WO1997023581A1

WO1997023581A1 - Reducing dust emissions

Info

Publication number: WO1997023581A1
Application number: PCT/US1996/013568
Authority: WO
Inventors: Girish Keshav Chitnis; Paul Arthur Howley; Stephen James Mcgovern; Thomas Mebrahtu
Original assignee: Mobil Oil Corporation
Priority date: 1995-12-26
Filing date: 1996-08-23
Publication date: 1997-07-03
Also published as: EP0879272A1; AU7152596A; JP2000502386A; EP0879272A4; CA2239496A1

Abstract

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 degree turn at the top of the reactor at elbow (10). Spent catalyst and cracked products discharged from the riser reactor pass through riser cyclone (12) which efficiently separates 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.

Description

REDUCING DUST EMISSIONS

The field of 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 coke 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 0.1 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 C0₂ within the regenerator (to conserve heat and reduce air pollution) many FCC operators add a CO combustion promoter. U.S. 4,072,600 and 4,093,535 teach use of combustion-promoting metals such as Pt, Pd, lr, 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 recovery 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. 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 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^Λ3.

The solids loading on various cyclones in various 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 microns 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 both dust and SOx from the flue gas. As the water evaporates, dust particles came closer 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 with alumina in the catalyst particles and fines to form soluble aluminum sulfate, the "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. The present process can also be used for wet scrubbing, with injection of "alkaline rain", water with an alkaline pH. This alkaline 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 permit essentially complete vaporization of at least 90% of the droplets within 1 second. The droplets are 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 of 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 10 microns are charged through a transfer line at a temperature above 538EC (1000°F) to a fines/gas separator, the fines 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 1 second of injection. The droplets, which have a diameter at least 10 times greater than the average diameter of the catalyst fines 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 10 microns and the S0_X 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 feed water. The Drawings

Figure 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 Ultra Orthoflow converter Model F shown as Fig. 17 of 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 90D 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 fractionato .

Spent catalyst is discharged down from a dipleg of riser cyclones 12 into catalyst stripper 8 where one, or 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 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 flue gas line via line 22.

This regenerator is ideal for the practice of the present invention. The bubbling dense bed in such a 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. Line 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 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 agglomerated 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. 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 tubes 235 and are discharged from the base of the tubes as an annular stream of solids 230. A clean gas stream is withdrawn via outlet tubes 239 to be removed from the vessel via outlet 290. Solids are removed via solids outlet 265.

Well atomized injection 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 precipitator, porous sintered metal filter or some type of fabric filter media.

Preferably a plurality of atomizing feed nozzles are used to inject 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 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 (UHP 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 C0₂ 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, 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 705° 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 chemical properties of either the injected aqueous phase and/or the flowing gas stream containing fines. Each area will be discussed in greater detail hereafter. DROPLET SIZE 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 is quite a departure from conventional "gluing" approaches - if 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 believed 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 preferably 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. 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 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 1 - 3 micron particles and damaged by 1/10 as much, by weight, of 10 - 30 micron particles. A refiner may wish to fine tune the process to agglomerate only larger particles and ignore smaller particles. 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 - 10 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 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" mixing nozzles in the practice of the present invention. 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 10% 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 injection permit inefficient use of injected water. CONDITION IN FLOWING GAS STREAM

Vapor velocity and temperature in the flue gas line or other process line will generally be set by other concerns. 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 equipment 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 (1300° 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 many 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 injection 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 0.5 to 1 seconds or more of vapor residence time to ensure complete vaporization upstream of the TSS or other pluggable downstream equipment. 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 makes 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 sulfur/catalyst 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 0.01 to 0.05 wt %. Preferably the acid rain is formed in situ in the flue gas line. 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 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 S0_X from the regenerator flue gas. Injection 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 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 sticky 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 PHYSICAL 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 mixing 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. 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. 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 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.

Claims

1. A fluidized catalytic cracking process wherein a hydrocarbon feed is catalytically cracked by contact with a cracking catalyst in a cracking reactor to produce lighter products and spent catalyst, spent catalyst is regenerated in a catalyst regenerator having one or more separators for recovery of catalyst and fines from flue gas to produce regenerated catalyst which is recycled to the cracking reactor and regenerator flue gas containing catalyst fines having a diameter less than 10 microns is charged in a transfer line at a temperature above 1000°F to a separator, and wherein fines are agglomerated in the transfer line by injecting a controlled amount of water into the gas stream to form acidified droplets having a diameter at least 10 times larger than the average diameter of the fines and a diameter small enough to permit essentially complete vaporization of at least 90% of the droplets within 1 second; capturing fines in the droplets to produce evaporating droplets containing captured fines; dissolving a portion of the captured fines to form partially dissolved fines in the evaporating droplet; contacting partially dissolved fines by reducing the diameter of the droplets by evaporation to produce contiguous particles each having an outer layer of partially dissolved material; fusing the contiguous particles by evaporating water from the partially dissolved material to produce dry, fused fines.

2. The process of claim 1 in which the flue gas contains 50 to 1000 vol ppm SOx.

3. The process of claim 1 in which injected water has a pH of 3 to 7, preferably 4 to 6.

4. The process of claim 1 in which the gas stream is above 982°C (1300°F) just before droplet injection.

5. The process of claim 1 in which the droplets are acidified by evaporating injected water droplets containing dissolved acidic compounds.

6. The process of claim 1 in which the droplets are acidified by adsorption of acidic vapor including sulfur dioxide present in the flue gas stream by the droplets followed by evaporation of water from the droplets.

7. The process of claim 1 in which the regenerator flue gas contains 50 to 1000 preferably 100 to 500 volume ppm SOx.

8. The process of claim 1 in which the injected water droplets water contain sufficient dissolved or entrained solids to preclude use of the water as boiler feed water

9. The process of claim 8 in which the injected water is a slurry of water and an alkaline solid such as limestone.

10. The process of claim 8 in which the injected water is a slurry of water and an alkaline solid which is a SOx capture agent present in an amount sufficient by stoichiometry to remove essentially all SOx from the flue gas.