Note: Descriptions are shown in the official language in which they were submitted.
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REDUCING DUST EMISSIONS
The field o~ the invention is use of separators to
remove dust from gas streams and fluidized catalytic
cracking of heavy hydrocarbon feeds.
The invention provides a way to overcome problems
encountered in the fluidized catalytic cracking (FCC)
process used in many petroleum refineries. In FCC, a
cracking catalyst circulates between a cracking reactor and
a catalyst regenerator. In the reactor, hydrocarbon feed
contacts a source of hot, regenerated catalyst. The hot
catalyst vaporizes and cracks the feed at 425~C-600~C,
usually 460~C-560~C. The cracking reaction deposits co~e
on the catalyst, thereby deactivating it. The cracked
products are separated from the coked catalyst. The coked
catalyst is stripped of volatiles, usually with steam, in a
catalyst stripper and the stripped catalyst is then
regenerated. The catalyst regenerator burns coke from the
catalyst with oxygen containing gas, usually air. Decoking
restores catalyst activity and simultaneously heats the
catalyst to 500~C-900~C, usually 600~C-750~C. Modern fluid
catalytic cracking (FCC) units use zeolite catalysts.
Zeolite-containing catalysts work best when coke on the
catalyst after regeneration is less than O.l wt %, and
preferably less than 0.05 wt %. Heated catalyst is
recycled to the cracking reactor to crack more fresh feed.
Flue gas formed by burning coke in the regenerator may be
treated to remove particulates and convert carbon monoxide,
after which the flue gas is normally discharged into the
atmosphere.
To regenerate FCC catalyst to this low residual carbon
level and to burn CO completely to CO2 within the
regenerator (to conserve heat and reduce air pollution)
m~ny FCC operators add a CO combustion promoter. U.S.
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4t 072,600 and 4,093,535 teach use of combustion-promoting
metals such as Pt, Pd, Ir, Rh, Os, Ru and Re in cracking
catalysts in concentrations of 0.01 to 50 ppm, based on
total catalyst inventory.
The FCC unit must operate without exceeding local
emission limits on particulates. Many refiners also use a
power recovery system wherein the energy in FCC regenerator
flue gas drives the air blower supplying air to the
regenerator. The amount and particle size of fines in most
FCC flue gas streams exiting the regenerator is enough to
erode turbine blades if a power recovery system is
installed. Generally a third stage separator (TSS) unit is
installed upstream of the turbine to reduce the catalyst
loading and protect the turbine blades. Some refiners even
now install electrostatic precipitators or some other
particulate removal stage downstream of third stage
separators and turbines to further reduce fines emissions.
Many refiners now use high efficiency third stage
separators, typically involving multiple, relatively small
diameter cyclones, to decrease loss of FCC catalyst fines
and/or protect power reco~ery turbine blades. However,
current and future legislation will probably require
another removal stage downstream of the third stage
cyclones unless significant improvements in efficiency can
be achieved.
The problem addressed by the present invention is the
third stage separator or TSS unit. The TSS must produce
gas with essentially no particles greater than 10 microns
(when power recovery turbines are used) and/or achieve
sufficient removal of fines to meet emissions particulates
regulatory limits.
Modern, high efficiency third stage separators
typically have 50 to 100 or more small diameter cyclones.
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One type of third stage separator is described in "Improved
hot-gas expanders for cat cracker flue gas" Hydrocarbon
Processing, March 1976. The device is fairly large, a 26'
diameter vessel. Catalyst laden flue gas passes through
S many swirl tubes. Catalyst is thrown against the tube
walls by centrifugal force. Clean gas is withdrawn up via
a central gas outlet tube while solids are discharged
through two blowdown slots in the base of an outer tube.
The device removed most 10 micron and larger particles.
The unit processed 550,000 lbs./hour of flue gas containing
300 lbs/hour of particles ranging from sub-micron fines to
60 micron sized catalyst particles. This corresponds to an
inlet loading of 680 mg/NM~3.
The solids loading on various cyclones in various
1~ parts of the FCC process varies greatly. The third stage
separator has the most difficult separation in terms of
particle size, while the primary separators typically do
99% of the solids recovery.
In most commercial FCCs, regenerator flue gas has a
bimodal particle size distribution. The dust is 0.5 - 3
~icrons or 10 - 60 microns, with essentially no 4 - 10
micron material. We found, however, that it was possible
to bring roughly 20% of the dust into the 3 - 10 micron
size range by injecting water upstream of the thirs stage
separator to meet a temperature constraint. We examined
this dust under an electron microscope and saw 3 - 10
micron dust particles made from an agglomeration of finer
particles. The fines were held together by a "glue" with a
sulfur/silicon ratio approaching 1:1. In contrast, the
sulfur/silicon ratio in the catalyst was less than 0.05:1.
We believe the mechanism of dust agglomeration
involves at least two distinct. Water droplets injected
into this unit picked up ~oth dust and SOx from the flue
gas. As the water evaporates, dust particles came closer
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together within a droplet. The water droplets
simultaneously formed sulfuric acid from S03 in the flue
gas. This sulfuric acid, a short lived species of acid
rain formed in situ in the flue gas transfer line, reacts
S with alumina in the catalyst particles and fines to form
soluble aluminum sulfate, the r'glue" holding fines
together.
Water quench, if properly controlled, therefore
provides a powerful way to remove fines from FCC
regenerator flue gas streams. It could also be used to
agglomerate fines in hot flue gas streams from other
processes, such as circulating fluidized bed combustion
(CFBC) units, various other types of fluidized bed coal
combustion units, and similar processes.
1~ The present process can also be used for wet
scrubbing, with injection of "alkaline rain", water with an
alkaline pH. This alkali~e water will react with acidic
species in the flue gas to produce a dry powder which can
be recovered using conventional downstream solids recovery
means such as a third stage separator.
Alternatively, an aqueous slurry of an alkaline solid
such as limestone or dolomite may be injected for fines
recovery and removal of acidic species from the gas.
The present invention provides a process for removing
fines, having an average particle diameter less than 10
microns and soluble in aqueous acidic solutions, entrained
in a gas stream having a temperature above 500~F flowing in
fully developed turbulent flow conditions including a vapor
velocity above 50 fps. The process is operaed by injecting
a controlled amount of water into the gas stream as
droplets having a diameter at least 10 times larger than
the average diameter of the fines and a diameter small
enough to per~it essentially complete vaporization of at
least 90% of the droplets within 1 second. The droplets are
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acidified either by using ijected water which contains
acidic compounds or by adsorption of an acidic vapor such
as sulfur dioxide which is present in the gas stream
followed by evaporation. The fines are captured in the
droplets, preferably with at least two fines per droplet.
A portion o~ the captured fines are dissolved in the
evaporating droplets which then undergo evaporation to
reduce the diameter of the droplets to produce contiguous
particles each having an outer layer of partially dissolved
material. The contiguous particles are fused by
evaporating water from the partially dissolved material to
produce agglomerated dry, fused fines.
In the fluidized catalytic process where the catalyst
fines have a diameter less than lO microns are charged
through a transfer line at a temperature above 538EC
(1000~F) to a fines/gas separator, the ~ines are
agglomerated in the transfer line by injecting a controlled
amount of water into the transfer line as droplets to
permit essentially complete vaporization of the droplets
within l second of injection. The droplets, which ha~e a
diameter at least lO times greater than the average
diameter of the catalyst ~ines to be agglomerated, are
simultaneously acidified by concentrating dissolved acidic
compounds present in the injected droplets and/or by
adsorption of sulfur oxides in the flue gas. In a typical
FCC operation, the catalyst fines will have a diameter less
than lO microns and the SOx will be charged in the transfer
line at a temperature above 650~C (1200~F) to carry the
droplets and fines to a fines/gas separator. The water
used to form the droplets can be low purity water which
contains sufficient dissolved or entrained solids to
preclude its use as boiler ~eed water.
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The Drawings
~ igure 1 is a simplified schematic view of an FCC unit
of the prior art with a preferred quench injection process.
Figure 2 (prior art) is a simplified schematic view of
a third stage separator of the prior art.
The present invention can be better understood by
reviewing it in conjunction with a conventional riser
cracking FCC unit. Figure 1 begins with a fluid catalytic
cracking system of the prior~art, and is similar to the
Kellogg Ultxa Orthoflow converter Model F shown as Fig. 17
o~ Fluid Catalytic Cracking Report, in the January 8, 1990
edition of Oil & Gas Journal.
A heavy feed such as a gas oil, vacuum gas oil is
added to riser reactor 6 via feed injection nozzles 2. The
cracking reaction is almost completed in the riser reactor,
which takes a 90~ turn at the top of the reactor at elbow
10. Spent catalyst and cracked products discharged from
the riser reactor pass through riser cyclones 12 which
efficiently separate most of the spent catalyst from
cracked product. Cracked product is discharged into
disengager 14 and eventually is removed via upper cyclones
16 and conduit 18 to the fractionator.
Spent catalyst is discharged down from a dipleg of
riser cyclones 12 into catalyst stripper 8 where one, or
2~ preferably 2 or more, stages of steam stripping occur, with
stripping steam admitted by means 19 and 21. The stripped
hydrocarbons, and stripping steam, pass into disengager 14
and are removed with cracked products after passage through
upper cyclones 16 Stripped catalyst is discharged down via
spent catalyst standpipe 26 into catalyst regenerator 24
The flow of catalyst is controlled with spent catalyst plug
valve 36. Catalyst is regenerated in regenerator 24 by
contact with air, added via air lines and an air grid
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distributor not shown. A catalyst cooler 28 is provided so
heat may be removed from the regenerator if desired.
Regenerated catalyst is withdrawn from the regenerator via
regenerated catalyst plug valve assembly 30 and discharged
via lateral 32 into the base of the riser reactor 6 to
contact and crack fresh feed injected via injectors 2 as
previously discussed. Flue gas, and some entrained
catalyst, is discharged into a dilute phase region in the
upper portion of regenerator 24. Entrained catalyst is
separated from flue gas in multiple stages of cyclones 4
and discharged via outlets 38 into plenum 20 for discharge
to the ~lue gas line via line 22.
This regenerator is ideal for the practice of the
present invention. The bubbling dense bed in such a
lS regenerator exhibits excellent horizontal mixing, and the
heat exchanger 28 allows full CO burn operation even with
heavy feeds.
Figure 1 does not show a third stage separator. ~ine
22 in most refineries goes to a third stage separator (not
shown~, usually one involving 50 to 100 (or more) small
diameter horizontal or vertical cyclones. Purified flue
gas would then pass through an optional power recovery
turbine (not shown) then go to a stack for discharge to the
atmosphere, optionally via a flue gas clean up device, such
2~ as an SOx scrubber, or the like, not shown. Fig. 1 does
show injection of rapidly vaporizing droplets via nozzle
means 80 connected to fluid supply line 82.
Figure 2 (Prior Art) shows a conventional third stage
separator, a preferred way of collecting zgglomerated or
clumped fines. This figure is similar to Fig. 1 of
Improved hot-gas expanders for cat cracker flue gas, are
referred to in Hydrocarbon Processing, March 1976, p. 141.
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Third stage separator 200 receives a fines containing
FCC flue gas via inlet 210. Gas is distributed via plenum
220 to the inlets of a plurality of small diameter ceramic
tubes 235 containing swirl vanes not shown. Fines,
including agglomerated fines formed in the transfer line to
the TSS, collect on the walls of tu~es 235 and are
discharged from the base of the tubes as an annular stream
of solids 230. A clean gas stream is withdrawn ~ia outlet
tubes 239 to be removed from the vessel via outlet 290.
Solids are removed via solids outlet 265.
Well atomized in~ection of controlled amounts of
water, preferably mildly acidic water, may be carried out
into the FCC regenerator flue gas upstream of a TSS or
other particle collection means, such as an electrostatic
1~ precipitator, porous sintered metal filter or some type of
fabric filter media.
Preferably a plurality of atomizing feed nozzles are
used to in~ect controlled amounts of water into the FCC
flue gas line. Ideally the SOx content of the gas, and the
pH of the water, are at least periodically or preferably
continuously monitored so that the short lived droplets
will have sufficient SOx content to form glue to
agglomerate fines. Preferably the opacity of the flue gas
stream is measured at least periodically downstream of the
water injection point to ensure that no liquid water or
damp catalyst will enter the TSS or other downstream
equipment, which might cause pLugging thereof.
FCC FEED
Any conventional FCC feed can be used. The feeds may
range from typical petroleum distillates or residual
stocks, either virgin or partially refined, to coal oils
and shale oils. Preferred feeds are gas oil, vacuum gas
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oil, atmospheric resid, and vacuum resid. The invention is
most useful with feeds having an initial boiling point
above 650~F.
FCC CATALYST
Any commercially available FCC catalyst may be used.
The catalyst can be 100% amorphous, but preferably
includes some zeolite in a porous refractory matrix such as
silica-alumina, clay, or the like. The zeolite is usually
5-40 wt% of the catalyst, with the rest being matrix.
Conventional zeolites include X and Y zeolites, with ultra
stable, or relatively high silica Y zeolites being
preferred. Dealuminized Y (DEAL Y) and ultrahydrophobic Y
(U~P Y) zeolites may be used. The zeolites may be
stabilized with Rare Earths, e.g., 0.1 to 10 wt% RE.
Relatively high silica zeolite containing catalysts
are preferred for use in the present invention. They
withstand the high temperatures usually associated with
complete combustion of CO to CO2 within the FCC
regenerator.
The catalyst inventory may contain one or more
additives, either as separate additive particles, or mixed
in with each particle of the cracking catalyst. Additives
can enhance octane (shape selective zeolites, typified by
ZSM-5, and other materials having a similar crystal
structure), absorb SOX (alumina), or remove Ni and V (Mg
and Ca oxides).
Additives for SOx removal are available commercially,
e.g., Katalistiks International, Inc.'s "DeSOx." CO
combustion additives are available from catalyst vendors.
FCC REACTOR CONDITIONS
Conventional cracking conditions may be used.
Preferred riser cracking reaction conditions include
catalyst/oil weight ratios of 0.5:1 to 15:1 and preferably
3:1 to 8:1, and a catalyst contact time of 0.1-50 seconds,
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and preferably 0.5 to 5 seconds, and most preferably 0.75
to 4 seconds, and riser top temperatures of 900 to 1050~F.
It is best to use an atomizing feed mixing nozzle in
the base of the riser reactor. Details of a preferred
nozzle are disclosed in US 5,289,976.
It is preferred but not essential to have a riser
catalyst acceleration zone in the base of the riser.
It is preferred but not essential to have the riser
reactor discharge into a closed cyclone system for rapid
and efficient separation of cracked products from spent
catalyst. A closed cyclone system is disclosed in U.S.
5,055,177 to Haddad et al.
It may be beneficial to use a hot catalyst stripper,
heating spent catalyst by adding some hot, regenerated
catalyst to spent catalyst. If hot stripping is used, a
catalyst cooler may cool heated catalyst upstream of the
catalyst regenerator. Suitable designs are shown in U.S.
3,821,103 and 4,820,404.
CATALYST REGENERATION
The process and apparatus of the present invention can
use conventional FCC regenerators. Most regenerators are
either bubbling dense bed or high efficiency. Catalyst
regeneration conditions include temperatures of 650~ to
982~C (1200~ to 1800~F), preferably 7~5~ to 760~C ~1300~ to
1400~F), and full or partial CO combustion by controlled
injection of air or oxygen containing gas.
WATER INJECTION TO FLUE GAS STREAM
There are several constraints on water injection which
must be satisfied to achieve optimum results. Basically
these relate to droplet size/ amount of water injection,
conditions in the flowing gas stream (primarily vapor
velocity and temperature)/ and gas residence time between
water injection and clumped particle removal. Other
modifications involve changing the che~ical properties of
-
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either the injected aqueous phase and/or the flowing gas
stream containing fines. Each area will be discussed in
greater detail hereafter.
DROP~ET SIZE
S In general terms, the injected water must be injected
in a form and in a direction so that good distribution of
the injected water in the flowing gas stream is achieved
and the droplets survive long enough to agglomerate
particles, but not long enough to plug downstream
equipment.
The water droplets should be larger than the particles
to be agglomerated. This in itself ls quite a departure
from conventional "gluing" approaches - i~ the same
approach were used to glue arms to a rocking chair the dab
of glue would be bigger than the chair. The large size is
believéd beneficial in "capturing" several particles, and
drawing the particles closer together as the water droplet
evaporates. A large droplet size relative to catalyst
fines particle size may also be beneficial in ensuring
significant amounts of "slip" in the transfer line, so that
large droplets will at least sporadically bump into and
capture fines.
Thus fine droplet size, say 20 microns or so, is good
for dispersing water droplets in the flowing gas but may
not be large enough to capture multiple fines nor to
survive long enough in the flowing gas stream.
The droplets of the injected aqueous liquid phase
should be above 50 microns, preferably above 100 microns,
more pre~erably above 500 microns. In many refineries
water droplet sizes above 1000 microns will give good
results if sufficient residence time is available in the
flowing gas stream to ensure essentially complete
vaporization of water upstream of pluggable process
equipment.
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The upper limit on droplet size involves two
considerations. An absolute limit is set by plugging of
equipment, whether the transfer line or downstream
equipment. Another consideration is whether it is better
S to have a few large droplets which sweep clean everything
in their path or more smaller droplets which provide better
areal sweep of the transfer line. Local site
considerations, and the amount of slip which can be
tolerated in the transfer line will affect this. If some
of the transfer line is a vertical upflow pipe, much larger
droplets may be tolerable and even preferred.
The optimum size of the water droplets may also be
affected by the size of particles to be collected. Large
droplets may be most efficient at collecting large
particles, if there is a significant gas flow around the
large water droplets which diverts only small particles.
Some refiners may wish to target selected portions of
the fines in the flowing gas stream, based on downstream
concerns. Thus a power recovery turbine may be able to
tolerate a relatively large mass of l - 3 micron particles
and damaged by l/lO as much, by weight, of lO - 30 micron
particles. A refiner may wish to fine tune the process to
agglomerate only larger particles and ignore smaller
particles.
2~ In a related vein, a refiner may have a TSS which can
efficiently recover particles above 30 microns, and only
poorly recover particles in the 3 - lO micron range. For
this refiner it may be important to ensure that such fines
as are agglomerated agglomerate into particles which can be
efficiently captured by downstream equipment.
A refiner could actually misuse our process to ~!
increase erosion of turbine blades by converting 0.5 to 3
micron fines (which can be tolerated to some extent by the
turbine blades) into 5 - 30 micron particles which are
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difficult to recover in many TSS units and extremely
damaging to turbine blades.
Thus in many refineries mediocre removal of fines with
relatively few large droplets, will be preferred. This may
be achieved using "bad'l mixing nozzles in the practice of
the present lnvention. Bad nozzles, in terms of droplet
size, are usually preferred for use herein. Some refiners
may prefer to use relatively high tech nozzles which could
achieve fine atomization but degrade nozzle operation to
achieve larger droplet size. Two phase nozzle performance
can be degraded by use of less atomization gas or by
supplying water at a lower pressure to the nozzle. Single
phase nozzle performance can be degraded by using a lower
pressure aqueous feed and/or using a nozzle discharge
orifice which is larger than normal.
Any conventionally available nozzles used to create
finely atomized dispersions of water in hot gas streams may
be used. The nozzle disclosed in US 5,289,976, developed
for injecting heavy hydrocarbon feed into the base of an
FCC riser reactor, may be used. In addition, nozzles such
as the Maxipass nozzle made by Bete Fog, Inc. may be used.
AMOUNT OF WATER INJECTION
In general, enough water should be injected so that at
least l0~ by weight of particles having a size less than 5
microns agglomerate in the transfer line. If the water is
injected primarily for quenching (temperature control), it
may be beneficial to inject large amounts of finely
atomized water. The efficiency of the each droplet at
collecting fines may be poor, as small droplets evaporate
quickly, but the large quantity of water injection can
compensate. Thus large amounts of water iniection permit
inefficient use of injected water.
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CONDITION IN FLOWING GAS STREAM
Vapor velocity and temperature in the flue gas line or
other process line will generally be set by other concernsO
Most FCC units were built decades ago. Water must be
injected into the lines largely at the conditions which
exist in the lines. It is neither practical nor necessary
to start taking out a lot of existing e~uipment to provide
for water injection, the process works well with conditions
which now exist in such transfer lines.
Typically the temperature is near the temperature of
the FCC regenerator, or other source of particulates.
Typical temperatures include 650~ to 982~C (1200~ to
1800~F~. In many refineries the flue gas temperature is
677~ to 815~C (1250 - 1500~F), with most in 705~ to 760~C
(13Q0~ to 1400~F) range. TypicalLy vapor velocities in
transfer lines are above 15.2 m./sec. (50 fps), with many
operating in the 22.8 - 61 m/sec. (75 - 200 fps) range. In
man~ FCC units the vapor velocity in the regenerator flue
gas transfer line is above 30 m/sec. (100 fps), with many
operating at 45 m/sec (150 fps). The flow will usually be
fully developed turbulent flow.
GAS RESIDENCE TIME AFTER WATER INJECTION
The gas residence time between water injection and
downstream equipment, such as the TSS, is within the
refiner's control. The water quench in~ection point should
be sufficiently upstream of the TSS or electrostatic
precipitator to achieve the desired result. In some
installations, especially those with the hottest gas, as
little as 0.1 seconds of vapor residence time will be
sufficient for agglomeration and essentially complete
vaporization of water. Many refiners will want ~.5 to 1
seconds or more of vapor residence time to ensure complete
vaporization upstream of the TSS or other pluggable
downstream equipment.
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Once the water evaporates the resulting agglomerates
are relatively stable. Additional residence time
downstream of the water quench injection point may be
provided without detriment.
CHEMICAL PROPERTIES - INJECTED AQUEOUS PHASE
The pH of the water is preferably monitored so that
after injection but before complete evaporation an aqueous
phase forms which is will "glue" fines together. The
"glue" may form from something injected with the water,
e.g., a solution of a salt or silicon or the like, which
becomes sticky as it dries.
The preferred method of forming "glue" involves making
use of noxious compounds in the vapor to form an acidic
aqueous medium which can be used to fuse solids together.
This three phase approach makes efficient use of acidic
components in the gas to form "acid rain" which lasts just
long enough to capture fines.
The process works especially well when the FCC unit
has a scrubber, for SOx removal upstream of the stack. The
mildly acidic water produced by the scrubber ma~es an ideal
source of quench water, with considerable native acidity,
in addition to the extra SOx picked up by the acid water
when it is injected for particulates agglomeration.
Naturally occurring acid rain is an ideal quench
liquid for many applications. Such water contains little
in the way of dissolved solids and sufficient S03 to
enhance formation of soluble sulfurJcatalyst reaction
products. Acid rain may be artificially prepared, by
~ adding low concentrations of sulfuric acid to the water, in
the range of 0.001 to 0.1 wt ~, preferably in the range of
J O . 01 to 0.05 wt %. Preferably the acid rain is formed in
situ in the flue gas line.
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Expressed in terms of pH, the quench liquid may have a
pH ranging from neutral to 2, preferably from 2.5 to 6.5
and most preferably from 3 to 6.
While acidic injected water is preferred to maximize
S fines capture, local constraints or other considerations
may make use of basic or alkaline water injection
beneficial. There are benefits and burdens to this
approach. A refiner may wish to remove some SOx from the
regenerator flue gas. In~ection of alkaline water, or
water containing an emulsion or slurry of alkaline solids,
can be used to permit removal of at least some of the SOx
or other acidic gas present in the flue gas stream as a dry
solid or as part of the recovered fine solids. A burden
to this approach is that it retards formation of an acidic
1~ phase which may degrade fines capture.
When alkaline solids are added, any of those
conventionally used in wet scrubbing processes can be used,
such as limestone or dolomite.
It is also possible to add relatively neutral stick~
materials, or a slurry of materials which does not change
in pH but which becomes sticky as the water droplet
containing the material evaporates. Thus a salt solution
might be injected, using the concentrating brine solution
as glue to hold fines together.
CHEMICAL AND PHYSIGAL PROPERTIES - FLUE GAS
While it is the intent to develop a process which
works with the flue gas as it is, it may be beneficial to
change the properties of the flowing gas. As high
superficial vapor velocities in the transfer line promote
good mi xi ng and good contact of droplets with vapor and
entrained fines, it may be useful to increase vapor
velocity, by reducing the pipe diameter or installing a
venturi section.
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In most FCC units the native Sox content of the flue
gas will be sufficient, with a controlled amount of water
injection, to achieve the desired results. Refiners may
wish to inject vaporizable acidic materials into the
flowing flue gas stream, on an intermittent or continuous
basis, to promote rapid formation of acidic glue as water
droplets evaporate.
CONTROL
Automatic opacity measuring equipment or visual
observation may be used to ensure that the water is
completely evaporated upstream of the TSS unit.
In view of the constant change in FCC unit operation
which occurs in many refineries, and changes in weather, it
is preferable if a continuous monitoring system be used to
ensure that all injected water droplets survive the desired
time in the flue gas line. It will be preferred in many
instances to provide monitoring equipment a given distance
downstream of the water injection point and adjust unit
operation as necessary to ensure survival of a controlled
number of droplets at the monitoring point. If no droplets
remain, then more water could be injected, or less
atomization air used, or some nozzles blocked in and
remaining ones overloaded with water, so that the desired
droplet population survives. If too many droplets, or even
just a few droplets of unduly large size, are present, it
will be necessary to eliminate water injection or adjust
injection to avoid plugging downstream process equipment.
THIRD STAGE SEPARATOR/ELECTROSTATIC PRECIPITATOR
Any conventionally available dust removal equipment
may be used to remove the agglomerated fines from the flue
gas such as third stage separators, electrostatic
precipitators, porous stainless steel filters, bag houses
and the like which are commercially available.
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The new approach to dust removal allows refiners to change
the dust in their gas streams, rather than change dust
removal equipment, to meet local laws or to protect
downstream processing equipment. In many FCC units the
S injection of our acid rain, or a like acidity water stream,
upstream of a third stage separator will eliminate the need
for an electrostatic precipitator to reduce opacity and
achieve particulate emissions of less than 50 mg/Nm3.
