strategies that can be used to reduce emissions of SO2.  Examples of
such strategies include switching to a fuel with a lower sulfur content,
or coal cleaning prior to combustion.  Methods of SO2 control applicable
to ICI boilers are listed in Table 4.1 with a brief description of the
control option, applicability, and range of performance.  After the
table, a more detailed description of the control option and an analysis
of the four factor assessment for reasonable progress is presented.

SO2 Control Option Descriptions

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 fuel switching and, more
significantly, in fluidized bed boilers, in which limestone is added to
the fuel in the combustion chamber.

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 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.  Descriptions of available SO2 control technology
options are in Table 4.1.  A brief discussion of these techniques
follows.

Table 4.1  Available SO2 Control Options For ICI Boilers

Technology	Description	Applicability	Performance

Switch to a Low Sulfur Coal (generally <1% sulfur) 	Replace high-sulfur
bituminous coal combustion with lower-sulfur coal	Potential control
measure for all coal-fired ICIs currently using coal with high sulfur
content	50-80% reduction in SO2 emissions by switching to a lower-sulfur
coal

Switch to Natural Gas (virtually 0% sulfur)	Replace coal combustion with
natural gas	Potential control measure for all coal-fired ICIs	Virtually
eliminate SO2 emissions by switching to natural gas

Switch to a Lower Sulfur Oil	Replace higher-sulfur residual oil with
lower-sulfur distillate oil.  Alternatively, replace medium sulfur
distillate oil with ultra-low sulfur distillate oil	Potential control
measure for all oil-fired ICIs currently using higher sulfur content
residual or distillate oils	50-80% reduction in SO2 emissions by
switching to a lower-sulfur oil

Coal Cleaning	Coal is washed to remove some of the sulfur and ash prior
to combustion	Potential control measure for all coal-fired ICI boilers
20-25% reduction in SO2 emissions

Combustion Control	A reactive material, such as limestone or
bi-carbonate, is introduced into the combustion chamber along with the
fuel 	Applicable to pulverized coal-fired boilers and circulating
fluidized bed boilers	40%-85% reductions in SO2 emissions

Flue Gas Desulfurization (FGD) - Wet	SO2 is removed from flue gas by
dissolving it in a lime or limestone slurry.  (Other alkaline chemicals
are sometimes used)	Applicable to all coal-fired ICI boilers	30-95%+
reduction in SO2 emissions

Flue Gas Desulfurization (FGD) – Spray Dry	A fine mist containing lime
or other suitable sorbent is injected directly into flue gas	Applicable
primarily for boilers currently firing low to medium sulfur fuels
60-95%+ reduction in SO2 emissions

Flue Gas Desulfurization (FGD) –Dry	Powdered lime or other suitable
sorbent is injected directly into flue gas	Applicable primarily for
boilers currently firing low to medium sulfur fuels	40-60% reduction in
SO2 emissions

Table references:

1.  Assessment of Control Technology Options for BART-Eligible Sources,
NESCAUM, March 2005.

2.  Controlling Fine Particulate Matter Under the Clean Air Act: A Menu
of Options, STAPPA-ALAPCO, March 2006.

Switch to Coal with Lower Sulfur Content

Switching from a high sulfur fuel to one with sufficiently low sulfur
content is the first option available for SO2 reduction in this category
for pre-combustion control of SO2.  Fuels naturally low in sulfur
content are readily available for solid (coal) and liquid (oil) fired
boilers.  For coal-fired boilers, low-sulfur fuels may be obtained
directly or, 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 fuel may not be a technically feasible or
economically practical SO2 control alternative for all boilers.  In some
cases, a fuel with the required sulfur content to meet the applicable
emission reduction may not be available or cannot be fired
satisfactorily in a given boiler unit design.  Even if such a fuel is
available, use of the lower-sulfur fuel that must be transported long
distances from the supplier may not be cost competitive with burning
higher sulfur fuel supplied by near-by suppliers and using a
post-combustion control device.  The feasibility of fuel switching
depends partly on the characteristics of the plant and the particular
type of fuel change being considered.  Many plants will be able to
switch from high-sulfur to low-sulfur bituminous coal without serious
difficulty, but switching from bituminous to sub-bituminous coal may
present greater challenges and costs.  In some instances, fuel switching
will require significant investment and modifications to an existing
plant.  Switching to a lower sulfur fuel, either coal or oil, can affect
fuel handling systems, boiler performance, PM control effectiveness and
ash handling systems.  Overall SO2 reductions estimated from switching
to low-sulfur fuels range from 50-80%.

Switch to Natural Gas

Switching from coal combustion to natural gas combustion virtually
eliminates SO2 emissions.  It is technically feasible to switch from
coal to natural gas, but it is currently uneconomical to consider this
option for large ICIs due to the fuel quantity necessary and the price
of natural gas.  The price of natural gas is roughly seven times the
price of coal in terms of heating value.

Reduced Sulfur Oil

Oil-fired boilers may opt for lower sulfur distillate fuels or, if
available, ultra-low sulfur distillate fuel.  Number 2 distillate fuel
oil, heating oil, and highway diesel fuel oil are the same
refinery-produced liquid, and are only differentiated for tax purposes.
This differentiation is accomplished through addition of a red dye in
the fuels supplied for non-transportation related use.  Currently, the
sulfur content in Number 2 oil varies between 15 and 20,000 ppm.
Beginning in 2006, the permissible level of sulfur in highway diesel
fuel (ultra low sulfur diesel, or ULSD) was reduced to15 ppm.  Prior to
that, highway low sulfur diesel fuel was refined to contain 500 ppm
sulfur (Low Sulfur Diesel, or LSD).  Consequently, refineries have
already performed the capital investments required for the production of
LSD and ULSD fuel oil.  Based on EIA data for the week of Feb 23, 2007
domestic production of ULSD fuel oil accounted for about 45% of all
distillate oil in the United States and LSD fuel oil accounted for
slightly over 17% of domestic production (See Chapter 8).

Coal Cleaning

According to the 2006 STAPPA-ALAPCO document on control technologies
titled Controlling Particulate Matter Under the Clean Air Act: A Menu of
Options, coal cleaning or washing is a widely practiced method of
reducing impurities in coal, particularly sulfur.  Reducing the sulfur
content of the fuel used in the boiler reduces the SO2 emissions
proportionally.  Coal cleaning has been shown to reduce SO2 emissions by
20-25%, while increasing the heating value of the fuel.  Additional
removal can be achieved through advanced chemical washing techniques,
but no detailed information on these techniques was available.

Conventional (physical) coal washing techniques remove ash and sulfur
from coal by crushing the fuel and separating the components in a liquid
bath, such as water.  The lighter coal particles float to the top of the
bath for recovery, while the heavier impurities sink to the bottom for
removal.

Although there are benefits associated with coal washing, there are
limitations associated with this technology.  The 20-25% SO2 reduction
is beneficial, but post-combustion controls have been shown to reduce
SO2 emissions by greater percentages.  Also, solid and liquid wastes are
generated using the washing process and must be addressed.

Combustion Control

SO2 reduction is also possible through combustion related control
technologies.  One such technology that has been demonstrated and is
currently available is the use of fluidized bed boilers.

Fluidized bed boilers generally operate at lower temperatures than other
combustion systems, 800° to 870° C (1500° F to 1600° F). 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 800° C (1500° F). SO2 released from the fuel reacts with
CaO to form CaSO4, which is thermodynamically stable at bed
temperatures. By recycling some of the solids leaving the bed up to 90%
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.

Flue Gas Desulfurization (FGD)

There are three types of FGD scrubbers: wet, spray dry, and dry.
According to the 2006 STAPPA-ALAPCO document on control technologies
titled Controlling Particulate Matter Under the Clean Air Act: A Menu of
Options, EPA reports that 85% of the FGD systems in use in the United
States are wet systems.  Twelve percent of the FGD systems are spray dry
systems, and 3% are dry systems.  The operating parameters, efficiency,
and costs of each SO2 removal method are different.

SO2 in the 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”.  Most wet FGD systems for control of SO2
emissions 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 used by a small 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
hemi-hydrate 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 disposal of large quantities
of waste sludge.

The SO2 removal efficiencies of existing wet limestone scrubbers range
from 31-97%, with an average of 78%.  The SO2 removal efficiencies of
existing wet lime scrubbers range from 30 to 95%.  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.

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, 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-to-sulfur 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 60-95%.

For the dry injection process, dry powdered lime (or another suitable
sorbent such as trona) 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%.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR ICI BOILERS

Each of the control options presented in Table 4.1 is reviewed in this
section utilizing a four factor analysis approach for determining
reasonable progress as required by Section 169A(g)(1) of the Clean Air
Act and Section 51.308(d)(1)(i)(A).  The information provided in this
section is intended to be used by the States in setting Reasonable
Progress Goals (RPGs) for reducing regional haze in Class I areas in
MANE-VU Class I areas.

Cost of Compliance

To compare the various control options, information has been compiled on
the cost-effectiveness of retrofitting controls. In general,
cost-effectiveness increases as boiler size and capacity factor (a
measure of boiler utilization) increases.

Cost of Switching to Low Sulfur Coal, Distillate Oil, or Natural Gas

Switching to a low-sulfur coal or blending a lower sulfur coal can
impact cost due to the following two main reasons:

The cost of low-sulfur coal compared to higher sulfur coal.

The cost of boiler or coal handling equipment modifications necessary

The cost of low-sulfur coal compared to higher sulfur coal is not only
related to the “dollar per ton” cost of the coal, but the heating
value of the coal also impacts the cost analysis.

Table 4.2 reflects the potential sulfur reduction possible by switching
fuels:

Table 4.3 shows the average 2004 and 2005 cost data from the Energy
Information Administration for various fuels.

Refineries were required to make significant capital investments to meet
the LSD and ULSD highway fuel sulfur requirement.  To achieve the LSD
and ULSD sulfur goals, refineries were required to implement diesel
desulfurization technologies.  Estimates for the capital costs were
developed in 2001 by the Energy Information Administration (EIA) and are
based on calendar year 1999.  Table 4.4 presents the capital costs for
desulfurization technologies presented by the EIA.  The EIA developed
estimates for new and revamped desulfurization technologies at existing
refineries.

Table 4.2  Potential SO2 Reductions Through Fuel Switching

Original Fuel	Sub-bituminous Coal

(% Reduction)	Distillate oil

(% Reduction)	Natural Gas

(% Reduction)

Bituminous Coal	72.9	91.2	99.9

Sub-bituminous coal	-	69.5	99.9

Residual Oil	-	91.5	99.9

Distillate Oil	-	-	99.7

Calculations based on typical fuel sulfur content listed in Department
of Energy EIA analysis for 2000.  Energy Policy Act Transportation Rate
Study:  Final Report on Coal Transportation

In its highway diesel fuel rulemaking, EPA also developed cost estimates
for the deployment and implementation of desulfurization technologies at
refineries.  EPA estimated that it would cost existing refineries an
estimated $50 million per refinery to install desulfurization
technologies.  No estimates were made for the costs associated with new
refineries as none are currently being constructed in the United States.
 The EPA analysis spread the investment cost over a 2-year period.
Consequently, it was estimated that the US refinery-wide investment for
calendar year 2004 was $2.45 billion and $2.83 billion for calendar year
2005 (EIA 2001)  (Converted from 2001 to 2006 dollars using a conversion
factor of 1.1383   HYPERLINK "http://www.inflationdata.com"
www.inflationdata.com ).

Using the most recently available EIA price information for 2006 No. 2
Distillate oil for industrial, commercial, and institutional facilities
in the northeast (excluding taxes), a cost per ton of SO2 removed was
calculated to be $734/ton SO2 by switching to 500 ppm LSD and $554/ton
SO2 by switching to ULSD fuel oils.  (See the discussion of fuel oil
prices in Chapter 7 – Heating Oil.)

Cost of Coal Cleaning

The World Bank, an organization which assists with economic and
technological needs in developing countries reports that the cost of
physically cleaning coal varies from $1 to $10 per ton of coal cleaned,
depending on the coal quality, the cleaning process used, and the degree
of cleaning desired.  In most cases the costs were found to be between
$1 and $5 per ton of coal cleaned.

Cost of Combustion Control

Dry sorbent injection, (DSI), systems have lower capital and operation
costs than post-combustion FGD systems due to: simplicity of design,
lower water use requirements, and smaller land use requirements.  Table
4.3 presents the estimated costs of adding DSI based SO2 controls to ICI
boilers based on boiler size, fuel type, and capacity factor.  Capacity
factor is the amount of energy a boiler generates in one year divided by
the total amount it could generate if it ran at full capacity.

Table 4.3  Estimated Dry Sorbent Injection (DSI) Costs For ICI Boilers
(2006 dollars)

Fuel	SO2 Reduction (%)	Capacity Factor (%)	Cost Effectiveness ($/Ton of
SO2)

	100 MMBTU/hr	250 MMBTU/hr	1,000 MMBTU/hr

2%-sulfur

coal

	40	14	4,686	3793	2,979

50	1,312	1062	834

83	772	624	490

3.43%-sulfur

coal

	40	14	2,732	2,212	1,737

50	765	619	486

83	450	364	286

2%-sulfur

coal

	85	14	2,205	1,786	1,402

50	617	500	392

83	363	294	231

3.43%-sulfur

coal

	85	14	1,286	1,040	818

50	360	291	229

83	212	171	134

Calculations based on information available from EPA Publications,
EPA-452/F-03-034, Air Pollution Control Technology Fact Sheet, and
EPA-600/R-05-034, Multipollutant Emission Control Technology Options for
Coal-fired Power Plants

(Converted from 2005 to 2006 dollars using a conversion factor of 1.0322
  HYPERLINK "http://www.inflationdata.com"  www.inflationdata.com )

Cost of FGD

Installation of post-combustion SO2 control in the form of FGD has
several impacts on facility operation, maintenance, and waste handling.
FGD systems typically require significant area for construction of the
absorber towers, sorbent tanks, and waste handling.  The facility costs
are, therefore, variable and dependent on the availability of space for
construction of the FGD system.  Solid waste handling is another factor
that influences the cost of FGD control systems.  Significant waste
material may be generated that requires disposal.  This cost may be
mitigated, however, by utilization of a forced oxidation FGD process
that produces commercial quality gypsum, which may be sold as a raw
material for other commercial processes.

Table 4.4 presents the total estimated cost effectiveness of adding FGD
based SO2 controls to ICI boilers based on boiler size, fuel type, and
capacity factor.  There is no indication that these cost data include
revenue from gypsum sales.  Revenue from gypsum sales would reduce the
cost of these controls.

Table 4.4  Estimated Flue Gas Desulfurization (FGD) Costs For ICI
Boilers (2006 dollars)

Fuel	Technology	SO2 Reduction (%)	Capacity Factor (%)	Cost Effectiveness
($/Ton of SO2)

100 MMBTU/hr	250 MMBTU/hr	1,000 MMBTU/hr

High-sulfur

coala

	FGD (Dry)	40	14	3,781	2,637	1,817

	50	1,379	1,059	828

	83	1,006	814	676

Lower-sulfur

coalb

	FGD (Dry)	40	14	4,571	3,150	2,119

	50	1,605	1,207	928

	83	1,147	906	744

Coal	FGD (Spray

dry)

	90	14	4,183	2,786	1,601

	50	1,290	899	567

	83	843	607	407

High-sulfur

coala

	FGD (Wet)	90	14	3,642	2,890	1,909

	50	1,116	875	601

	83	709	563	398

Lower-sulfur

coalb

	FGD (Wet)	90	14	4,797	3,693	2,426

	50	1,415	1,106	751

	83	892	705	492

Oilc	FGD (Wet)	90	14	10,843	8,325	5,424

	50	2,269	1,765	1,184

	83	1,371	1,079	740

a. Assumes sulfur content = 3.43% and ash content = 12.71%.

b. Assumes sulfur content = 2.0% and ash content = 13.2%.

c. Sulfur content of oil is not specified.

Table references:

Source:  Controlling Fine Particulate Matter Under the Clean Air Act:  A
Menu of Options, STAPPA-ALAPCO, 2006.

Primary Reference:  Khan, S. Methodology, Assumptions, and
References—Preliminary SO2 Controls Cost Estimates for Industrial
Boilers (EPA-HQ-OAR-2003-0053-166), October-November 2003.

(Converted from 2004 to 2006 dollars using a conversion factor of 1.0672
  HYPERLINK "http://www.inflationdata.com"  www.inflationdata.com )

Time Necessary for Compliance

Generally, sources are given a 2-4 year phase-in period to comply with
new rules. Under the previous Phase I of the NOX SIP Call, EPA provided
a compliance date of about 3½ years from the SIP submittal date.  Most
MACT standards allow a 3-year compliance period. Under Phase II of the
NOX SIP Call, EPA provided a 2-year period after the SIP submittal date
for compliance. States generally provided a 2-year period for compliance
with RACT rules. For the purposes of this review, we have assumed that a
2-year period after SIP submittal is adequate for pre-combustion
controls (fuel switching or cleaning) and a three year period for the
installation of post combustion controls.

For BART control measures, the proposed BART guidelines require States
to establish enforceable limits and require compliance with the BART
emission limitations no later than 5 years after EPA approves the
regional haze SIP.

Refiners in the United States are already producing low sulfur diesel
fuel which may be marketed as distillate oil.  There is a potential that
offshore refiners may not be able to produce enough 15 ppm sulfur for
export to the Northeast United States to meet peak demand, but so far
this has not occurred.

ICI boilers would not have to retrofit or install expensive control
technology to burn ULSD distillate fuel oil, therefore, compliance with
the standard is driven by supply and demand of the lower sulfur
distillate oils.

For combustion based and post-combustion based engineering and
construction leads times will vary between 2 and 5 years depending on
the size of the facility and specific control technology selected.

Energy and Non-Air Impacts

Fuel switching and cleaning do not significantly affect the efficiency
of the boiler but may add to transportation issues and secondary
environmental impacts from waste disposal and material handling
operations (e.g. fugitive dust).  FGD systems typically operate with
high pressure drops across the control equipment, resulting in a
significant amount of electricity required to operate blowers and
circulation pumps.  In addition, some combinations of FGD technology and
plant configuration may require flue gas reheating to prevent physical
damage to equipment, resulting in higher fuel usage.

The primary environmental impact of FGD systems is the generation of
wastewater and sludge from the SO2 removal process.  When the exhaust
gas from the boiler enters the FGD the SO2, metals, and other solids are
removed from the exhaust and collected in the FGD liquid.  The liquid
slurry collects in the bottom of the FGD in a reaction tank.  The slurry
is then dewatered and a portion of the contaminant-laden water is
removed from the system as wastewater.  Waste from the FGD systems will
increase sulfate, metals, and solids loading in a facility’s
wastewater, potentially impacting community wastewater treatment
facilities for smaller units that do not have self contained water
treatment systems.  In some cases FGD operation necessitates
installation of a clarifier on site to remove excessive pollutants from
wastewater.  This places additional burdens on a facility or community
wastewater treatment and solid waste management capabilities.  These
impacts will need to be analyzed on a site-specific basis.  If lime or
limestone scrubbing is used to produce calcium sulfite sludge, the
sludge must be stabilized prior to land filling.  If a calcium sulfate
sludge is produced, dewatering alone is necessary before land filling,
however, SO2 removal costs are higher due to increased equipment costs
for this type of control system.  In some cases calcium sulfate sludge
can be sold for use in cement manufacturing.

With wet FGD technologies a significant visible plume is present from
the source due to condensation of water vapor as it exits the smoke
stack.  Although the water eventually evaporates and the plume
disappears, community impact may be significant.

Reducing the sulfur contents of distillate fuel oil has a variety of
beneficial consequences for ICI boilers.  Low sulfur distillate fuel is
cleaner burning and emits less particulate matter which reduces the rate
of fouling of heating units substantially and permits longer time
intervals between cleanings.  According to a study conducted by the New
York State Energy Research and Development Authority, (NYSERDA), boiler
deposits are reduced by a factor of two by lowering the fuel sulfur
content from 1,400 ppm to 500 ppm.  These reductions in buildup of
deposits result in longer service intervals between cleanings. (Batey
and McDonald 2005)

Remaining Useful Life of the Source

Available information for remaining useful life estimates of ICI boilers
indicates a wide range of operating time, depending on size of the unit,
capacity factor, and level of maintenance performed.  Typical life
expectancies range from about 10 years up to over 30 years.

REFERENCES

Batey, J.E. and R. McDonald, 2005.  Low Sulfur Home Heating Oil
Demonstration Project Summary Report.  Project funded by The New York
Sate Energy Research and Development Authority.  Contract No.
6204-IABR-BR-00.

U.S. EPA, 2005, Multipoint Emission Control Technology Options for
Coal-fired Power Plants, Washington, DC, EPA-600/R-05/034.

U.S. EPA, 2003, Air Pollution Control Technology Fact Sheet, Washington,
DC, EPA-425/F-03-034.

STAPPA ALAPCO, 2006,  Controlling Fine Particulate Matter Under the
Clean Air Act:  A Menu of Options.

The Lake Michigan Air Directors Consortium, Midwest Regional Planning
Organization Boiler Best Available Retrofit Technology Engineering
Analysis, March 30, 2005

U.S. EPA, 1993, PM-10 Innovative Strategies:  A Sourcebook for PM-10
Control Programs, Research Triangle Park, NC, EPA-452/R-93-016.

U.S. Energy Information Administration, October 2000, Energy Policy Act
Transportation Rate Study: Final Report on Coal Transportation,
Publication downloaded from World Wide Web in February, 2007 at
HYPERLINK "http://www.eia.doe.gov/cneaf/coal/coal_trans/epact2000.html"
http://www.eia.doe.gov/cneaf/coal/coal_trans/epact2000.html

GE Water & Process Technologies.  Information accessed on web March 27,
2007:

  HYPERLINK
"http://www.zenon.com/applications/FGD_wastewater_treatment.shtml"
http://www.zenon.com/applications/FGD_wastewater_treatment.shtml

U.S. Energy Information Administration, 2007. :”No. 2 Distillate
Prices By Sales Type”, Information downloaded from the World Wide Web
on March 7, 2007, at   HYPERLINK
"http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm"
http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm

U.S. Energy Information Administration, 2007. :”weekly Inputs,
Utilization and Production”, Information downloaded from the World
Wide Web on March 7, 2007, at   HYPERLINK
"http://tonto.eia.doe.gov/dnav/pet/pet_pnp_wiup_dcu_r10_w.htm"
http://tonto.eia.doe.gov/dnav/pet/pet_pnp_wiup_dcu_r10_w.htm

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CHAPTER 5

ANALYSIS OF SELECTED INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL BOILERS

SOURCE CATEGORY DESCRIPTION

Modeling of visibility impacts on Class I regions was conducted by the
Vermont Department of Environmental Conservation (VTDEC) and MANE-VU to
identify the major ICI sources contributing to visibility impairment in
the northeast.  Table 5.1 lists the ICI sources identified to contribute
significant levels of SO2 to the MANE-VU region.  MACTEC was directed by
MARAMA and the Reasonable Progress Workgroup to focus on the 17 major
sources listed in Table 5.1.

As explained in the previous chapter, there are a wide variety of proven
control technologies for reducing SO2 emissions from ICI boilers and
specifically the control method for SO2 applied to any individual ICI
boiler is dependent upon the type of boiler, type of fuel, capacity
utilization, and the types and staging of other air pollution control
devices.  However, cost effective emissions reduction technologies for
SO2 are available and are effective in reducing emissions from the
exhaust gas stream of ICI boilers.

INFORMATION OBTAINED FROM STATE AGENCIES

For the selected ICI boilers, MACTEC contacted State and or regional
regulatory agencies to evaluate the status of each unit and determine if
additional pollution controls had been mandated as a part of regulatory
actions taken since the data used for the visibility impairment modeling
were collected.  Table 5.1 presents the information obtained from the
States.Table 5.1  Point Source Information Collected from the Top 17
Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name	State	2002

SO2

Total

(tons)	Primary Emissions Point Description	Point ID

(Permit

ID No.)	Design

Capacity	Existing

Control(s)	Proposed/

Planned

Control(s)	Additional Information

Motiva Enterprises LLC – Delaware City1	DE	29,747	Fluid Coking Unit
(FCU) and FCU Carbon Monoxide Boiler	002	57,199 barrels per day of total
feed	None	Cansolv Regenerative Wet Gas Scrubber and SNCR	Data from
Permit APC-82/0829 Amendment 5 SO2 permit limit is 174 tpy

	Fluid Catalytic Cracking Unit (FCCU) and FCCU Carbon Monoxide Boiler
012	FCCU coke burn rate limit is 56,000 lbs/hr	None	Cansolv Regenerative
Wet Gas Scrubber	Data from Permit APC-82/0981 Amendment 6 SO2 permit
limit is 361 tpy

Kodak Park Division2, 3	NY	23,508	Building 31 and 321 stationary
combustion installations, including package ABD built up boilers used
for the generation of process steam and electricity

Boilers:

1 – Package boiler, No. 6

2 – Package boiler, No. 6

3 – Package boiler, No. 6

4 – Package boiler, No. 6

13 – Underfed stoker, coal

14 – Underfed stoker, coal

11 – Underfed stoker, coal

12 – Underfed stoker, coal

15 – Wet bottom cyclone, coal/No. 6

16 – Wall-fired, coal/No. 6

41 – Wet bottom cyclone, coal/No. 6

42 – Wet bottom cyclone, coal/No. 6

43 – Wet bottom cyclone, coal/No. 6

44 – Tangential-fired pulverized coal, coal/No. 2	U0015

Boilers (EP-031B-1):

1

2

3

4

13

14

Boilers (EP-031B-2):

11

12

15

16

Boilers (EP-321B-3):

41

42

Boilers (EP-321B-4):

43

44

98 MMBTU/hr

98 MMBTU/hr

98 MMBTU/hr

98 MMBTU/hr

265 MMBTU/hr

265 MMBTU/hr

197 MMBTU/hr

222 MMBTU/hr

478 MMBTU/hr

544 MMBTU/hr

500 MMBTU/hr

500 MMBTU/hr

640 MMBTU/hr

670 MMBTU/hr	None	BART analysis - NOX & SO2 controls affordable on
Boilers 41, 42, & 43

Wet scrubber (90% reduction) would be ~$2,150/ton

Dry scrubber (40% reduction) would be ~$1,850/ton	Process K07 (Bldg 31)
is No. 6 fuel oil combustion in package boilers

Process K09 (Bldg 31) is bituminous coal combustion in built up Boilers
13 and 14

Process K10 (Bldg 31) is No. 6 fuel oil combustion in built up Boilers
15 and 16

Process K11 (Bldg 31) is bituminous coal combustion for built up Boiler
15

Process K12 (Bldg 321) is No. 6 fuel oil combustion for built up Boilers
41, 42 and 43

Process K13 (Bldg 321) is bituminous coal combustion for built up
Boilers 41, 42 and 43

Process K14 (Bldg 321) is No. 2 fuel oil combustion with NSPS
applicability in Boiler 44

Process K15 (Bldg 321) is bituminous low sulfur coal combustion

MW Custom Papers LLC – Chillicothe Mill4	OH	23,216	No.5 Coal Boiler -
wet bottom, pulverized coal-fired boiler (C. E. model VU-40), capable of
running on #2 fuel oil as backup fuel	B001	380 MMBTU/hr maximum heat
input	Cyclone/

multi-clone

ESP	None	9.9 lbs of sulfur dioxide per MMBTU actual heat input

	No.7 Coal Boiler - wet bottom, pulverized coal-fired boiler (C. E.
model VU-405), capable of running on #2 fuel oil as backup fuel	B002	422
MMBTU/hr maximum heat input	Cyclone/

multi-clone

ESP	None	9.9 lbs of sulfur dioxide per MMBTU

actual heat input

	No.8 Coal Boiler - wet bottom, pulverized coal-fired boiler (C. E.
model VU-40), capable of running on #2 fuel oil as backup fuel.	B003	505
MMBTU/hr maximum heat input	Cyclone/

multi-clone

ESP	None	9.9 lbs of sulfur dioxide per MMBTU

actual heat input

Eastman Chemical Company5, 6	TN	22,882	Two fuel burning installations
(B-83-1 & B-253-1) w/a total of 19 coal fired boilers of which 14 units
(#18-#24) are located at Powerhouse B-83-1 & 5 units (#25-#29) are
located at Powerhouse B-253-1.  The primary fuel is coal.  In addition,
wood, waste solids, waste liquids, & biosludge may be burned in these
Powerhouses, while NG & process gas may also be burned in the Powerhouse
B-253-1 boilers.	82-0003-01-19

(020101, 021520)	6,625 Million BTU/hr nominal heat input

	ESP	Scubbers potentially	The five boilers in Powerhouse B-253-1 are
subject to BART.  The State does not have confirmation yet, but they
believe that the boilers will be controlled by scrubbers of some sort.

Units #11-#17, that were located at Powerhouse B-83-1, have been removed

	Coal-Fired Boilers 30 and 31	PES

B-325-1or 82-1010-15 (261501)	Heat input is limited to 780 and 880
MMBTU/hr, respectively, on a 30 calendar day rolling average basis	None
None

	Westvaco Fine Papers7, 8	MD	19,083	Boiler 24 is a coal fired-cyclone
boiler	1	590 MMBTU/hr maximum heat input	SNCR (NOX)

ESP (PM)	Baghouse (PM)	Not BART eligible due to age

	Boiler 25 is a coal fired-tangential boiler	2	785 MMBTU/hr maximum heat
input	Low NOX burners/

overfired air (NOX)

ESP (PM)	Scrubber (FGD in design)

SNCR (NOX)

Baghouse to replace ESP (PM)	BART eligible

PPG Industries Inc.9	WV	12,678	Boiler 3 is a coal-fired boiler installed
in 1942 and modified in 1981	R011 (002) or S076	243 MMBTU/hr	Fabric
filter

Low NOX burners	None	Not BART eligible

	Boiler 4 is a coal-fired and natural gas-fired boiler installed in 1952
R015 (001) or S076	496 MMBTU/hr	ESP

Low NOX burners	None	Not BART eligible

	Boiler 5 is a coal-fired boiler installed in 1966	R072 (003) or S482
878 MMBTU/hr	ESP

Low NOX burners	None	BART eligible, facility to decrease emissions by
using low-sulfur coal and taking an emission limit of 1,478.8 lb SO2/hr

Williams Ethanol Services

Inc.10, 11	IL	12,244	4 boilers

Boiler A & B are coal-fired boilers constructed in 1944

Boiler C is a coal/oil supplemental-fired boiler constructed in 1958

Boiler D is a NG/No. 2 oil-fired boiler constructed in 1976	10	Boilers A
& B:  242 MMBTU/hr

Boiler C:

330 MMBTU/hr

Boiler D:

195 MMBTU/hr	Boilers A & B:  Multi-cyclone

Boiler C:

ESP

Boiler D:

None	None	Not BART eligible.

There is also a steep acid preparation system (Unit 2) that converts
sulfur into sulfurous acid that will be used for the steeping process.
Total sulfur usage for this unit is limited to 961,750 lbs/yr (at least
48% of the sulfur added to steepwater shall be retained in the products
shipped from the plant).

Corn Products International Inc.10, 11	IL	9,281	Utilities:

Coal fired Boilers #1, #2, & #3 (pre 1972)

Natural gas-fired Boilers #4 & #5 (pre 1972)

Natural gas-fired Boiler #6 constructed in 1992

2 natural gas-fired turbines constructed in 1995	Group 9	Boilers #1, #2,
& #3:

250 MMBTU/hr

Boilers #4 & #5:

312.5 MMBTU/hr

Boiler #6:

600 MMBTU/hr

Turbines:

65 MMBTU/hr	Boilers #1, #2, & #3:

ESP

Boilers #4 & #5:  None

Boiler #6:

low-NOX burner & flue gas recirculation

Turbines:

None	None	Not BART eligible

Mead

Westvaco Packaging Resource Group12	VA	8,552	Four (4) boilers

#6 – primarily coal-fired

#7 – coal/bark/wood-fired

#8 - coal/bark/wood-fired

#9 – primarily coal-fired	25	550 MMBTU/hr

440 MMBTU/hr

580 MMBTU/hr

807 MMBTU/hr	ESP

Scrubbers

FGR

LNB	None

	PH Glatfelter Co./Spring Grove13, 14	PA	7,855	#4 Power Boiler that
burns bituminous coal (13 tons/hr), #6 oil (751 gal/hr), & #2 oil (108
gal/hr)	034	363.7 MMBTU/hr	Cyclone dust collector

ESP	None	Not BART eligible

	#5 Power Boiler that burns bituminous coal (10.3 tons/hr), #6 oil (300
gal/hr), “as fired” wood (12.2 tons/hr), & #2 oil (451.2 gal/hr)	035
262.3 MMBTU/hr	Cyclone dust collector

ESP	None	BART eligible

Goodyear Tire & Rubber Co.4	OH	5,903	"A" Boiler, which is a coal-fired
boiler	B101	301 MMBTU/hr	ESP	None	4.64 lbs of sulfur dioxide per MMBTU
actual heat input for B101, B102, and B103 exiting through

Stack 4

	"B" Boiler, which is a coal-fired boiler	B102	301 MMBTU/hr	ESP	None
4.64 lbs of sulfur dioxide per MMBTU actual heat input for B101, B102,
and B103 exiting through

Stack 4

	"C" Boiler, which is a coal-fired boiler 	B103	174 MMBTU/hr	ESP	None
4.64 lbs of sulfur dioxide per MMBTU actual heat input for B101, B102,
and B103 exiting through

Stack 4

Sunoco Inc. (R&M)15, 16	PA	3,645	Plt. 10-4 FCC Unit	101	4,792.000 bbl/hr
fresh feed	None	SCR and a wet gas scrubber installed in 2010.  At the
latest, compliance is required by 2013.	SO2 limit of 9.8 lbs/1000 lbs of
coke burn-off in the catalyst regenerator determined daily on a 7-day
rolling average basis

Valero Refining Co. – NJ17, 18	NJ	3,597	FCCU Regenerator with In-Line
Heater	E21 or U1	102 MMBTU/hr	WGS	None	Per Consent Decree, SO2
concentration emission limits at the point of emission to the atmosphere
of no greater than 25 ppmvd, measured as a 365-day rolling average, and
50 ppmvd, measured as a 7-day rolling average, both at 0% O2.

Stone Container Corp. (dba Smurfit-Stone Contain)19	VA	3,379	#8 Power
Boiler that burns bituminous coal	2	1,056 MMBTU/hr	None	Wet gas scrubber
(2007)	Consent Decree dated 11/2004 which states that SO2 emission rate
will not exceed 0.26 lb/MMBTU on a 30-day rolling average basis.

Great Northern Paper Inc. Mill West20, 21	ME	1,842	Power Boilers #4
(Riley-Stoker))	004 (WB4)	740 MMBTU/hr	None	None	Unit to be shut down so
BART not an issue (only BART eligible source at this facility)

NRG Energy Center Dover LLC1, 22, 23	DE	1,836	Riley Stoker Boiler fired
on pulverized bituminous coal (primary fuel) and natural gas (for
startup/ignition).	C-1 (001)	243 MMBTU/hr	Four (4) DB Riley Low NOX
burners

Cyclonic Combustion Venturi burner assemblies

Low excess air

ESP w/23,000 ft2 collecting electrode area	None	Not BART eligible

Sappi- Somerset20, 21	ME	1,734	Power Boiler #1 (Babcock & Wilcox)	001
(PB#1)	848 MMBTU/hr (all fuels) &

250 MMBTU/hr (fossil fuels)	None	None	CEMS for SO2

Facility to reduce SO2 emissions by 50% by 2013 (BART deadline)

1	MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing
Reasonable Progress for Regional Haze in the Mid-Atlantic North Eastern
Class I Areas”, March 8, 2007.  Comments regarding Motiva Enterprises
LLC – Delaware City and NRG Energy Center Dover LLC facilities
received from Mr. John Sipple<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) via E-mail
on March 13, 2007.

2	New York State Department of Environmental Conservation, Division of
Air Resources.  Personal communications regarding Kodak Park Division
facility between Mr. Mike Cronin, P.E.<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) and
Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 1 and 9,
2007.

3	New York State Department of Environmental Conservation, Division of
Air Resources.  Personal communications regarding Kodak Park Division
facility from Mr. Mike Cronin, P.E.<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) via
E-mail on February 12, 2007.

4	Ohio Environmental Protection Agency, Division of Air Pollution
Control.  Personal communication regarding MW Custom Papers LLC –
Chillicothe Mill and Goodyear Tire and Rubber Company facilities from
Mr. William Spires<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) via
E-mails on February 20, 2007.

5	Tennessee Department of Environment and Conservation, Division of Air
Pollution Control.  Personal communication regarding Eastman Chemical
Company facility from Ms. Julie Aslinger<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) via
E-mail on March 1, 2007.

6	MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing
Reasonable Progress for Regional Haze in the Mid-Atlantic North Eastern
Class I Areas”, March 8, 2007.  Comments regarding Eastman Chemical
Company facility received from Ms. Julie Aslinger<PHONE_NUMBER>,
HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) via E-mail on March 30, 2007.

7	Maryland Department of the Environment.  Personal communication
regarding Westvaco Fine Papers facility between Mr. Andy Heltibridle
(410-537-4218,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) and Ms. Lori Cress, MACTEC Federal
Programs, Inc. on January 31, 2007.

8	Maryland Department of the Environment.  Personal communication
regarding Westvaco Fine Papers facility from Mr. Andy Heltibridle
(410-537-4218,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) via E-mail on January 31, 2007.

9	West Virginia Division of Air Quality.  Personal communications
regarding PPG, Industries, Inc. facility between Ms. Laura Crowder
(304-926-0499 Ext. 1247,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) and Mr. Steve Pursley<PHONE_NUMBER> Ext. 1218) and
Ms. Lori Cress, MACTEC Federal Programs, Inc., on March 14, 2007.

10	Virginia Department of Environmental Quality, Division of Air
Quality.  Personal communication regarding Mead Westvaco Packaging
Resource Group facility between Ms. Doris McLeod<PHONE_NUMBER>,
HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 20,
2007.

11	Pennsylvania Department of Environmental Protection, Bureau of Air
Quality.  Personal communication regarding PH Glatfelter Company/Spring
Grove facility between Ms. Nancy Herb<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) and Ms. Lori Cress,
MACTEC Federal Programs, Inc. on January 31, 2007.

12	Pennsylvania Department of Environmental Protection, Bureau of Air
Quality.  Personal communications regarding PH Glatfelter Company/Spring
Grove facility from Ms. Nancy Herb<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) via E-mail on January 31
and February 7, 2007.

13	Illinois Environmental Protection Agency, Bureau of Air.  Personal
communication regarding Williams Ethanol Services Incorporated and Corn
Products International Incorporated facilities between Mr. Rob Kaleel
(217-524-4387,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) and Ms. Lori Cress, MACTEC Federal Programs,
Inc. on February 2, 2007.

14	Illinois Environmental Protection Agency, Bureau of Air.  Personal
communication regarding Williams Ethanol Services Incorporated and Corn
Products International Incorporated facilities from Mr. Rob Kaleel
(217-524-4387,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) via E-mail on February 2, 2007.

15	Pennsylvania Department of Environmental Protection, Bureau of Air
Quality.  Personal communications regarding Sunoco Inc. (R&M) facility
between Ms. Nancy Herb<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) and Ms. Lori Cress,
MACTEC Federal Programs, Inc. on January 31, 2007.

16	Pennsylvania Department of Environmental Protection, Bureau of Air
Quality.  Personal communications regarding Sunoco Inc. (R&M) facility
from Ms. Nancy Herb<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) via E-mail on February
22, 2007.

17	New Jersey Department of Environmental Protection, Division of Air
Quality.  Personal communications regarding Valero Refining Company
facility between Mr. Ray Papalski<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>)
and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31 and
February 2, 2007.

18	New Jersey Department of Environmental Protection, Division of Air
Quality.  Personal communication regarding Valero Refining Company
facility from Mr. Ray Papalski<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>)
via E-mail on February 21, 2007.

19	Virginia Department of Environmental Quality, Division of Air
Quality.  Personal communication regarding Stone Container Corporation
facility from Ms. Doris McLeod<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) via
E-mail on February 9, 2007.

20	Maine Department of Environmental Protection Agency, Bureau of Air
Quality.  Personal communications regarding Great Northern Paper
Incorporated Mill West and Sappi - Somerset facilities between Ms. Lynn
Ross<PHONE_NUMBER>,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) and Mr. Marc Cone<PHONE_NUMBER>) and Ms. Lori
Cress, MACTEC Federal Programs, Inc. on February 2, 2007.

21	Maine Department of Environmental Protection Agency, Bureau of Air
Quality.  Personal communication regarding Great Northern Paper
Incorporated Mill West and Sappi - Somerset facilities between Ms. Lynn
Ross<PHONE_NUMBER>,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) via E-mail on February 2, 2007.

22	Delaware Department of Natural Resources and Environmental Control,
Division of Air and Waste Management.  Personal communications regarding
NRG Energy Center Dover LLC facility between Ms. Tammy Henry
(302-323-4542,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) and Ms. Lori Cress, MACTEC Federal Programs,
Inc. on March 5, 2007.

23	Delaware Department of Natural Resources and Environmental Control,
Division of Air and Waste Management.  Personal communications regarding
NRG Energy Center Dover LLC facility from Ms. Tammy Henry<PHONE_NUMBER>,
  HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>)
via E-mail on March 5, 2007.

This page left blank intentionally.

CHAPTER 6

SOURCE CATEGORY ANALYSIS:  KILNS

SOURCE CATEGORY DESCRIPTION

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 1,400oC (2,650oF).  High combustion temperatures
require large amounts of fuel and can result in significant emissions of
SO2 and NOX.  Crushing of ingredients and finished clinker can release
dust and particles.  Ammonia is sometimes produced during the heating of
limestone.

Figure 6.1 shows a process flow diagram of a Portland cement facility.
The process flow diagram (taken from AP-42) shows both wet and dry
Portland cement processes.

Figure 6.1  Portland Cement Process Flow Diagram

EPA. January, 1995.  AP42 Section 11.6 – “Portland Cement
Manufacturing”.

Figure 6.1 shows that the Portland cement process can generally be
broken down into the following steps:  raw materials handling, raw
material preparation, dry mixing, optional preheating and/or
precalcining, kiln treatment (pyroprocessing step), clinker handling and
storage, and finishing operations (finishing, storage and shipment).
The pyroprocessing step transforms the raw mix into clinkers, which are
gray, glass-hard, spherically shaped nodules that range from 0.125 to
2.0 inches in diameter.

The pyroprocessing step is the predominant source of gaseous pollutant
emissions.  In general, there are five different processes used in the
Portland cement industry to accomplish the pyroprocessing step: the wet
process, the dry process (long dry process), the semidry process, the
dry process with a preheater, and the dry process with a
preheater/precalciner.

Each of the pyroprocessing types vary with respect to equipment design,
method of operation, and fuel consumption.  Generally, fuel consumption
decreases in the order of the processes listed due to the heat required
to evaporate water present in the raw material slurry (e.g., wet
processes use the most fuel).

In the long dry process, all of the pyroprocessing activity occurs in
the rotary kiln.  Dry process pyroprocessing systems have been improved
in thermal efficiency and productive capacity through the addition of
one or more cyclone-type preheater vessels in the gas stream exiting the
rotary kiln.  This system is called the preheater process.  The vessels
are arranged vertically, in series, and are supported by a structure
known as the preheater tower.  Hot exhaust gases from the rotary kiln
pass countercurrently through the downward-moving raw materials in the
preheater vessels.  Compared to the simple rotary kiln (long dry
process), the heat transfer rate is significantly increased, the degree
of heat utilization is greater, and the process time is markedly reduced
by the intimate contact of the solid particles with the hot gases.  The
improved heat transfer allows the length of the rotary kiln to be
reduced.  An added benefit of the preheater operation is that hot gases
from the preheater tower are used to help dry raw materials in the raw
mill.  Because the catch from the mechanical collectors, fabric filters,
and/or electrostatic precipitators (ESP) that follow the raw mill is
returned to the process, these devices can also be considered to be
production machines as well as pollution control devices.

Additional thermal efficiencies and productivity gains have been
achieved by diverting some of the fuel to a calciner vessel at the base
of the preheater tower.  This system is called the preheater/precalciner
process.

Regardless of the type of pyroprocess used, the last component of the
pyroprocessing system is the clinker cooler.  The clinker cooler serves
two main purposes.  First, this portion of the process:

recoups up to 30% of the heat input to the kiln system;

locks in desirable product qualities by freezing mineralogy; and

makes it possible to handle the cooled clinker with conventional
conveying equipment.

The more common types of clinker coolers are reciprocating grate,
planetary, and rotary.  In these coolers, the clinker is cooled from
about 1,100°C  to 90°C (2000°F to 200°F) by ambient air that passes
through the clinker and into the rotary kiln for use as combustion air.
However, in the reciprocating grate cooler, lower clinker discharge
temperatures are achieved by passing an additional quantity of air
through the clinker. Because this additional air cannot be used in the
kiln for efficient combustion, it is vented to the atmosphere, used for
drying coal or raw materials, or used as a combustion air source for the
precalciner.

The second portion of the clinker process, a series of blending and
grinding operations, completes the transformation of clinker into
finished cement.  Up to 5% gypsum or natural anhydrite is added to the
clinker during grinding to control the cement setting time, and other
specialty chemicals are added as needed to impart specific product
properties.  This finish milling is accomplished almost exclusively in
ball or tube mills.  Typically, finishing is conducted in a
closed-circuit system, with product sizing by air separation.

Coal is the fuel of choice in cement kilns, primarily because of its low
cost, but also because the coal ash contributes to the product.  The
current fuel usage in cement kilns is about 82% coal; 4% natural gas;
and 14% other fuels, mainly combustible waste (industrial waste, tires,
sewage sludge, etc.).  In addition to conventional fuels, many Portland
cement facilities are employing the use of petroleum derived coke
(petcoke) blended with coal to fire kilns.

Lime kilns are similar to cement kilns.  The kiln is the heart of the
lime manufacturing plant, where various fossil fuels (such as coal,
petroleum coke, natural gas, and fuel oil) are combusted to produce the
heat needed for calcination.  There are five different types of kilns
used in lime manufacturing: rotary, vertical, double-shaft vertical,
rotary hearth, and fluidized bed.  The most popular is the rotary kiln,
however the double-shaft vertical kiln is an emerging new kiln
technology gaining in acceptance primarily due to its energy efficiency.
 Similar to cement plants, rotary kilns at lime manufacturing plants may
also have preheaters to improve energy efficiency.  Additionally, energy
efficiency is improved by routing exhaust from the lime cooler to the
kiln.  SO2 emissions from lime predominately originate from compounds in
the limestone feed material and fuels and are formed from the combustion
of fuels and the heating of feed material in the kiln.

All types of kilns at lime manufacturing plants use external equipment
to cool the lime product, except vertical (including double-shaft)
kilns, where the cooling zone is part of the kiln.  Ambient air is most
often used to cool the lime (although a few use water as the heat
transfer medium), and typically all of the heated air stream exiting the
cooler goes to the kiln to be used as combustion air for the kiln.  The
exception to this is the grate cooler, where more airflow is generated
than is needed for kiln combustion, and consequently a portion (about
40%) of the grate cooler exhaust is vented to the atmosphere.  EPA has
estimated that there are about five to ten kilns in the United States
that use grate coolers.  The emissions from grate coolers include lime
dust (PM) and trace metallic HAPs found in the lime dust, but not
typically SO2.

For cement and lime kilns, add-on control technology options identified
for SO2 include advanced flue gas desulfurization (AFGD), dry FGD, and
wet FGD.

EVALUATION OF SO2 EMISSION CONTROL OPTIONS

Sulfur dioxide may be generated both from the sulfur compounds in the
raw materials and from sulfur in the fuel.  The sulfur content of both
raw materials and fuels varies from plant to plant and with geographic
location.  However, the alkaline nature of the cement provides for
direct absorption of SO2 into the product, thereby reducing the quantity
of SO2 emissions in the exhaust stream.  Depending on the process and
the source of the sulfur, SO2 absorption ranges from about 70% to more
than 95%.

In contrast to electric utility and industrial boilers, SO2 emissions
from rotary cement kilns are not strongly dependent on fuel sulfur
content.  Instead, SO2 emissions are more closely related to the amount
of sulfide (e.g. pyrite) in kiln feedstocks 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 during processing,

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
the kiln, and

Temperature profile in the kiln system.

SO2 emission reductions may also result from attempts to reduce other
pollutants (primarily NOX), typically due to changes in the flame
characteristics of combustion.  For example, staged combustion with
mid-kiln injection of a low-sulfur fuel may be considered for reducing
SO2.  Similarly, including high pressure 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
and because their efficiencies are typically more limited than other
techniques they are not considered in additional detail here.

Other more specific SO2 control technologies applicable to cement kilns
are listed below.  A summary of controls evaluated for this work is
provided in Table 6.1.  Details of each of the control technologies
follow Table 6.1.  Additional information on this source category and
associated controls can be found in the 2005 NESCAUM document titled:
Assessment of Control Technology Options for BART-Eligible Sources.

Table 6.1  SO2 Control Technologies for Cement Kilns

Technology	Description	Applicability	Performance

Fuel Switching	Limiting the sulfur content of both raw materials and
fuels can reduce releases of SO2.  Availability of these materials is
highly site-specific.	All Kilns	Depends on availability of low-sulfur
raw materials

Dry Flue Gas Desulfurization - Spray Dryer Absorption (FGD)	Addition of
absorbents such as slaked lime (Ca(OH)2), quicklime (CaO) or activated
fly ash with high CaO content to the exhaust gas of the kiln can absorb
some of the SO2.	All Kilns	60-80% reduction

Wet Flue Gas Desulfurization (FGD)	SO2 is absorbed by a liquid/slurry
sprayed in a spray tower or is bubbled through the liquid/slurry.  Wet
scrubbers also significantly reduce the HCl, residual dust, metal and
NH3 emissions. 	All Kilns	90-99.9% reduction

Advanced Flue Gas Desulfurization (FGD)	DOE demonstrated a retrofit
Passamaquoddy Technology Recovery Scrubber™ using cement kiln dust
(CKD), an alkaline-rich (potassium) waste, to react with the acidic flue
gas.	All Kilns	95-99.5% reduction

Table References:

1.  Assessment of Control Technology Options for BART-Eligible Sources,
NESCAUM, March 2005.

2.  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.

Fuel Switching

As with any fuel-fired SO2 emission source, reduction of sulfur levels
in the fuel itself typically results in lowered emissions.  However,
this technique 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, and more specifically
the pyrite content, 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.

Flue Gas Desulfurization (FGD)

Both wet and dry flue gas desulfurization (FGD) systems have been used
effectively to control SO2 emissions from cement kilns.  FGD systems at
cement facilities typically are, 1) dry flue gas desulfurization (spray
dryer absorption) 2) wet flue gas desulfurization, and  3) advanced flue
gas desulfurization (AFGD).  A brief description of each of these
technologies is provided below.

Dry Flue Gas Desulfurization (Spray Dryer Absorption)

Spray dryer absorption (SDA) systems spray lime slurry into an
absorption tower where SO2 is absorbed by the slurry, forming a mixture
of calcium sulfite and calcium sulfate.  The liquid-to-gas ratio is such
that the water evaporates before the droplets reach the bottom of the
tower.  The dry solids are carried out with the gas and collected with a
fabric filter or ESP.  When used to specifically control SO2, the term
dry flue-gas desulfurization (dry FGD) may also be used. As with other
types of dry scrubbing systems (such as lime/limestone injection)
exhaust gases that exit at or near the adiabatic saturation temperatures
can create problems with this control technology by causing the baghouse
filter cake to become saturated with moisture and plug both the filters
and the dust removal system.  In addition, the lime slurry would not dry
properly and would plug up the dust collection system.  However there is
some argument in the control community that indicates that some of the
SO2 removal actually occurs on the filter cake.  Therefore, dry FGD
(spray dryer absorption) may not be technically feasible if exit gas
temperatures are not substantially above the adiabatic saturation
temperatures.  For Portland cement facilities, these temperatures are
likely to be above the adiabatic saturation temperatures.

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 air-cooling
after the gases leave the kiln.  Adding a conditioning tower to replace
wet suppression or dilution air enables the alkaline slurry system to be
used to reduce SO2 emissions (the equivalent of a spray dryer).  The use
of an alkaline slurry spray dryer type scrubber should be applied to
long wet kilns with care because the addition of the lime slurry may
drop the exhaust gases temperature below the acid adiabatic saturation
temperatures, creating significant plugging and corrosion problems in
the downstream particulate control device, duct work, and induced draft
fan.

Wet Flue Gas Desulfurization (FGD)

Wet scrubbing processes used to control SO2 and particulate emissions
are generally termed flue-gas desulfurization (FGD).  FGD utilizes gas
absorption technology, the selective transfer of materials from a gas to
a contacting liquid, to remove SO2 in the waste gas.  Caustic, crushed
limestone, or lime are used as scrubbing agents.  Our screening
evaluation assumes that lime is the scrubbing agent.

Caustic scrubbing produces a liquid waste, and minimal equipment is
needed.  When lime or limestone is used as the reagent for SO2 removal,
additional equipment is needed for preparing the lime/limestone slurry
and collecting and concentrating the resultant sludge.  Calcium sulfite
sludge is watery and is typically stabilized with fly ash for land
filling.  Calcium sulfate sludge is stable and easy to dewater.  To
produce calcium sulfate, an air injection blower is needed to supply the
oxygen for the second reaction to occur.  The normal SO2 control
efficiency range for SO2 scrubbers is 80-90% for low efficiency
scrubbers and 90-99.9% for high efficiency scrubbers.

While wet scrubbers have been used successfully in the utility industry,
they require more care when used for a Portland cement facility.
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 particulate control device (e.g., fabric filter).  Failure of
the particulate control device can pose difficult problems for a
downstream wet scrubber.

Advanced Flue Gas Desulfurization (FGD)

The AFGD process accomplishes SO2 removal in a single absorber which
performs three functions: prequenching the flue gas, absorbing SO2, and
oxidizing the resulting calcium sulfite to wallboard-grade gypsum.
Figure 6.2 shows the process flow for an AFGD system.

Incoming flue gas is cooled and humidified with process wet suppression
before passing to the absorber.  In the absorber, two tiers of
fountain-like sprays distribute reagent slurry over polymer grid packing
that provides a large surface area for gas/liquid contact.  The gas then
enters a large gas/liquid disengagement zone above the slurry reservoir
in the bottom of the absorber and exits through a horizontal mist
eliminator.

Figure 6.2  Advanced Flue Gas Desulfurization Process Flow

As the flue gas contacts the slurry, the sulfur dioxide is absorbed,
neutralized, and partially oxidized to calcium sulfite and calcium
sulfate.  The overall reactions are shown in the following equations:

CaCO3 + SO2 ( CaSO3 • 1/2 H2O + CO2

CaSO3 •1/2 H2O + 3H2O + O2 ( 2 CaSO4 • 2 H2O

After contacting the flue gas, slurry falls into the slurry reservoir
where any unreacted acids are neutralized by limestone injected in dry
powder form into the reservoir.  The primary reaction product, calcium
sulfite, is oxidized to gypsum by the air rotary spargers, which both
mix the slurry in the reservoir and inject air into it.  Fixed air
spargers assist in completing the oxidation.  Slurry from the reservoir
is circulated to the absorber grid.

A slurry stream is drawn from the tank, dewatered, and washed to remove
chlorides and produce wallboard quality gypsum.  The resultant gypsum
cake contains less than 10% water and 20 ppm chlorides.  The clarified
liquid is returned to the reservoir, with a slipstream being withdrawn
and sent to the wastewater evaporation system for injection into the hot
flue gas ahead of the electrostatic precipitator.  Water evaporates and
dissolved solids are collected along with the flyash for disposal or
sale.

The production of gypsum may actually be beneficial for Portland cement
as gypsum is added to Portland cement in the final grinding process to
regulate the setting time of the concrete.  However, to date there are
no known installations of AFGD at Portland cement facilities.

Inherent Removal

Removal of SO2 in the cement manufacturing process is inherent to that
process.  The raw materials used in the process, 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 generating a free lime, which then
reacts with SO2 in the gas stream, 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).  The overall
effectiveness and costs associated with this method are highly variable
and are related primarily to the type of kiln operation and the ability
of the facility to change raw material feeds.  These costs can be
difficult to quantify.

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:

Change in the oxygen concentration in the flame/exhaust gas area.  The
concentrations of oxygen and (more importantly) carbon monoxide strongly
influence the stability of alkali and calcium sulfates in the burning
zone.  By ensuring that sufficient oxygen is present to stabilize these
compounds, SO2 emissions can be controlled.  Control of burning-zone O2
and CO concentrations is a widely used industrial practice, and a
control technique applicable to all rotary cement kilns.  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 ensure that reducing
conditions in the flame are minimized.  Flame impingement in the hot
zone has 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 kilns
producing cement clinker, requires proper solid fuel preparation and
proper flame shaping and control.

Changes in raw materials to alter the alkali/sulfur molar ratio can also
be used to control SO2 emissions. SO2 concentrations in kiln exit gases
vary with the molar ratio of alkali to sulfur.  When there are
sufficient alkalis in excess of sulfur, SO2 emissions are typically low,
due to more sulfur being retained as alkali sulfates in the clinker.
Cement plants may also change their raw materials to reduce SO2
emissions.  Typically this is accomplished by substituting a raw
material containing pyritic sulfur or organic sulfur with one containing
lesser amounts of these compounds, leading to reduced 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).

As with inherent removal, the overall effectiveness and costs associated
with this method are highly variable and are related primarily to the
type of kiln operation and the ability of the facility to change raw
material feeds.  These costs can be difficult to quantify.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR KILNS

Cost of Compliance

To compare the various control options, information has been compiled on
the cost-effectiveness of retrofitting controls.  In general,
cost-effectiveness increases with the amount of cement produced by the
facility.

In a study performed for LADCO for a BART analysis, MACTEC developed
control costs for SO2 for a “model” cement plant for SO2.  For the
wet scrubber, the control cost estimates were prepared using lime as the
base in the scrubbing liquor. Caustic (NaOH) and limestone are potential
alternatives for a scrubber and could change the costs slightly.  While
lime and limestone require additional equipment for slurry preparation
and for solids separation from the sludge generated in the scrubber,
lime scrubbers are the most commonly used since lime is plentiful and
relatively cheap.  Materials of construction must also be made suitable
for caustic, lime, or limestone if existing equipment is modified for
wet scrubbing of SO2.

AFGD systems require additional capital costs for the spargers and
blowers necessary to oxidize the waste product to gypsum and for
equipment to dewater the product (e.g., centrifuge).  However if the
commercial grade gypsum can be sold or used by the cement facility, some
of these costs can be offset.

Dry FGD costs were calculated based on the low and high control
efficiencies typical for these systems.  For dry scrubbers, the flue gas
must be cooled to a temperature 10 to 20 degrees above adiabatic
saturation.  This is typically accomplished using a heat recovery
boiler, an evaporative cooler or a heat exchanger.  In addition, if the
facility does not have one, a particulate removal device is required for
removal of the dry materials used to absorb SO2.

For all scrubbers, costs for an additional or upgraded induced air draft
fan to make up for pressure drops within the system may be required.  In
addition, for wet systems, flue gas reheating may be required, thus a
reheater may be necessary.

Tables 6.2 – 6.4 present estimated SO2 control costs for AFGD, Wet
FGD, and Dry FGD applied to dry kilns and preheater kilns.  The range of
costs for these systems vary depending on the size of the kiln and
control efficiency, so costs are presented for three size ranges of
kilns.  Although the capital and annual operating costs of these three
types of control vary widely depending on kiln size and control
efficiency, the ultimate cost in terms of $/ton of SO2 reduction are
estimated to be from $2,000 - $7,000 for dry kilns and $9,000 to $73,000
for preheater kilns.

Table 6.2  SO2 Control Costs for AFGD Applied to Dry Kilns and Preheater
Kilns

(2006 dollars)

	Dry Kiln	Preheater Kiln

Unit Relative Size	Capital Costs (106 $)	Annual Operating Costs (106 $)
SO2 Cost Effectiveness ($/ton SO2 reduction)	Capital Costs (106 $)
Annual Operating Costs (106 $)	SO2 Cost Effectiveness ($/ton SO2
reduction)

Small	$7.03 – $22.9	$3 - $6	$2,000 - $4,000	$4.5 - $14.5	$1.2 –
$11.8	$13,600-$38,000

Medium	$14.1 - $45.9	$6.1 - $11.9

$8.9 - $29.0

Large	$28.1 - $91.6	$12.1 – $23.7

$17.8 - $58.0

Table 6.3  SO2 Control Costs for Wet FGD Applied to Dry Kilns and
Preheater Kilns

(2006 dollars)

	Dry Kiln	Preheater Kiln

Unit Relative Size	Capital Costs (106 $)	Annual Operating Costs (106 $)
SO2 Cost Effectiveness ($/ton SO2 reduction)	Capital Costs (106 $)
Annual Operating Costs (106 $)	SO2 Cost Effectiveness ($/ton SO2
reduction)

Small	$2.43 – $36.5	$3 - $9	$2,000 - $6,200	$1.5 - $23.1	$0.9 –
$18.9	$9,700-$64,600

Medium	$4.9 - $73.0	$6.0 - $18.4

$3.1 - $46.3

Large	$9.5 - $142.5	$11.9 – $36.8

$6.2 - $92.5

Table 6.4  SO2 Control Costs for Dry FGD Applied to Dry Kilns and
Preheater Kilns

(2006 dollars)

	Dry Kiln	Preheater Kiln

Unit Relative Size	Capital Costs (106 $)	Annual Operating Costs (106 $)
SO2 Cost Effectiveness ($/ton SO2 reduction)	Capital Costs (106 $)
Annual Operating Costs (106 $)	SO2 Cost Effectiveness ($/ton SO2
reduction)

Small	$1.45 – $37.0	$3 - $9	$1,900 - $7,000	$0.9 - $26.3	$0.9 –
$21.0	$10,000-$72,800

Medium	$2.9 - $84.9	$5.5 - $20.0

$1.8 - $52.6

Large	$5.6 - $165.5	$10.7 – $38.9

$3.6 - $105.2

The LADCO region had no wet kilns so cost estimates were not available
for those type kilns.  For the purposes of this study, wet kiln cost
effectiveness is assumed to be similar to that for long dry kilns.

Additional details concerning the calculation of cost effectiveness of
controls for kilns is located in a document developed by MACTEC for
LADCO titled: Cement Best Available Retrofit Technology (BART)
Engineering Analysis.  This document can be downloaded from the web at
the following location:    HYPERLINK
"http://www.ladco.org/reports/rpo/Regional%20Air%20Quality/BART/Cement_B
ART_Engineering%20Analysis%20%2B%20Appendix%20A1.pdf"
http://www.ladco.org/reports/rpo/Regional%20Air%20Quality/BART/Cement_BA
RT_Engineering%20Analysis%20%2B%20Appendix%20A1.pdf .

Time Necessary for Compliance

Generally, sources are given a 2-4 year phase-in period to comply with
new rules.  Under the NOX SIP Call for Phase I sources, EPA provided a
compliance date of about 3½ years from the SIP submittal date.  Most
MACT standards allow a 3-year compliance period. Under Phase II of the
NOX SIP Call, EPA provided a 2-year period after the SIP submittal date
for compliance.  States generally provided a 2-year period for
compliance with RACT rules.  For BART control measures, the proposed
BART guidelines require States to establish enforceable limits and
require compliance with the BART emission limitations no later than 5
years after EPA approves the regional haze SIP.

For the purposes of this review, we have assumed that a 2-year period
after SIP submittal is adequate for pre-combustion controls (fuel
switching or cleaning) and a three year period for the installation of
post combustion controls.

Energy and Non-Air Impacts

Fuel switching and cleaning and process changes do not significantly
impact efficiency of the cement operation, but may add to transportation
issues and secondary environmental impacts from waste disposal and
material handling operations (e.g. fugitive dust).  FGD systems
typically operate with high pressure drops across the control equipment,
resulting in a significant amount of electricity required to operate
blowers and circulation pumps.  In addition, some combinations of FGD
technology and plant configuration may require flue gas reheating to
prevent physical damage to equipment, resulting in higher fuel usage.

Environmental Impacts

The primary environmental impact of AFGD is the generation of byproduct
gypsum.  While gypsum is generated as a byproduct, the intent of the
AFGD system is to produce gypsum that is commercial grade that can be
sold.  In the case of cement kilns, production of gypsum would result in
some cost offsets since gypsum is a component of Portland cement.  Thus
the gypsum produced could be used to offset gypsum purchases.

The primary environmental impact of wet scrubbers is the generation of
wastewater and sludge.  Waste from wet scrubbers will increase the
sulfate and solids loading in the facility’s wastewater.  This places
additional burdens on a facility’s wastewater treatment and solid
waste management capabilities.  These impacts will need to be analyzed
on a site-specific basis.  If lime or limestone scrubbing is used to
produce calcium sulfite sludge, the sludge is water-laden, and it must
be stabilized for land filling.  If lime or limestone scrubbing is used
to produce calcium sulfate sludge, it is stable and easy to dewater.
However, control costs will be higher because additional equipment is
required. Scrubber exhaust gases are saturated with water, thus creating
a visible plume.  Plume visibility may be a local/community concern.
Once the exhaust mixes with sufficient air, the moisture droplets
evaporate, and the plume is no longer visible.

Disposal of removed material from dry FGD systems is also required and
will result in landfill impacts.

Energy Impacts

A scrubber operates with a high pressure drop, resulting in a
significant amount of electricity required to operate the blower and
pump.  In addition for some technologies, a flue gas reheater may be
required resulting in slightly increased fuel usage.

Remaining Useful Life of the Source

MACTEC could find little information on the typical lifetime of a cement
plant.  In a Security and Exchange filing (  HYPERLINK
"http://www.secbd.org/prosmcldopr.html"
http://www.secbd.org/prosmcldopr.html ) for a facility in India, typical
lifetimes of various components of the plant range between 20-50 years.
In an evaluation of waste management of cement kiln dust (CKD),
remaining useful lifetimes of waste management units were around 20
years (  HYPERLINK
"http://www.epa.gov/epaoswer/other/ckd/rtc/chap-4.pdf"
http://www.epa.gov/epaoswer/other/ckd/rtc/chap-4.pdf ).  Thus we found
nothing to suggest that the amortization of capital costs or calculation
of annual operating costs would be affected by the remaining useful
life.

For the purposes of this analysis, we assumed that the remaining useful
life of each emission unit was a minimum of at least 10 years and that
it was likely that some units would continue to operate for at least
20-30 more years with proper maintenance and upkeep.

REFERENCES

Assessment of Control Technology Options for BART-Eligible Sources,
NESCAUM, March 2005.

EPA. January, 1995.  AP42 Section 11.6 – “Portland Cement
Manufacturing”.

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.

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.

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.

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ANALYSIS OF SELECTED KILNS

SOURCE CATEGORY DESCRIPTION

Emission control regulations for cement kilns have historically focused
on particulate emissions.  Over the past several years, regulations for
the control of NOX and hazardous air pollutant (HAP) emissions have also
been adopted.  SO2 emission controls are largely non-existent.  Some
States have mandated emission limits as part of the Title V requirements
but no national regulatory program for SO2 controls for cement kilns
exists.  The only exceptions to this is for sources subject to New
Source Review under Title I of the Clean Air Act and for sources subject
to the Best Available Retrofit Technology (BART) requirements of the
regional haze regulations.

Title I subjects new and modified large stationary sources that increase
their emissions to permitting requirements that impose control
technologies of varying levels of stringency (known as New Source
Review, or NSR).  NSR prescribes control technologies for new plants and
for plant modifications that result in a significant increase in
emissions, subjecting them to Best Available Control Technology (BACT)
in attainment areas and to the Lowest Achievable Emission Rate (LAER) in
nonattainment areas.  The control strategies that constitute BACT and
LAER evolve over time and are reviewed on a case-by-case basis in State
permitting proceedings.

INFORMATION OBTAINED FROM STATE AGENCIES

MACTEC contacted State agencies to obtain information on kilns from
those facilities in the list of the top 20 individual non-EGU sources.
We requested permit information, information about SO2 controls recently
implemented or planned at the facility and any available information on
BART, consent decrees, or other regulations that will impact control
devices at the facilities.  The information we obtained is included in
Table 7.1.

Table 7.1  Point Source Information Collected from the Top 3 Kilns
Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name	State	2002

SO2

Total

(tons)	Primary Emissions Point Description	Point ID

(Permit

ID No.)	Design

Capacity	Existing

Control(s)	Proposed/

Planned

Control(s)	Additional Information

LaFarge Building Materials Inc.1	NY	14,800	Two rotary, wet process kilns
(Kiln 1 & 2) and two clinker coolers (Clinker Cooler 1 & 2).  There are
buildings at either end of the kilns; the discharge end building where
the clinker coolers are located, and the feed end building.	041000
Unknown	Fabric filter dust collector on clinker coolers (PM)

ESP (PM)	None

	St. Lawrence Cement Corp. – Catskill Quarry2, 3	NY	3,562	Cement kiln
permitted to burn coal, oil, tires, waste oil, natural gas,
non-hazardous fuels, and coke.  This is a wet kiln built in 1964.	U00K18
Unknown	ESP	Low-sulfur fuel	Consent Decree dated 1/9/91 limits burning
solid fuel with a max sulfur content of 3.8 lbs/MMBTU/hr.  BART analysis
has not been completed.

Lafarge Midwest, Inc., Alpena Plant4	MI	16,576	Five rotary dry kilns,
clinker coolers and associated materials handling operations.  Kilns
fire with coal, coke or waste derived fuel	EU-Kiln19

EU-Kiln20

EU-Kiln21

EU-Kiln22

EU-Kiln23	Unknown	Baghouses on kiln dust return systems	Unknown as of
date of report - these units are subject to BART	SO2 Emission limits on
all five kilns:

EUKiln19 = 2,088 tons

EUKiln20 = 2,065 tons

EUKiln21 = 2,056 tons

EUKiln22 = 9,685 tons

EUKiln23 = 9,728 tons

1	New York State Department of Environmental Conservation, Division of
Air Resources.  Personal communication regarding LaFarge Building
Materials Incorporated facility between Mr. Rick Leone<PHONE_NUMBER>)
and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 2, 2007.

2	New York State Department of Environmental Conservation, Division of
Air Resources.  Personal communication regarding St. Lawrence Cement
Corporation – Catskill Quarry facility between Mr. Rick Leone
(518-402-8403) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on
February 9, 2007.

3	New York State Department of Environmental Conservation, Division of
Air Resources.  Personal communication regarding St. Lawrence Cement
Corporation – Catskill Quarry facility from Mr. Rick Leone
(518-402-8403) via E-mail on February 9, 2007.

4	Michigan Department of Environmental Quality, Air Quality Division.
Personal communication regarding LaFarge Midwest, Incorporated Alpena
Plant from Ms. Teresa Walker<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) via E-mail on
February 7, 2007.

This page left blank intentionally.CHAPTER 8

HEATING OIL

BACKGROUND

Number 2 distillate fuel oil, heating oil, and diesel fuel oil are
essentially the same refinery-produced liquid.  In the Northeast United
States, home heating accounts for 54% of distillate fuel oil demand.  In
comparison, highway diesel accounts for 38% (NESCAUM, 2005).  Annually,
home heating oil use generates an estimated 100,000 tons of sulfur
dioxide (SO2) emissions in the Northeast (NESCAUM, 2005).  Climate and
seasonality play important roles in the use of heating oil, and
therefore the emissions from combustion of heating oil.  While it is
important to consider the emissions from heating oil in the Northeast
United States, emissions from heating oil combustion in other areas of
the United States such as the VISTAS States are not significant in
comparison to other emission sources.

SO2 emissions are proportional to fuel oil sulfur content.  It is not
feasible to control SO2 emissions from homes using control devices;
therefore, the most efficient method for controlling SO2 emissions from
home heating is by lowering the amount of sulfur in the fuel.
Currently, the sulfur limits in heating oil vary between 2,000 to 20,000
ppm.  Table 8.1 provides information on the range of sulfur in heating
oils throughout the Northeast.

Table 8.1  State Sulfur Limits for Heating Oil

State	Sulfur Limit in Percent	Sulfur Limit in parts per million (ppm)

Connecticut	0.3	3,000

Maine	0.3 to 0.5	3,000 to 5,000

Massachusetts	0.3	3,000

New Hampshire	0.4	4,000

New Jersey	0.2 to 0.3	2,000 to 3,000

New York Upstate	1.0 to 1.5	10,000 to 15,000

New York Downstate	0.2 to 0.37	2,000 to 3,700

Rhode Island	0.5	5,000

Vermont	2.0	20,000

Source:  NESCAUM, 2005

Beginning in 2006, the permissible level of sulfur in highway diesel
fuel (ultra low sulfur diesel, or ULSD) was 15 ppm.  Prior to that,
highway low sulfur diesel fuel was refined to contain 500 ppm sulfur
(Low Sulfur Diesel, or LSD).  Consequently, refineries have already
performed the capital investments required for the production of LSD and
ULSD fuel oil.  The Northeast States are considering adopting consistent
low sulfur heating oil requirements, and a memorandum titled DRAFT
Memorandum of Understanding for Regional Fuel Sulfur Content Standards
for Distillate Number 2 Heating Oil, the Northeast States proposed to
reduce the sulfur content to 500 ppm.  A reduction of sulfur in heating
oils from the current levels to 500 ppm would reduce SO2 emissions by
approximately 75% per year on a nationwide basis (Batey and McDonald,
2005).  There has also been some discussion regarding the reduction of
heating oil sulfur content to 15 ppm.

This memorandum presents the four factor analysis that was applied to
the heating oil sulfur reduction proposal.  The four factors are:  cost
of compliance, time necessary for compliance, energy and non-air
impacts, and remaining useful life of the sources.  This document
primarily focuses on reducing the sulfur content of heating oil to 500
ppm.  Information on reducing the sulfur content of heating oil to 15
ppm is presented wherever data were available.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR EMISSIONS FROM
HEATING OIL COMBUSTION

Cost of Compliance

Refinery Retrofit Costs

Refineries were required to make significant capital investments to meet
the LSD and ULSD highway fuel sulfur requirement.  To achieve the LSD
and ULSD sulfur goals, refineries were required to implement diesel
desulfurization technologies.  Estimates for the capital costs were
developed in 2001 by the Energy Information Administration (EIA) and are
based on calendar year 1999.  Table 8.2 presents the capital costs for
desulfurization technologies developed by the EIA, which were converted
from a calendar year 1999 dollar basis to 2006 dollars.  The EIA
developed estimates for new and revamped desulfurization technologies at
existing refineries.

Table 8.2  Ultra Low Sulfur Diesel (ULSD) Desulfurization Technology
Costs for Individual Refineriesa,b

Desulfurization Unit Type	Throughput (Barrels per Day)	Capital Costs
(2006 Dollars per Daily Barrel Produced)	Total Capital Cost per Unit
(Million 2006 Dollars)

New	50,000	1,204	60.3

New	10,000	2,187	21.9

Revamp	50,000	716	35.8

Revamp	10,000	1,464	14.6

aBased on cost estimates for hydrotreaters to produce ULSD.

bSource for this information is the Energy Information Administration

Note – A conversion factor of 1.2101 was used to convert the dollar
values from 1999 to 2006   HYPERLINK "http://www.inflationdata.com"
www.inflationdata.com

In its highway diesel fuel rulemaking, EPA also developed cost estimates
for the deployment and implementation of desulfurization technologies at
refineries.  EPA estimated that it would cost existing refineries an
estimated $56 million (2006 dollars) per refinery to install
desulfurization technologies, and that this effort would be spread out
over a 2-year time period.  EPA based its conclusions on the assumption
that refineries would revamp their hydrotreating technologies.  It
further estimated that 80% of the hydrotreaters at the refineries would
be revamped.  The EPA also estimated that the cost of a new hydrotreater
would be $91 million (2006 dollars), and that roughly 25 refineries
nationwide would have to make this investment.  No estimates were made
for the costs associated with new refineries as none are currently being
constructed in the United States.  The EPA analysis spread the
investment cost over a 2-year period.  Consequently, it was estimated
that the US refinery-wide investment for calendar year 2004 was $2.45
billion and $2.83 billion for calendar year 2005 (EIA 2001)  (Converted
from 2001 to 2006 dollars using a conversion factor of 1.1383.
HYPERLINK "http://www.inflationdata.com"  www.inflationdata.com ).

In the August 9, 2006 edition of This Week in Petroleum, EIA reported
that total ULSD production progress has been good and that ULSD is
currently being produced in all Petroleum Administration for Defense
Districts (PADDs).  Stocks of ULSD in the United States in January 2007
were approximately equal to distillate oil containing greater than 500
ppm sulfur.  However on the East Coast, stocks of ULSD were
approximately one-third the size of distillate oil stocks containing
more than 500 ppm sulfur (EIA).  Another independent source, The
Marathon Petroleum Company, LLC, found that 90% of refineries in the
continental United States that were included in a survey had designed
units capable of producing ULSD.  Also, Marathon determined that the
planned US capacity for ULSD would be in excess of 2.5 million barrels
per day in 2006 (Marathon Petroleum Corporation 2007).

Heating Oil Cost Increases

It is assumed that the costs for retrofitting refineries will be passed
on to consumers.  In its December 2005 study, NESCAUM estimated that the
average price increment for the lower sulfur product (500 ppm) would be
$0.16 per gallon.  In December 2005, this represented a 1% increase of
the average oil price.

To update these costs we compared the costs of low-sulfur diesel fuel
(15 – 500 ppm) with regular diesel fuel (2,000 ppm) for 2006.  These
data were gathered from DOE EIA Web site on March 8, 2007.  We used the
difference in diesel fuel prices because the cost for low sulfur heating
oil is currently not reported and because diesel fuel and number 2
distillate are essentially the same product.  It is therefore reasonable
to assume that the cost differential between low sulfur and regular
diesel fuel should reflect the potential cost differential between low
sulfur and regular heating oil.  All cost comparisons are before taxes.
EIA only reports a low-sulfur diesel fuel category which includes both
low sulfur (500 ppm) and ultra low sulfur diesel (15 ppm).  For the
first two months on 2007, EIA reports that stocks of 15 ppm sulfur oil
were roughly twice that of 500 ppm sulfur oil.  We averaged monthly
costs to compute annual average costs for PADD 1A (CT, ME, MA, NH, RI,
VT) and PADD 1B (DE, DC, MD, NJ, NY, PA) for low sulfur and regular
diesel fuel from January to December 2006.  For PADD 1A, the cost of low
sulfur diesel fuel ranged from $1.954 to $2.433 per gallon and the cost
of regular diesel fuel ranged from $1.963 to $2.429 per gallon.  The
monthly difference between low sulfur and regular diesel fuel ranged
from -1.1 cents per gallon to 0.5 cents per gallon with an annual
average of -0.8 cents per gallon.  That is, low-sulfur diesel fuel was
on average less expensive that regular diesel fuel in PADD 1A in 2006.
Similarly in PADD 1B, the cost of low sulfur diesel fuel ranged from
$1.894 to $2.358 per gallon and the cost of regular diesel fuel ranged
from $1.894 to $2.321 per gallon.  The monthly difference between low
sulfur and regular diesel fuel ranged from -1.3 cents per gallon to 4.7
cents per gallon with an annual average of 1.6 cents per gallon.  In
both regions fuel costs were highest in the summer and the difference in
cost between low sulfur and regular diesel fuel was also highest in
summer.  To calculate an average cost differential, we weighed the PADD
1A and PADD 1B cost differentials by residential fuel use in each PADD
for 2005 (the latest date data are available from EIA).  In 2005, PADD
1A States used 1.9 million gallons and PADD 1B States used 2.5 million
gallons.  Therefore, on average low sulfur distillate oil would be
expected cost 0.8 cents per gallon more than regular heating oil in
MANE-VU States.  This average price differential translates in to
$734/ton of sulfur removed if it assumed that the low sulfur diesel has
a concentration of 500 ppm sulfur or $554/ton of sulfur removed for
ultra low 15 ppm sulfur diesel.

STAPPA-ALAPCO (2006) estimates that the annual fuel oil consumption per
household is 865 gallons per year.  Using the price differential data
presented above, the average household would spend about $7 per year
additional on home heating costs by using low or ultra low sulfur fuel.

The use of LSD/ULSD will also result in cost savings to owners/operators
of residential furnaces and boilers due to reduced maintenance costs.
When the existing heating oil sulfur content is 2,000 ppm and 500 ppm
sulfur is substituted, the service interval can be extended by a factor
of three or more (e.g., cleaning at three year intervals rather than
annually).  Vacuums are used to remove deposition caused by SO2 from
furnaces and boilers.

The potential vacuum cleaning costs savings for the United States, for a
starting fuel sulfur content of 2,000 ppm ranges from approximately $200
million a year to $390 million a year for service costs of $50 to $100
per hour.  Therefore, if all oil heated homes switched to 500 ppm sulfur
heating oil, more than $200 million a year could be saved, which would
significantly lower the overall operating costs of fuel oil marketers.
Given the dominant share of the U.S. heating oil market represented by
the Northeast States, a large percentage of the projected national
benefits would accrue in the region (NESCAUM 2005).  In a brochure
distributed by EIA titled Residential Heating Oil Prices: What Consumers
Should Know, EIA reports that 6.3 million of the 8.1 million households
using heating oil in the United States (78%) are in the Northeast
Region.  This region includes the New England and Central Atlantic
States.

Heating Oil Supply

EPA addressed the issue of using ULSD for heating oil purposes in its
regulatory impact analysis for Heavy-Duty Engine and Vehicle Standards
and Highway Diesel Fuel Sulfur Control Requirements (2000).  EPA found
that refiners in the Mid-Atlantic and Northeast (PADD 1) could produce
more of this fuel and reduce the need for imports.

EIA reports that in 2004, 5,975,966,000 gallons of heating oil were sold
in the United States.  This decreased to 5,548,827,000 gallons in 2005.
The EIA publishes weekly updates on the availability of heating oil.
Information was retrieved for January 2007 and is summarized in Table
8.3 below.

Table 8.3  Average January 2007 Distillate Stocks

(Million Barrels)a

Location	15 ppm and

Under Stocks	15 ppm --

500 ppm Stocks	>500 ppm Stocks	Total Distillate

Stocks

US (Total)	57.2	25.0	59.7	141.8

East Coast	14.7	21.9	44.5	66.5

Average Days of Supply of Distillate Fuel Oilb	34.4	34.4	34.4	34.4

aSource for this information is the Energy Information Administration.

bThe sulfur content of distillate stocks is not distinguished by the EIA
for this data point.

The EIA also makes available information regarding the production and
imports of heating oil.  This information is summarized in Table 8.4,
and includes specific data for the East Coast.

The information presented in Table 8.4 indicates that on a nationwide
basis, more ULSD is produced than both LSD and high sulfur fuel.  This
is due to the predominant use of ULSD in highway diesel vehicles.  This
information also supports the conclusion that the United States has the
infrastructure to produce adequate stocks of LSD and ULSD.

Table 8.4  Distillate Production and Imports

(Million Barrels per Day)a,b

Location	15 ppm and

Under Production	15 ppm -

500 ppm Production	>500 ppm Production	Total Distillate

Production

US	2.659	0.624	0.970	4.253

East Coast	0.248	0.024	0.277	0.549

Imports	0.204	0.018	0.115	0.392

aSource for this information is the Energy Information Administration.

bBased on the four week average ending January 12, 2007.

Currently, the 15 ppm fuel is sold for highway use diesel, whereas the
>500 ppm stocks are sold for heating oil.  The 15-500 ppm fuel can still
be used until 2010 under the hardship provisions of the heavy duty
highway diesel program (EPA 2004).  Under these provisions of the heavy
duty highway diesel program, if there is a shortage of 15 ppm fuel, the
15 -500 ppm fuel could be used to relieve the shortage.  With this
flexibility, the likelihood of a fuel shortage in the short term, due to
usage of ULSD for heating oil is reduced.

Time Necessary for Compliance

Refiners in the United States are already producing low sulfur highway
diesel fuel.  This same fuel can be marketed as heating oil since it is
the same refinery product as highway diesel except with dye added to the
fuel to differentiate it for tax purposes.  Some time may be required to
allow petroleum marketers to adjust to distributing ULSD to heating oil
customers, however, the distribution network for motor fuels and heating
oil are already in place.

NESCAUM (2005) estimated that during peak periods of demand, up to 20%
of the required heating oil is imported.  This analysis does not address
whether offshore refineries should be able to produce 15 ppm sulfur for
export to the Northeast United States.  In case of a shortage of 15 ppm
fuel during the transition period from LSD to ULSD, the heavy duty
highway diesel program allows the use of 15-500 ppm sulfur fuel.

Existing residential furnaces and boilers do not need to be retrofitted
or modified to combust 15 ppm sulfur.  The capacity for producing LSD
and ULSD already exists among US refiners.  Consequently, the time
necessary for compliance does not hinge on the heating oil
furnace/boiler.

Energy and Non-Air Impacts

Reducing the sulfur contents of heating oil has a variety of beneficial
consequences for residential furnaces and boilers.  Low sulfur
distillate fuel is cleaner burning and emits less particulate matter
which reduces the rate of fouling of heating units substantially and
permits longer time intervals between cleanings.  According to a study
conducted by the New York State Energy Research and Development
Authority, (NYSERDA), boiler deposits are reduced by a factor of two by
lowering the fuel sulfur content from 1,400 ppm to 500 ppm.  These
reductions in buildup of deposits result in longer service intervals
between cleanings. (Batey and McDonald 2005).  Batey and McDonald (2005)
estimated that the potential cost savings from decreased vacuum
cleanings ranges from $200 million per year to $390 million per year.
The decreased deposits would also enable a more efficient transfer of
heat, thereby reducing the fuel usage.  Further reducing the heating oil
sulfur from 500 to 15 ppm would increase the cost savings from decreased
maintenance needs due to heat exchanger fouling.

The decreased sulfur levels would enable manufacturers to develop more
efficient furnaces and boilers by using more advanced condensing
furnaces and boilers.  These boilers recoup energy that is normally lost
to the heating of water vapor in the exhaust gases.  Historically, the
use of high sulfur fuels prevented this due to the corrosion of the
furnace/boiler due to the creation of sulfuric acid in the exhaust
gases.  The increased efficiency results in a decrease in the amount of
heating oil a heating unit uses, therefore, this would make a switch to
lower sulfur heating oils more attractive and cost effective.

Remaining Useful Life of the Source

Residential furnaces and boilers have finite life times, but they do not
need to be replaced to burn low or ultra low sulfur fuel.  The Energy
Research Center estimates that the average life expectancy of a
residential heating oil furnace is approximately 18 years, and that the
average life expectancy of a residential heating oil boiler is 20-25
years (Personal communication with Mr. John Batey, Energy Research
Center on February 6, 2007).

Finally, the number of homes that are being heated with heating oil is
declining by approximately 100,000/year (RedOrbit 2007).  No
geographical distribution was available for this estimate, but since
heating oil is predominantly used in the Northeast, most of the changes
will be occurring there.  Consequently, emissions from heating oil
combustion will become less significant of a source of SO2 emissions in
the future.

REFERENCES

Batey, J.E. and R. McDonald, 2005.  Low Sulfur Home Heating Oil
Demonstration Project Summary Report.  Project funded by The New York
Sate Energy Research and Development Authority.  Contract No.
6204-IABR-BR-00.

Energy Research Center.  Personal communication on February 6, 2007 with
Mr. John Batey and Mr. Bernd Haneke of MACTEC Federal Programs, Inc.

EPA, 2004.  Overview of EPA’s Low Sulfur Diesel Fuel Programs.
Presented at the Ultra-Low Sulfur Diesel Fuel Implementation Workshop by
the EPA’s Office of Transportation and Air Quality, New Orleans,
Louisiana, November 15, 2004.

Marathon Petroleum Company, LLC.  Ultra Low Sulfur Diesel.  PowerPoint
Presentation downloaded from the World Wide Web on January 31, 2007
from:    HYPERLINK "http://www.marathonpetroleum.com/"
http://www.marathonpetroleum.com/

NESCAUM, 2005.  Low Sulfur Heating Oil in the Northeast States:  An
Overview of Benefits, Costs and Implementation Issues.

RedOrbit, 2007.  Refiners Have Many Options to Convert High-Aromatic
Streams into ULSD.  Article downloaded from the World Wide Web on
January 31, 2007 at:   HYPERLINK "http://www.redorbit.com"
http://www.redorbit.com

STAPPA ALAPCO, 2006.  Controlling Fine Particulate Matter Under the
Clean Air Act:  A Menu of Options.

US Energy Information Administration, August 9, 2006.  This Week in
Petroleum.

US Energy Information Administration, 2001.  Brochure titled Residential
Heating Oil Prices: What Consumers Should Know.

US Energy Information Administration, 2001.  The Transition to Ultra-Low
–Sulfur Diesel Fuel:  Effects on Prices and Supply.  Publication
downloaded from the World Wide Web on January 31, 2007 at:    HYPERLINK
"http://www.eia.doe.gov/oiaf/servicerpt/ulsd"
www.eia.doe.gov/oiaf/servicerpt/ulsd

US Energy Information Administration, 2007.  Information downloaded from
the World Wide Web on March 8, 2007.at:   HYPERLINK
"http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm"
http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm

US EPA, 2000.  Regulatory Impact Analysis:  Heavy Duty Engine and
Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements.
EPA Publication Number EPA420-R-00-026.

CHAPTER 9

RESIDENTIAL WOOD COMBUSTION

BACKGROUND

The MANE-VU Contribution Assessment and other MANE-VU reports have
documented that visibility impairment in this region is primarily due to
regional secondary sulfate.  However, in the MANE-VU Class I areas,
biomass combustion also has been identified as a contributor to
visibility impairment.  Biomass combustion emissions due to human
activity primarily derive from residential wood combustion.  While some
biomass burning occurs throughout the year, residential wood combustion
occurs predominantly in the winter months, potentially contributing to
wintertime peaks in PM concentrations.

In the document, Control Analysis and Documentation for Residential Wood
Combustion in the MANE-VU Region, OMNI Environmental Services, Inc.
(OMNI) conducted a control analysis and documentation of residential
wood combustion (RWC) in the 11 States and the District of Columbia that
make up the MANE-VU region.  Information for the OMNI analysis was
obtained from:  (1) The MANE-VU Residential Wood Combustion Emission
Inventory published by MARAMA (July 2004 report), (2) Residential Energy
Consumption Surveys published by the EIA, (3) the National Emission
Inventory published by the EPA, (4) Simmons Marketing Research reports,
and (5) American Housing Surveys for the United States published by the
U.S. Department of Commerce and the U.S. Department of Housing and Urban
Development.  In addition, the results of three RWC surveys at the
State-level have been published in the last decade for the Mid-Atlantic
and New England area, which allow for comparison of data extrapolated
from the national- and regional-scale surveys to the State level for
three States.  These were the: (1) 1995 Delaware Fuelwood Survey, (2)
Residential Fuelwood Use in Maine, Results of 1998/1999 Fuelwood Survey,
and (3) Vermont Residential Fuel Wood Assessment for 1997-1998.

To facilitate understanding of the cost effectiveness analyses done by
OMNI, descriptions of the various appliances used, as well as a brief
discussion of efficiency, are provided from the OMNI report.

Cordwood-Fired Stoves and Fireplace Inserts

Uncertified, certified catalytic, and certified non-catalytic cordwood
stoves and fireplace inserts together are considered cordwood heaters.
They are designed to burn bulk cordwood and are room space heaters,
i.e., they primarily rely on radiant and convection heat transfer, in
contrast to centralized heating systems such as warm-air furnaces or
boilers which utilize heat distribution systems to heat multiple rooms.
Fireplace inserts are essentially wood stoves that are designed to be
inserted into an existing fireplace cavity.  Because of the heat
transfer shielding effect of the fireplace cavity and the fact the
majority of existing fireplace chimneys are against an outside wall,
their heating efficiency is less than a similar freestanding woodstove.
Many fireplace inserts have fans to facilitate transfer of heat from the
portion that is inside the fireplace cavity.  Both freestanding cordwood
stoves and fireplace inserts rely on a natural draft using room air for
combustion and the venting of exhaust through the chimney to the
atmosphere.  Though the majority of cordwood heaters use room air for
combustion, some insert installations, such as in mobile homes, require
the use of outside air for combustion.

Uncertified Conventional Cordwood-Fired Stoves and Fireplace Inserts

Uncertified cordwood fired stoves and fireplace inserts include units
manufactured before the 40 CFR Part 60, Subpart AAA New Source
Performance Standard (NSPS) July 1, 1990 certification requirement, and
currently or recently manufactured exempt units which operate similarly
to some old pre-EPA certification units.

NSPS Certified Catalytic Cordwood-Fired Stoves and Fireplace Inserts

Certified catalytic units pass the exhaust through a catalyst to achieve
emission reductions.  Generally, a coated ceramic honeycomb catalyst is
located inside the stove where the incompletely combusted gases and
particles ignite and are combusted further, thus reducing air emissions
and increasing combustion overall efficiency.

NSPS Certified Non-Catalytic Cordwood-Fired Stoves and Fireplace Inserts

Certified non-catalytic stoves and fireplace inserts rely on design
features to reduce air emission and increase efficiency.  They generally
rely on the introduction of heated secondary air to improve combustion,
as well as firebox insulation, and baffles to produce a longer, hotter
gas flow path, as well as other design features to achieve low emissions
and higher efficiency.

Pellet Stoves and Fireplace Inserts

Analogous to cordwood stoves and fireplace inserts, pellet stoves and
fireplace inserts are considered room heaters.  They burn pellets
generally made from sawdust, although there has been, and continues to
be, research into utilizing other biomass fuels to make pellets.
Combustion air is drawn from the room for most models, and exhaust is
vented outdoors.  Some pellet appliances use outside air for combustion.
Pellet stoves and inserts require the use of electric motors to power
the combustion air and heat transfer fans and the pellet-feeding auger.
Modern pellet units use electronic sensors and controls.  Pellets are
introduced into the hopper, and the auger continuously feeds a
consistent amount of pellets into the firebox.  The feed rate is
controlled electronically by a feed rate setting selected by the user.
There are two basic designs: bottom-feed and top-feed models.  Pellet
units have a high efficiency and low emissions due to the use of the
electric auger and fan that produce uniform and controlled combustion
conditions.  Some units are certified by the NSPS process and some are
not.  The performance of the certified and uncertified models are
similar.  What is considered by most as a “loop-hole” in the NSPS
regulations essentially allows certification to be bypassed.

Wood-burning Fireplaces without Inserts

Fireplaces without inserts include manufactured units (often referred to
as “zero-clearance” fireplaces) and site-built masonry units
operated both with and without glass doors.  Combustion air is drawn
from the natural draft created by fire, and that same draft vents the
exhaust gases through the chimney.  Fireplaces without inserts have low
efficiencies due to the large amount of heated room air that is
exhausted out of the chimney from the draft.  Many fireplaces without
inserts are not used in a given year, some are used for aesthetic
purposes and some are used for heating.  Those that are used for heating
are almost always used for secondary heating purposes and not primary
heating due to their low efficiency and lack of heat transfer
capabilities.  Manufactured wax/fiber firelogs are often used as a fuel
in them with about 30% of fireplace users nationwide claiming that they
use wax/fiber firelogs some of the time.  Most fireplaces are
wall-mounted, however, this category also includes some free-standing
models.

Direct Vent Gas Stoves and Fireplace Inserts (LPG and Natural Gas)

Direct vent gas stoves and inserts are sealed units that draw their
combustion air from, and vent their exhaust to, the outside air.
Venting can be extended vertically or horizontally out of the home.  A
common type of venting is coaxial, which has the exhaust pipe contained
within the air inlet pipe, so the temperature of the combustion air is
raised, and the temperature of the exhaust is lowered, creating more
efficient combustion.  It should be noted that natural gas is not
readily available in all locations, however LPG may be available for
use.

Vent-Free Gas Stoves and Fireplace Inserts (LPG and Natural Gas)

Vent-free gas stoves and inserts receive their combustion air from the
room in which the unit is placed, and all of the products of combustion
are exhausted into the room as well.  The high efficiency of vent free
units is due to the fact that the heat produced is kept in the room.
Vent free gas stoves and inserts have a maximum heat input in order to
avoid emitting excess CO, CO2, or NOX into the room, and the units also
have an O2 depletion sensor or other device to shut the unit down if
oxygen levels become too low.  It is important to note that vent-free
natural gas and LPG stoves, inserts and log sets should not be
considered options for primary or even significant secondary heating
use.  There is considerable concern regarding indoor air quality and
damage to homes by moisture created from their use, as combustion gases
are not vented to the atmosphere.  If the devices are used prudently,
these problems are reduced.  Their appropriate role is for aesthetics
and minor secondary heating.  Just as with direct vent gas stoves and
fireplace inserts, LPG can be used as an alternative where natural gas
is not readily available.

B-Vent Gas Stoves and Fireplace Inserts (LPG and Natural Gas)

B-vent gas stoves and inserts draw their combustion air from the room,
and exhaust is vented outdoors.  These units use a draft hood for the
proper venting of exhaust. B-vent gas stoves and inserts have lower
efficiency than direct vent due to the fact that already heated room air
is used as combustion air, which is then exhausted to the outdoors,
taking heat away from the room.

OMNI Study Summary

In the OMNI study, the amount of fuel consumed by RWC devices was
considered the measure of activity.  Activity data were provided by
individual appliance type by State and for the total MANE-VU region.
The activity study conducted by OMNI showed that there were
approximately 6.4 million tons of fuel burned in 2002 by RWC devices in
the MANE-VU region.  The majority of RWC combustion was located in New
York (1.9 million tons of fuel burned) and Pennsylvania (1.4 million
tons of fuel burned).

OMNI then compiled an emissions inventory by county, by State, and for
the entire MANE-VU region for the 2002 base year.  The dry mass of fuel
(activity) for cordwood, pellets, and manufactured wax/fiber firelogs
compiled in the activity task was multiplied by the applicable emission
factor in the units of mass air pollutant per mass of dry fuel.  The
emission factors were obtained by reviewing and averaging (if multiple
sources were available) data obtained from available reports and
publications.  PM and VOC (an ozone precursor) are the main criteria
pollutants of concern for RWC and non attainment areas.  The OMNI
emissions inventory reported that there were 92,470 tons of total PM
emissions and 87,741 tons of VOC generated from RWC devices in the
MANE-VU region during the base year (2002).  It should be noted that
this analysis assumed that PM10 was equivalent to PM.  The only
emissions control efficiency, and control device information available
is for PM10.  We have therefore assumed that data for PM10 are
applicable to PM2.5.

Table 9.1 from the OMNI report summarizes measures for RWC RACM
developed by EPA in EPA-450/2-89-015.  OMNI reported the RACM fall in
three primary categories:  (1) improvement of performance, (2) reducing
the use of RWC devices, and (3) episodic curtailment.  The effectiveness
in reducing RWC emissions and a related discussion of each of the
various activities are also provided in Table 9.1.  In addition to the
three primary categories for RWC RACM, the RACM document emphasizes the
importance of public awareness in many RWC emission control programs and
provides considerable information on the subject.

Table 9.1  Summary of Measures Available for RWC RACM – PM10

Program Elements	Estimated Effectiveness

(%)	Discussion

IMPROVEMENT OF PERFORMANCE

State implementation of NSPS	0	States are not expected to adopt this
program element at levels that would affect program effectiveness
significantly.

Ban on resale of uncertified devices	0	No credit recognized because
requirement is largely unenforceable: other elements will be required to
include disabling of retired used devices.

Installer Training Certification or Inspection Program	~ 5	Reduction in
emissions from each new certified RWC device where either the installer
is trained/certified or the installation is inspected.

Pellet stoves	90	Reduction in emissions from each new or existing
conventional, uncertified RWC device replaced with a pellet stove.

	75	Reduction in emissions from each new or existing Phase II EPA
certified RWC device replaced with a pellet stove.

EPA Phase II certified RWC devices	~50	Reduction in emissions from each
new or existing conventional, uncertified RWC device replaced with an
EPA Phase II certified RWC device.

Retrofit requirement	<5	Reduction in emissions from each existing
conventional, uncertified RWC device equipped with a retrofit catalyst
or pellet hopper (to maximum when all existing uncertified RWC devices
have retrofit devices installed).

Accelerated changeover requirement	~50	Reduction in emissions from each
existing conventional, uncertified RWC device replaced with Phase II
certified device.

	100	Reduction in emissions from each existing conventional, uncertified
RWC device removed and not replaced: requires existing device to be
disabled and not resold.

Accelerated changeover inducement	~50	Reduction in emissions from each
existing conventional, uncertified RWC device replaced with Phase II
certified device.

	100	Reduction in emissions from each existing conventional, uncertified
RWC device removed and not replaced: requires existing device to be
disabled and not resold.

Table 9.1  Summary of Measures Available for RWC RACM – PM10

Program Elements	Estimated Effectiveness

(%)	Discussion

Require fireplace inserts	0	No credit recognized for fireplace inserts,
since inserts change use of fireplace from aesthetic to primary heat
source, resulting in an increase in amount of wood combusted and higher
overall emissions.

Wood moisture	<5	Reduction in total emissions from all RWC devices in
the community/airshed.

Trash burning prohibition	0	No credit recognized for eliminating trash
burning in RWC devices.

Weatherization of residences	<5	Reduction in total emissions from all
RWC devices in the community/airshed.

Opacity limits	<5	Reduction in total emissions from all RWC devices in
the community/airshed.

REDUCING USE OF RWC DEVICES

Availability of alternative fuels	100	Reduction in emissions from each
RWC device removed from service and replaced with device using natural
gas: recognize no more than 10% of RWC devices replaced under program
with no additional incentives.

Emission trading	Computation required	For a 2:1 trading ratio, the
reduction in emissions from each new stove would be calculated as the
difference between emissions of a new RWC device and 2 times the average
emissions per stove in the community:

multiplier would change for other trading ratios.

Taxes on RWC devices	Variable	Emission reduction credit would vary with
utility or tax rate structure adopted and extent to which this structure
resulted in reduction in number of RWC devices in the community versus
reduction in use of RWC devices.

Regulatory ban on RWC devices in new dwellings	100	Reduction in
emissions from new RWC devices purchased for installation in new
dwellings.

Regulatory ban on

existing RWC devices	100	Reduction in emissions from each RWC device
removed.

Table 9.1  Summary of Measures Available for RWC RACM – PM10

Program Elements	Estimated Effectiveness

(%)	Discussion

EPISODIC CURTAILMENT

Voluntary	10	Reduction in emissions for all RWC devices not exempted.

Mandatory	60% fireplace

50% woodstoves	Reduction in emissions for all RWC devices not exempted.

Table Reference:  U.S. EPA, 1992, Technical Information Document for
Residential Wood Combustion Best Available Control Measures, Research
Triangle Park, NC, EPA-450/2-92-002.

Table 9.2 from the OMNI report summarizes measures for RWC BACM
developed by EPA in EPA-450/2-92-002.  As shown in Table 9.2, the BACM
fall into two primary categories:  (1) integral measures which are
necessary for the success of a long-term RWC pollutant reduction
programs but, by themselves, are not adequate to provide long-term
reductions and (2) flexible (long-term) measures to reduce, eliminate,
or prevent increases in pollutant emissions for existing and/or new
installations.  With the exceptions of the device and upgrade offsets,
the specific elements of the BACM are essentially those described in the
RACM document with the various efficiencies listed in Table 9.1 being
applicable.

Table 9.2  Summary of Measures Available for RWC BACM – PM10

Integral Measures1	Flexible Measures that Reduce or Eliminate

Emissions from

Existing Installations2	Flexible Measures that Reduce Emissions or

Prevent Emission

Increases from New

Installations2	Flexible Measures

that Reduce

Emissions from

New and Existing

Installations2

1. Public awareness and

education.	1. Conversion of existing wood-burning fireplaces to gas
logs. 	1. Gas fireplaces or gas logs in new wood burning fireplace
installations.	1. Device offset.4

2. Mandatory curtailment during predicted periods of high PM10
concentrations.	2. Changeover to EPA certified,

Phase II stoves or equivalent.	2. Upgrade offset.4	2. Upgrade offset. 4

3. All new stove installations EPA-certified, Phase II stoves or
equivalent.	3. Changeover to low emitting device.3	3. Restriction on
number and density of new wood-burning stove and/or fireplace
installations.

	4. Measures to improve wood burning performance:

-control of wood moisture content

-weatherization of homes with wood stoves -educational opacity program

4. Requirement that new stove installations be low emitting.

	1	Integral measures are regarded as critical for the success of a RWC
control program, but by themselves are not intended to result in
long-term attainment of the PM10 NAAQS for serious PM10 nonattainment
areas.

2	Flexible measures are designed for permanent control of RWC emissions
and thus long-term attainment of the PM10 NAAQS.

3	This measure is virtually identical to item 2, except that the
changeover is recommended to a “low-emitting” device that can
document “in-home” field test emissions less than the emission
factor averages of “in-home” field test emissions data for
EPA-certified stoves.  This can include classes of devices that are
demonstrated to be capable as a class of producing lower field
emissions, as well as, specific model units that perform better in the
field than the class collectively (an example might include masonry
heaters, uncertified pellet-fueled devices, and wood fired gasification
centralized heating systems).

4	Offsets are intended to achieve emission reductions, when retiring
(device offset) or changing-out (upgrade offset) conventional stoves,
greater than the emissions increase resulting from new stove
installations.

Table Reference:  U.S. EPA, 1992, Technical Information Document for
Residential Wood Combustion Best Available Control Measures, Research
Triangle Park, NC, EPA-450/2-92-002.

OMNI reported that the RWC RACM and BACM have been the basis for PM10
innovative strategies implemented in various western States and in local
jurisdictions and have also been, in-large part, the basis for a number
of western State and their local RWC regulations.  As part of these
strategies, strict particulate emission standards have been developed
which will take effect in 2008.

The OMNI report states that the Washington State standard is notable
among State and local regulations for residential wood burning devices.
Washington State has implemented more stringent standards for
residential wood burning devices, so devices installed in Washington
State must be certified to the more stringent standard.  This has
affected the stove market because many U.S. certified stove
manufacturers choose to have their appliances certified to the more
stringent Washington State standard, unless the manufacturer can not or
does not choose to test to the tighter standard.  Discussions with EPA
indicate that most manufacturers are choosing to design and sell units
that meet the Washington State standards of 4.5 g/hr for non catalytic
wood stoves and 2.5 g/hr for catalytic wood stoves (personal
communication with Mr. John Dupree of the U.S. EPA).

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR RESIDENTIAL
WOOD COMBUSTION

Cost of Compliance

OMNI analyzed the cost effectiveness of five categories of widely
existing, older technology wood-burning devices.  These are: (1)
freestanding cordwood stoves, (2) cordwood-fueled fireplace inserts, (3)
cordwood fireplaces (without inserts) used for heating purposes, (4)
centralized cordwood heating systems and (5) cordwood fireplaces used
for aesthetic purposes.  Table 9.3 lists these five categories with the
available, improved technology replacement, installation scenarios, and
fuel switching alternatives that would reduce particulate and VOC
emissions.

OMNI noted that wood resources are abundant and widely utilized as fuel,
and heating is essential due to the climate of the region.  The cost to
households of any regulatory program mandating acceptable heating
practices is an important consideration.  Likewise, the cost to
households of any voluntary program is paramount for its success.  The
cost effectiveness of all reasonable scenarios for the replacement,
modification or alternative fuel use for older existing, high emission
wood-burning appliances was provided in the OMNI report for regulators
and policy makers charged with the task of specifically lowering
particulate and VOC emissions from residential wood combustion.

The tables provided in this chapter based on the OMNI report allow for a
direct comparison of the cost burden for each realistic mitigation
option that would be shouldered by residential users.  As an example,
for an average resident in the MANE-VU region with an existing older
technology centralized cordwood heating system, the best current option
in terms of cost among the pellet, natural gas, and LPG options, is
natural gas (assuming natural gas is available).  Similarly, for
wood-burning fireplaces used for aesthetics, manufactured wax/fiber
firelogs offer the lowest cost per unit mass of air pollutant reduction.
 The cost effectiveness of each option is dependent on the costs of the
new equipment and the cost of required fuels.  The costs presented in
the tables in this chapter were the most current information available
as of the date of the OMNI report.

Estimates of costs per ton of reductions in the tables in this chapter
are specific to the MANE-VU region because they reflect the estimated
usage of various devices in this region.

Table 9.3  Improved Technologies and Fuel Alternatives

Existing Cordwood Device	High Technology Replacement, Installation or
Alternative Fuel

Uncertified Freestanding Cordwood

Stove	Replacement with Certified NSPS Non-Catalytic Cordwood Stove

	Replacement with Certified NSPS Catalytic Cordwood Stove

	Replacement with Pellet Stove

	Replacement with Gas Stove – natural gas (B vent, direct vent)