperatures, or the quantity
of excess combustion air affects thermal NOX formation. The formation of NOX by
oxidation of nitrogen compounds contained in the coal is referred to as “fuel NOX.” The
nitrogen content in coal and petcoke ranges from approximately 0.5 to 2 percent; in
wood, the nitrogen content is typically 0.1 to 0.2 percent. The amount of nitrogen
available in the fuel is relatively small compared with the amount of nitrogen available in
the combustion air. However, a significant portion of the fuel nitrogen can be converted
to NO in the flame. Local temperature, oxygen concentration and NO concentration
affect the conversion of fuel nitrogen to NO and this is exploited in low-NOX firing
systems.
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Sulfur Dioxide
SO2, like NOX, is a precursor to acid rain and fine particulate matter (PM2.5) and is
also an undesirable byproduct of the combustion of sulfur-containing fuels. Coal
deposits contain sulfur in amounts ranging from trace quantities to as high as 8 percent or
more. Natural gas contains virtually no sulfur. Residual oil can have 1 to 2 percent
sulfur by weight, while petroleum coke can have as much as 6 percent sulfur. During
combustion, sulfur compounds in the fuel are oxidized to gaseous SO2 or SO3. When
firing bituminous coal, almost all of the sulfur present in coal is emitted as gaseous sulfur
oxides (on average, 98 percent). The more alkaline nature of ash in some sub bituminous
coals causes a portion of the sulfur in the coal to react to form various sulfate salts; these
salts are emitted as fly ash or retained in the boiler bottom ash. When firing petcoke or
residual oil, more of the SO2 is converted to SO3 because of the oxidation that is
catalyzed by vanadium in the ash. In coal-fired boilers, SO3 levels are typically 10 ppm
or less. With petcoke firing, however, SO3 levels as high as several hundred ppm have
been reported (Fernando,2001). Formation of SO3 is a concern because the temperature
of the particulate control device or scrubber is often below the acid dew point, resulting
in nucleation and condensation of ultrafine sulfuric acid particles from the SO3 present in
the gas. These particles can contribute to the fine PM emissions from the stack.
Unlike nitrogen in fossil fuels and wood, almost all of the sulfur in fuel is
oxidized to form SO2. This means that the relationship between sulfur content in the fuel
and SO2 production is much more direct than that between fuel nitrogen and NOX, and as
such, it makes fuel switching (for example higher to lower sulfur coal) directly
proportional to reductions in SO2. Generally, the percentage of sulfur in the fuel that is
converted to sulfur oxides during combustion does not vary with the boiler design or
operation. The exception to this is the fluidized bed boiler in which limestone is added to
the bed. The bed is operated at a sufficiently low temperature (compared to other
combustion systems) that sulfur is captured effectively in the bed as calcium sulfate.
Particulate Matter
Primary PM emissions from boilers consist primarily of fly ash. Ash is the
unburned carbon and the mineral portion of the fuel. Coals contain 4 to 12 percent ash
typically. Other liquid or solid fuels (oil, petroleum coke, wood) contain less than one
percent ash. The amount of ash that ultimately exits the boiler unit as fly ash is a
complex function of the fuel properties, furnace-firing configuration, and boiler
operation. For the dry-bottom, pulverized-coal-fired boilers, approximately 80 percent of
the total ash in the as-fired coal exits the boiler as fly ash. Wet-bottom, pulverized-coalfired boilers emit significantly less fly ash: on the order of 50 percent of the total ash
exits the boiler as fly ash. In a cyclone-fired boiler, most of the ash is retained as liquid
slag; thus, the quantity of fly ash exiting the boiler is typically 20 to 30 percent of the
total ash. However, the high operating temperatures unique to these designs promote ash
vaporization and this results in larger fractions of submicron fly ash compared to dry
bottom designs. Fluidized-bed combustors emit high levels of fly ash since the coal is
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fired in suspension and the ash is present in dry form. Spreader-stoker-fired boilers can
also emit high levels of fly ash. However, overfeed and underfeed stokers emit less fly
ash than spreader stokers, since combustion takes place in a relatively quiescent fuel bed.
In addition to the fly ash, PM emissions from boilers result from reactions of the
SO2 and NOX compounds as well as unburned carbon particles carried in the flue gas
from the boiler. The SO2 and NOX compounds are initially in the vapor phase following
coal combustion in the furnace chamber but can partially chemically transform in the
stack, or near plume, to form fine PM in the form of nitrates, sulfur trioxide (SO3), and
sulfates. Firing configuration and boiler operation can affect the fraction of carbon (from
unburned fuel) contained in the fly ash. Combustion efficiencies tend to be lower in
industrial boilers than in EGUs. Oil or petcoke combustion results in high amounts of
sulfur trioxide as compared to coal combustion because of the high vanadium content of
residual oil and petcoke.
NOX control technologies that inject ammonia or amine-based reagents (like
Selective Catalytic Reduction or Selective Non-Catalytic Reduction) produce ammonia,
generally with concentrations less than 10 ppm. This ammonia can also form fine
particulate in the stack, if it persists through the air pollution control devices.
3.3.2. Control Technologies used for Industrial Boilers
Application Status
According to the 1998 survey of industrial boilers by USEPA (2004), only 2
percent of gas-fired boilers and 3 percent of oil-fired boilers had any kind of air pollution
control device. More coal-fired boilers had air pollution control devices: 47 percent had
some control device and these were largely PM controls.
For PM controls, ESPs were used on 12 percent of the coal-fired boiler units in
1998, fabric filters or baghouses were used on 10 percent of the boiler units, mechanical
collectors were used on 21 percent of the units, and particulate scrubbers were only used
on 2 percent of the units. 66 percent of wood-fired boilers used mechanical collectors for
PM control, while 10 percent used PM scrubbers and another 10 percent used ESPs.
Post-combustion SO2 control was used by less than one percent of industrial
boilers in 1998, with the exception of boilers firing petcoke: 2 percent of boilers firing
petroleum coke had acid scrubbers. A small percentage of industrial boilers had
combustion controls in place in 1998, although since 1998, additional low-NOX firing
systems may have been installed.
SO2 Reduction Overview
Almost all SO2 emission control technologies fall in the category of reducing SO2
after its formation, as opposed to minimizing its formation during combustion. The
exception to the nearly universal use of post-combustion controls is found in fluidized
bed boilers, in which limestone is added to the fluidized bed combustion. Typically 90
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percent of the sulfur can be captured in a coal-fired fluidized bed using limestone with
Ca/S molar ratios of 2 to 2.5, depending on the sulfur content of the fuel, the reactivity of
the limestone and the operation of the combustor.
Post-combustion SO2 control is accomplished by reacting the SO2 in the gas with
a reagent (usually calcium- or sodium-based) and removing the resulting product (a
sulfate/sulfite) for disposal or commercial use depending on the technology used. SO2
reduction technologies are commonly referred to as Flue Gas Desulfurization (FGD)
and/or "Scrubbers" and are usually described in terms of the process conditions (wet
versus dry), byproduct utilization (throwaway versus saleable) and reagent utilization
(once-through versus regenerable).
Within each technology category, multiple variations are possible and typically
involve the type and preparation of the reagent, the temperature of the reaction (for dry
processes), the use of enhancing additives, etc. Because these variations mostly involve
complex process chemistry, but are fundamentally similar, this summary focuses on the
major categories of SO2 control technologies, their applicability, performance and cost.
Pre-Combustion Control
A coal with sufficiently low sulfur content that when burned in the boiler meets
the applicable SO2 emission standards without the use of additional controls is sometimes
referred to as “compliance coal.” Coals naturally low in sulfur content may be mined
directly from the ground. Alternatively, the sulfur content of coal fired in the boiler may
be lowered first by cleaning the coal or blending coals obtained from several sources.
However, burning low-sulfur coal may not be a technically feasible or economically
practical SO2 control alternative for all boilers. In some cases, a coal with the required
sulfur content to meet the applicable standard may not be available or cannot be fired
satisfactorily in a given boiler unit design. Even if such a coal is available, use of the
low-sulfur coal that must be transported long distances from the mine may not be costcompetitive with burning higher sulfur coal supplied by closer mines and using a postcombustion control device.
Various coal cleaning processes may be used to reduce the sulfur content of the
coal. A significant portion of the pyritic sulfur minerals mixed with the mined coal can
usually be removed by physical gravity separation or surface property (flotation)
methods. However, physical coal cleaning methods are not effective for removing the
organic sulfur bound in coal. Another method of reducing the overall sulfur content of
the coal burned in a given boiler unit is to blend coals with different sulfur contents to
meet a desired or target sulfur level.
In-Process Controls
Fluidized bed boilers generally operate at lower temperatures than other
combustion systems, 800 to 870oC (1500 to 1600oF). The lower temperatures allow the
use of limestone or dolomite to be added to the bed to capture sulfur. Limestone
(CaCO3) is converted to CaO at approximately 800oC (1500oF). SO2 released from the
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fuel reacts with CaO to form CaSO4, which is thermodynamically stable at bed
temperatures. By recycling some of the solids leaving the bed, which contain unsulfated
calcium, 90 percent removal of SO2 can be achieved with Ca/S molar ratios of 2 to 2.5 in
circulating fluidized beds. Higher Ca/S ratios are required in bubbling beds. In either
case, the sorbent is removed with the ash from the bed and sent to disposal.
Post-Combustion Controls
Wet Processes
Wet FGD "scrubbers" date back to the 1960s with commercial applications in
Japan and the U.S. in the early 1970s. They represent the predominant SO2 control
technology in use today with over 80% of the controlled capacity in the world and the
U.S.
In a wet scrubber, the SO2-containing flue gas passes through a vessel or tower
where it contacts an alkaline slurry, usually in a counterflow arrangement. The intensive
contact between the gas and the liquid droplets ensures rapid and effective reactions that
can yield greater than 90 percent SO2 capture. Currently, advanced scrubber designs
have eliminated many of the early problems, primarily related to reliability, but have also
demonstrated very high SO2 reduction capabilities with some units providing over 95
percent control.
Variations of the basic technology, in addition to equipment improvements made
over the years, include reagent and byproduct differences. Limestone, lime, sodium
carbonate and even seawater-based processes are commercial. Limestone is by far the
most widely used with commercial-grade gypsum (wallboard quality) being produced in
the so-called Limestone Forced Oxidation (LSFO) process. The use of other reagents, as
mentioned, is driven by site-specific criteria, such as local reagent availability,
economics, efficiency targets, etc.
Dry Processes
Dry processes include spray dryer absorbers (SDA) and Dry Sorbent Injection
(DSI) technologies. SDA refers to a configuration where the reaction between SO2 and
the sorbent takes place in a dedicated reactor or scrubber hence the common reference to
"dry scrubber"; conversely, DSI uses the existing boiler/duct system as the "reactor" and
several configurations are possible based on the temperature window desired. This can
occur at furnace (~2200ºF), economizer (800-900ºF) or duct temperatures (~250ºF). Dry
processes are more compatible with low to medium sulfur coals due to limitations in
reaction rates and sorbent handling (e.g., atomization). Therefore, high-sulfur
applications are not likely. In addition, another common feature among them is the need
for particulate control downstream of the sorbent injection. Usually this is accomplished
through the use of fabric filters (baghouses) which are, not only efficient collectors of
particulates, but also provide additional SO2 removal as the flue gas passes through
unreacted sorbent collected on the filters.
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Dry SO2 controls vary significantly in performance, with SDAs being able to
achieve about 80 percent removal rates, whereas the various forms of DSI are capable of
40 to 75 percent efficiencies.
NOX Reduction Overview
As a result of the complex interactions in the formation of NOX, an equally large
number of approaches to minimize or reduce its emissions into the atmosphere have been
and continue to be developed. A relatively simple way of understanding the many
technologies available for NOX emission control is to divide them into two major
categories: (1) those that minimize the formation of NOX during the combustion process
(e.g., smaller quantities of NOX are formed); and (2) those that reduce the amount of NOX
formed during combustion prior to exiting the stack into the atmosphere. In industry
"language" it is common to refer to the first approach under the "umbrella" of
Combustion Modifications whereas technologies in the second category are termed PostCombustion Controls.
Within each of these categories, several technologies and variations of the same
technology exist. Finally, combinations of some of these technologies are not only
possible but often desirable as they may produce more effective NOX control than the
application of a stand-alone technology.
The following summaries describe the major technologies in each category.
Combustion Modifications
Combustion modifications can vary from simple "tuning" or optimization efforts
(similar to a "tune-up" in a car) to the deployment of dedicated technologies such as
Low-NOX Burners (LNB), Overfire Air (OFA) or gas recirculation (GR).
Boiler Tuning or Optimization
Combustion optimization efforts can lead to improvements in NOX emissions of 5
to 15 percent or even higher in cases where a unit may be badly "de-tuned." It is
important to remember that optimization results are truly a function of the "preoptimization" condition of the power plant or unit (just as the improvement in a car from
a "tune-up" depends on how "bad" it was running prior to it), and as such have limited
opportunity for drastic emission reductions.
Recent development of "intelligent controls" - software-based systems that "learn"
to operate a unit and then maintain its performance during normal operation, are expected
help in keeping plants well-tuned, as they gain acceptance and become common features
in combustion control systems.
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Low-NOX Burners and Overfire Air
LNBs and OFA represent practical approaches to minimizing the formation of
NOX during combustion. Simply, this is accomplished by "controlling" the quantities and
the way in which fuel and air are introduced and mixed in the boiler (usually referred to
as "fuel or air staging").
These technologies are the most prevalent in the power industry at present. For
example, plants that have had to comply with Title IV of the CAAA of 1992 have largely
used these technologies for compliance. Competing manufacturers have proprietary
designs, geared towards application in different boiler types, as well as reflecting their
own design philosophies. LNBs and OFA, which can be used separately or as a system,
are capable of NOX reductions of 40 to 60 percent from uncontrolled levels. Again, the
type of boiler (e.g., dry versus wet-bottom, wall- versus tangential-fired, NSPS versus
pre-NSPS) and the type of fuel (e.g., bituminous versus sub-bituminous) will influence
the actual performance achieved.
Furthermore, all combustion modification approaches face a common challenge:
that of "striking a balance" between NOX reduction and fuel efficiency. The concern is
exemplified by the typically higher carbon levels in the fly ash, which reflect lower
efficiency (more fuel needed for the same electrical output), but also the contamination of
the fly ash itself possibly making it unsuitable for reutilization (e.g., cement industry).
LNBs/OFA have little or no impact on operating costs (other than by the potential
for the above-mentioned efficiency loss).
From a schedule standpoint, LNB/OFA retrofit projects have "lead" times of 10 to
14 weeks and can require outages of 6 to 10 weeks, depending on factors such as scope of
work, integration with other plant outage requirements, etc.
Post-Combustion Controls
Readily available post-combustion NOX controls are limited to Selective NonCatalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR). They are
fundamentally similar, in that both use an ammonia-containing reagent to react with the
NOX produced in the boiler, and convert it to harmless nitrogen and water, SNCR
accomplishes this at higher temperatures (1700ºF-2000ºF) in the upper furnace region of
the boiler, while SCR operates at lower temperatures (about 700ºF) and hence needs a
catalyst to produce the desired reaction between ammonia and NOX.
While this difference between the two technologies may seem minor, it yields
significant difference in performance and costs. This is because in the case of SNCR, the
reaction occurs in a somewhat uncontrolled fashion (e.g., the existing upper furnace
becomes the "makeshift" reactor which is not what it was originally designed to be),
while in the SCR case, a dedicated reactor and the reaction-promoting catalyst ensure a
highly controlled, efficient reaction. In practice, this means that SNCR has lower capital
costs (no need for a reactor/catalyst); higher operating costs (lower efficiency means that
more reagent is needed to accomplish a given reduction in NOX); and finally, has limited
NOX reduction capability (typically 30 to 40 percent with some cases achieving
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reductions in the 50 percent range). SCR, on the other hand, offers lower operating costs
and the opportunity for very high NOX reductions (up to 90 percent and higher).
Operating costs are driven primarily by the consumption of the chemical reagent –
usually urea for SNCR and ammonia for SCR, - which in turn is dependent upon the
efficiency of the process (usually referred to in terms of reagent utilization) as well as the
initial NOX level and the desired percent reduction. Two additional parameters important
in the overall operating costs are: (1) the potential contamination of coal fly ash by
ammonia making it unsaleable; and (2) the life cycle of the catalyst due to premature
“poisoning.”
Selective Catalytic Reduction
The selective catalytic reduction (SCR) process uses a catalyst with ammonia gas
(NH3) to reduce the NO and NO2 in the flue gas to molecular nitrogen and water. The
ammonia gas is diluted with air or steam, and this mixture is injected into the flue gas
upstream of a metal catalyst bed (composed of vanadium, titanium, platinum, or zeolite).
In the reactor, the reduction reactions occur at the catalyst surface. The SCR catalyst bed
reactor is usually located between the economizer outlet and air heater inlet. The catalyst
modules take up a considerable amount of space; in addition ductwork must be added for
the ammonia injection section. There is not always room in an existing boiler to retrofit
an SCR system. As a consequence, fan capacity may have to be increased, owing to the
incremental pressure drop from the SCR and associated ductwork. In some cases, the
boiler must be modified to increase the economizer exit temperature to the minimum
and/or the air preheater must be modified. Installation of an SCR on a boiler is sitespecific and this results in a range of capital costs for SCR systems on boilers.
Selective Noncatalytic Reduction
The selective noncatalytic reduction (SNCR) process is based on the same basic
chemistry of reducing the NO and NO2 in the flue gas to molecular nitrogen and water
but does not require the use of a catalyst to prompt these reactions. Instead, the reducing
agent is injected into the flue gas stream at a point where the flue gas temperature is
within a very specific temperature range. A minimum of 0.5 seconds of residence time is
required at a temperature of about 1800oF to achieve high (50 to 60 percent) NOX
removal with SNCR. Good dispersion of the reagent in the flue gas is also needed to get
good utilization of the reagent and to avoid excessive ammonia slip from the process.
The need for a sufficient volume in the boiler at the right temperature window precludes
the application of SNCR in all types of industrial boilers.
PM Reduction Overview
Particulate matter is generated by a variety of physical and chemical processes. It
is emitted to the atmosphere through combustion, industrial processes, fugitive emissions
and natural sources. In combustion processes, the mineral matter (inorganic impurities) is
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converted to ash. The particles suspended in the flue gas are known as fly ash. Fly ash
constitutes the primary particulate matter, which enters the particulate control device.
Particulate matter is in general referred to as "PM", " PM10", " PM2.5" (particulate matter
(PM) with an aerodynamic equivalent diameter of 10 microns or less and 2.5 microns or
less, respectively).
Quantity and characteristics of the fly ash and particle size distribution depend on
the mineral matter content of the fuel, combustion system, and operating conditions.
Combustion technique mainly determines the particle size distribution in the fly ash and
hence the final particulate emissions. Common combustion systems in pulverized coal
firing include dry bottom, wall (front, opposed) and corner (tangential) burners and wet
bottom furnaces. In dry bottom boilers, 10 to 20 percent of the ash is discharged as dry,
bottom ash. In wet bottom boilers, 50 to 60 percent of the ash is discharged at the bottom
of the boiler as slag. Stokers or grate-fired boilers are used to burn coal, wood and waste.
The majority of the ash falls through the grate and is discharged as bottom ash. Mineral
composition of the coal and the amount of carbon in the fly ash determine the quantity,
resistivity and cohesivity of the fly ash.
PM emissions from other point source processes involve similar phenomena
where particulate matter is carried with the flue gas, in suspension to the stack. Hence,
the general technologies applicable to one source are typically suitable for the others as
well. Factors such as type and quantity of PM, characteristics of the process gas
(temperature, moisture, other contaminants) have a major influence on the selection and
design of the PM control technology.
PM Control Technologies
The following four major types of particulate controls technologies are common
for a variety of applications:
Wet scrubbers
Scrubbers work on the principle of rapid mixing and impingement of the
particulate with the liquid droplets and subsequent removal with the liquid waste. For
particulate controls the “venturi scrubber” is an effective technology whose performance
is directly related to the pressure loss across the venturi section of the scrubber. Venturi
scrubbers are effective devices for particulate control. However, for higher collecting
efficiencies and a wider range of particulate sizes, higher pressures are required. Highenergy scrubbers refer to designs operating at pressure losses of 50 to 70 inches of water.
Of course, higher pressure translates to higher energy consumption. Performance of
scrubbers varies significantly across particle size range with as little as 50 percent capture
for small (<2 microns) sizes to 99 percent for larger (>5 microns) sizes, on a mass basis.
Electrostatic Precipitators (ESP)
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ESP’s operate on the principle of electrophoresis, by imparting a charge to the
particulates and collecting them on opposed charged plates. Dry vs. wet refers to whether
the gas is water cooled and saturated prior to entering the charged plate area, or is
collected dry on the plates. In gases with high moisture content, dry ESPs are not suitable
because the wet gas would severely limit the ability to collect the “sticky” particulates
from the plates. The wet ESP technology is capable of very high removal efficiencies
and is well suited for the wet gas environments. Both types of ESPs are capable of
greater than 99 percent removal of particle sizes above 1 micron on a mass basis.
Fabric Filters
These are essentially “giant” vacuum cleaners. As in the case of the dry ESP,
Fabric Filters (FFs, sometimes called baghouses) are not well suited for wet gas
applications. However FFs are extremely efficient in collecting PM including fine
(submicron) size fractions.
Cyclones
Cyclones are devices that separate particulates from the gas stream through
aerodynamic/centrifugal forces. However, the technology is only effective in removing
larger size particles (greater than about five microns).
3.4. Costs of Technology
3.4.1. NOX Technologies
A representative summary of range of costs associated with various technologies
for NOX control in industrial boilers is provided in Table III-4, taken from Reference 4.
Capital costs and pollutant removal costs (in $/ton of pollutant removed) are given for
three different boiler sizes: 1000, 500, and 100 MMBtu/hr. For each boiler size, the
range of costs corresponds to a range of capacities from about low (5 to 14 percent of
capacity) to high (86 to 93 percent of capacity). Industrial boilers have a wider range of
sizes than EGUs and often operate over a wider range of capacities.
Low-NOX Burners (LNBs)
The capital costs for coal burners range from $2,500 to $5,100 per MMBtu/hr of
boiler size. The lower end of this range applies when existing burners are modified
instead of replaced to achieve lower NOX. Operating costs are negligible unless
increased unburned carbon results in lost revenues from ash sales. An outage is generally
required when implementing this technology, but coal-flow sensors and adjustable
orifices are best installed when a mill is out of service. Low-NOX Burners provide
moderate NOX reductions in the range of 30 to 50 percent at moderate to high cost ($200
to $3,000 per ton of NOX removed). The size of the boiler affects both the capital cost
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and the cost per ton. The combination of LNBs and overfire air (OFA), with or without
flue gas recirculation (FGR), is more expensive but NOX reduction is higher, as high as
80 percent for gas-fired boilers. From a schedule standpoint, LBB/OFA retrofit projects
can require outages of 3 to 6 weeks, depending on factors such as scope of work,
integration with other plant outage requirements, etc.
SNCR
The capital costs for SNCR application are low making it an attractive option for
moderate NOX reductions (about 40 percent). As discussed above, the NOX reduction
that can be achieved will vary from one boiler to another, and depend on the residence
time available in the boiler in which the temperatures fall within the window for the
SNCR chemistry to take place. Capital costs range from $2,000 to $4,000 per MMBtu/hr
for industrial boilers. Operating costs are driven primarily by the consumption of the
chemical reagent – usually urea for SNCR - which in turn is dependent upon the
efficiency of the control equipment as well as the initial NOX level and the desired
percent reduction. These are typically in the range of $1,300 to $10,000/ton of NOX.
An additional consideration important in the overall operating costs for coal-fired
boilers is the potential contamination of fly ash by ammonia, making it potentially
unsalable.
SCR
Capital costs for retrofit SCR systems to industrial boilers are mostly within the
range of $4,000 to $15,000 per MMBtu/hr. Installation of an SCR on a boiler is sitespecific and this results in a range of capital costs for SCR systems on boilers. Coal-fired
boilers have higher capital costs. The systems must be larger to allow for flow of fly ash
through the catalyst without plugging. Catalyst activity deteriorates faster in coal-fired
boilers because of the higher levels of contaminants in the flue gas (like arsenic) and the
deposition of ash on the catalyst. Catalysts must be replaced more frequently in coalfired systems, which increases the operating cost. The lower end of this range applies to
retrofits with nominal difficulty. The high end of the range would typically be associated
with retrofits having significantly impeded construction access, extensive relocations, and
difficult ductwork transitions.
In addition to catalyst replacement costs, operating costs are mainly driven by
cost of reagent, energy penalty (pressure loss, ammonia vaporization) and dedicated O
and M costs. SCR technology offers very high NOX reductions (80 percent or better); the
cost per ton of NOX removed is considerably higher than SNCR, although the overall
NOX reduction is higher.
3.4.2. SO2 Technologies
Both wet and dry scrubbers are in wide commercial use in the U.S. The capital
costs for new or retrofit wet or dry scrubbers are high when compared to the capital costs
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for NOX and PM controls (Khan, 2004b). Dry sorbent injection (DSI) has lower capital
costs than a spray dryer absorber (SDA), although DSI can only achieve about 40 percent
SO2 reduction. SDA systems can achieve 90 percent reduction. Capital costs for DSI are
in the range of $8,600 to $26,000 per MMBtu/hr, depending on the size of the system and
on the sulfur content of the fuel. Capital costs for SDA systems are about double that for
DSI systems, but the cost per ton of SO2 removed is similar: $400 to $4,000 per ton of
SO2 removed. These costs are higher than the costs for scrubbers on EGUs, which are
only $100 to $200 per ton of SO2 removed.
Wet FGD systems also remove 90 percent and higher of the SO2, but the capital
cost is about 50% higher than the cost for an SDA system. The costs per ton of SO2
removed are similar to the costs for SDA for coal-fired boilers. Costs per ton of SO2 are
estimated to be about twice as high for oil-fired boilers as compared to coal-fired boilers.
3.4.3. PM Technologies
As with most control technologies, the costs of PM controls involve both capital
and operating costs. A cost-effectiveness indicator, such as $/ton as is typically used for
other technologies (e.g. NOX and SO2), is very difficult to address for generic PM
control costs, as the range of PM reductions for different fuels and processes is so wide
that cost ranges become useless. An attempt to summarize costs in terms of capital and
O&M components is presented below.
Capital
While it is customary to indicate capital costs on a $/kW basis for power
generation applications, this is not relevant for non-power applications since no
electricity is generated. However, one of the main parameters dictating the “sizing” and
hence, the costs of a PM control device, is the quantity of flue gas it must handle. As a
result, it is more appropriate to generalize capital costs per actual cubic feet per minute
(ACFM) of gas flow and is given on a “$/ACFM” basis. The following values represent
typical costs for several of these technologies (these numbers reflect unit sizes ranging
from utility-size units up to about 2,000,000 ACFM to smaller process down to about
10,000 ACFM))
•
•
•
•
•
•
Dry ESPs - $15 - $40/ACFM
Wet ESPs - $15 - $40/ACFM
Reverse Air Fabric Filter - $17 - $40/ACFM
Pulse Jet Fabric Filter - $12 - $40/ACFM
Venturi Scrubber - $5 - $20/ACFM
Cyclone - $1 - $5/ACFM
O&M
O&M costs are difficult to generalize for such a variety of technologies and
applications, as they are affected by many parameters that include type of fuel, type of
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process, local ash disposal options, local cost of power, etc. O&M costs include fixed
costs (FOM) and variable costs (VOM). The costs provided below are presented in
$/year-ACFM and reflect costs for coal-based fuels but should reasonably apply to other
sources as well.
Fixed O&M
•
•
•
•
•
•
Dry ESPs - $0.25 - $0.65/yr-ACFM
Wet ESPs - $0.15- $0.50/yr-ACFM
Reverse Air Fabric Filter - $0.35 - $0.75/yr-ACFM
Pulse Jet Fabric Filter - $0.50 - $0.90/yr-ACFM
Venturi Scrubber - $0.25 - $0.65/yr-ACFM
Cyclone – Not applicable
Variable O&M
•
•
•
•
•
•
Dry ESPs - $0.45 - $0.60/yr-ACFM
Wet ESPs - $0.25 - $0.50/yr-ACFM
Reverse Air Fabric Filter - $0.70 - $0.80/yr-ACFM
Pulse Jet Fabric Filter - $.90 - $1.1/yr-ACFM
Venturi Scrubber - $1.2 - $1.8/yr-ACFM
Cyclone – Not applicable
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References
Fernando, R., The use of petroleum coke in coal-fired plant. IEA Coal Research:
London, 2001.
Khan, S. Methodology, Assumptions, and References Preliminary NOX Controls Cost
Estimates for Industrial Boilers.
http://cascade.epa.gov/RightSite/dk_public_collection_item_detail.htm?ObjectType=dk_
docket_item&cid=OAR-2003-0053-0170&ShowList=xreferences&Action=view
(Accessed February 19, 2004a).
Khan, S. Methodology, Assumptions, and References Preliminary SO2 Controls Cost
Estimates For Industrial Boilers.
http://cascade.epa.gov/RightSite/dk_public_collection_item_detail.htm?ObjectType=dk_
docket_item&cid=OAR-2003-0053-0166&ShowList=xreferences&Action=view
(Accessed February 14, 2004b).
U.S. Environmental Protection Agency, National Air Pollutant Emissions Trends, 19001998, U.S. EPA and the States: Working Together for Cleaner Air; Nizich, S. V.; Pope,
A. A.; Driver, L. M., EPA-454/R-00-002 (NTIS PB2000-108054); Office of Air Quality
Planning and Standards: Research Triangle Park, NC, March 2000.
U.S. Environmental Protection Agency, National Emission Standards for Hazardous Air
Pollutants for Industrial/ Commercial/Institutional Boilers and Process Heaters,
http://cascade.epa.gov/RightSite/dk_public_collection_detail.htm?ObjectType=dk_docke
t_collection&cid=OAR-2002-0058&ShowList=items&Action=view (Accessed February
25, 2004).
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Table III-4. NOX reduction and control costs for industrial boilers (Khan, 2004a).
Fuel Technology
Gas LNB/OFA
Gas LNB/OFA/GR
Oil
LNB/OFA(1)
Oil
LNB/OFA/GR (1)
Oil
LNB/OFA/GR (2)
Coal LNB (subbit.)
Coal LNB/OFA (subbit.)
Coal LNB/OFA (bit)
Gas SNCR
Oil
SNCR (1)
Oil
SNCR (2)
Coal SNCR
Gas SCR
Oil
SCR (1)
Oil
SCR (2)
Coal SCR
Notes
(1) 0.5 lb/MMBtu inlet NOX
(2) 0.36 lb/MMBtu inlet NOX
NOX
Reduction
%
60
80
30
50
30
51
65
51
40
40
40
40
80
80
80
80
$/Ton of Pollutant vs. Boiler Size
1000
250
MMBtu/hr
MMBtu/hr
280 - 5260
424 - 7973
368 - 6204
543 - 9415
306 - 2630
464 - 3986
326 - 2505
477 - 3790
741 - 5694
1085 - 8613
256 - 1520
389 - 2305
306 - 1727
454 - 2608
392 - 2197
581 - 3317
1842 - 14165 2193 - 20870
1485 - 4271 1670 - 5892
1628 - 5497 1889 - 7753
1285 - 2962 1473 - 4015
986 - 14815 1354 - 21095
760 - 10458 997 - 14443
1017 - 14601 1343 - 20113
876 - 4481
1123 - 5924
3-17
Capital Costs $/ MMBtu/hr vs. Boiler
Size
100
1000
MMBtu/hr MMBtu/hr
559 - 10521
1280
700 - 12374
2000
612 - 5260
1280
615 - 4973
2000
1399 - 11303
2000
512 - 3033
2554
593 - 3428
3649
757 - 4358
3649
2521 - 27105
2111
1840 - 7399
2045
2123 - 9842
2045
1625 - 4970
2639
1689 - 26859
4014
1245 - 18544
5547
1694 - 25838
5547
1349 - 7262
7298
250
MMBtu/hr
1940
3031
1940
3031
3031
3872
5531
5531
3200
3100
3100
4000
6084
8407
8407
11062
100
MMBtu/hr
2554
3991
2554
3991
3991
5097
7281
7281
4212
4081
4081
5266
8009
11067
11067
14562
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 3-18
Table III-5. SO2 reduction and control costs for industrial boilers (Khan, 2004b).
Fuel Technology
Coal
Coal
Coal
Coal
Coal
Oil
DSI high S coal
DSI lower S coal
SDA
Wet FGD high S coal
Wet FGD lower S coal
Wet FGD
SO2
Reduction
%
40
40
90
90
90
90
$/Ton of Pollutant vs. Boiler Size
1000
MMBtu/hr
633 - 1703
697 - 1986
381 - 1500
373 - 1789
461 - 2273
693 - 5082
Capital Costs $/ MMBtu/hr vs. Boiler
Size
250
100
1000
MMBtu/hr
MMBtu/hr MMBtu/hr
763 - 2471
943 - 3543
12508
849 - 2952 1075 - 4283
8648
569 - 2611
790 - 3920
20275
528 - 2708
664 - 3513
32313
661 - 3460
836 - 4495
29888
1011 - 7801 1285 - 10160
27455
3-18
250
MMBtu/hr
18838
12987
36226
48857
45283
41604
100
MMBtu/hr
26835
17995
54679
64240
59598
54761
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 4-1
4. PORTLAND CEMENT KILNS
Portland cement is a main ingredient for concrete and other common building
materials. Portland cement is mainly composed of clinker, a material formed by heating
limestone and other ingredients to temperatures over 2,650oF. High combustion
temperatures require significant amounts of fuel and can result in significant emissions of
NOX and SO2. Crushing of ingredients and finished clinker can release dust and
particles. Ammonia is sometimes produced during the heating of limestone.
The cement industry has seen significant growth in capacity and technology over
the last 30 years. In 2000, the U.S. had 201 cement kilns with the annual capacity to
produce 84 million metrics tons of concrete, with production projected to grow to 109
million metric tons in 2004 (Portland Cement Association, 2000).
4.1. Description of Cement-Making Processes
Concrete is a combination of Portland cement, sand, and gravel. The key
component of Portland cement is clinker, a material produced by heating limestone and
other raw materials to temperatures over 2,650ºF, requiring combustion temperatures of
about 3,000ºF. These high temperatures are normally achieved in a rotary kiln, as shown
in Figure IV-1. Feed material is added at the elevated end of the rotating, refractorylined, cylindrical kiln and the feed gradually tumbles to the high-temperature end of the
kiln and the main combustion zone, sometimes referred to as the "Burn Zone." The tilted
design of the cement kiln allows gravity to assist the motion of the clinker material while
hot exhaust gases move upward and exit at the elevated end of the kiln.
Exhaust Gases
to Precalciner
and Gas
Cleaning
Flame –
the "Burn Zone"
Raw material, or
material from
precalciner
Fuel and
Air In
Clinker
Out
Figure IV-1. Simplified Sketch of a Rotary Kiln.
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Cement kilns fall into four general process categories. Preheater kilns preheat and
partially calcine feed material in a series of cyclones or grates prior to admitting the feed
to the rotary kiln. This additional heat supplements the heat in the exhaust from the kiln.
The calcined feed then enters the rotary kiln at about 1,500ºF to 1,650ºF. Precalciner
kilns, on the other hand, utilize a burner in a separate vessel along with a series of
cyclones or grates to preheat and calcine the feed. In long kiln systems, the raw feed
material is added to the rotary kiln itself as either a powder (“dry”) or a slurry (“wet”).
Long wet and long dry kilns do not have preheaters and have much longer rotary kilns,
with wet process kilns being the longest - normally several hundred feet long. Preheater
and precalciner kilns are more energy efficient than long wet or long dry kilns and
typically have greater capacity. A preheater kiln is similar, but fuel is not added and
there is no burner on the cyclonic preheater portion. Preheaters could also be replaced
with suspension preheaters, but these are less common. If past trends continue, many of
the existing long wet kilns and dry kilns are expected to be replaced with precalciner and
preheater kilns since precalciner and preheater kilns are more energy efficient and also
typically have greater capacity.
Coal is the fuel of choice in cement kilns, primarily because of its low cost, but
also because the coal ash contributes somewhat to the product. The current fuel use in
cement kilns is about 82% coal; 4% natural gas; and 14% other fuels, mainly combustible
waste (industrial waste, tires, sewage sludge, etc.). Fuel nitrogen therefore contributes a
small but significant amount to the total NOX for nearly all cement applications (see the
section on NOX controls included later).
Recent years have seen Portland cement plant capacity stretched by high demand,
making technologies that can increase capacity without increased capital expenditures
very attractive. The industry is therefore developing technologies that improve facility’s
outputs or reduce their operating costs. Incidentally, some of these technologies also
offer the potential to reduce NOX and other emissions.
4.2. Review of BART-Eligible Cement Kilns in the MANE-VU Region
NESCAUM’s analysis of BART-eligible sources in the MANE-VU Region6
(NESCAUM, 2004) identified two Portland cement facilities as being eligible for BART.
The facilities are shown in Table IV-1. [Editor’s note: Additional facilities are likely to
be added when PA and NY inventories are complete]
6
NESCAUM does not believe that there are any BART-eligible sources in the State of Vermont or any of
the member Tribes in MANE-VU and thus we have not developed lists for these jurisdictions. In addition,
Pennsylvania and the District of Columbia have developed BART-Eligible source lists following their own
methodology and any identified sources are contained here and in the final list in Appendix A.
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Table IV-1 BART-Eligible Portland Cement facilities in MANE-VU Region
Facility
Kiln type
Capacity,
thousands Primary
tons/yr
Fuel(s)
St. Lawrence Cement (Hagerstown, MD)
Dry
550
Dragon Products (Thomaston, ME)
Wet
392
Coal
Coal,
petcoke
4.3. Available Control Technologies
A number of technologies exist for controlling emissions from cement kilns.
Secondary (post-combustion) control devices can be helpful in reducing emissions, and a
variety of these are available. Many technologies and techniques have been developed in
response to a specific environmental need and target a specific pollutant, sometimes
achieving reduction in other pollutants at the same time. Both secondary controls and
process changes are discussed below, grouped by their targeted pollutant. When
additional emissions reductions are possible, they are noted with the targeted pollutant.
Controls are examined for SO2, NOX, PM, and VOCs.
4.3.1. SO2 Controls
In contrast with electric utility boilers, SO2 emissions from rotary kilns producing
cement clinker under oxidizing conditions are nearly independent of fuel sulfur input,
but, rather, are closely related to the amount of sulfide (e.g. pyrite) in kiln feed and to the
molar ratio of total sulfur to total alkali input to the system. In cement kilns SO2
emissions generally depend on:
•
Inherent SO2 removal efficiency of kiln system,
•
Form of sulfur (e.g. pyritic) and sulfur concentrations in raw material,
•
Molecular ratio between sulfur and alkalis,
•
Prevailing conditions (oxidizing or reducing) and their location within
kiln, and
•
Temperature profile in the kiln system.
Depending upon the level of sulfur in a plant’s limestone compared to the sulfur
content of its heating fuel, fuel switching may not be sufficient to reduce SO2 emissions
(Tanna and Schipholt, 2004). However, when fuel sulfur levels are high, fuel switching
may have a significant benefit of reducing SO2 levels.
In addition to the control techniques used in the electric utility boilers, cement
plants may also resort to other basic reductions techniques involving reduction of sulfur
input to the kiln, by switching fuels or changing the limestone, or reduction of SO2
emissions from reducing both the sulfur in the sources and using a secondary control
device. It is common to achieve some level of SO2 reductions when seeking to reduce
another pollutant, usually NOX (technologies targeting another pollutant, but also
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reducing SO2, are described in the NOX and PM sections below). In addition to
considering a change in the primary fuel for the kiln, staged combustion with mid-kiln
injection of a low-sulfur fuel may be considered for reducing SO2. Including highpressure air injection at a mid-kiln firing site can limit oxygen in the kiln and suppress
SO2 formation (Hansen, 2002). Since these techniques are primarily used to reduce NOX,
more information about mid-kiln fuel injection can be found in the section on NOX
emissions, but other specific SO2 control technologies applicable to cement kilns are
listed below.
Fuel Switching
Selecting a fuel with lower sulfur content, a strategy commonly adopted in the
utility boilers, is less effective in cement-making systems, where SO2 emissions are not
strongly dependent on fuel sulfur content. Depending upon the level of sulfur in a plant’s
limestone compared to the sulfur content of its heating fuel, fuel switching may not be
sufficient to reduce SO2 emissions (Tanna and Schipholt, 2004). However, when fuel
sulfur levels are high, fuel switching may have a significant benefit in SO2 levels.
Inherent Removal
Raw materials, primarily limestone, are preheated in the cement-making process
either in the preheater tower or in the rotary kiln. In either case, the limestone comes in
contact with hot combustion exhaust gases. The calcium in the lime reacts with SO2 in
the gas, providing in-process removal of sulfur in the kiln system. Removal efficiencies
in rotary kiln systems range between 38% and 99% of sulfur input, and 50% to 70% of
the remaining SO2 is removed from exhaust gases when passing through an in-line raw
mill system (Miller et al., 2001).
Process Alterations
The following methods to remove and prevent formation of SO2 by modifying or
controlling conditions in the system are available due to the nature of the Portland cement
manufacturing process:
•
The oxygen concentration of the exhaust gases can be controlled to ensure
sufficient oxygen exists to stabilize alkali and calcium sulfate compounds
formed in the process. Concentrations of O2 and, more importantly CO,
have a strong influence on the stability of alkali and calcium sulfates in the
burning zone. Control of burning- zone O2 and CO concentrations is a
widely used industrial practice, and a control technique applicable to all
rotary kilns producing cement clinker. The downside of this technique is
the more favorable conditions created for generation of NOX in the rotary
kiln.
•
Burning-zone flame shape can be modified to minimize localized reducing
conditions. It has been observed (Hansen, 1986) that flame impingement
in the hot zone had a major effect on SO2 emissions from the kiln, even if
total oxygen is sufficient to fully combust all fuel. Avoiding flame
impingement in the burning zone minimizes SO2 formation. Avoiding
flame impingement on the clinker, a technique applicable to all rotary
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Page 4-5
kilns producing cement clinker, requires proper solid fuel preparation and
proper flame shaping and control.
•
Raw materials can be altered to affect the alkali/sulfur molar ratio. SO2
concentrations in kiln exit gases vary with the molar ratio of alkali to
sulfur; when alkalis are in excess of sulfur, SO2 emissions are typically
low, due to more sulfur being retained in clinker as alkali sulfates. Also,
kiln feed containing carbon seems to directly cause SO2 emissions.
Changing raw materials may reduce SO2 emissions. Substituting a raw
material containing pyritic sulfur or organic sulfur with one containing
lesser amounts of these compounds reduces SO2 emissions. Replacement
of raw materials, however, is often constrained by economic
considerations, while alkali input increase may also be limited by cement
product quality specifications on total alkali in cement.
•
Alterations to system can influence SO2 emissions. It has been found that
an improved distribution of kiln feed may equalize temperatures in bottom
stage cyclones and reduce SO2 emission by as much as 20% (Miller,
2001).
Scrubbers
Dry Reagent Injection
Steuch and Johansen (1991) found that Ca (OH)2 (hydrated lime) was the most
effective scrubbing agent, particularly when added to the kiln feed and when the exhaust
gases were near the dew point. Adding quicklime or hydrated lime into the upper
preheater cyclones demonstrated up to 70% removal efficiency (Nielse, 1991).
Several dry reagent systems are available:
•
The RMC Pacific process (Sheth, 1991) injects dry Ca(OH)2, and with
different stoichiometric ratios (40:1 to 50:1), has obtained efficiencies
ranging from 55% to 65%. SO2 removal of 80% was obtained with
injection into the roller mill.
•
Krupp Polysius Polydesox process uses hydrated lime where SO2 in the
raw feed tends to form from pyrites and obtains removal efficiencies of up
to 85% (Miller, 2001).
•
De-SoX Cyclone, by Fuller Company (Miller, 2001), reduces SO2
emissions in a precalciner kiln by removing a portion of the gases from the
precalciner outlet to a cyclone, and from there to the Stage II cyclone
where pyritic sulfur in kiln feed is decomposed into SO2. The feed (or
“raw meal”), containing freshly produced lime, is discharged into the
outlet duct of the second stage (this process is known as hot meal
injection). Removal efficiencies of 5 to 30% are claimed.
Lime/Limestone Spray Dryer Absorber
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Design stoichiometric ratios of calcium to sulfur for spray dryer systems in utility
boilers are typically between 0.9 and 1.5, with most below 1.0. These SO2 scrubbers are
designed for removal efficiencies in excess of 80%.
SO2 reacts with CaCO3, to form CaSO4, a reaction that becomes more complete as
the temperature and the fineness of CaCO3 increase. The presence of water vapor also
increases conversion.
Most of the spray dryer type SO2 control technologies in the cement industry are
applied to preheater or preheater/precalciner kilns. Exhaust gases from long dry kilns are
cooled by either spray water introduced into the feed end of the kiln or by dilution aircooling after the gases leave the kiln. Adding a conditioning tower to replace water
sprays or dilution air enables the alkaline slurry system to be used to reduce SO2
emissions (the equivalent of a spray dryer). The range of temperatures for exit gases from
long wet kilns does not allow the use of an alkaline slurry spray dryer type scrubber
because the addition of the lime slurry may drop the exhaust gases temperature below the
acid dew point, creating significant plugging and corrosion problems in the downstream
Particulate Control Device (PCD), duct work, and induced draft (ID) fan.
RMC Pacific's Alkaline Slurry Injection System (Sheth, 1991)
RMC Pacific uses a hydrated lime, spray dryer absorber to reduce SO2 emissions.
The captured sulfur compounds are returned as a portion of the raw material feedstock to
the roller mill, which results in no scrubber effluent or sludge disposal. When SO2
emissions are high and preheater exit gas temperatures are low, sufficient lime slurry
cannot be added to reduce SO2 to acceptable levels. With different stoichiometric ratios
(40:1 to 50:1), the process has obtained efficiencies ranging from 55% to 65%. SO2
removal of 80% was obtained with injection into the roller mill.
EnviroCare Microfine Lime System (Miller, 2001)
This system uses the existing gas conditioning tower to introduce the scrubbing
reagent (water suspension of finely pulverized calcium hydroxide, Ca (OH)2). The small
size of the lime particles (3-10 microns) allows the particles to dissolve in water droplets
quickly and react with SO2 as it is absorbed into the water droplet. The dried lime
continues to react with any remaining SO2 in the downstream kiln system and PCD. Lime
injection rate can be optimized through a feedback control loop from an SO2 monitor.
EnviroCare claims an SO2 removal efficiency of greater than 90%.
Wet SO2 Scrubbers
Wet scrubbers have been used successfully in the utility industry. Calcium sulfate
scaling and cementitious buildup when a wet scrubber is used for acid gas control applied
to the exhaust gas from a cement kiln can be avoided if these systems are installed
downstream of a high efficiency PCD (e.g., fabric filter). Failure of the PCD can pose
difficult problems for a downstream wet scrubber.
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Page 4-7
Fuller Company (FLS Miljø) (Miller, 2001)
The Monsanto Dyna Wave wet SO2 scrubber has been installed by the Fuller
Company and used on several cement kilns in the U.S. This wet scrubber is designed to
remove SO2, halide gases, and some particulate matter.
The scrubber, typically located downstream from the kiln PCD and operated
under positive pressure, uses limestone as the absorbent. A slurry (approximately 20%
limestone and 80% water) produced in the mixing tank is sprayed countercurrent to the
gas flow to cool the gases and react with SO2 forming calcium sulfite (CaSO3) and
calcium sulfate (CaSO4), which precipitates. Air is sparged into the sump at the bottom of
the tower to oxidize CaSO3 to CaSO4+2H2O (gypsum).
Monsanto EnviroChem DynaWave (Miller, 2001)
DynaWave is a "Reverse Jet" scrubber that can simultaneously accomplish
several gas cleaning/process needs: hot gas quenching, particulate removal, and acid gas
absorption. The reverse jet is an annular orifice scrubber having one to three large-bore
nozzles through which a relatively large volume of scrubbing liquid is injected counter to
the gas flow to create a froth zone. The gas collides with the liquid, forcing the liquid
radialy outward toward the wall. A standing wave, created at the point the liquid is
reversed by the gas, is an extremely turbulent region where the gas absorption and
particulate collection occurs.
The system is a tailpipe system generally installed downstream of the PCD, and
operates with a saturated gas stream. Therefore, it would likely be applicable to most if
not all the cement kilns. A single-stage DynaWave scrubber in full-scale operation has a
reported SO2 removal efficiency of about 90%. Monsanto EnviroChem claims that
multiple units may be installed in series to achieve whatever removal efficiency is
required (e.g., 99.9%).
4.3.2. NOX Controls
The following sections discuss the formation of NOX in cement kilns, potential
NOX control techniques, NOX control in the cement industry, and the cost effectiveness
of applicable controls.
NOX Formation in Kiln Systems
Nitrogen oxides (NOX) are formed during the combustion of fuels in the cementmaking process. In kiln exhaust gases, more than 90% of NOX is NO, with NO2 generally
making up the remainder from rotary kilns producing cement clinkers (Gardeik, 1984).
There are three different NOX formation mechanisms - thermal, fuel, and feed NOX typically contributing to NOX emissions.
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Thermal NOX
Thermal NOX is formed by oxidation of atmospheric molecular nitrogen at high
temperatures (>1,200 °C). Most NOX formed in the high-temperature environment of the
main combustion zone (burning zone) of a kiln is "thermal NOX". Since the flame
temperature in a kiln is significantly above that threshold, a considerable amount of
thermal NO is generated in the burning zone.
While conditions in the burning zone of a cement kiln favor formation of thermal
NOX, those prevalent in secondary combustion zones (e.g. calciners, preheater riser ducts
and mid-kiln firing in long wet or dry kilns) with temperatures below 1200°C, are less
conducive to significant thermal NOX formation. In that zone, formation of fuel NOX and
feed NOx is more prevalent.
The amount of thermal NOX produced is related to fuel type, burning zone
temperature, and oxygen content. Therefore, raw materials that are hard to burn (i.e.,
materials that require more heat input per ton of clinker produced) generate more NOX.
Fuel NOX
Fuel NOX is the result of oxidation of nitrogen compounds in fuel. Fuel nitrogen
is only partially converted into NOX during combustion. The amount formed depends on
fuel type, precalciner type and precalciner temperature. NOX formed in the secondary
combustion zone, primarily fuel NOX (Gardeik, 1984), depends on:
•
Nitrogen concentration in the fuel,
•
Oxygen concentration in the combustion zone,
•
Initial NO concentration in the combustion gas,
•
Volatile concentration in the (solid) fuel, and
•
Temperature in the secondary combustion zone.
As opposed to the burning zone of the kiln, where higher temperatures result in
much higher NOX formation, higher temperatures (up to 1100°C) in the precalciner may
actually reduce NOX emissions when a fuel containing nitrogen is used (Nielsen, 1990).
In the design of modern low-NOX calciners, high temperatures and reducing
conditions are proven methods for suppressing the formation of fuel NOX generated in
the precalciner, and for destroying thermal NOX generated in the burning zone of the
rotary kiln (Keefe and Shenk, 2002).
Feed NOX
NOX emissions can also result from the oxidation of nitrogen compounds in the
raw material feed to the kiln (feed NOX). The range of nitrogen concentrations in various
4-8
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Page 4-9
kiln feeds is 20-1000 ppm (Gartner, 1983) and the potential contribution of feed NOX to
total NOX emissions is 0.2-10 lbs of NOX per ton of clinker.
Up to 50% of feed nitrogen may be converted to NOX, if raw materials are heated
slowly: with rapid heating, the conversion rate is much lower.
The following conclusions can be made for rotary kiln systems (Young and von
Seebach, 1999):
•
Formation of thermal NOX in the burning zone is the major contributor to
NOX emissions from the kiln
•
Fuel NOX is the major contributor in the secondary combustion zone of
precalciner and riser duct fired preheater kilns
•
Feed NOX is usually a minor contributor to the total NOX generated in
rotary kiln systems.
It should be further noted that, due to the dynamic nature of kiln operations, NOX
formation can be highly variable so each kiln will tend to have unique NOX emission
characteristics, inherent to the variability in cement manufacturing process. Figure IV-2
illustrates the wide range of NOX emissions from different types of kilns.
NOX emissions rates are also site- and kiln-specific, and may be quite dissimilar
between two apparently identical kilns, for causes not fully understood, but, probably
connected to the raw materials used. Other causes for NOX emissions rate differences
may result from different types or classes of cement products being produced; chemical
variations between these different products can influence cement kiln operating
parameters and thus NOX emissions. Short-term process transients such as kiln feed rates
and fuel quality also affect NOX emissions. All of these factors can influence the
applicability and costs of incorporating NOX controls.
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Figure IV-2. NOX emissions for various cement kiln types (USEPA, 1994).
(SP: Suspension Preheater kilns)
NOX Control Techniques
There are two broad categories of NOX reduction techniques for cement kilns:
1) process controls, including combustion modifications, that rely on reducing or
inhibiting the formation of NOX in the manufacturing process (modifications for cement
kilns include low-NOX Burners (LNB), secondary combustion, and staged combustion);
and 2) post-combustion (secondary) controls, where flue gases are treated to remove
NOX that has already been formed.
It should be noted that the quality of clinker produced in a kiln varies with
characteristics of the combustion, so primary controls need to be selected carefully. Dry
low-NOX (DLN) operation, for example, has seen varied levels of success. The main
firing zone of the kiln requires very high temperatures and is not compatible with the
lower flame temperature used by DLN to reduce NOX. Low excess air and air-staging
are problematic control options for kilns because the kilns need an oxidizing environment
not provided by those techniques. Despite these problems, indirect firing in combination
with a LNB has been successfully used in some facilities, including California Portland
Cement. Low-NOX combustion methods can be used in the precalciner because high
temperatures are not required in that part of the process.
Indirect firing is a method that permits use of LNBs in the primary kiln burning
zone. When indirect firing is used, pulverized coal is fed to and collected in a particulate
matter collection system (a cyclone separator that exhausts gas through a fabric filter).
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The pulverized coal is then temporarily stored in a bin or hopper, where it is fed to the
burner. This method allows less primary air to be used in the burner than with a directfired coal mill, resulting in less thermal NOX.
LNBs can be used when indirect firing is employed. When implementing indirect
firing with LNBs, other process improvements are often implemented, such as better
process controls. According to Portland Cement Association (1998), 20%-30% NOX
reductions can be achieved from the use of indirect firing with LNBs and associated
process modifications.
Combustion modifications are less successful at reducing NOX emissions in
thermal processing applications (like cement kilns) than in boilers for steam and/or power
production. Chemical reactions producing cement clinker require high material and gas
temperatures, and product quality also requires an oxidizing atmosphere in the
combustion zone of a cement kiln. Excessively high temperatures in the burning zone
pose equipment damage risk, while temperatures too low will no longer produce a salable
product.
NOX emissions can also be affected by kiln feed chemical characteristics, feed
chemical uniformity, and specific fuel consumption. As stated by EPA’s NOX Alternative
Control Technique Document for the Cement Manufacturing Industry (USEPA, 1994),
"For any given type of kiln, the amount of NOX formed is directly related to the amount
of energy consumed in the cement-making process. Thus, measures that improve the
energy efficiency of this process should reduce NOX emissions in terms of lb of NOX /
ton of product."
Following are some of the more common process modifications that have been
made to reduce NOX emissions from cement kilns (NESCAUM, 2001):
•
Changing fuel (e.g. natural gas to coal firing).
•
Improving kiln feed chemical uniformity, for more stable kiln operations:
o Modifications to quarry operations,
o Raw material blending facilities, and
o On-line analytical control systems for raw material proportioning
(e.g. kiln feed blending systems).
•
Modifications to improve thermal efficiency, including:
o Reducing excess air infiltration,
o Increasing efficiency of cyclones in preheater kilns,
o Reducing the amount of moisture in slurry (wet process kilns
only),
o Revising kiln chain systems in long wet or long dry kilns,
o Modifying or replacing clinker coolers to improve heat recovery
and cooler efficiency,
o Initiating operator training programs, and
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o Returning as much cement kiln dust (CKD) as possible to the kiln
system (without adversely affecting product quality).
•
Installing or upgrading kiln system sensors and instrumentation.
•
Installing or upgrading computer controls of kiln systems to stabilize kiln
operation and avoid burning zone temperature variations.
According to Young and von Seebach (1999), industry data and experience show
that control of burning zone temperature is the primary process control method applicable
to lowering thermal NOX formation. Process modifications that allow better control of the
kiln burning zone temperature will result in reducing thermal NOX formation and
minimizing NOX spikes. Stable kiln operation, through feed chemical uniformity, results
in overall NOX reductions of 10% - 15%, while poor kiln feed chemical uniformity
results in overfiring the kiln, and higher NOX emissions.
Fuel Switching
Switching to a lower-nitrogen fuel in a precalciner may reduce NOX emissions,
but the nitrogen content of the fuel burned in the burning zone has little or no effect on
NOX generation. Generally, no relationship has been found between fuel nitrogen content
and the NOX emissions from a cement kiln (Miller and Egelov, 1980).
Process Optimization and Automated Control
Process optimization is a common method for reducing NOX emissions from
cement kilns. In principle, any effort that reduces the amount of fuel being fired to
produce clinker will result in a reduction in NOX generation. In practice, process
optimization often entails the use of advanced computer controls and instrumentation.
Many of the primary NOX control technologies described are implemented along with
process optimization to take advantage of their combined effects and to improve overall
facility operation. NOX reductions reported in this Chapter are generally attributed to the
changed combustion process (for example, mid-kiln firing). Combined reductions
reported in a case study (NESCAUM, 2001) equivalent to 55% reduction in average NOX
emissions - from 845 lb/hr to 383 lb/hr – were achieved largely by reducing the
variability of the process with a computer-automated optimization system. Mid-kiln
firing provided additional NOX reduction for an overall NOX emission reduction of 59%
from controls.
Flue Gas Recirculation
Flue gas recirculation (FGR) or water/steam injection into the main flame to
reduce flame temperatures and NOX formation is not a viable method of reducing NOX in
a cement kiln burning zone. FGR's effectiveness relies on cooling the flame and
generating an oxygen deficient (reducing) atmosphere for combustion to reduce NOX
formation, conditions that are not compatible with cement kiln operation. High flame
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temperature and an oxidizing atmosphere are process requirements to produce a quality
clinker product.
Indirect Firing
Conversion from a direct coal firing system to an indirect firing system kiln with a
low NOX burner may result in NOX reductions ranging from 0% to about 20% (Kupper et
al., 1990; Schrsemli, 1990). Incorrect use of multi-channel (low NOX) burners can
increase NOX rather than reduce NOX, and it has been found (Hansen, 1985) that less
excess air in the kiln combustion gases results in less NO formation at the same burning
zone temperature. NOX reductions of 15% were reported.
Low-NOX Burners
LNBs have been successfully used in the primary burn zone and especially in the
precalciner kilns.
Secondary combustion zones have proven effective at reducing NOX emissions in
cement kilns. In long kilns, secondary combustion can be partly accomplished by midkiln injection of fuel (less than 20% of kiln fuel). NOX emissions are reduced because
less fuel is burned in the high temperature environment of the burning zone. Another
NOX reducing technique is the use of fuel in the riser duct of preheater kilns, although,
because of high prevailing temperatures, such reductions do not always occur. With
precalciner kilns, which employ a secondary combustion zone at a much lower
temperature than the burning zone, typically 60% of the fuel is burned in the precalciner,
with the combustion air coming directly from the clinker cooler, and NOX emissions for
these kilns are less than from long wet, long dry, or preheater kiln systems because 60%
of the total fuel requirement is burned under lower temperature conditions where
negligible amounts of thermal NOX are formed. Furthermore, precalciner kilns have the
potential for staged combustion as a NOX control technique. All major equipment
suppliers offer "low-NOX” precalciner designs. Fuel burned in a sub-stoichiometric O2
environment creates a strongly reducing atmosphere (relatively high concentrations of
CO) that inhibits formation of fuel NOX and destroys a portion of the NOX formed in the
kiln burning zone. Additional tertiary combustion air is added later to complete
combustion of the fuel.
Staged combustion has become a well-known method for reducing NOX
emissions from cement plants, but as NOX and CO emissions limits become more
stringent, control via fuel and air staging are coming under reconsideration. Low- NOX
calciners combine high temperature combustion and firing under reducing conditions
without staging fuel/air.
Low-NOX Precalciners
Precalciner kilns can employ LNBs because the temperature in the precalciner can
be low enough to reduce thermal NOX but still be effective in heating the limestone.
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Since roughly 60% of the fuel burned in a precalciner kiln is fired in the precalciner, NOX
reductions can be substantial. All new precalciner kilns are equipped with low-NOX
burners in the precalciner. Low-NOX precalciners have been shown to reduce NOX by
30%-40% compared to conventional precalciners (Young and von Seebach, 1998). This
reduction is from the precalciner-generated NOX, not for the entire kiln.
Several precalciner kilns in the U.S. have recently been retrofitted with these
"two-NOX" calciners, and several new kiln lines have been installed using low-NOX
precalciner technology. Operating experience indicates a noticeable reduction in NOX per
ton of clinker. Industry reports place the NOX reduction potential of staged combustion
with a low-NOX precalciner at 30% - 40% when compared to a conventional precalciner
kiln system.
Low-NOX precalciner is a proven way to reduce NOX emissions in a cementmaking system, and all new cement-making systems are expected to be built with it. They
come in two types, “in-line”, commonly used with “normal” fuels (e.g. coal, oil, gas), or
“separate-line”, selected for difficult-to-burn fuels (e.g. petroleum coke and anthracite)
because its high oxygen atmosphere ensures improved fuel burnout. In-line calciners
have lower specific NOX emissions than separate-line ones, but both are capable of
meeting current CO/NOX emission standards for any combination of fuel and feed, and
both are dependent on the presence of strong reduction and oxidation zones.
CemStar
Another approach that has been proven effective in reducing NOX is the patented
CemStar process, originally developed and sold as a method to increase production of
clinker from existing kilns while minimizing capital expenditures (Young, 1995; Young,
1996). In the CemStar process, steel or blast furnace slag is introduced as feed material
into the kiln. The slag is generally added at the inlet to the rotary kiln (typically after the
precalciner or preheater), regardless of kiln type. Unlike normal cement materials, which
require significant processing to achieve adequate grain size, the slag need only be
crushed to 3/4 to 1-1/2 inch pieces. Minimal processing is necessary because the slag has
a low melting temperature and its chemical nature is very similar to the desired clinker.
Minimal slag processing permits the equipment for the CemStar to be inexpensive and
also reduces energy consumption per unit of clinker produced. Moreover, the CemStar
process can be implemented on a kiln quickly with minimal impact to facility operations.
The equipment needed is mostly material handling equipment.
The CemStar approach has many advantages: energy input can be reduced, NOX
emissions (both lbs/hr and lbs/ton of clinker) can be reduced, and kiln capacity can be
increased. Since the steel slag more closely resembles the desired kiln product than do
the normal raw materials, kilns with CemStar require less intense firing and allow for a
significant reduction of peak burn-zone temperature. The lower burn zone temperature
results in less thermal NOX generation. NOX reduction may be expected to be in the
range of 20% or more for most kilns. If initial, uncontrolled NOX is high due to thermal
NOX, CemStar is likely to provide reductions on the order of 40%-50%. Results of
controlled testing of CemStar with baseline conditions resulted in 20% reduction in NOX,
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corresponding with a reduction in average burn-zone temperature of over 200°F. Kiln
capacity is increased because each ton of steel slag added to the kiln results in about a ton
of additional production, though the precise amount of additional kiln production is
dependent on the mineral characteristics of the local raw material. This capacity increase
is the reason that many facility owners may initially choose to use CemStar.
TXI, the developer of CemStar, reports that more than 10 plants are currently
equipped with the technology. NESCAUM (2001) discusses one application of CemStar
on a long-wet process kiln.
Mid-Kiln Firing
Mid-kiln firing entails injecting a fuel, usually tires, mid-way through long dry
and long wet kilns. This method has been shown to reduce NOX by about 30% with midkiln heat input comprising about 20% of the total heat input (Portland Cement
Association, 1998). Results of tests of mid-kiln firing on several kilns are summarized in
Table 2 (NESCAUM,2001). The average NOX reduction for these kilns is about 27%.
Mid-kiln firing reduces the heat needed, and therefore the thermal NOX produced in the
primary burn zone. Fuel NOX will also be reduced because tires and other mid-kiln fuels
have low nitrogen contents. Nitrogen content in tires is roughly one fifth that of coal on a
mass basis, while heating value on a mass basis is similar (Schrama et al., 1995;
Stillwater and Wahlquist, 1998). Coal can be used as a mid-kiln firing fuel, but tires are
preferable because they provide a revenue source when kiln operators are paid a tipping
fee for taking whole tires. Other revenue-generating fuels could potentially be used as
well.
Table IV-2 NOX Reduction at Cement Kilns Using Mid-Kiln Technology
(NESCAUM,2001)
Initial NOX (ppm)
936
1372
1342
1359
565
513
Final NOX (ppm)
790
994
600
883
488
456
% Reduction
16%
28%
55%
35%
14%
11%
High-pressure air injection, mentioned in the previous section as a potential
control for SO2 emissions, was primarily developed as a NOX reduction strategy (Hansen,
2002). The technique was designed for use with staged fuel combustion (mid-kiln firing)
and mixing air. Mid-kiln firing with mixing air creates stratified thermal layers in the
kiln, preventing immediate combustion of the mid-kiln fuel and lowering exit oxygen
levels enough that additional CO is produced. Injecting high-pressure air into the kiln
provides energy to mix the layers, lowering the main flame temperature and creating a
reducing area between the fuel and air injection points, which encourages the destruction
of NOX. The technique has been shown to reduce NOX by about 50%, while also
reducing CO by 47% and SO2 by 97%.
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Biosolids Injection
Biosolids Injection (BSI) is a technology that was developed in the 1990's by the
cement industry for NOX reduction in precalciner and preheater kilns (Biggs, 1995). BSI
adds dewatered sewage sludge to the mixing chamber of the precalciner. The dewatered
biosolids provide a source of ammonia, producing an SNCR reaction to reduce NOX. At
a Mitsubishi Cement Kiln in California, BSI provided about 50% reduction in NOX from
about 250 ppm (at 12% oxygen) to 120-125 ppm (at 12% oxygen). BSI has the
additional benefit of offering a potential revenue stream because many communities are
willing to pay a tipping fee for accepting biosolids. BSI technology may require
significant capital equipment expenditures, however. The material handling equipment
needed and the moisture in the dewatered biosolids is sufficient to strain the capacity of
the fans of many existing facilities. It appears that biosolids injection may be an effective
approach for NOX reduction, but it will depend on the specifics of the kiln.
Selective Non-catalytic Reduction
Selective Non-catalytic Reduction (SNCR) of NOX is based on the injection of a
reagent, typically NH3 or urea, into the kiln system at a location with an appropriate
temperature window 1140 – 2010oF (870 - 1100°C). Some researchers have found that
the most effective temperature range is narrower, about 1650 – 2000°F (900 - 1000°C).
Temperature is critical because no catalyst is used. At temperatures too high, the reagents
will form additional NOX, and, at low temperatures, the reactions proceed slowly and
promote the escape of substantial amounts of unreacted ammonia. Under optimum
conditions about one mole of NH3 is required to reduce one mole of NOX, but the
amount of NH3 is always critically dependent on the reaction temperature. Ammonia
slip, which increases rapidly when the molar ratio of NH3 to NO is above one, causes a
detached plume and can increase opacity of the stack gases.
Preheater and precalciner kilns operate with kiln gas exit temperatures in the
appropriate temperature range. SNCR systems have been used on some preheater kilns in
Europe. For wet and long dry kilns, these temperatures exist midway through the kiln.
Access to this area is possible only through ports in the kiln shell as used in mid-kiln
firing or with scoops used to return cement kiln dust. Ammonia must be added
continuously in a fixed molar ratio to NOX in order to be effective and to minimize
ammonia slip. Therefore, SNCR is not technically feasible at this time on long wet
process or long dry process kilns.
SNCR has been tested in the U.S. on precalciner kilns and is planned for
commercial use in other countries (Steuch et al., 1994; Sun et al., 1994). Experience is
limited to only a few units worldwide, but some tests have reported significant
reductions. Table 3 lists commercial installations of urea SNCR on precalciner kilns and
the results of some demonstration programs. Effective operation of SNCR requires
availability of a section of kiln with the proper temperature and residence time
characteristics for good reduction. The specifics of the installation will determine the
level of reduction that is possible. It is unlikely that SNCR can be used effectively on
many long kilns (wet or dry) because of the need for access to the proper temperature
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region for injecting urea or ammonia reagent. However on some precalciner kilns the
access to the proper temperature zone is good.
Although SNCR technology has the potential to offer significant reductions on
some precalciner kilns and it is being used in numerous cement kilns in Europe, it has
been tested in only one facility in the U.S.
Table IV-3 NOX Reduction Performance of Urea SNCR on Precalciner Cement
Kilns (NESCAUM, 2001)
Company /
Location
Unit Type
Size
(MMBtu/hr)
NOX Baseline
Reduction
(%)
NH3
SLIP,
(ppm)
Ash Grove Cement
Seattle, WA
(Demo)
Cement
Kiln/
Precalciner
160 tons
solids/hr
350-600 lb/hr
>80
< 10
Korean Cement
New
Suspension
Precalciner
na
1.27 lb/MMBtu
45
na
Taiwan Cement
Units #3, #5, & #6
Cement
Kiln/
Precalciner
260
697
658
1.29 lb/MMBtu
1.58 lb/MMBtu
0.92 lb/MMBtu
50
45
25
15
15
15
Wulfrath Cement
Germany (Demo)
Cement
Kiln
140
1000 mg/Nm3
500 ppm
90
na
Dong Yang Cement,
Korea (Demo)
Selective Catalytic Reduction
Selective Catalytic Reduction (SCR) uses ammonia, in the presence of a catalyst
(e.g. titanium dioxide; vanadium pentoxide), to selectively reduce NOX emissions from
exhaust gases. SCR has been extensively and quite successfully used in a very cost
effective manner on coal- and gas-fired utility boilers, industrial boilers, gas turbines and
internal combustion diesel engines in the U.S. Typically, anhydrous ammonia, usually
diluted with air or steam is injected into hot flue gases, which then pass through a catalyst
bed where NOX is reduced to N2 gas and water. The optimum temperature for SCR
depends on the catalyst but is usually between 570 and 840oF (300 and 450°C).
Exit gas temperatures from dust collectors on wet kilns, for long dry kilns, and for
dust collectors in preheater kilns that use in-line raw mills for grinding and drying raw
materials are relatively low and flue gases would have to be reheated before employing
SCR. This technology so far has not been applied to the cement kilns but is being
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evaluated by some of the state air permitting agencies as Best Available Control
Technology (BACT) for some of the new cement kilns being proposed in the U.S.
Combination of Technologies
It is not uncommon to combine combustion technologies with post-combustion
technologies for other source types, and this could be done for cement kilns in some
cases. It is also possible to combine multiple combustion technologies on cement kilns.
For example, one of the case studies in Status Report on NOx Controls for Gas Turbines,
Cement Kilns, Industrial Boilers, Internal Combustion Engines; Technologies and Cost
Effectiveness (NESCAUM, 2001) combines indirect firing and mid-kiln firing to reduce
NOX by a combined amount approaching 50%. It is also reasonable to expect that
technologies such as CemStar might be combined with a combustion technology such as
mid-kiln firing to provide combined benefits, and it may be feasible to use SNCR or SCR
in combination with other controls for cement kilns. The exact amount of reduction will
depend upon the regulatory requirements and technical limitations. In some cases the
NOX reductions may not be additive.
4.3.3. PM2.5 Controls
The particulate matter exiting the kiln system with the exhaust gases is relatively
coarse, with most of the particuate matter having diameters greater than 10 microns, but
the concentrations of particles in the exhaust can be several times higher than in a coalfired power plant. Particulate control devices for cement plants must be able to clean
gases with fairly high dust loading.
As is the case for many other industrial sectors, the main control options for fine
particles are baghouses (more formally known as Fabric Filters) and electrostatic
precipitators (ESPs), described in Section 2.3.2 (EGUs). The following section describes
some issues specifically related to cement kilns and the use of these devices, including a
new filter system combining a baghouse and an ESP.
Cement kilns primarily utilize baghouses of the reverse-air and pulse-jet types.
Both types are usually configured so that the bags can be cleaned during an “off-line”
cycle, in which a section of the baghouse is closed off from the main exhaust flow for
cleaning. This tends to reduce the need for a high-pressure pulse that causes additional
wear on the filtration fabric, allows less time for particles to be collected in the hopper
during its brief and frequent use, and requires additional power for operation. The choice
between a reverse-air and pulse-jet system is generally made on the basis of the volume
of exhaust and production from the kiln. In general, kilns producing less than 1650 stpd
(with exhaust volumes below 128,000 acfm) are most efficiently served by a jet-pulse
system (D’Lima and Pirwitz, 2000). The decision is more complex for kilns up to 6600
stpd (with exhaust volumes up to 853,000 acfm), for which initial equipment costs are
similar but lifetime operation costs are more complicated. D’Lima and Pirwitz (2000)
concluded that jet-pulse systems are appropriate for the smallest kilns and reverse-air
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systems are preferred for all larger kilns, even though they may have higher installation
costs for kilns of more modest size.
Corrosion in baghouses has been an important topic in the cement kiln control
literature (Jansen and Mazeika, 2003; Biege and Shenk, 2001). A 2002 EPA rule [40
CFR Part 63 Subpart LLL (2002)] requires gas temperatures entering the control device
not to exceed 400°F (205°C) in order to control dioxin emissions. Water sprays are
usually utilized to control exhaust temperature, but adding water vapor to the exhaust
stream while lowering exhaust temperature brings the gas near the dew point of some
corrosive components. Corrosion issues can be addressed in a number of ways, but all
add cost to the use of the control system.
The three components of corrosion are corrosive gases, condensation, and a
corrodible surface; reducing any component will reduce corrosion. Corrosive gases can
be reduced in a roller mill; this may be one of the most effective methods to reduce
corrosion. Many of the gases are absorbed by the feed during the milling process and are
therefore not available to form acids in the exhaust. Changing the feed may also reduce
some of the acidic gases. Condensation is prevented most easily by keeping the exhaust
temperature hot; however, when this is not allowed, it is best to maintain the exhaust
temperature as high as possible, preventing drops which may allow acidic condensation.
Insulating surfaces and carefully sealing unused sections of the control device can
prevent exhaust from leaking into cool areas where it can condense and cause corrosion.
Finally, corrosive-resistant materials and acid-resistant coatings can help reduce
corrosion in control equipment.
Instead of a baghouse or an ESP, a combined system has become available,
utilizing components of both systems. Whereas an in-series, hybrid system has the ESP
and baghouse systems in independent compartments, this technology is described as “an
ESP in which every other row of discharge electrodes is replaced by a single row of filter
bags” (Gebert et al., 2003). In this new system, where the filter bags are directly adjacent
or parallel to the ESP electrical field, ESP zones alternate with filter zones, allowing
primary collection by the ESP and pre-ionization of the remaining dust for collection on
the filter bags. A highly efficient expanded polytetrafluoroethylene (ePTFE) membrane is
used as the filter fabric, which can remove an order of magnitude more of fine particulate
than ordinary bags. During a pilot system test of a 225 m3/min (9000 acfm) slipstream
from a coal-fired power plant in South Dakota, greater than 99.99% removal efficiency
was shown. With the ESP fully engaged, bag cleaning was required only every 300
minutes, compared to every fifteen minutes when the ESP was not used. This system has
been utilized in full-scale commercial operation at a cement kiln in Italy since September
2002, capturing dust from the cement kiln, raw mill and clicker cooler. Another similar
filter is in operation since October 2002 at the coal-fired power plant in South Dakota
mentioned above.
The synergy between the two technologies enables operation of the filter bags at
high air-to-cloth (A/C) ratios, and, combined with the new compact size for filters,
provides the following benefits for a cement plant:
•
Ability to reach high control efficiencies in all operation modes,
•
Continuous stable operation, and
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•
Page 4-20
Lower operating costs, due to reduced number of system components.
4.3.4. VOC Controls
No controls which specifically targeted VOCs were identified for cement kilns.
4.4. Costs and Availability
4.4.1. Sulfur Dioxide Control
The SOx control techniques applicable to the cement industry and the assumed
SOx reductions that the various control technologies can achieve are summarized in Table
IV-4.
The achievable SOx reductions vary greatly. Even when the same control
technology is applied to kilns of the same type, the removal efficiency will depend on
kiln operating parameters, uncontrolled SOx emissions rate, and many other site-specific
factors.
Wet-limestone scrubbers and spray dryers can be used as secondary control
devices to reduce SO2 emissions from a cement kiln.
Capital and operating costs for spray dryers and wet scrubbers as applied to
cement kilns were computed by Young (2002). Both technologies were assumed to be
installed after the existing APCD, which would allow the CKD to be recycled back to the
kiln. If CKD is not recycled, there is a negative impact on the operating cost of the plant.
Table IV-5 summarizes the capital and operating costs in terms of $ per ton of clinker
produced for different types of kilns. The capital and operating costs of the spray dryer
include a baghouse, new stack and new ID (induced draft) fan. The capital and operating
costs for the wet scrubber include new fans and a new stack as well as a new wastewater
treatment facility.
Another installation was made in 1998 at Castle Cement’s Ribblesdale (UK)
facility (Castle Cement, 2004). Scrubber installation cost £5 million and operational
costs are about £750,000 annually. Emissions from one unit were reduced by 90%.
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Table IV-4 SO2 Control Techniques Applicable to Cement Kilns (Miller, 2001)
SO2 reduction
technique
Applicable to kiln type
Long wet Long dry
Process alterations
Range of
removal
efficiency
x
x
x
0-100%
Dry reagent injection
x
x
25-85%
Hot meal injection
x
x
0-30%
x
x
x
50-90%
x
x
x
80-95%
Spray dryer absorber
Wet SO2 scrubber
x
x
Preheater Precalciner
Table IV-5 Capital and operating costs of spray dryers and wet scrubbers applied
to cement kilns (Young, 2002)
Spray Dryer
Wet Scrubber
Annual
Annual
Clinker Capital Operating Capital Operating
capacity, Cost, $/ton Cost, $/ton Cost, $/ton Cost, $/ton
tpy
clinker
clinker
clinker
clinker
Small wet kiln
300,000 $54.67
$20.02
$47.00
$22.59
Medium wet kiln
600,000 $38.17
$14.09
$32.67
$17.58
Medium dry kiln
600,000 $39.75
$14.79
$31.83
$17.21
Large dry kiln
1,200,000 $23.17
$9.43
$20.42
$13.05
Medium preheater kiln
600,000 $17.92
$7.51
$15.83
$9.85
Medium precalciner kiln w/ bypass 600,000 $25.17
$10.20
$19.33
$11.42
Large preheater kiln
1,200,000 $10.96
$5.41
$10.83
$8.14
An alternative secondary control device for SO2 was designed and applied as part
of U.S. Department of Energy’s Clean Coal Technology program. A co-project of
Passamaquoddy Technology and Dragon Products Company in Thomaston, ME, the
Passamaquoddy Technology Recovery ScrubberTM (Recovery ScrubberTM) utilizes
cement-kiln dust as a reagent for removing SO2 from kiln exhaust gases (USDOE, 2001).
Waste heat from the kiln is used to crystallize K2SO4, a saleable, fertilizer-grade byproduct. The remaining cement kiln dust is returned to the kiln, significantly reducing
particulate emissions, eliminating the need for removal of the dust to a landfill, and
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reducing the requirement for raw materials by about 10 percent. Sulfur dioxide was
reduced by 82 to 98.5%, depending on scrubber inlet SO2 rates. In addition, NOX was
reduced by about 25% and VOCs by 70%. Capital costs for a Recovery ScrubberTM were
estimated at about $10.5 million in 1996 dollars, with operating and maintenance costs of
$150,000 per year and electricity costs of $350,000 per year (787 kW at $0.06/kW).
4.4.2. Nitrogen Oxides Control
Table 6 presents a summary of NOX controls that are feasible for cement kilns, the
range of potential NOX reductions from applying these controls, the cost effectiveness of
the controls, and effects on other emissions when using these controls.
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Table IV-6 Summary of the Feasibility of NOX Controls for Cement Kilns
Cost Effectiveness
($/ton NOX
Effect on Other
Reference
removed)
Emissions
Technical
Feasibility
NOX Reduction Potential
(%)1
Process Modifications
In full-scale
use
0 - 30 [15]
3,100 - 8,800
Unknown
Low NOX Burners w/
Indirect Firing
In full-scale
use
0 – 20 [10]
5,800 - 8,100
Unknown
Low NOX Burners w/
Indirect Firing and Midkiln Tire Injection
In full-scale
use
[49]
1 - 1,800
Unknown
Mid-Kiln Injection of
Fuel, Riser Duct Firing
Calciners
In full-scale
use
5,100 -11,500
May increase CO,
SO; hydrocarbon
emission
16
0 – 30 [15]
CemStar
Wet kilns
20 - 50 [20]
0-600
Unknown
17
Low NOX Precalciner
Have been
installed on
several fullscale kilns Offered by
several
different
vendors.
SNCR
May be
applicable
only on
preheater or
precalciner
kilns - limited
data
Biosolids Injection
May be
applicable
only on
preheater or
precalciner
kilns - limited
data
NOX Reduction Technique
1
16
16
17
16
30 – 40 [30]
2,700 - 3,600
May Increase
emissions CO,
S02, and/ or
hydrocarbons
900 - 1,200
May Increase
emissions CO,
NH3, and
NH4+salts
(detached plume)
100-1,800
May Increase
emissions CO,
NH3, and
NH4+salts
(detached plume
17
15 – 65 [45]
17
[50]
Values in brackets are the assumed NO X reductions used to calculate the estimated cost effectiveness of each
Technology.
4-23
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 4-24
4.4.3. PM2.5 Control
As discussed above, control of particulate matter in cement kilns is accomplished
using baghouses and electrostatic precipitators. These processes are also used in electric
utility generating units and industrial boilers. Capital and operating costs for fabric filters
and ESPs as applied to cement kilns were computed by Young (2002) and are
summarized in Table IV-7. The costs include the addition of a new fan.
Table IV-7 Capital and operating costs of baghouses and ESPs applied to cement
kilns (Young, 2002)
New ESP
New baghouse
Annual
Annual
Clinker Capital Operating Capital Operating
capacity, Cost, $/ton Cost, $/ton Cost, $/ton Cost, $/ton
tpy
clinker
clinker
clinker
clinker
Small wet kiln
300,000 $14.00
$3.35
$16.67
$3.81
Medium wet kiln
600,000 $11.00
$2.49
$13.00
$2.92
Medium dry kiln
600,000 $10.50
$2.54
$12.00
$2.78
Large dry kiln
1,200,000 $7.33
$1.51
$8.67
$1.96
Medium preheater kiln
600,000 $4.33
$1.03
$5.17
$1.17
Medium precalciner kiln w/ bypass 600,000 $5.33
$1.42
$6.33
$1.53
Large preheater kiln
1,200,000 $3.33
$0.74
$4.00
$0.90
4-24
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 4-25
References
Biege, NW and RE Shenk. “Strategies for Reducing Cement Kiln Baghouse Corrosion
Problems.” IEEE/PCA Cement Industry Technical Conference, Vancouver, British
Columbia; May 2001.
Biggs, H.O. "BioSolids Injection Technology: an Innovation in Cement Kiln NOX
Control." Proceedings of the 31st International Cement Seminar. TP 881 .I5, 1995.
Castle Cement. “http://www.castlecement.co.uk/env_emm.htm” 5 May 2004.
D’Lima, Hector and W. Pirwitz. “Cement Kiln Baghouse: 20 Year Life Cycle
Comparison, Jet Pulse vs. Reverse Air.” IEEE-IAS/PCA Cement Industry Technical
Conference; Salt Lake City, UT: May 2000.
Gardeik. H.O. et.al., Research Institute of the Cement Industry, Dusseldorf; Behavior of
nitrogen oxides in rotary kiln plants of the cement industry; Trans of ZKG No.10/84
Gartner, E.M.; Nitrogenous Emissions from Cement Kiln Feeds; Interim Report on
Project HM7140-4330; For presentation at Rule 1112 Ad Hoc Committee Meeting South
Coast Air Quality Management District, El Monte, CA; June 7, 1983
Jansen, A. and L. Mazeika. “Alternative Solutions for Corrosion Problems in Cement
Plant Pollution Control Equipment.” IEEE-IAS/PCA 44th Cement Industry Technical
Conference; Dallas, TX: May 2003.
Gebert, R., et al. “A New Filter System, Combining a Fabric Filter and Electrostatic
Precipitator for Effective Pollution Control Be hind Cement Kilns.” IEEE-IAS/PCA 44th
Cement Industry Technical Conference; Dallas, TX: May 2003.
Hansen, E.R., The Use of Carbon Monoxide and Other Gases for Process Control; 27th
I.E.E.E. Cement Industry Technical Conference Proceedings, May 1985
Hansen, E.R., “Panel Discussion: Reduction of Clinker Alkali and SO2, NOX Emissions
from Preheater Kilns,” Portland Cement Association, GTC Fall Meeting, September,
1986.
Hansen, Eric R. “Staged Combustion for NOX Reduction Using High Pressure Air
Injection” IEEE-IAS/PCA 43rd Cement Industry Technical Conference; Jacksonville,
FL: May 2002.
Keefe, B.P. and R.E.Shenk, “Staged Combustion for Low-NOX Calciners; Sept, 2002
Kupper, D., et. al.; Trends on Desulfurization and Denitification Techniques in the
Cement Industry; Proceeding of Emerging Technologies in Resource Recovery and
Emission Reduction in the Cement Industry; Sponsored by the Portland Cement
Association, Dallas, TX; September, 1990
4-25
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 4-26
Miller, F.M. and A.H. Egelov; Relationship between cement kiln operation and content
of NOX is kiln gases; Zement-Kalk-Gips International; Weisbaden, Germany, 1980.
Miller, F.M. et. al. “Formation and Techniques of Control of Sulfur Dioxide and Other
Sulfur Compounds in Portland Cement Kiln Systems. Portland Cement Association R&D
Serial No. 2460, 2001.
NESCAUM, Status Report on NOX Controls for Gas Turbines, Cement Kilns, Industrial
Boilers, Internal Combustion Engines; Technologies and Cost Effectiveness, Amar, P.,
Staudt, J., Northeast States for Coordinated Air Use Management, Boston, MA, January,
2001.
NESCAUM, Technical Memorandum #6: Development of a List of BART-Eligible
Sources in the MANE-VU Region. Boston, MA; May, 2004.
Nielse, P.B., “Die SO2 – und NOX-Emissionen bei modernen Zementdrehofen_Anlagen
mit Blick auk=f zukünftige Verordnungen (SO2 and NOX Emissions from Modern
Cement Kilns with a View of Future Regulations),” Zement-Kalk-Gips, Vol. 44, No.9,
1991 pp. 449-456
Nielsen, P.B., and O.L.Jepsen; An Overview of the Formation of SOx and NOX in
Various Pyroprocessing Systems; Presented at: IEEE Cement Industry Technical
Conference, XXXII; Tarpon Springs, FL, May, 1990
Portland Cement Association. "Report on NOX Formation and Variability in Portland
Cement Kiln Systems Potential Control Techniques and Their Feasibility and Cost
Effectiveness." PCA R&D Serial No. 2227, December, 1998.
Portland Cement Association, U.S and Canadian Portland Cement Industry: Plant
Information Summary, Data as of December 31, 2000.
Schrsemli, Dr. W.; Experience with Measures to Reduce SO2 and NOX Emissions from
Cement Kilns In; Proceeding of Emerging Technologies in Resource Recovery and
Emissions Reduction in the Cement Industry; Sponsored by the Portland Cement
Association, Dallas, TX; September, 1990
Schrama, H., Blumenthal, M., and Weatherhead, E. C. "A Survey of Tire Burning
Technology for the Cement Industry." IEEE Cement Industry Technical Conference.
San Juan, Puerto Rico: June 4-9, 1995.
Sheth, S.H., “SO2 Emissions History and Scrubbing System—Santa Cruz Plant,
California, RMC Limestone,” 33rd IEEE Cement Industry Conference, Mexico City,
Mexico, May, 1991.
Steuch, H.E., and Johansen, V., “Some Facts on SO2 Emissions”, Rock Products, Vol. 94,
No.6, 1991, pp.65-71
4-26
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 4-27
Steuch, H.E., Hille, J., Sun, W.H., Bisnett, M.J, and Kirk, D.W. "Reduction of NOX
Emissions from a Dry Process Preheater Kiln with Calciner Through the Use of the
NOXOUT Process." Portland Cement Association Meeting of the General Technical
Committee. Seattle, WA: September 18-21, 1994.
Stillwater, M.A. and Wahlquist, C.J. "Building a Successful Tire Derived Fuel
Program." Proceedings of the 34th International Cement Seminar. December 6-9, 1998,
Salt Lake City, UT.
Sun, W.H., Bisnett, M.J., et al. "Reduction of NOX Emissions from Cement
Kiln/Calciner through the Use of the NOXOUT Process." International Specialty
Conference on Waste Combustion in Boilers and Industrial Furnaces. Air and Waste
Management Association. Kansas City, MO: April 21, 1994.
Tanna, B. and B. Schipholt. “Waste-Derived Fuel Use in Cement Kilns” ERAtech
Group, LLC http://www.eratech.com/papers/wdf.htm, accessed September, 2004.
U.S. Department of Energy, NETL. Cement Kiln Flue Gas Recovery Scrubber Project:
A DOE Assessment. DOE/NETL-2002/1163, November 2001.
U.S. Environmental Protection Agency. “Alternative Control Techniques Document -NOX Emissions from Cement Manufacturing.” EPA453/R-94-004, March, 1994.
Young, R.D. "Method and Apparatus for Using Steel Slag in Cement Clinker
Production." U.S. Patent No. 5,421,880. Issued June 6, 1995.
Young, R.D. "Method and Apparatus for Using Blast-Furnace Slag in Cement Clinker
Production." U.S. Patent No. 5,494,515. Issued February 27, 1996.
Young, G.L. Review of Model Kiln Scenarios and Cost Estimates for Control of
Hazardous Air Pollutants. Portland Cement Association, Report SP127, 2002.
Young, G. L. and von Seebach, M. " NOX Variability Emission and Control from
Portland Cement Kilns." Proceedings of the 34th International Cement Seminar,
December 6-9, 1998
Young, G.L. and von Seebach, Michael; NOX Abatement in Kiln Plants in the Cement
Industry, Zement-Kalk-Gips, Volume 52, Number 6, 1999
4-27
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-1
5. KRAFT PULP MILLS
5.1. Description of pulp and paper processes
Kraft pulping processes consists of wood preparation, pulping, pulp washing,
oxygen delignification and/or bleaching of pulp and chemical recovery as illustrated in
Figure V-1. Beginning with wood preparation, logs are debarked, ground into wood
chips, and then screened to remove chips of unacceptable sizes. During the pulping
process, the wood chips enter the digester where they are cooked with liquor and broken
down into a pulp slurry. The pulp slurry is transferred to a blow tank while the spent
liquor is sent to a flash tank. The pulp slurry then enters the pulp washing process where
knots, shives, and short fibers are removed, spent cooking chemicals are recovered from
the pulp slurry, and the pulp slurry is thickened for later processes. Next, the pulp
enters the oxygen delignification process where the lignin content of the pulp is reduced
to increase brightness of the pulp. The brightness of the pulp is further enhanced by
bleaching, a multi step process that removes residual lignin by using chemicals to oxidize
and dissolve the lignin compounds. Lastly, the chemical recovery process recovers the
spent cooking liquor using the following methods: evaporation to reduce water content
in spent liquor, combustion of concentrated spent liquor, and recovery of chemicals from
Figure 1. Schematic of the Kraft Pulping and Recovery Process (Someshwar and
Pinkerton, 2000).
5-1
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-2
combustion products. The regeneration of lime, which is used for recovering sodium, is
an additional step of the kraft chemical recovery process not found in the acid sulfite,
mechanical, or semi chemical processes.
Acid Sulfite and semi chemical processes are very similar to the kraft process,
however, the acid sulfite process differs from the kraft process in the type of cooking
liquor used and the semi chemical process differs from the kraft process in the use of
lower temperatures, more dilute cooking liquor or shorter cooking time, and mechanical
disintegration. Mechanical pulping uses high-energy refining systems to produce pulp
from chips and bleaching agents are used to decolorize lignin instead of removing lignin.
(Someshwar and Pinkerton, 2000; Pinkerton, 2000).
5.2. Review of BART-Eligible Pulp and Paper facilities in the MANEVU Region
There are 10 facilities with BART-Eligible industrial boilers in the MANE-VU
region. Table III-2 contains a list of these sources based on a previous NESCAUM report
(2003) and follow-up review by state permitting authorities. 7 [Editor’s note: additional
facilities may be added after NY and PA have completed their inventory].
Table V-1 BART-eligible pulp and paper facilities.
State
Company/Facility
City/Town Category
Maryland
Maine
Maine
Maine
WESTVACO FINE PAPERS
Domtar - Pulp & Paper
Fort James - OldTown
IP Androscoggin
Luke
Baileyville
Old Town
Jay
kraft pulp
kraft pulp
kraft pulp
kraft pulp
Maine
Lincoln Pulp and Paper
Lincoln
kraft pulp
Maine
Madison Paper
Madison
kraft pulp
Maine
Mead WestVaco
Rumford
kraft pulp
Maine
SD Warren - Somerset
Skowhegan kraft pulp
Maine
SD Warren Co.
Westbrook
kraft pulp
Berlin
kraft pulp
New Hampshire Pulp & Paper Mills
(33007-00001-11)
5.3. Available Control Technologies
The pulp and paper production, consisting of chemical, mechanical, and semi
chemical processes, has a number of potential sources of SOx, NOX, particulates, and
VOC emissions (Pinkerton, 2000). The major chemical wood pulping processes are
kraft, acid sulfite, and semi chemical pulping. Kraft pulping accounts for 80% of the
7
NESCAUM does not believe that there are any BART-eligible sources in the State of Vermont or any of
the member Tribes in MANE-VU and thus we have not developed lists for these jurisdictions. In addition,
Pennsylvania and the District of Columbia have developed BART-Eligible source lists following their own
methodology and any identified sources are contained here and in the final list in Appendix A.
5-2
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-3
pulp produced in the U.S, mechanical and semi chemical pulping, for 10% and 6%,
respectively and sulfite or soda chemical process accounts for the remaining pulping
capacity (Someshwar and Pinkerton, 2000).
A variety of technologies exist for controlling emissions from pulp and paper
facilities. Secondary control devices can be helpful in reducing emissions, and a number
of them are available. Many facilities have found that significant emissions reductions
can be achieved through process changes at the facility. Both secondary controls and
process changes are discussed below, grouped by their targeted pollutant. When
additional emissions reductions are possible, they are noted with the main (or targeted)
pollutant. The sections below will describe the potential sources of significant SOx,
NOX, particulates, and VOC emissions in the major pulping processes and the measures
used to control them.
5.3.1. SO2 Controls
In a kraft mill, SO2 is a product of the incineration of black liquor in the recovery
furnace; black liquor is made up of 3-5% sulfur by weight of dissolved solids. The
majority of the sulfur exits the furnace in the smelt; however, typically less than 1% can
be emitted as a gas or particulate, resulting in average SO2 concentrations of 0-500 ppm
in stack gases. Recovery furnace SO2 emissions are a function of liquor properties such
as sulfidity (sulfur-to-sodium ratio), heating value, and solids content; combustion air and
liquor firing patterns; furnace design features; furnace load; auxiliary fuel use; and stack
gas oxygen content. To reduce SO2 emissions from the recovery furnace, the
temperature in the lower furnace must be uniform. This has been achieved by optimizing
liquor and combustion air properties and firing patterns. Reducing liquor sulfidity has
also been used as a control strategy for SO2 emissions. Flue gas desulfurization as an
effective control strategy is uncertain due to the mostly low and unpredictable levels of
SO2 emitted.
In a lime kiln, SO2 is produced from the combustion of fuel oil or non
condensable gases (NCG). On average, lime kiln SO2 emissions are very low due to the
capture of SO2 from the alkaline material inside the kiln and the venturi scrubber usually
installed immediately after the kiln.
In semi chemical processes, only neutral sulfite semi chemical (NSSC) pulping
emits SO2 emissions as a result of the combustion of sulfur-containing semi chemical
spent liquor in a fluidized bed combustor. Limited data shows an SO2 emission factor for
a fluidized bed combustor burning NSSC liquor as 1 lb SO2/a.d. ton of pulp.
A major source of SO2 in acid sulfite processes is from the digester and blow tank
areas. During a hot blow, significant quantities of SO2 can be released into the blow
gases ranging from 10 to 70 pounds per ton of pulp. Using an alkaline solution to scrub
the blow gases, 97% of SO2 can be recovered and returned to the acid-preparation
system. While this approach is possible using sodium and NH3 bases, magnesium and
calcium bases need slurry scrubbers deemed less practical. Scrubbing becomes
5-3
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-4
impractical when during a cold blow, only 4 to 20 pounds SO2 per pulp are released into
the blow gases.
SO2 can also escape from acid bisulfite washers and screens which can result in
uncontrolled emissions generally ranging from 1 to 4 lb SO2/ton pulp but can get up to as
much as 16 lb SO2/ton pulp. The gases emitted from the washers and screens are hooded
and then directed to a direct-contact scrubber where the SO2 is scrubbed from the gases.
(Someshwar and Pinkerton, 2000; Pinkerton, 2000).
5.3.2. NOX Controls
NOX is produced from the incineration of black liquor in the kraft recovery
furnace with black liquor containing 0.05% to 0.25% nitrogen by weight of liquor solids
content. Normal NOX emissions from kraft recovery furnaces are less than 100 ppm.
NOX emissions are mainly a result of fuel NOX since the maximum temperature in the
recovery furnace is approximately 2400oF and the temperature required for formation of
significant amounts of thermal NOX is greater than 2800oF. NCASI studied the origins of
NOX emissions from kraft recovery furnaces and concluded that the two most important
factors affecting NOX emissions, in order of importance, were the black liquor nitrogen
content and excess oxygen in the zone where most of the liquor combustion occurs.
Since it is difficult to alter the liquor N content, the best approach to minimizing NOX in
recovery furnaces is staged-air combustion. Currently, most recovery furnaces already
optimally use staged combustion and emit less than 100ppm NOX.
NOX is produced in the kraft lime kiln from the combustion of fossil fuels, such as
natural gas and residual fuel oil. Due to the design of the lime kiln, SNCRs and SCRs
are not viable NOX reduction techniques. Installing Low-NOX Burners (LNBs) is also
not a practical NOX reduction technique according to a BACT analysis conducted on a
new lime kiln in 1997. The installation of LNBs had a negative influence on the
efficiency, energy usage, and calcining capacity of the lime kiln. Hence, like the
recovery furnace, combustion modification such as decreasing excess air is the best way
to reduce NOX emissions. However, since the mechanisms of NOX formation and NOX
emission reduction are not completely known, NOX reduction strategies should be
considered on a case-by-case basis.
Some NOX emissions result from the burning of stripper off gases (SOGs) with
significant ammonia and methanol content and combustion of NCG in the kiln, thermal
oxidizer, or boiler. When SOGs containing methanol and ammonia are incinerated, the
ammonia could potentially oxidize to produce NOX. NH3 will oxidize to NOX when
injected into gases above 2000oF to 2200oF, reduce NOX to N2 when gas temperatures
range from about 1600oF to 2200oF, and remain as NH3 in temperatures below 1600oF.
However, the degree of NH3 conversion to NOX and the expected baseline level of NOX
emissions from pulp process units burning NCG and SOGs are not known.
NOX emissions are expected during combustion of liquor in recovery furnaces for both
semi chemical and acid sulfite processes. (Pinkerton, 2000; Someshwar, 1999).
5-4
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-5
5.3.3. PM2.5 Controls
Measurable particulate emissions sources in a kraft mill are recovery furnaces,
smelt-dissolving tanks, and lime kilns while fugitive particulate emissions sources are
coal piles, paved and unpaved roads, bulk material handling such as lime, limestone, or
starch, and wood handling. Particulate emissions from recovery furnaces are controlled
by ESPs with particulate removal efficiencies of 90% in older units and 99% in newer
units. Demister pads, packed towers or venturi scrubbers are used to achieve particulate
emissions control in smelt-dissolving tanks, and venturi scrubbers and ESPs are used for
control in lime kilns. Controlled mean particulate emission factors from smelt dissolving
tank vents and kraft lime kilns are 0.13 lb/ton black liquor solids and 1.82 lb/ton of
reburned lime product, respectively. Fugitive emissions are controlled by wetting; using
chemical agents, building enclosures, and windscreens; paving or wetting roads; and
modifying handling equipment.
In semi chemical processes, particulate emissions only become a concern when
recovery furnaces are used. These emissions are controlled by using ESPs, wet ESPs or
venturi scrubbers. In acid sulfite processes, the burning of both ammonium and
magnesium base liquors will result in the release of particulate matter in the form of
ammonium salts and magnesium oxide, respectively. The ammonium salts are removed
when the flue gas exiting the absorption unit enters a series of fabric mesh pads called
“candles.” The magnesium oxide particulates are removed using multiple cyclones, a
series of 3 or 4 packed tower absorbers, and in addition, some mills use venturi scrubbers
and/or a SO2 scrubber. Controlled particulate emissions of ammonia salt particles are
<0.5 gr/dscf @ 8% O2 and for magnesium oxide, 0.05 to 0.1 gr/dscf correct to 8% O2.
(Someshwar and Pinkerton, 2000).
5.3.4. VOC Controls
VOC emissions sources in a kraft mill are recovery furnaces and lime kilns. In a
recovery furnace, VOC emissions are produced from incomplete combustion or from the
contact between the black liquor and flue gas where volatile material from the liquor can
transfer to the flue gas. Factors that affect recovery-furnace VOC emissions are the level
of excess air used and the degree of mixing achieved within the furnace. To lower
recovery-furnace VOC emissions, the residence time, oxygen content, temperature, and
level of turbulence in the furnace combustion zone must be increased. However,
increasing these parameters will increase NOX emissions.
VOC emissions from lime kilns are also produced from incomplete combustion.
In addition, VOC emissions can be a result of VOCs entering the kiln with the liquid part
of the lime mud and VOCs being present in the scrubber makeup water. These
additional VOCs are then emitted into the flue gas when the lime mud is heated and the
flue gas exiting the kiln strips the VOCs from the scrubber makeup water. VOC
emissions from lime kilns tend to be small with the majority being methanol.
In semi chemical and acid sulfite pulping processes, VOC emissions are a product
of incomplete combustion in the fluidized bed combustor or in a specialized recovery
furnace. Semi chemical VOCs can also be introduced into the flue gas if flue gas comes
5-5
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-6
in contact with pulping liquor. VOCs from both semi chemical and acid sulfite pulping
processes can enter the flue gas if the flue gas is able to strip organic compounds such as
methanol from the scrubber makeup water. According to limited data, VOC emissions
can significantly be reduced by improving combustion conditions and controlling liquor
firing.
Mechanical pulping processes only emit VOCs and steam into the atmosphere.
The VOCs in wood are emitted with the steam when wood undergoes cooking and
refining processes. A study conducted by NCASI showed that VOC emission rates were
proportional to steam emission rates. This data suggests that in order to decrease VOC
emissions, the temperature in the exhaust gas must be reduced below the boiling point of
water. (Someshwar and Pinkerton, 2000; Pinkerton, 2000).
5.4. Costs and availability
According to John Pinkerton at the National Council of the Paper Industry for Air and
Stream Improvement (NCASI) (Pinkerton, 2004), pulp and paper industry representatives
have been working with several engineering firms to evaluate to assess the costs and
emission reduction potential of SO2 and NOX control technologies. Many of the
technologies are candidates for evaluation as part of a BART site-specific engineering
analysis. Particulate matter (PM) control strategies were also evaluated by NASCI.
Information on applicability and cost is summarized in Tables V-2 through V-5 for Kraft
Recovery Furnaces, Lime Kilns, Wood and Wood/Gas boilers and Wood/Coal and
Wood/Oil boilers.
Information on the technologies referenced in the tables was collected by NASCI
based on installation of processes or evaluation of these processes as part of New Source
Review (NSR) Best Available Control Technology (BACT) or Lowest Achievable
Emission Rate (LAER) analyses, state Reasonably Available Control Technology
(RACT) evaluations in ozone non-attainment areas, the USEPA NOX SIP Call, or for
other reasons.
The range in costs and emission reductions reflects the fact that site-specific
factors play a critical role in determining how cost-effective various technologies will be
in practice. Existing facilities do not always adequate or appropriate space for new
equipment, which adds uncertainty to the capital and operating cost, as well at to the
achievable emissions reductions. Hence the range of costs cited in the tables.
5-6
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-7
Table V-2 Reduction of NOX, SO2 and PM in Kraft Recovery Furnaces (Pinkerton,
2004).
Current
Emission Levels
National
Emission
Standards
~0 to 300 ppm
NOX
Type of furnace, operating
practices, nitrogen content
of black liquor, black
liquor solids
concentration.
40 to 130 ppm
none
none
Recent BACT
Determinations
Current Installed
End of Pipe
Control
Technologies
Control Options
50 to 300 ppm
75 to 150 ppm
1978 NSPS, 2001
MACT Existing Source
– 0.044 gr/dscf. New
source MACT is 0.015
gr/dscf
0.021 to 0.044 gr/dscf
none
none
ESPs
Optimize, on site-specific
basis, liquor solids and
operating practices; install
SO2 scrubber
Scrubbing possible on
some units to reduce SO2
to as low as 10 ppm.
Some units have emissions
this low or lower at
present.
Staged combustion
practices (very sitespecific)
Larger ESPs
SNCR and SCR not
demonstrated as
technically feasible.
Larger ESP possible on
some units, although
retrofit costs highly sitespecific. Depending on
current ESP design and
condition, replacement
or expansion of existing
ESP can be considered
Replacement of ESP to
achieve 0.015 gr/dscf
PM emissions: for a 3.7
MMlb BLS/day NDCE
furnace - Capital $29.3
million; operating $1.9
million/yr; for a 1.7
MMlb BLS/day DCE
unit: $18.4 million
capital; $1.2 million/yr
operating. Costs are very
site-specific.
Factors affecting
emissions
Applicability of
Control Option
and Potential
Emission
Reductions
Cost of Option
SO2
Type of furnace, operating
practices, black liquor
solids concentration.
Capital $8 million (1.7
MMlb/day BLS DCE unit;
$12.8 million (3.7
MMlb/day BLS NDCE
unit); Operating costs of
$1.1 to $1.3 million (1.7
MMlb/day unit), or $1.6 to
1.8 million/yr (3.7
MMlb/day unit). Lower
operating costs are for
achieving 50 ppm; higher
for achieving 10 ppm.
Costs are very sitespecific.
5-7
PM
Type of furnace, ESP
efficiency
0.01 – 0.1 gr/dscf
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-8
Table V-3 Reduction of NOX, SO2 and PM in Lime Kilns (Pinkerton, 2004).
Current Emission
Levels
National
Emission
Standards
~0 to 20 ppm
none
NOX
Type of fuel (gas vs. oil),
operating temperatures,
nitrogen content of oil
and oxygen availability
in flame zone, burning
NCGs
0.05 to 0.4 lb/106 Btu
heat input
none
Recent BACT
Determinations
Current Installed
Control
Technologies
Control Options
30 to 80 ppm
100 to 220 ppm
1978 NSPS – 0.067/0.13
gr/dscf (gas/oil); 2001
MACT Existing Source
– 0.064 gr/dscf. New
source MACT is 0.01
gr/dscf
0.015 to 0.13 gr/dscf
none
none
Wet scrubbers, ESPs
Wet scrubber with
supplemental caustic
control
none
Replace wet scrubber
with ESP
Factors affecting
emissions
SO2
Emissions are minimal
due to alkaline nature of
lime in kiln
Applicability of
Control Option
and Potential
Emission
Reductions
PM
Type of control device
and control device
efficiency
0.01 – 0.2 gr/dscf
ESPs have higher
removal efficiencies than
wet scrubbers; all lime
kilns installed in last ten
years have ESPs rather
than scrubbers. Average
ESP emissions are on the
order of 0.01 gr/dscf.
Replacement of scrubber
with ESP to achieve 0.01
gr/dscf PM emissions:
for a 270 ton CaO/day
kiln - $3.4 million;
operating $0.2
million/yr.
Cost of Option
5-8
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-9
Table V-4 Reduction of NOX, SO2 and PM in Wood and Wood/Gas-Fired Boilers
(Pinkerton, 2004).
SO2
NOX
PM
Factors affecting
emissions
Sulfur content of wood
minimal
Current Emission
Levels
National
Emission
Standards
0.025 lb/106 Btu is AP42 emission factor
none
Type of boiler, wood nitrogen and
moisture content, operating
practices
0.15 to 0.3 lb/106 Btu
Wood ash content, control
device efficiency,
operating practices
0.05 to 0.6 lb/106 Btu
Recent BACT
Determinations
Current Installed
Control
Technologies
Control Options
0.01 to 0.045 lb/106 Btu
Subpart Db NSPS- none if gas
capacity factor limited to 10% or
less; gas capacity factor over 10%
- 0.3 lb/106 BTU except 0.2 lb/106
BTU for new/reconstructed units
after 1997
0.25 to 0.3 lb/106 Btu
Subpart D, Db, Dc NSPS –
0.1 lb/106 Btu; final boiler
MACT limit – 0.07 lb/106
Btu for existing, 0.025
lb/106 Btu for new solid
fuel boilers
0.02 to 0.1 lb/106 Btu
none
SNCR for base loaded boilers
none
SNCR for base loaded boilers
Mechanical collectors, wet
scrubbers, gravel bed
filters, ESPs, fabric filters
Replace wet scrubber with
an ESP
ESPs in use on many wood
boilers. Emission levels as
low as 0.02 lb/106 Btu
possible. Retrofit costs
highly site-specific.
Applicability of
Control Option
and Potential
Emission
Reductions
Cost of Option
Control Option
Applicability of
Control Option
and Potential
Emission
Reductions
Cost of Option
SNCR has been installed on a few
new wood boilers to achieve NOX
reductions in the 20 to 50% range.
SNCR not appropriate for boilers
with high load swings. SCR has
not been applied.
Installing SNCR to achieve 0.15
lb/106 Btu NOX emissions on a
300,000 pph wood boiler: Capital
$1.5 million; operating $0.1
million/yr
Methane de-NOX Reburn
Has been applied to one boiler
burning wood, gas, and sludge.
Involves natural gas injection and
flue gas recirculation in stokertype boilers only. NOX reduction
reported to be 40 to 50% in
boilers burning high nitrogen
content fuels.
Capital costs unavailable. Lower
operating costs claimed due to
increased boiler efficiency.
5-9
Installing ESP to achieve
0.04 lb/106 Btu PM
emissions on a 300,000
pph wood boiler: Capital
$21.3 million; operating
$1.4 million/yr. Costs to
achieve a 0.065 lb/106
standard range from $18.7
million to $5.1 capital,
$900,000 to $77,000
operating—highly sitespecific
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-10
Table V-5 Reduction of NOX, SO2 and PM in Wood/Coal and Wood/Oil-Fired
Boilers (Pinkerton, 2004).
NOX
Type of boiler, coal/oil nitrogen
content, wood nitrogen and
moisture content, ratio of wood to
coal/oil
0.25 to 0.7 lb/106 Btu
PM
Wood/coal/oil ash content,
oil S level, control device
efficiency
Revised 1998 NSPS has 0.2
lb/106 Btu limit for boilers over
100 x 106 Btu/hr for all fossil
fuels, limit applies if annual fossil
fuel capacity factor exceeds 10%.
Prior NOX limits were fuel-type
dependent and ranged from 0.3 to
0.7 lb/106 Btu for oil and coal.
Subpart D, Db, Dc NSPS –
0.1 lb/106 Btu unless
annual wood capacity
factor is less than 10%;
final boiler MACT limit –
0.07 lb/106 Btu for existing,
0.025 lb/106 Btu for new
solid fuel boilers
0.3 to 0.7 lb/106 Btu
0.03 to 0.1 lb/106 Btu
Alkaline scrubbing
SNCR for base loaded boilers,
FGR, Low NOX burners
Mechanical collectors, wet
scrubbers, gravel bed
filters, ESPs, fabric filters
Alkaline scrubbing
Low NOX burners
Applicability of
Control Option
and Potential
Emission
Reductions
Generally applicable;
reductions up to 90%
possible
Cost of Option
Capital cost for scrubber
installation following
and ESP on a 300,000
pph wood/coal boiler $7.4 to 8.2 million.
Annual operating cost
for 50% removal $1.0
million, $1.5 to 2.0
million for 90% removal.
Lower S content coal/oil;
gas
Generally applicable
This option only available to
pulverized coal/stoker boilers or
oil/wood units. NOX reductions in
the 20 to 50% range can be
achieved for the coal or wood
contribution to total NOX.
Installing low NOX burners to
achieve a 0.3 lb/106 Btu level on
a 300,000 pph wood/pulverized
coal boiler: Capital $2.9 million;
operating $0.15 million/yr.
Retrofit costs site-specific.
Replace wet scrubber with
an ESP
ESPs in use on many
wood/coal and wood/oil
boilers. Emission levels as
low as 0.02 lb/106 Btu
possible. Retrofit costs
highly site-specific.
Remove existing control
device and install ESP to
achieve 0.04 lb/106 Btu PM
emissions on a 300,000 pph
wood/coal boiler: Capital
$5.1 to 20.5 million;
operating $70,000 to 1.2
million/yr. Retrofit costs
site-specific.
Factors
affecting
emissions
Current
Emission Levels
National
Emission
Standards
Recent BACT
Determinations
Current
Installed
Control
Technologies
Control Options
Control Option
Applicability of
Control Option
and Potential
Emission
Reductions
Cost of Option
SO2
Coal/oil sulfur content,
ratio of wood to coal/oil
Depends on fuel mix and
coal/oil S content
Subpart D NSPS limits
SO2 to 1.2/0.8 lb/106 Btu
(coal/oil); Subparts Db
and Dc require percent
reduction (except for
very small boilers or
those with low coal
capacity factors) or use
of very low S oil
0.3 to 0.5 lb/106 Btu
Dependent on fuel prices
SNCR for base loaded boilers
Limited NOX reductions possible,
in the 20 to 40% range. SNCR
not appropriate for boilers with
high load swings.
Capital cost of $1.5 million for a
300,000 pph wood boiler with
limited coal or oil use; operating
cost of $0.15 million/yr. Retrofit
costs site-specific.
5-10
0.03 to 0.3 lb/106 Btu
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 5-11
References
Someshwar, A. V.; Pinkerton, J. E., “Wood Processing Industry” in Air Pollution
Engineering Manual, 2nd ed.; Davis, W. T., John Wiley & Sons, Inc.: New York City,
2000; 780-801.
Pinkerton, J. E., “Pulp and Paper Air Pollution Problems” in Industrial Environmental
Control Pulp and Paper Industry, 3rd ed.; Springer, A. M., Tappi Press: Atlanta, 2000;
501-526.
Someshwar, A. V. A., Review of NOX Emission Control Strategies for Industrial Boilers,
Kraft Recovery Furnaces, and Lime Kilns; NACSI: Research Triangle Park, 1999; 22-27.
Pinkerton, J.E., National Council of the Paper Industry for Air and Stream Improvement
(NCASI), [email protected], 2004.
5-11
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 6-1
6. CONCLUSION
As states prepare to conduct BART determinations for their eligible facilities,
preliminary information has been collected on the availability, costs and efficiencies of a
variety of technology options. Depending on the requirements contained in the final
BART regulations, anticipated for April 2005, states will have to decide what level of
cost and what degree of visibility improvement is considered reasonable before
completing BART determinations. MANE-VU has reviewed technology options for four
of the 26 BART-eligible source categories. For EGUs, industrial boilers, cement plants
and paper and pulp facilities, we present typical control options and costs. Facility
specific reviews will be needed to determine specific controls and costs for each BARTEligible source in the region.
6.1. EGUs
The presumptive level of control for previously uncontrolled EGU boilers as
included in the proposed BART regulations include FGD (Scrubber) technology with an
SO2 control efficiency of approximately 95 percent. Chapter 2 points out that the average
scrubber operating today does not achieve this level of control (existing scrubbers have a
range of efficiencies between 30 and 97 percent); however, new installations are
achieving rates even higher than 95 percent removal. Additional measures which can be
considered for SO2 control include the use of low-sulfur coal (compliance coal) (typically
XX percent SO2 reduction), spray dry adsorption (60-95 percent removal), dry scrubbing
(40-60 percent removal) or circular fluidized-bed adsorption technology (80-98 percent
removal). SO2 control is highly cost effective with operational costs in the $100-200 per
ton range.
NOX control technologies can be grouped into combustion controls (including
low-NOX burners (LNBs), overfire air, off-stoichiometric firing, selective or biased
burner firing, reburning, burners-out-of-service, and air staging) and post-combustion
controls (include selective non-catalytic reduction (SNCR) and selective catalytic
reduction (SCR) processes). Combustion controls result in typical NOX reductions of 15 to
60 percent, depending on the specific boiler and combination of controls. SCR achieves a
90-95 percent reduction whereas SNCR achieves 25-50 percent reduction in NOX. Costs
for NOX removal range from $200-500/ton for some of the low yield techniques to $1000
to $1500/ton for SCR with 90-95 percent removal efficiency.
Particulate matter (PM) control technologies include electrostatic precipitators
(ESPs), fabric filters (FFs) (also called “baghouses”), and particulate scrubbers (PS).
These technologies typically achieve greater than 95 percent removal of total particulate
mass with over 80 percent removal of PM smaller than 0.3 um (with the exception of
particulate scrubbers which achieve only 30-85 percent removal for this smaller size
fraction). Mechanical collectors have even lower trapping efficiencies. PM controls are
in place on virtually all EGUs already, hence the issue that will be faced in conducting
BART determinations is how these existing controls will interface with proposed controls
for other pollutants.
6-1
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 6-2
6.2. Industrial Boilers
For industrial boilers, many of the same control technologies for EGUs are
applicable to this source category including: low sulfur coal, wet and dry FGD (or
scrubber) technology for SO2, combustion modifications and SCR and SNCR technology
for NOX, and ESP, fabric filter and wet scrubbing techniques for PM. However,
industrial boilers have a wider range of sizes than EGUs and often operate over a wider
range of capacities. Thus cost estimates for the same technologies will generally range,
depending on the capacity of the boiler and typical operating conditions. High end cost
estimates for NOX removal can be over $10,000/ton.
6.3. Cement Kilns
Designing a system of emission controls for cement kilns are somewhat more
complicated given that the quality of clinker produced in a kiln varies with characteristics
of the combustion, it is possible to combine combustion technologies with postcombustion technologies for cement kilns in some cases and it is also possible to combine
multiple combustion technologies on cement kilns. As a result, primary controls need to
be selected carefully taking engineering and cost decisions into account for each specific
kiln.
Control options for SO2 include in-process removal, process changes (e.g.
combustion optimization, flame shape adjustment or raw material changes), and the use
of wet or dry scrubbers. For NOX, both process modifications (e.g. combustion
modifications, low-NOX burners, secondary combustion or staged combustion) as well as
post combustion controls need to be selected carefully. Particulate control devices for
cement plants must be able to clean gases with fairly high dust loading given that the
concentrations of particles in the exhaust can be several times higher than in a coal-fired
power plant. In addition, PM technologies are affected by the presence of corrosive gases
which can be reduced most effectively in a roller mill. While fabric filters (baghouses)
and electrostatic precipitators are still the most common means of PM control at cement
plants, a number of novel techniques and procedures are used to deal with the unique
issues face by cement kilns.
Costs for SO2 controls at cement kilns will vary widely depending on control
options selected and process variables (e.g. whether material is recycled in the control
process). Capital cost for typical wet/dry scrubbing post-combustion controls have been
estimated in the $10-50/ton of clinker produced with operating costs in the $5-20/ton of
clinker range. PM controls are similarly estimated in the $3-15/ton of clinker range for
capital costs and $0-30/ton clinker for operating costs on an annual basis. NOX has not
been estimated on a per ton of clinker basis, but estimates vary between 0 and
$10,000/ton of NOX reduced.
6.4. Pulp Mills
Paper and pulp facilities have perhaps the widest range of operational
configurations and thus possibilities for reducing pollutant emissions. A variety of
6-2
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 6-3
technologies exist for controlling emissions from pulp and paper facilities. Secondary
control devices can be helpful in reducing emissions for some processes, and a number of
them are available. Many facilities have found that significant emissions reductions can
be achieved through process changes at the facility. Both secondary controls and process
changes are presented as options.
For Kraft mill recovery furnaces, combustion modifications can be effective at
reducing SO2, NOX, and VOCs. Reducing the liquor sulfidity can also help reduce SO2
emissions. PM control for recovery furnaces is typically achieved through the use of
ESPs or wet ESPs.
Lime kilns are also a significant source of visibility impairing pollutants;
however, there are fewer options for effectively reducing SO2 emissions. Combustion
modifications can reduce NOX and VOC emissions and Venturi scrubbers and ESPs are
commonly used for PM control.
Demister pads, packed towers and Venturi scrubbers are used to reduce PM
emissions from smelt dissolving tanks.
The range in costs and emission reductions reflects the fact that site-specific
factors play a critical role in determining how cost-effective various technologies will be
in practice. Existing facilities do not always adequate or appropriate space for new
equipment, which adds uncertainty to the capital and operating cost, as well at to the
achievable emissions reductions. Hence a wide range of costs have been cited.
6-3
DRAFT – Assessment of Control Options for BART-Eligible Sources
Page 1
Appendix A: BART-Eligible Facilities in the
MANE-VU Region
NESCAUM has conducted two previous studies to identify a comprehensive list
of BART-eligible sources in the MANE-VU region (NESCAUM, 2001; NESCAUM,
2003). These studies have been carefully reviewed by permitting authorities in each of
the MANE-VU jurisdictions and the sources listed in Table A-1 represent the list of
sources identified through that process. Non-EGU sources for Pennsylvania and New
York are still pending and should be available for inclusion in the Final Report.
Table A-1 BART-Eligible Facilities in the MANE-VU Region
State
Connecticut
Connecticut
Connecticut
Connecticut
Connecticut
Connecticut
Connecticut
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
District of
Columbia
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Facility
Middletown
Montville
Norwalk Harbor
PSEG Power Connecticut LLCBridgeport Harbor
PSEG Power Connecticut LLC-New
Haven Harbor
SPRAGUE PAPERBOARD INC
PFIZER INC
Edge Moor
Indian River
Mckee Run
Citisteel
DuPont Edge Moor
Reichhold
Motiva
Benning (PEPCO)
Brayton Point
Canal
Cleary Flood
Braintree Electric
Mystic
New Boston
Salem Harbor
EASTMAN GELATINE CORP
GENERAL ELECTRIC AIR (GE
Aircraft Engines)
TRIGEN BOSTON ENERGYKNEELAND STATION
1
Town/City
BART Category
EGU
EGU
EGU
EGU
Versailles
Groton
Claymont
Edge Moor
Cheswold
Delaware City
District of
Columbia
EGU
boilers
chemical plant
EGU
EGU
EGU
iron and steel
chemical plant
chemical plant
petrol. storage
Peabody
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
chemical plant
Lynn
boilers
Boston
boilers
DRAFT – Assessment of Control Options for BART-Eligible Sources
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Massachusetts
Maryland
Maryland
Maryland
Maryland
Maryland
Maryland
Maryland
Maryland
Maryland
Maryland
Maine
Maine
Maine
Maine
Maine
Maine
Maine
Maine
Maine
Maine
Maine
Maine
Maine
New Hampshire
New Hampshire
New Hampshire
New Hampshire
New Hampshire
New Jersey
New Jersey
New Jersey
New Jersey
New Jersey
New Jersey
GULF OIL LP CHELSEA
REFUSE ENERGY SYSTEM
COMPANY
SOLUTIA INC. (MONSANTO CO.)
EXXON EVERETT TERMIN
(EXXON EVERETT MARKETING
TERMINAL #240
GLOBAL PETROLEUM CORP.
HARVARD UNIVERSITY
CAMBRIDGE
C P Crane
Chalk Point
Dickerson
Herbert A Wagner
Morgantown
Vienna
EASTALCO ALUMINUM
ST. LAWERENCE CEMENT(formerly
Independent Cement)
WESTVACO FINE PAPERS
METTIKI COAL CORPORATION
William F Wyman
Domtar - Pulp & Paper
Dragon Products
Fort James - OldTown
International Paper - Bucksport
IP Androscoggin
Katadhin - Mill W.
Lincoln Pulp and Paper
Madison Paper
Mead WestVaco
SD Warren - Somerset
SD Warren Co.
Gulf Oil - S Portland
Merrimack
Newington
Annheuser-Busch
Pulp & Paper Mills (33007-0000111)
Dartmouth College
Hudson
CHEVRON PRODUCTS CO 18058
AMERADA HESS CORP PORT
READING 17996
BAYWAY REFINING CO 41805
COASTAL EAGLE POINT OIL
COMPANY 55781
COLORITE SPECIALTY RESINS
45940
2
Page 2
Chelsea
petrol. storage
Saugus
Springfield
incinerator
boilers
Everett
Revere
petrol. storage
petrol. storage
Cambridge
boilers
EGU
EGU
EGU
EGU
EGU
EGU
aluminum ore
Frederick
Hagerstown
Luke
Oakland
Baileyville
Thomaston
Old Town
Bucksport
Jay
Millinocket
Lincoln
Madison
Rumford
Skowhegan
Westbrook
South Portland
Merrimack
Berlin
Hanover
portland cement
kraft pulp
coal cleaning
EGU
kraft pulp
portland cement
kraft pulp
boilers
kraft pulp
boilers
kraft pulp
kraft pulp
kraft pulp
kraft pulp
kraft pulp
petrol. storage
EGU
EGU
boilers
Perth Amboy
kraft pulp
boilers
EGU
petrol. refinery
Woodbridge
Linden
petrol. refinery
petrol. refinery
Westville
petrol. refinery
Burlington
chemical plant
DRAFT – Assessment of Control Options for BART-Eligible Sources
New Jersey
New Jersey
New Jersey
New Jersey
New Jersey
New Jersey
New York
New York
New York
New York
New York
New York
New York
New York
New York
New York
New York
New York
New York
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Pennsylvania
Rhode Island
Rhode Island
GATX TERMINALS CORP
CARTERET FACILITY 18010
GENERAL CHEMICAL CORP 07369
GREEN TREE CHEMICAL
TECHNOLOGIES INC 18185
Griffin Pipe Products (45954)
Infineum USA LP- Bayway Chemical
Plant (41767)
SHELL OIL PRODUCTS CO
SEWAREN PLANT 18051
Arthur Kill
Astoria
Bowline Point
Charles Poletti
Danskammer
E F Barrett
Lovett
Northport
Oswego
Ravenswood
Roseton
Samuel A Carlson Generating Station
Consolidated Edison's 59th St Station
Bruce Mansfield
Brunner Island
Cheswick
Conemaugh
Eddystone
Hatfield's Ferry
Homer City
Keystone
Martins Creek
Mitchell
Montour
New Castle
Portland
Warren
BROWN UNIVERSITY
Clariant Corp.
3
Page 3
Carteret
Newark
petrol. storage
acid, sulfur, charcoal
Parlin
Florence
chemical plant
iron and steel
Linden
chemical plant
Sewaren
petrol. storage
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
EGU
boilers
chemical plant
Providence
Coventry
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