Market for Wet Calcium FGD to Remain At a High Level
The big push to retrofit flue gas desulfurization (FGD) systems on all the
coal-fired boilers in the U.S., Western Europe, Japan, Taiwan and Korea is now
over. The market in China has peaked but remains strong. Other countries in Asia
and Africa are now addressing their SO2 emission problems.
McIlvaine in its
FGD Market and Strategies
therefore, predicts:
·
A multibillion dollar annual market for new systems with the bulk being
purchased in Asia.
·
An equally large market to upgrade and replace systems in developed countries.
·
A continuing trend to rely on limestone gypsum wet scrubbing technology.
·
Some penetration from dry scrubbing approaches.
India has now committed to several wet limestone FGD systems.
Indonesia, Vietnam and other Asian countries are increasingly installing SO2
capture systems with new coal-fired boilers. China continues to build
power plants with FGD. It has also committed to upgrade more than 100
plants where the SO2 removal efficiency was low.
There are some potential technology developments which could expand the
investment in new coal-fired power plants but change the type of FGD chosen.
·
One development is the catalytic filter. When combined with direct sorbent
injection it allows NOx, particulate and SO2 to all be
captured in one device.
·
Another development is two-stage scrubbing in which HCl and flyash are captured
in a venturi scrubber and SO2 is captured in a second absorber.
The first-stage slurry is recycled and a 30 percent dirty hydrochloric acid
stream is bled to a rare earths processing plant. Both salable
hydrochloric acid and valuable rare earths are the resultant products.
For more information on
N027 FGD Market and Strategies,
click on:
http://home.mcilvainecompany.com/index.php/markets/2-uncategorised/107-n027
Operators Are Challenged To Keep Up With Latest Gas Turbine Combined Cycle
Technology
A number of new products, services and processes combined with changing
regulations are making it difficult to make the right decisions relative to the
purchase of new gas turbine and combined cycle components. Operation
and maintenance decisions are also being impacted by new options and new
demands. McIlvaine is offering an organized decisions program to ease the
effort and help operators make the best choices.
The basic decision is whether to start with a simple cycle or combined cycle
design. One option is to add the steam cycle later. In any case, the
fuel efficiency is low without the combined cycle operation. If the plant is
going to be situated at the site of an old coal-fired power plant, the owner
must decide whether to use the existing boiler feedwater treatment and
wastewater systems. There is even the possibility to use the existing
boiler for steam generation. Fuel selection is very important. Which will
be the primary fuel and will there be a liquid backup fuel which can be stored
on site? A recent additional option is LNG which can be delivered by what
is called the virtual pipeline (truck). China is planning massive use of
coal-derived gas.
The emission control approach differs greatly between simple and combined cycle
operations. In the simple cycle system, the selective catalytic system for
NOx reduction is subjected to high temperatures. Use of an
expensive high temperature catalyst is one option. An alternative is to
bleed in ambient air and operate at lower temperatures.
The method by which NH3 is delivered to the catalyst system differs.
Urea to ammonia processes eliminate safety hazards during transport.
Aqueous ammonia has low safety risks but is more expensive than anhydrous
ammonia.
Cooling options include wet, hybrid and dry cooling. There are cost
implications as well as environmental. The energy required for dry cooling
with air cooled condensers is high. Another concern is capacity in hot
weather. One the other hand, dry cooling is an answer to water scarcity or
difficulty in obtaining a water permit.
The water and wastewater issues can be avoided even with wet cooling. Many
plants are opting to use treated municipal wastewater. They can also
install Zero Liquid Discharge (ZLD) systems. Assuming that the treated
municipal wastewater would otherwise have been sent to a receiving stream, the
GTCC plant can claim to reduce area water pollution rather than increase it.
It is desirable to take a holistic view when selecting components. The
question of pulse jet cleanable intake filters vs. static filters should factor
in the valve system used to clean the pulsed filters. A better design pulse
cleaning system may be just as important as a better filter medium.
There are pump design considerations based on the fast cycling needs. The
drive decisions are also impacted. Pumps for once-through cooling can be
fitted with variable speed drives to make flow adjustments. One reason to adjust
flow is to minimize damage to aquatic life. There are substantial analyses of
this phenomenon.
Electric, hydraulic and pneumatic actuator each have advantages and
disadvantages. The best option varies with the service. There are a number
of innovations in HRSG design to adapt to the fast cycling needs. Just to keep
up with new developments with this technology is a challenge.
There are many operational challenges. Should you repair or replace
service valves? An alternative to buying the lowest first cost valve and
then replacing it frequently is to buy the best valve and repair rather than
replace it. Operational problems with rapid cycling GTCC systems include
Flow Accelerated Corrosion (FAC). Stellite delamination of valves is
another problem created by rapid cycling.
Rapid progress is being made with gas turbine combined cycle power plants. In
order to stay abreast, consider
Gas
Turbine and Combined Cycle Decisions.
$500 Million per Year for Gas Turbine Air Filters
By 2020 gas turbine operators will spend more than $500 million/yr. for new and
replacement air intake filters. This is the latest forecast in the
N022 Air Filtration and Purification World Market
published by the McIlvaine Company. (www.mcilvainecompany.com)
The high rate of revenue growth is due to the following factors:
1.
Gas turbine capacity is growing rapidly due to the low capital cost of this form
of power generation coupled with the low price of the fuel.
2.
The revenue stream per turbine is increasing due to the realization that more
expensive and more efficient filters pay for themselves due to decreased turbine
maintenance and increased turbine output.
The high efficiency filters which are replacing the medium efficiency filters
are several times the price. The filter life is slightly less.
Nevertheless, turbine operators find that turbine blades do not quickly build up
a thin varnish layer of fine particles. This deposition requires shutdowns
and expensive washing cycles. The turbine operating with a varnish layer
does not deliver the same electrical capacity as a clean turbine.
Filter suppliers are being challenged to make further improvements including:
1.
Filter media which can deal with high moisture levels.
2.
Filters which can deal with the corrosive environments found on floating
platforms and seashore installations.
3.
Filters which can perform with relatively low pressure loss when encountering:
a.
The high dust loads found in desert conditions
b.
Snow and ice conditions found in the artic
c.
Oily contaminants found in industrial areas
Many new media and filter designs have recently been introduced to address all
these problems. Some of the solutions involve multiple stages.
For more information on
N022 Air Filtration and Purification World Market,
click on:
http://home.mcilvainecompany.com/index.php/markets/2-uncategorised/108-n022
“SO3 Removal Options” is the “Hot Topic Hour” on June 18,
2015 at 10:00 a.m. CST
This session will build on
SO3
Decisions Guide.
Panelists will summarize the options available and reference documents in the:
44I Power
Plant Air Quality Decisions
(Power Plant Decisions Orchard)
Additions to this website are encouraged in advance. Participants are encouraged
to review this site prior to the meeting.
Participants in Discussion on SO3 Removal
Options June 18, 2015
Sheila Glesmann,
Senior Vice President, Environmental and External Affairs, ADA-CS
Will send slides, cannot attend
Steve Jassund,
A. H. Lundberg Associates
Mark Wajer,
VP Business Development & Technology, Martin Marietta Magnesia Specialties LLC
Curt Biehn,
Manager of Technical Sales & Marketing, Mississippi Lime Company
Josh Allen,
Applications Engineer, NatronX
Dianne Novak,
Sr. Specialist/ Marketing, Nol-Tec Systems
Here
is an overview of the issues and options:
SO3 Decisions Overview
Coal-fired power plants are making major decisions relative to reduction of SO3.
This overview is designed to help these plants focus on the issues and options
which need to be addressed in order to arrive at the best
decision. This overview leads into a Decision Guide which in turn is part
of the complete Decision Program
44I Power
Plant Air Quality Decisions (Power
Plant Decisions Orchard).
China is among the countries finding that solution of their NOx and
SO2 problems create sulfuric acid mist. The environmental
impact is serious and has created an urgency for solution. Companies with
the solution have a big opportunity to expand their worldwide reach.
Plants which install NOx control systems and scrubbers are creating
sulfuric acid mist. The mist plumes are often more visible than the
exhaust before the major air pollution control investments. Furthermore,
the nearby structures can be quickly damaged by condensing acid mist.
This problem creates a major opportunity for a number of companies who found
solutions to the acid mist problem when it arose in the U.S. Suppliers of
processes, sorbents, catalysts, filters and heat exchangers have experience
which is now applicable around the world.
This acid mist problem affects the design of all the other air pollution control
equipment. So the solution knowledge empowers the international suppliers.
In pursuit of the solution, suppliers have discovered ways to make the entire
plant more efficient, so this knowledge is even more valuable.
The first knowledge need involves regulatory implications. SO2
in the flue gas is converted to SO3 in the catalytic reactor used for
NOx reduction. The stack gas is cooled in the scrubber and the
SO3 leaving the stack is mostly condensed sulfuric acid mist.
It is small in total mass but very visible and also destructive to nearby
buildings. The mist is often treated as particulate by regulators.
Since limits on particulate are an order of magnitude lower than on SO2,
the regulatory impact is very significant. There are many unresolved
issues on measurement and limits on the mist.
The solutions to the SO3 problem are different for each of three air
pollution control processes: Wet Calcium, Dry Scrubber and Hot Gas Filter.
Flow Sequence |
Wet Calcium |
Dry Scrubber |
Hot Gas Filter |
Fuel |
High sulfur |
Medium/low |
Medium/low |
Combustion |
LNB, FGR, SNCR, Br |
LNB, FGR, SNCR, Br |
LNB, FGR, SNCR, Br
but also CaCO3 |
After Economizer |
SCR with catalyst to deal with
SO3, NOx
and Mercury |
ACI, SCR with catalyst to deal
with SO3, NOx
and mercury |
Ceramic catalytic filter with
DSI |
Air Pre Heater |
Sorbent injection for SO3
and acid gas trim |
Sorbent injection for SO3
and acid gas trim |
Extract all heat and reduce exit
to 200oF |
Particulate |
ESP or FF |
Dry scrubber/FF |
Already captured |
SO2 |
Wet calcium FGD |
Captured with particulate |
Already captured |
Trim |
Wet ESP |
Not available |
Mercury module |
LNB= low NOx burner, FGR= flue gas recirculation, Br= bromine
addition with fuel. SNCR= selective non-catalytic reduction, CaCO3 =
pulverized limestone addition in furnace, ACI= activated carbon injection, SCR=
selective catalytic reduction, DSI= dry sorbent injection, HE= heat exchanger,
ESP= electrostatic precipitator, FF = fabric filter, FGD= flue gas
desulfurization.
Prior to pursuing the solution, the decision maker needs to carefully review all
the regulatory as aspects of the SO3. These include:
·
Opacity: Sulfuric acid mist is a blue plume which is visible at just 10
ppm.
·
Does the regulation specify limits on total particulate including condensibles
or just discrete particulate?
·
Total particulate. SO3 can easily add 0.03 lbs./MMBtu to the
total particulate emissions.
·
Local ambient air regulations including startup, shutdown and special situations
in pristine areas or cities.
Fuel:
Once the reduction target is determined, then a decision program can commence.
Fuel is the first factor in the decision program. A fraction of the sulfur
in the fuel is converted to SO3. Therefore, the problem is
directly proportional to the sulfur content of the fuel. Since the price
of fuel is directly disproportionate to the sulfur content, the decision maker
must weigh the fuel price against the investment cost of the selected system.
There are in effect many decision trees affecting the ultimate decision.
It is necessary to keep retracing steps from one decision tree to another.
Combustion:
Since the creation of SO3 and NOx are a result of
combustion, there are many decisions to be made relative to burners, flue gas
recirculation and additives in the boiler. The hot gas filter option actually
starts with capture of SO3 with powdered limestone in the furnace.
Boiler additives can be selected to minimize boiler fouling, oxidize mercury and
for other purposes. The SNCR approach involves urea or ammonia injection
into the furnace to either eliminate the downstream SCR or to supplement it.
The reduction accomplished by means other than catalytic reaction reduces SO3
formation.
After the economizer.
The optimum temperature for catalytic reduction is 850oF.
Therefore, the SCR is generally located downstream of the economizer but prior
to the air heater. The catalyst reduces NOx but oxidizes SO2
to SO3. Catalyst manufacturers have developed products which
minimize SO3 formation while maximizing NOx reduction and
mercury oxidation. The performance on each of the three pollutants plus cost and
maintenance issues all serve to make the decision complicated.
If mercury is to be removed with ACI, a decision needs to be made whether to
inject it ahead of the SCR or downstream. Most particulate filters are
only capable of withstanding temperatures below 400oF.
Therefore, they are located after the air pre heater. The catalytic filter
is able to withstand 850oF and can be located prior to the air pre
heater.
The catalytic filter with DSI or powdered limestone injection achieves high
efficiency removal of particulate, NOx and acid gases. There is
less experience with this technology than the other two alternatives.
Otherwise it has considerable advantage from the standpoint of cost and space
requirements. There are a number of large companies entering this space.
So the options are continuously changing.
The catalytic filter with DSI also removes the SO3. The exit
gas is clean. As a result, efficient heat exchangers can be utilized and
boiler efficiency substantially increased.
Air Preheater:
Plugging and corrosion in the air preheater are accelerated with the higher
levels of SO3 created in the SCR. One remedy is the injection
of sorbents ahead of the air preheater. Unlike DSI, only a modest amount
of sorbent is needed to reduce the acid dew point. Benefits include reduced
maintenance and corrosion as well as the ability to extract more heat in
the heat exchanger.
The air preheater capability is limited by the acid dew point. The
injection of sorbents captures the SO3 and enough of other acid gases
to lower this dew point. Greater heat extraction can increase boiler
efficiency by more than one percent. Proponents of this approach recommend
it for most boilers and not just ones with SO3 problems.
Particulate:
A fabric filter or electrostatic precipitator generally follows the air
preheater. Most plants use dry precipitators which do not remove the acid
mist. The mist problem was first solved in the U.S. by adding wet electrostatic
precipitators downstream of the scrubber. China has chosen WESPs for many of its
problem installations. This is an effective but costly solution. It cannot
be justified just on its ability to remove SO3. However, there
are arguments for its inclusion for other reasons.
One inexpensive approach is to use a wet calcium scrubber for both initial
particulate capture and SO2 absorption. A downstream wet
precipitator is then used for trim. The disadvantage is that flyash and
gypsum are mixed.
There is debate about the locations for dry sorbent injection. One option is to
inject it just prior to the precipitator. Another option is to inject it
prior to the scrubber. The purpose is to remove SO3 but an
additional advantage is that the sorbent is then fully utilized in the scrubber.
The air toxics rule for power plants in the U.S. originally set limits for total
particulate including condensibles. With this definition the sulfuric acid
mist became the most challenging pollutant for reduction. Just 10 ppm of mist
was enough to cause particulate exceedances. Due to intensive opposition,
the rule was changed just prior to promulgation and limits only discrete
particulate.
Total particulate continues to be the measurement criterion for some state and
local regulations and is the basis for measuring ambient air quality.
States are presently tasked with reducing the ambient levels of fine
particulate. Therefore the contribution of SO3 has to be taken
into account.
Most fine particulate is a reaction between acid gases and base compounds such
as ammonia, sodium or calcium. Sulfuric acid mist is a toxic pollutant
whereas SO2 is not. Nearby the exhaust stack the distinction is
important. However, relative to long term ambient air quality the sulfur
from either compound becomes a particulate sulfate.
The decision maker needs to consider which regulations over the long term will
govern his equipment selection. A more stringent regulation which is
likely a few years from now has to be given weight in the analysis.
SO2:
Wet calcium FGD systems are very efficient in removing SO2 but not in
removing acid mist. In fact by cooling the gas they cause acid mist to fall
closer to the exhaust stack. Dry scrubbers are less efficient SO2
removal devices but do remove acid mist. The catalytic filter removes both.
Wet calcium FGD systems are the most popular choice because they use an
inexpensive sorbent (limestone) and create a salable byproduct (gypsum).
The other two options do not create gypsum. In China there are bricks and other
construction materials created from the flyash/gypsum mix.
DSI injection ahead of the wet calcium FGD provides SO3 removal and
additional sorbent for SO2 capture.
If the product is going to be sent to a landfill, it can be chemically fixed
with lime addition. This is desirable to prevent leaching of toxic
compounds. The salability of flyash and gypsum are two inputs in the analytic
process. Landfill requirements and cost are another.
Trim:
A wet electrostatic precipitator located in the top of the scrubber or as a
standalone device will provide very high acid mist removal and also efficient
removal of discrete particles. The precipitator market leaders are Chinese
companies. Tough new particulate limits require change or replacement of
the existing dry precipitators. So the addition of wet precipitators to
solve the SO3 problem and capture discrete particulate has been a
popular solution.
Materials of construction for the WESP are a major cost factor. The price of
nickel has fluctuated greatly. The attractiveness of the WESP approach is in
part dependent on nickel pricing.
If the catalytic filter route is chosen, then there may be a need for trim with
a mercury module. This is an expendable absorbent which may have a life of
several years. It can be placed after the heat exchanger and before the stack.
Alternatively, the catalytic filter can be operated at 600oF rather
than 850oF and activated carbon added along with the DSI. The
analysis must weigh the initial and operating cost of the two approaches.
Site Specific Issues:
The physical layout of an existing plant is likely to be a cost factor in the
analysis. If a catalytic filter can be installed with little change in
ductwork while an SCR and dry scrubber fabric filter will require long duct runs
and major demolition, then the catalytic filter will be economically attractive.
If the area has water problems, the dry scrubber/baghouse or catalytic filter
will have advantages over the wet calcium approach. The expected remaining
life of the plant is another major consideration. Sale of byproducts and cost of
landfill are two additional site specific factors.
Decisions relative to SO3 reduction involve many different general
and site specific factors. The catalytic filter option is being more
clearly defined each day. Opportunities for improving boiler efficiency while
removing SO3 should be widely considered. The McIlvaine
Decision Guide to SO3 reduction and Power Plant Air Quality Decisions
Program will, therefore, be of continuing value.
Renewable Energy Briefs
Hawaii Enacts Nation’s First 100 Percent Renewable Energy Requirement
Hawaii has enacted a law that requires all of the state's electricity to be
produced from renewable energy sources no later than 2045. The new policy, Act
97, makes Hawaii the first state in the nation to adopt a 100 percent renewable
requirement, further solidifying Hawaii's role as a global clean energy leader.
Many believe that Hawaii can achieve 100 percent renewable electricity in a
shorter timeframe than the law requires. Hawaii's renewable energy use has
doubled in the past five years, with the islands currently generating about 22
percent of their electricity from wind, solar, geothermal, and other renewable
energy resources.
The new law also increases an interim requirement, targeting at least 30 percent
renewable electricity by 2020. Failure to achieve the new standards could cost
Hawaii utilities two cents for each kilowatt hour of excess fossil fuel
electricity.
First Cross-Border Renewable Energy Facility Begins Commercial Operation
InterGen and IEnova announced that the Energía Sierra Juárez wind project began
commercial operations in Tecate, Baja California, Mexico. InterGen has a 50
percent interest in the project with Infraestructura Energética Nova, S.A.B. de
C.V. “IEnova.” Energía Sierra Juárez is the first cross-border wind generation
project between Mexico and the U.S.
Energía Sierra Juárez is an approximately U.S.$300 million, 155 megawatt (MW)
wind generation project consisting of 47 Vestas turbines of 3.3 MW each. The
turbines are situated along Baja California´s Sierra de Juarez mountain range,
one of the strongest wind resources on the west coast of North America.
Through a 20-year power purchase agreement with San Diego Gas & Electric
(SDG&E), the project will interconnect with SDG&E’s Southwest Powerlink
transmission system east of San Diego via a new cross-border transmission line.
The project could also potentially connect to the Mexican power grid.
Centauri Energy, LLC Receives Approval on CAISO Application for 300 MW Solar
Project in California’s Central Valley
Centauri Energy, LLC announced receiving approval from the California
Independent System Operation (CAISO) to secure a queue position for Beltran
Solar, the company’s 300-Megawatt (MW) solar project in Stanislaus County, CA.
The queue position will allow Beltran Solar to connect to the state’s power
grid.
At 300 MW, Beltran Solar represents one of the largest solar projects under way
in California. It spans approximately 1,600 acres near Interstate 5, and is
located approximately an hour southeast of the Bay Area. Beltran Solar will be
built in three phases, with the first phase slated to deliver power in 2016 and
2017.
Waneta 335 MW Hydro Expansion Project is Now Generating Clean, Renewable and
Cost Effective Power
The Waneta Expansion Limited Partnership (WELP), between Fortis Inc., Columbia
Power Corporation and Columbia Basin Trust, has connected the Waneta Expansion
Project near Trail, British Columbia to the electrical grid. The plant is
located on the border between Canada and the U.S. and is now generating power on
the BC Hydro grid.
The 335 MW expansion adds a second powerhouse, immediately downstream of the
Waneta Dam on the Pend-d'Oreille River, which shares the existing hydraulic head
and generates clean, renewable, cost effective power from water that would
otherwise be spilled. The project also included construction of a 10 km, 230 kV
transmission line and provides enough energy to power about 60,000 Canadian
homes per year.
At the time of substantial completion, the project was the eighth largest hydro
electrical infrastructure project in British Columbia. The Waneta Expansion
Project was completed six weeks ahead of schedule. Two parallel tunnels are
feeding the two Francis turbine units, each supplying 167.5 MW. In addition to
the turbines, Voith Hydro supplied the generators, governors, exciters and
various additional auxiliary systems of the plant's equipment. Voith Hydro is a
subcontractor to SNC Lavalin Inc. acting as the prime contractor on the project.
The owner WELP announced that the project employed over 1,400 people overall in
the five years of design, manufacturing, construction and commissioning. Voith
Hydro started working on the project in October 2010.
Cape Tidal Awards another Major Contract to Nova Scotia Company
A third Nova Scotian company has secured a multi-million dollar contract with
the Cape Sharp Tidal project, which has potential to be the first grid-connected
tidal array in the world.
Hawboldt Industries of Chester, Nova Scotia has been awarded a $4.7-million
contract for the design and manufacturing of three heavy lift winches to be used
on the OpenHydro deployment and recovery barge. Cape Sharp Tidal is a
partnership between OpenHydro – a DCNS company – and Emera Inc. to develop a
tidal industry in Nova Scotia.
In its first phase, Cape Sharp Tidal will deploy two, 2 MW, grid-connected
turbines off Parrsboro, NS later this year. The project aims to progress in
phases toward a 300 MW, commercial scale industry in the 2020’s.
For more information on Renewable Energy Projects and Update
please visit
http://www.mcilvainecompany.com/brochures/Renewable_Energy_Projects_Brochure/renewable_energy_projects_brochure.htm
Headlines for Utility E-Alert – June 12, 2015
UTILITY E-ALERT
#1227– June 12, 2015
Table of Contents
COAL – US
·
NC issues Permits for Coal Ash Landfills in Chatham, Lee Counties
COAL – WORLD
·
Signing of Supply Contract for CFB Boiler for Coal-fired Power Plant Facilities
to Tanjung Power Indonesia
·
Orascom and Siemens plan Two Coal-fired Power Plants
·
Emerson to automate New NTPC Limited Power Plant for Power Station in Odisha,
India
GAS/OIL – US
GAS/OIL – WORLD
·
Reliance Power to set up a 3 GW LNG powered Combined Cycle Energy Project in
Bangladesh
·
Azito Energie to boost Ivory Coast
Gas-fired Power Plant Capacity by 139 MW
·
GE awarded Agreement for Combined Cycle Power Plant in Russia
·
Taoiseach (Prime Minister) Enda Kenny (Ireland) to open Great Island Combined
Cycle Power Plant
BIOMASS
NUCLEAR
BUSINESS
INDUSTRIAL VALVE SUMMIT - ITALY
HOT TOPIC HOUR
·
“SO3 Removal Options” is the Hot Topic Hour on June 18, 2015 at 10
a.m. CDT
·
Upcoming Hot Topic Hours
For more information on the Utility Tracking System, click on:
http://home.mcilvainecompany.com/index.php/databases/2-uncategorised/89-42ei
McIlvaine Hot Topic Hour Registration
On Thursdays at 10:00 a.m. Central time, McIlvaine hosts a 90 minute web meeting
on important energy and pollution control subjects. These Webinars are
free of charge to owner/operators of the plants. They are also free
to McIlvaine Subscribers of Power Plant Air Quality Decisions and Utility
Tracking System. The cost for others is
$300.00 per webinar.
See below for information on upcoming Hot Topic Hours. We welcome your
input relative to suggested additions.
DATE |
SUBJECT |
DESCRIPTION |
June 18, 2015 |
SO3 Removal Options |
|
July 2, 2015 |
Hot Gas Filtration |
|
July 23, 2015 |
Mercury Removal Options |
Click here
for the
Subscriber
and Power Plant or Cement Plant
Owner/Operator
Registration Form
Click here
for the
Non-Subscribers
Registration Form
----------
You can register for our free McIlvaine Newsletters at:
http://home.mcilvainecompany.com/index.php?option=com_rsform&formId=5
Bob McIlvaine
President
847-784-0012 ext 112
rmcilvaine@mcilvainecompany.com
www.mcilvainecompany.com