White Paper
Evaluating Options for Post CO2 Removal of Flue Gas Streams;
Single or Two Stages of FGD Scrubbing
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FLUE GAS TREATMENT
Paper presented in the poster session (paper #22) of
EPRI-DOE-EPA-AWMA Combined Power Plant Air Pollutant Control Mega Symposium 2010;
Baltimore, MD – USA
Kevin Smith, Carl Laird & Julia Mercer
Carmeuse Lime & Stone, 3600 Neville Road, Pittsburgh, PA 15225, USA
Abstract
Earlier comparative studies were conducted assessing how current wet FGD
technologies might be designed to achieve SO2 emissions of 10-ppmv (~203
mg/Nm ) or less to accommodate downstream CO2 scrubber processes to
operate efficiently. These studies took the approach of either modifying existing
or designing new scrubbing systems to achieve SO2 removal efficiency in a
single stage of scrubbing. While this approach may be possible when
designing new scrubbing systems from the ground up; it may not be practically
or economically feasible to retrofit some existing scrubber units to have this
ability. This paper discusses when and how a secondary or polishing scrubbing
unit might be considered to achieve extremely low emissions of SO2 and other
acid gases in flue gas. Also to be discussed are reagent options available to be
used in the polishing step and how polishing steps can be integrated into the
existing FGD process.
Introduction
Although climate change legislation seems to have slowed, it is likely the U.S.
EPA will proceed to issue its own regulations that will attempt to limit CO2
emissions. U.S. power producers are awaiting the nature of regulations to
abide by before making very difficult decisions concerning carbon capture,
among the most difficult is determining what to do about reducing CO2
emissions from existing scrubbed coal fired power plants. The U.S. DOE is
sponsoring a research program intended specifically for existing coal-fired
power plants to develop advanced CO2 capture technologies, among them
post combustion CO2 capture technologies using solvents, sorbents and
membranes. This program recognizes that trace impurities (including acid
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gases) adversely affect all CO2 scrubbing processes. Many references
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Evaluating options for post CO2 removal of Flue Gas Streams
mention that the required SO2 concentration in flue gas to be treated by the
MEA process is 10-ppmv or less. An obvious way for a power plant already
employing a FGD process to achieve such low SO2 concentration in flue gas
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is to employ a second polishing scrubbing system. While a polishing
scrubber step is often mentioned as a way to accomplish such low SO2
concentration, other options exist for consideration and are explored in this
paper. Only technical aspects of each option studied are considered. An
evaluation of the economic consequences of all options is outside the scope
of this paper.
RELATIONSHIP OF SO2 REMOVAL EFFICIENCY & NTU
To discuss the scrubber design and operation relationship to percent SO2
removal efficiency, it is necessary to first convert percent to Number of
Transfer Units (NTU). NTU is a useful means of expressing SO2 removal
efficiency as it easily correlates to mass transfer required for a scrubber to
achieve a desired level of emissions.
Equation 1. NTU is calculated from percent removal using the equation:
NTU = −ln(1−SO2%/100)
where:
NTU = number of transfer units
SO2% = percentage SO2 removal efficiency
An incremental increase of 1 NTU represents a stage or unit of equal “effort”
to provide mass transfer of a constant amount. 2 NTU represents two equal
stages or equal amounts of “effort” yet does not result in twice the mass
transfer of 1 NTU. As NTU increases, increases in SO2 removal efficiency
diminishes as shown in Table 1. Therefore increasing SO2 removal efficiency
from 95% to 99.3% (a 4.3 percentage point increase) requires double the
effort of raising SO2 removal from 86.5% to 95% (an increase of 8.5
percentage points).
Table 1. Relationship of %SO2 removal to NTU
Since mass transfer correlates to NTU, it is useful to define the
constituents/parameters in which mass transfer occurs. For wet scrubbers,
the mechanical work required to push flue gas through a medium where
sufficient mass transfer exists to achieve a desired SO2 removal efficiency is
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Evaluating options for post CO2 removal of Flue Gas Streams
composed of the energy to operate recycle pumps and induced draft fans.
The mass transfer medium is usually a combination of liquid droplets from
spray headers, sieve trays or other flue gas flow straightening devices. Mass
transfer can also be aided by using alkalinity enhancing chemicals such as
Mg(OH)2 or dibasic acid (DBA). NTU is used consistently throughout the rest
of this paper to describe SO2 removal performance as a function of liquid and
gas contacting (also referred to as L/G or flue gas ∆P), flue gas
redistribution, liquid alkalinity or reagent reactivity.
“EQUIVALENT” L/G OR ∆P
The concept of “equivalent L/G” for spray towers and “equivalent ∆P” was
established for magnesium-enhanced lime (MEL), limestone forced oxidation
(LSFO), jet bubbling reactor (JBR) limestone and high calcium lime wet FGD
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by the authors in previous papers but inspired by a Babcock & Wilcox
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discussion of the concept. Mechanical modifications to spray towers such as
perforated plates, baffles (wall rings) and dual direction spray nozzles are
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each assigned an equivalent L/G value of 25 to 30 gal/1000-ft (3.34 to 43
l/m ) because each enhances liquid and gas contact.
Equation 2. Each modification’s equivalent L/G is added to actual L/G
calculated from liquid recirculation rate and flue gas flow rates and then
plotted against published design SO2 removal efficiencies of the most
recently installed scrubbers of each reagent type in the following way.
L/Gequivalent = L/G + L/Gtray + L/Gbaffles + L/Gnozzles + L/Gadditive + L/Greagent + L/Gfuel
where:
L/G = actual or equivalent liquid to gas ratio
L/Gtray = equivalent L/G attributable to a tray; 25 to 30-gallons/1000 actual
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ft (3.34 to 4.1 l/m )
L/Gbaffles = equivalent L/G attributable to a baffles; similar values as with a
tray
L/Gnozzles = equivalent L/G attributable to a dual flow nozzles; similar values
as with a tray
L/Gadditive = equivalent L/G attributable to organic acid; 97-gallons/1000
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actual ft (13-l/m )
L/Greagent = equivalent L/G attributable to switch in reagent i.e. lime; 753
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gallons/1000 actual ft (10.2-l/m )
L/Gfuel = equivalent L/G attributable to fuel blending to reduce SO2
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generated; 4-gallons/1000 actual ft (0.54-l/m )
For spray towers Figure 1 plots SO2 removal efficiency as NTU vs.
“Equivalent L/G” for MEL, high calcium lime and LSFO wet FGD.
A least squares trend line is extended to at least 6.2 NTU through each set of
data points to estimate the required Equivalent L/G or Equivalent ∆P to
achieve 10-ppmv SO2 emission or less in scrubbed flue gas by each
scrubber type. From this analysis it was determined for MEL, high calcium
lime and LSFO spray towers that equivalent L/G required to achieve 6.2 NTU
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was 10 (75), 29 (217) and 39.2 (292) - l/m (gallon/kacf) respectively.
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Evaluating options for post CO2 removal of Flue Gas Streams
Equation 3. Similarly for JBR limestone scrubbers, if data becomes available
to analyze in a similar way the following equation might be formed.
∆PEquivalent = ∆P + ∆Padditive + ∆Preagent + ∆Pfuel
where:
∆P = actual or equivalent pressure drop
∆Padditive = equivalent ∆P attributable to additive use
∆Preagent = equivalent ∆P attributable to switching to a more reactive
reagent, i.e. lime
∆Pfuel = equivalent ∆P attributable to fuel blending to reduce SO2 generated
Since no known published data on the use of organic acid additives or for
reagents other than limestone; a plot similar to Figure 1 is not yet possible to
create for the JBR scrubber system.
Options to improve SO2 removal performance
of existing plants
For operators of existing FGD plants, options exist to boost SO2 removal
efficiency to the level required by CCS processes but the extent of
modification depends on the starting point – the existing absorber design.
These options include mechanically modifying existing scrubbers to the
extent possible, switching to lower sulfur fuels or blending low with high sulfur
coals, boosting alkalinity of scrubbing liquor by blending reagents or a
combination of these individual options.
REDUCING THE AMOUNT OF SO2 TO SCRUB
Many eastern U.S. utilities are taking advantage of less expensive Powder
River Basin (PRB) coal to blend with their normal high sulfur eastern coal that
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Evaluating options for post CO2 removal of Flue Gas Streams
is typically burned. Table 2 shows typical coal prices as of June 2010 and
shows the attractiveness PRB coal has in terms of price per unit energy.
Table 2. Cost Price as of June 7, 2010
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Not only is PRB coal less expensive to burn but there is less sulfur to scrub
which reduces FGD operating costs. Blending PRB coal with an eastern
bituminous coal could also be a partial strategy to help existing FGD
processes achieve lower SO2 emissions. Figure 2 illustrates this point. Two
curves indicate required SO2 removal efficiency to achieve 10-ppmv (dry
basis) over varying proportions of PRB coal blended with either a Pittsburgh
Seam Coal or a Central Appalachian coal. The individual points on each line
from right to left represent 0, 5, 10 and 15% PRB coal making up the blend of
fuel fed to a boiler.
Typically PRB coal is blended up to 15% of total fuel feed to a boiler. 15%
PRB blend on the 4.17% sulfur (red) curve shows required SO2 removal
efficiency in NTU is reduced to 5.64 (99.64 %) from 5.72 (99.67 %). Although
this reduction or “saving” of NTU appears small at about 0.08 in the 4.17%
sulfur case, it is significant when put into tangible terms. Table 3 lists the
amount of reduction in L/G and volumetric flowrate of recycle flow for spray
towers and reduced pressure drop and ID fan power for JBR scrubbers
possible while still achieving 10-ppmv SO2 or less emissions. The source of
the calculations used to derive the values in Table 3 is referenced in each
column heading.
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Evaluating options for post CO2 removal of Flue Gas Streams
Table 3. Impact of fuel blending on FGD to achieve CCS compliant SO2 concentration
in Flue Gas
EFFECT OF REAGENT TYPE ON FGD PERFORMANCE
It is apparent from Figure 1 that an equivalent L/G can be assigned to
reagents when comparing one to another. For instance the lime and LSFO
trend lines are parallel to each other and indicate that if lime were to
completely replace limestone in a LSFO designed scrubber, it would have an
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equivalent L/G of 75 gallon/kacf or 10.2 l/m for any particular design SO2
removal efficiency.
If oxidation were to be moved outside of the scrubber, then the following
analysis could similarly be made between MEL and LSFO scrubbers. The
MEL trend line in Figure 1 has a greater slope than the LSFO trend line
resulting in a equivalent L/G significantly smaller as compared to high
calcium lime or LSFO for the same NTU. From Figure 1 at SO2 removal
efficiency of 6.2 NTU (99.8%), MEL reagent has an equivalent L/G of about
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75 gallon/kacf or 10.2 l/m but at 3 NTU (95%) MEL equivalent L/G reduces
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to 56.1 gallon/kacf or 7.5 l/m . Interestingly, MEL and Lime FGD have the
similar equivalent L/G at 3 NTU or 95% SO2 removal efficiency, but rapidly
diverge from each other as SO2 removal efficiency increases.
Figure 3 plots SO2 removal as NTU vs.
“Equivalent ∆P” for the JBR operated at
Southern Company’s Plant Yates. As
illustrated in Figure 3, the required
equivalent ∆P to achieve 6.2 NTU SO2
removal efficiency was 92 mbar or about
37-inches WC. Since JBR SO2 scrubbers
have only been designed and operated
using limestone for the reagent, it is
speculation to estimate the possible
benefit of substituting lime. If one
assumes that substituting lime for
limestone in JBR would have a similar
benefit as it might for LSFO, a way to
equate equivalent L/G to equivalent ∆P is
necessary.
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Evaluating options for post CO2 removal of Flue Gas Streams
ADDITIVES TO INCREASE SCRUBBING LIQUOR ALKALINITY
Additives have long been shown to enhance SO2 removal performance of
limestone scrubbers, particularly organic acids but also high calcium lime.
Therefore the concept of equivalent L/G and ∆P should be applicable to
additives. DBA is actually a variable blend of adipic, succinic and glutaric
acids commonly used in older limestone forced oxidation (LSFO) scrubbing
systems to boost SO2 removal efficiency. Adipic acid was studied extensively
by Wang and Burbank of Bechtel Group in the 1970’s and found to be quite
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effective.
Adipic acid was tested as an additive in a variety of limestone and lime
scrubbing processes but the one application that showed most promise was
in LSFO. Figure 4, taken from Wang and Burbank illustrates the ability of
adipic acid to enhance SO2 removal performance of an LSFO scrubber. With
the scrubber operated at three different pH levels and constant L/G of 85gal/kacf, SO2 removal was plotted at various concentrations of adipic acid
ranging from 0 to 2400 mg/l. At pH of 5.0, SO2 removal performance was
increased from 67.6% (1.124 NTU) to 97.5% (3.69 NTU) by increasing adipic
acid concentration from 0 to 1900 mg/l.
Using the LSFO plot in Figure 2 it is estimated that adipic acid at 1900 mg/l
has an equivalent L/G of 13 l/m3 or 97-gal/kacf. Applying this same SO2
removal efficiency improvement to the JBR reveals that 1900 mg/l adipic acid
potentially has an equivalent ∆P of 42 mbar or almost 17-inches WC.
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Evaluating options for post CO2 removal of Flue Gas Streams
DBA, which has adipic acid as a major constituent, was reported “The most
promising HCLA (High Calcium Lime with Additives) process tested…” for
boosting performance of the 4-MWe pilot forced oxidized lime scrubber at the
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Electric Power Research Institute (EPRI) High Sulfur Test Center (HSTC).
Unfortunately no test data could be located to quantify the benefit, but it is
not unreasonable to expect it to be similar to what was previously quantified
for LSFO.
POLISHING WET SCRUBBER USING A COMPATIBLE SECOND REAGENT
A brute force method of reducing SO2 emissions to an absolute minimum is
to install a polishing scrubber downstream in the flue gas path of an existing
scrubber regardless of type. Although this approach is likely the most capital
and energy intensive alternative with the highest operating costs, it may be in
certain situations the only viable course for certain power plants with existing
FGD units. Ideally the type of
scrubber and the reagent used
could be integrated into the
existing FGD process not only in
a way that creates few additional
operational issues but may
complement existing operations.
One possible combination for a
polishing scrubber could be a
simple
spray
tower
using
commercially available Mg(OH)2
as the reagent. One such
configuration where the polishing
scrubber is integrated into an
existing LSFO process is pictured
in Figure 5.
The chemistry and removal performance would simulate the MEL scrubber
but would have little or no solids recirculating. The purge stream would
contain soluble magnesium sulfite and magnesium sulfate salts that could be
purged to the LSFO reaction tank where it would be oxidized to MgSO4. The
primary scrubber purge stream would continue to gypsum dewatering and
process water recovery as is typical for LSFO processes. If byproduct
gypsum is to meet wallboard specifications, extra washing with fresh water
during filtration may be necessary. Recovery of magnesium from the FGD
wastewater purge stream may be necessary before processing by traditional
FGD wastewater systems. This is accomplished by reacting with hydrated
lime in an agitated tank followed by a two step process of separating
byproduct Mg(OH)2 from precipitated gypsum with a hydroclone and
concentrating byproduct Mg(OH)2 with a membrane filtration device.
Concentrated byproduct Mg(OH)2 could supplement reagent Mg(OH)2 to the
polishing scrubber, be injected into the boiler for slag control or injected into
the flue gas upstream of the air preheater for opacity control.
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Evaluating options for post CO2 removal of Flue Gas Streams
Table 4. Comparison of existing LSFO and Polishing scrubber to High Performance
LSFO scrubber
Table 4 compares the combination of an LSFO scrubber designed for 97%
SO2 removal (3.5 NTU) and a polishing scrubber designed using Mg(OH)2 to
take flue gas from the primary scrubber and remove an additional 84.4 %
SO2 (1.9 NTU) for a combined SO2 removal efficiency of 99.5 (5.36 NTU); to
a single LSFO scrubber designed to achieve the same overall SO2 removal
efficiency in a single unit. The dimensions of the higher SO2 removal
scrubber are such that the original scrubber could be modified after a
suitable outage, the resulting energy consumed to operate both the primary
and polishing scrubbers is estimated to be less by around 2000 kW-hr.
COMPARING OPTIONS
Table 5 takes a hypothetical case of a single LSFO spray tower configured to
achieve 97% SO2 removal efficiency (3.51 NTU) and compares the result of
implementing each of the options discussed that result with SO2 emissions of
10-ppmv or less. In order from left to right respectively are:
• Original LSFO scrubber design,
• Addition of a Mg(OH)2 polishing scrubber that when combined with the
original absorberdesign achieves a combined SO2 removal of 99.53% (5.36
NTU),
• Switching reagent to high calcium lime but otherwise operating the scrubber
and FGD system the same as with limestone,
• Adding adipic acid (or DBA) to the LSFO scrubber but otherwise operating
the same and finally switching to high calcium lime and adding adipic acid
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Evaluating options for post CO2 removal of Flue Gas Streams
The polishing spray tower was designed as if it were an MEL scrubber.
Based upon earlier discussion, lime and adipic acid each used an equivalent
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L/G of 9.1 and 13 l/m (68 and 75 gallon/1000 ft ) respectively. These
equivalent L/G values were combined with the equivalent L/G provided by
trays and actual L/G to arrive at total equivalent L/G values for each case.
Table 5. Options for increasing SO2 removal of an existing LSFO spray tower
Figure 6 is a plot of resulting equivalent L/G and SO2 removal as NTU for
each case listed in Table 5 that provides an easy way to judge the potential
boost of SO2 removal of an existing scrubber. The example of the original
spray tower and polishing scrubbers plots the sums of the equivalent L/G
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from both individual scrubbers (27 + 8.7 l/m ) and predicted SO2 removal
efficiency (3.51 NTU+ 1.86 NTU). Interestingly, the overall performance of
this approach is very nearly the same as what may be possible by using
adipic acid (or DBA) in an existing LSFO.
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Evaluating options for post CO2 removal of Flue Gas Streams
Conclusions
All post combustion CO2 removal processes, with the possible exception of
the chilled ammonia process, require SO2 to be less than 10-ppmv (< 20mg/Nm3) in order to slow degeneration of the CO2 reagent. From the
analysis presented power plants with existing FGD systems have options to
consider that achieve ultra low SO2 emissions removal without undertaking
major capital intensive modifications or incurring significant additional
parasitic load. These options of course have to be verified by FGD vendors.
For LSFO FGD systems organic acids like adipic acid and DBA appear to be
the obvious choice since they provide a very large boost in mass transfer and
require little if any mechanical modifications to implement. Existing
wastewater treatment systems will likely require modification to process
waste liquor containing organic acids. Switching to high calcium lime
provides the next highest mass transfer boost but may need to be coupled
with organic acids, fuel blending or mechanical enhancement of the
scrubbers to achieve required ultra low SO2 emissions.
There is little publicly available test data that is useful to perform a similar
study of JBR limestone scrubbers; but the chemistry of this process is similar
enough that it is not inconceivable to think that similar boosting of SO2
removal performance of existing JBR systems is possible.
Lime forced oxidation scrubbers could employ the same set of mechanical
modifications or use of organic acids to boost mass transfer as LSFO
systems. Required modifications to lime forced oxidation systems should be
less extensive and organic acid use would be less than for LSFO. Options to
boost mass transfer in MEL FGD scrubber are likely limited to mechanical
modification although these would be relatively simple to implement. Any one
mechanical modification should be sufficient including: addition of a tray,
reducing the open area of an existing tray, install baffles between spray
headers or install dual flow nozzles.
Reference - Bibliography
1 “DOE/NETL’s Carbon Capture R&D Program For Existing Coal-Fired
Power Plants”; J.P. Ciferno-U.S. DOE/National Energy Technology
Laboratory and G.R. Vaux & J. T. Murphy-Science Applications
International Corp.; October 2009
2 “Impacts Of Carbon Capture On Coal-Fired Power Plant Emissions And
Liquid/Solid Waste Streams”, M. J. Krasnopoler and H. Wen; Bechtel
Power Corporation, 5275 Westview Drive, Fredrick, MD 21703; October
2009
3 “Evaluation of Wet FGD Technologies to Meet Requirements for Post
CO2 Removal of Flue Gas Streams; Paper #49”; Kevin Smith, William
Booth, Stephane Crevecoeur – Carmeuse Lime & Stone; EPRI-DOEEPA-AWMA Combined Power Plant Air Pollutant Control Mega
Symposium, August, 2008; Baltimore MD.
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Evaluating options for post CO2 removal of Flue Gas Streams
4 “Evaluation Of Wet FGD Technologies To Meet Requirements For Post
CO2 Removal Of Flue Gas Streams; Part 2”; Kevin Smith, Stephane
Crevecoeur, Pavel Hanzl; Carmeuse; Air Quality VII, October, 2009;
Arlington VA
5 “WFGD Case Study – Maximizing SO2 Removal by Retrofit with Dual
Tray Technology”; A. A. Silva and P.J. Williams- The Babcock & Wilcox
Company, Barberton, Ohio; J. Balbo – Michigan South Central Power
Agency, Litchfield, MI; EPRI-DOE-EPA-AWMA Combined Power Plant Air
Pollutant Control Mega Symposium, August 28-31, 2006; Baltimore MD.
6 Coal Outlook, Volume 34 / No 23 / June 7, 2010
7 Adipic Acid-Enhanced Lime/Limestone Test Results at the EPA Alkali
Scrubbing Test Facility; Wang, S-C & Burbank, D. A; ACS Symposium
Sponsored by the Division of Industrial and Engineering Chemistry; 181st
Meeting of ACS, Atlanta, GA, March 29-30, 1981, pages 267 - 306
8 “Overview of Recent Research Activities at EPRI’s High Sulfur Test
Center – April 1993 to March 1994”; R. E. Moser, D. R. Owens – EPRI
and M. Stohs – Radian Corporation.
Keywords
CCS, FGD, L/G, DBA, LSFO, MEL, JBR, limestone, lime, organic acid,
scrubber, polishing scrubber
contact our specialists at fgd@carmeuse.com - www.theFlueGasSolutions.com
www.carmeuse.com
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