WO1992001511A1 - Procede et appareil servant a commander la regeneration multiphase de catalyseurs avec combustion complete du co - Google Patents

Procede et appareil servant a commander la regeneration multiphase de catalyseurs avec combustion complete du co Download PDF

Info

Publication number
WO1992001511A1
WO1992001511A1 PCT/US1991/005019 US9105019W WO9201511A1 WO 1992001511 A1 WO1992001511 A1 WO 1992001511A1 US 9105019 W US9105019 W US 9105019W WO 9201511 A1 WO9201511 A1 WO 9201511A1
Authority
WO
WIPO (PCT)
Prior art keywords
catalyst
coke
fluidized bed
flue gas
regeneration
Prior art date
Application number
PCT/US1991/005019
Other languages
English (en)
Inventor
Hartley Owen
Paul Herbert Schipper
Original Assignee
Mobil Oil Corporation
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Mobil Oil Corporation filed Critical Mobil Oil Corporation
Publication of WO1992001511A1 publication Critical patent/WO1992001511A1/fr

Links

Classifications

    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J38/00—Regeneration or reactivation of catalysts, in general
    • B01J38/04—Gas or vapour treating; Treating by using liquids vaporisable upon contacting spent catalyst
    • B01J38/12—Treating with free oxygen-containing gas
    • B01J38/30—Treating with free oxygen-containing gas in gaseous suspension, e.g. fluidised bed
    • B01J38/34—Treating with free oxygen-containing gas in gaseous suspension, e.g. fluidised bed with plural distinct serial combustion stages
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J29/00—Catalysts comprising molecular sieves
    • B01J29/90—Regeneration or reactivation
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J38/00—Regeneration or reactivation of catalysts, in general
    • B01J38/04—Gas or vapour treating; Treating by using liquids vaporisable upon contacting spent catalyst
    • B01J38/12—Treating with free oxygen-containing gas
    • B01J38/30—Treating with free oxygen-containing gas in gaseous suspension, e.g. fluidised bed
    • B01J38/36—Treating with free oxygen-containing gas in gaseous suspension, e.g. fluidised bed and with substantially complete oxidation of carbon monoxide to carbon dioxide within regeneration zone
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G11/00—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C10G11/14—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts
    • C10G11/18—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts according to the "fluidised-bed" technique
    • C10G11/182—Regeneration
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G11/00—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C10G11/14—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts
    • C10G11/18—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts according to the "fluidised-bed" technique
    • C10G11/187—Controlling or regulating

Definitions

  • the field of the invention is regeneration of coked cracking catalyst in a fluidized bed.
  • Catalytic cracking is the backbone of many refineries. It converts heavy feeds to lighter products by cracking large molecules into smaller molecules. Catalytic cracking operates at low pressures, without hydrogen addition, in contrast to hydrocracking, which operates at high hydrogen partial pressures. Catalytic cracking is inherently safe as it operates with very little oil actually in inventory during the cracking process.
  • catalyst having a particle size and color resembling table salt and pepper, circulates between a cracking reactor and a catalyst regenerator.
  • hydrocarbon feed contacts a source of hot, regenerated catalyst.
  • the hot catalyst vaporizes and cracks the feed at 425*-600'C usually 460 # -560*C.
  • the cracking reaction deposits carbonaceous hydrocarbons or coke on the catalyst, thereby deactivating the catalyst.
  • the cracked products are separated from the coked catalyst.
  • the coked catalyst is stripped of volatiles, usually with steam, in a catalyst stripper and 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, e.g., 500 0 -900'C, usually 600'-750'C. This heated catalyst is recycled to the cracking reactor to crack more fresh feed. Flue gas formed by burning coke in the regenerator may be
  • SUBSTITUTESHEET treated for removal of particulates and for conversion of carbon monoxide, after which the flue gas is normally discharged into the atmosphere.
  • Catalytic cracking is endothermic, which means it consumes heat.
  • the heat for cracking is supplied at first by the hot regenerated catalyst from the regenerator. Ultimately, it is the feed which supplies the heat needed to crack the feed. Some of the feed deposits as coke on the catalyst, and the burning of this coke generates heat in the regenerator, which is recycled to the reactor in the form of hot catalyst.
  • Catalytic cracking has undergone progressive development since the 1940's.
  • the trend of development of the fluid catalytic cracking (FCC) process has been to all riser cracking and use of zeolite catalysts.
  • riser cracking gives higher yields of valuable products than dense bed cracking.
  • Zeolite-containing catalysts having high activity and selectivity are now used in most FCC units. These catalysts work best when coke on the catalyst after regeneration is less than 0.1 wt%, and preferably less than 0.05 wt%.
  • U.S. 4,072,600 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.
  • refiners attempted to use the process to upgrade a wider range of feedstocks, in particular, feedstocks that were heavier and also contained more metals and sulfur than had previously been permitted in the feed to a fluid catalytic cracking unit.
  • These heavier, dirtier feeds have placed a growing demand on the regenerator. Processing resids has exacerbated existing problem areas in the regenerator, sulfur, steam, temperature and NO .
  • One way to minimize SO in flue gas is to pass catalyst from the FCC reactor to a long residence time steam stripper, as disclosed in U.S. Patent No. 4,481,103 to Krambeck et al. This process preferably steam strips spent catalyst at 500'-550'C (932* to 1022*F), which is beneficial but not sufficient to remove some undesirable sulfur- or hydrogen-containing components.
  • Regenerators are operating at higher and higher temperatures. This is because most FCC units are heat balanced, that is, the endothermic heat of the cracking reaction is supplied by burning the coke deposited on the catalyst. With heavier feeds, more coke is deposited on the catalyst than is needed for the cracking reaction. The regenerator gets hotter, and the extra heat is rejected as high temperature flue gas. Many refiners severely limit the amount of resid or similar high CCR feeds to that amount which can be tolerated by the unit. High temperatures are a problem for the metallurgy of many units, but more importantly, are a problem for the catalyst. In the regenerator, the burning of coke and unstripped hydrocarbons leads to much higher surface temperatures on the catalyst than the measured dense bed or dilute phase temperature. This is discussed by Occelli et al in Dual-Function Cracking Catalyst Mixtures, Ch. 12, Fluid Catalytic Cracking, ACS Symposium Series 375, American Chemical Society, Washington, D.C, 1988.
  • U.S. Patent No. 4,353,812 to Lo as et al discloses cooling catalyst from a regenerator by passing it through the shell side of a heat-exchanger with a cooling medium through the tube side. The cooled catalyst is recycled to the regeneration zone. This approach will remove heat from the regenerator, but will not prevent poorly, or even veil, stripped catalyst from experiencing very high surface or localized temperatures in the regenerator.
  • the prior art also used dense or dilute phase regenerated fluid catalyst heat removal zones or heat-exchangers that are remote from, and external to, the regenerator vessel to cool hot regenerated catalyst for return to the regenerator. Examples of such processes are found in U.S. Patent Nos. 2,970,117 to
  • regenerators are now widely used. They typically are operated to achieve complete CO combustion within the dilute phase transport riser. They achieve one stage of regeneration, i.e., essentially all of the coke is burned in the coke combustor, with minor amounts being burned in the transport riser.
  • the residence time of the catalyst in the coke combustor is on the order of a few minutes, while the residence time in the transport riser is on the order of a few seconds, so there is generally not enough residence time of catalyst in the transport riser to achieve any significant amount of coke combustion.
  • Catalyst regeneration in such high efficiency regenerators is essentially a single stage of regeneration, in that the catalyst and regeneration gas and produced flue gas remain together from the coke combustor through the dilute phase transport riser.
  • the present invention provides a process for regenerating spent fluidized catalytic cracking catalyst used in a catalytic cracking process wherein a heavy hydrocarbon feed stream is preheated in a preheating means, catalytically cracked in a cracking reactor by contact with a source of hot, regenerated cracking catalyst to produce cracked products and spent catalyst which is regenerated in a high efficiency fluidized catalytic cracking catalyst regenerator comprising a fast fluidized bed coke combustor having at least one inlet for spent catalyst, at least one inlet for regeneration gas, and an outlet to a superimposed dilute phase transport riser having an inlet at the base connected with the coke combustor and an outlet the top connected to a separation means which separates catalyst and primary flue gas and discharges catal •_»yst into a second fluidized bed, to produce regenerated cracking catalyst comprising regenerating the spent catalyst in at least two stages, and maintaining at least 90% CO combustion to CO, in both stages by: partially regenerating the spent catalyst -
  • a primary regeneration gas comprising oxygen or an oxygen containing gas in a primary regeneration zone, comprising the coke combustor and transport riser, at primary regeneration conditions including a fast fluidized bed temperature and discharging from the transport riser partially regenerated catalyst and a primary flue gas stream; completing the regeneration of the partially regenerated catalyst with a controlled amount of a secondary regeneration gas comprising oxygen or an oxygen containing gas in a secondary regeneration zone, comprising the second fluidized bed, operating at secondary regeneration conditions including a second fluidized bed temperature and burning therein additional coke to carbon oxides; and controlling primary regeneration conditions to limit the combustion of coke on spent catalyst in the primary regeneration zone to less than 90% of the total coke on spent catalyst to carbon oxides while afterburning at least 90% of the resulting carbon oxides to CO_ and controlling secondary regeneration conditions to burn at least 5% of the total coke on spent catalyst to carbon oxides while afterburning at least 90% of the
  • the present invention provides a fluidized catalytic cracking process wherein a heavy hydrocarbon feed comprising hydrocarbons having a boiling point above 343*C (650*F) and at least 0.5 wt% sulfur is catalytically cracked to lighter products including H,S in an amount equal to at least 75% of the sulfur in the feed and a regenerator flue gas comprising less than 500 ppm SO and less than 1.0 mole % CO, comprising the steps of: catalytically cracking the feed in a catalytic cracking zone operating at catalytic cracking conditions by contacting the feed with a source of hot regenerated catalyst, including a sulfur getter additive containing adsorbed sulfur oxides, to produce a cracking zone effluent mixture having an effluent temperature and comprising cracked products and H 2 S produced by the getter in the reactor and spent cracking catalyst containing sulfur containing coke and strippable hydrocarbons; separating the cracking zone effluent mixture into a cracked product rich vapor phase and a solid
  • Figure 1 is a simplified schematic view of one embodiment of the invention using flue gas composition to control air addition and/or CO combustion promoter addition to the coke combustor of a multistage FCC high efficiency regenerator.
  • FIG. 2 is a simplified schematic view of an embodiment of the invention using a delta T
  • FIG. 3 is a simplified schematic view of an embodiment of the invention using flue gas compositions, or delta T's, to control air flow to both stages of the regenerator.
  • Figure 4 shows an embodiment using fixed air to both stages of the regenerator, and adjustment of feed preheat or feed rate to ensure complete afterburning.
  • Figure 5 shows relative CO burning rates of unpromoted and Pt promoted FCC catalyst.
  • the present invention can be better understood by reviewing it in conjunction with the Figures, which illustrate preferred high efficiency regenerators incorporating the process control scheme of the invention.
  • the present invention is applicable to other types of high efficiency regenerators, such as those incorporating additional catalyst flue gas separation means in various parts of the regenerator.
  • a heavy feed is charged via line 1 to the lower end of a riser cracking FCC reactor 4.
  • Hot regenerated catalyst is added via standpipe 102 and control valve 104 to mix with the feed.
  • some atomizing steam is added via line 141 to the base of the riser, usually with the feed .
  • heavier feeds e. g. , a resid, 2-10 wt.% steam may be used.
  • a hydrocarbon-catalyst mixture rises as a generally dilute phase through riser 4. Cracked products and coked catalyst are discharged via riser effluent conduit 6 into first stage cyclone 8 in vessel 2.
  • the riser top temperature, the temperature in conduit 6, ranges between 480" and 615*C (900* and 1150'F) , and preferably between 538' and 595*C (1000* and 1050'F) .
  • the riser top temperature is usually controlled by adjusting the catalyst to oil ratio in riser 4 or by varying feed preheat. - 14 -
  • Cyclone 8 separates most of the catalyst from the cracked products and discharges this catalyst down via • dipleg 12 to a stripping zone 30 located in a lower portion of vessel 2 . Vapor and minor amounts of catalyst exit cyclone 8 via gas effluent conduit 20 second stage reactor cyclones 14. The second cyclones 14 recovers some additional catalyst which is discharged via diplegs to the stripping zone 30.
  • the second stage cyclone overhead stream, cracked products and catalyst fines, passes via effluent conduit 16 and line 120 to product fractionators not shown in the figure. Stripping vapors enter the atmosphere of the vessel 2 and may exit this vessel via outlet line 22 or by passing through an annular opening in line 20 , not shown, i.e. the inlet to the secondary cyclone can be flared to provide a loose slip fit for the outlet from the primary cyclone.
  • the coked catalyst discharged from the cyclone diplegs collects as a bed of catalyst 31 in the stripping zone 30.
  • Dipleg 12 is sealed by being extended into the catalyst bed 31.
  • the dipleg from the secondary cyclones 14 is sealed by a flapper valve, not shown .
  • Stripper 30 is a "hot stripper. " Hot stripping is preferred, but not essential. Spent catalyst is mixed in bed 31 with hot catalyst from the regenerator. Direct contact heat exchange heats spent catalyst. The regenerated catalyst, which has a temperature from 55 *c (100 ' F) above the stripping zone 30 to 871 'C (1600'F) , heats spent catalyst in bed 31. Catalyst from regenerator 80 enters vessel 2 via transfer line 106, and slide valve 108 which controls catalyst flow. Adding hot, regenerated catalyst permits first stage stripping at from 55*C (100*F) above the riser reactor outlet temperature and 816*C (1500*F) .
  • the first stage stripping zone operates at least 83*C (150"F) above the riser top temperature, but below 760'C (1400*F) .
  • bed 31 a stripping gas, preferably steam, flows countercurrent to the catalyst.
  • the stripping gas is preferably introduced into the lower portion of bed 31 by one or more conduits 341.
  • the stripping zone bed 31 preferably contains trays or baffles not shown.
  • High temperature stripping removes coke, sulfur and hydrogen from the spent catalyst. Coke is removed because carbon in the unstripped hydrocarbons is burned as coke in the regenerator.
  • the sulfur is removed as hydrogen sulfide and mercaptans.
  • the hydrogen is removed as molecular hydrogen, hydrocarbons, and hydrogen sulfide.
  • the removed materials also increase the recovery of valuable liquid products, because the stripper vapors can be sent to product recovery with the bulk of the cracked products from the riser reactor.
  • High temperature stripping can reduce coke load to the regenerator by 30 to 50% or more and remove 50-80% of the hydrogen as molecular hydrogen, light hydrocarbons and other hydrogen-containing compounds, and remove 35 to 55% of the sulfur as hydrogen sulfide and mercaptans, as well as a portion of nitrogen as ammonia and cyanides.
  • the present invention is not, per se, the hot stripper.
  • the process of the present invention may also be used with conventional strippers, or with long
  • SUBSTITUTESHEET residence time steam strippers or with strippers having internal or external heat exchange means .
  • an internal or external catalyst stripper/cooler with inlets for hot catalyst and fluidization gas , and outlets for cooled catalyst and stripper vapor, may also be used where desired to cool stripped catalyst before it enters the regenerator.
  • the regenerator is conventional (the coke combustor, dilute phase transport riser and second dense bed) several significant departures from conventional operation occur.
  • FCC catalyst There is regeneration of FCC catalyst in two stages, i. e. , both in the coke combustor/transport riser and in the second dense bed.
  • Complete CO combustion is maintained in both the- irst and second stage of catalyst regeneration, and reliably .controlled in a way that accommodates changes in unit operation.
  • the unit preferably operates with far higher levels of CO combustion promoter, such as Pt, as compared to conventional high efficiency regenerators.
  • the second stage air addition rate is held relatively constant, while air addition to the first stage of regeneration, i. e. , the coke combustor, is controlled based on the CO content of the flue gas from the first stage, or a delta T associated with the flue gas . Sufficient air is added to, and sufficient CO combustion promoter is present in, the first stage to prevent CO breakthrough into the second stage.
  • the stripped catalyst passes through the conduit 42 into regenerator riser 60.
  • Air from line 66 and cooled catalyst combine and pass up through an air catalyst disperser 74 into coke combustor 62 in regenerator 80.
  • air catalyst disperser 74 into coke combustor 62 in regenerator 80.
  • bed 62 combustible materials, such at coke on the catalyst, are burned by contact with air or oxygen containing gas.
  • the amount of air or oxygen containing gas added via line 66, to the base of the riser mixer 60, is preferably constant and preferably restricted to 10-95% of total air addition to the first stage of regeneration. Additional air, preferably 5-50% of total air, is control1ably added to the coke combustor via flow control valve 161, line 160 and air ring 167. in this way the first stage of regeneration in regenerator 80 can be done with a controlled, and variable, air addition rate. Partitioning of the first stage air, between the riser mixer 60 and the air ring 167 in the coke combustor, can be controlled by a differential temperature, e.g., temperature rise in riser mixer 60.
  • a differential temperature e.g., temperature rise in riser mixer 60.
  • the total amount of air addition to the first stage i.e., the regeneration in the coke combustor and riser mixer, should be constant, and should be large enough to remove much of the coke on the catalyst, preferably at least 50% and most preferably at least 75%.
  • the temperature of fast fluidized bed 76 in the coke combustor 62 may be, and preferably is, increased by recycling some hot regenerated catalyst thereto via line 101 and control valve 103. If temperatures in the coke combustor are too high, some heat can be removed via catalyst cooler 48, shown as tubes immersed in the fast fluidized bed in the coke combustor. Very efficient heat transfer can be achieved in the fast fluidized bed, so it may be in some instances beneficial to both heat the coke combustor (by recycling hot catalyst to it) and to cool the coke combustor (by using catalyst cooler 48) at the same time. Neither catalyst heating by recycle, nor catalyst cooling, by the use of a heat exchange means, per se form any part of the present invention. - 18 -
  • the combustion air regardless of whether added via line 66 or 160, fluidizes the catalyst in bed 76, and subsequently transports the catalyst continuously as a dilute phase through the regenerator riser 83.
  • the dilute phase passes ' upwardly through the riser 83, through riser outlet 306 into primary regenerator cyclone 308.
  • Catalyst is discharged down through dipleg 84 to form a second relatively dense bed of catalyst 82 located within the regenerator 80.
  • flue gas is discharged to yet a third stage of cyclone separation, in third stage cyclone 92.
  • Flue gas, with a greatly reduced solids content is discharged from the regenerator 80 and from cyclone 92 via exhaust line 94 and line 100.
  • the hot, regenerated catalyst discharged from the various cyclones forms the bed 82, which is substantially hotter than any other place in the regenerator, and hotter than the stripping zone 30.
  • Bed 82 is at least 55'C (100'F) hotter than stripping zone 31, and preferably at least 83*C (150'F) hotter.
  • the regenerator temperature is, at most, 871*C (1600'F) to prevent deactivating the catalyst.
  • Bed 82 will usually be a bubbling dense bed, although a turbulent or fast fluidized bed is preferred. Regardless of density or fluidization regime, this bed preferably contains significantly more catalyst inventory than has previously been used in high efficiency regenerators. Adding inventory and adding combustion air to second dense bed 82 shifts some of the coke combustion to the relatively dry atmosphere of second fluidized bed 82, and minimizes hydrothermal degradation of catalyst. The additional inventory, and increased residence time, in bed 82 permit 5 to 75%, and preferably 10 to 60% and most preferably 15 to 50%, of the coke content on spent catalyst to be removed under relatively dry conditions. This is a significant change from the way high efficiency regenerators have previously operated, with limited catalyst inventories in the second dense bed 82, and essentially no catalyst regeneration.
  • the air addition rate to the second fluidized bed, bed 82 is fixed, in this embodiment, to provide a constant amount of air addition which should be in excess of that normally needed to achieve complete CO combustion.
  • the air addition rate, and/or the rate of addition of CO oxidation promoter to the first stage, i.e., the coke combustor, via line 160, is adjusted to maintain complete CO combustion, but only partial coke combustion, in the first stage. As long as conditions are right, it is possible to essentially completely afterburn all the CO to C0 2 in the coke combustor/transport riser, even though all of the coke is not removed from the catalyst. The easiest way to achieve this is usually by ensuring that sufficient CO combustion promoter is present.
  • flue gas analyzers such as CO analyzer controller 625 and probe 610 monitor composition of vapor in the dilute phase region in the top of the transport riser. It would also be possible, and preferred from an erosion standpoint, to measure flue gas composition in the cyclone exhaust 306. Although CO monitoring is preferred, it is also possible to monitor oxygen concentration in the flue gas, as excess oxygen will react rapidly with free CO so long as sufficient Pt is present and/or sufficiently dilute phase conditions exist in the transport riser.
  • the flue gas analyzer can also directly adjust the amount of CO combustion promoter added from hopper 600 via valve 610 and line 610.
  • the CO combustion promoter can be conventional materials, such as Pt on alumina, a solution of platinum dissolved in an aqueous or hydrocarbon phase, or any other equivalent source of CO combustion promoter.
  • the promoter can be added to the coke combustor, as shown in the Figure, or to any other part of the FCC unit, i.e., mixed with the heavy feed to the riser reactor, added to the second fluidized bed, etc. if a high CCR feed is charged to the unit, the coke make will increase, and the unit will deal with the increased coke burning requirement as follows.
  • the first signs of the increased coke make will be an increase in CO content of the flue gas from the firsf stage of regeneration, i.e., more CO will be observed by analyzer controller 625.
  • the controller will call for more primary combustion air to the coke combustor. This increased combustion air will burn the CO to CO- and restore the unit to complete CO combustion in the first stage.
  • Coke combustion in the first stage is limited by residence time, and by the nature of coke combustion, i.e., the less coke there is on catalyst the more difficult it is to remove it.
  • Similar control information can be derived by measuring the amount of afterburning that occurs in the dilute phase, i.e., by measuring a delta T (dT) in the flue gas from the first stage of regeneration.
  • dT delta T
  • control and measurement of, e.g., the CO content of the gas in the dilute phase will be equivalent, but these need not always be the case.
  • a unit which is heavily promoted with Pt could operate with a great range of CO concentrations, all of which correspond to little or no free oxygen being present, and little or not afterburning.
  • a control variable must be used which is sensitive to operation in the first stage and which does not respond ambiguously to changes in operation.
  • the amount of air added at each stage is preferably set to maximize hydrogen combustion at the lowest possible temperature, and postpone as much carbon combustion until as late as possible, with highest temperatures reserved for the last stage of the process. In this way, most of the water of combustion, and most of the extremely high transient temperatures due to burning of poorly stripped hydrocarbon occur in riser mixer 60 where the catalyst is coolest. The steam formed will cause hydrothermal degradation of the zeolite, but the temperature will be lower so activity loss will be minimized. Shifting some of the coke burning to the
  • second dense bed will limit the highest temperatures to the driest part of the regenerator.
  • the water of combustion formed in the riser mixer, or in the coke combustor, will not contact catalyst in the second dense bed 82, because of the catalyst flue gas separation which occurs exiting the dilute phase transport riser 83.
  • hot regenerated catalyst is withdrawn from dense bed 82 and passed via line 106 and control valve 108 into dense bed of catalyst 31 in stripper 30.
  • Hot regenerated catalyst is passes through line 102 and catalyst flow control valve 104 for use in heating and cracking of fresh feed.
  • a delta T controller adjusts air flow to the coke combustor and/or adjusts the amount of catalyst recirculation to the coke combustor.
  • Differential temperature controller 410 receives signals from thermocouples or other temperature sensing means responding to temperatures in the inlet and vapor outlet of cyclone 308 associated with the regenerator transport riser outlet. A change in temperature, delta T, indicates afterburning. An appropriate signal is then sent via control line 415 to alter secondary air addition by changing the setting on valve 72 in line 78 or to alter catalyst recirculation by changing the setting on valve 103 in catalyst recirculation line 101.
  • Operation with constant air to stage one, and variable air to stage 2 works best with relatively large amounts of CO combustion promoter.
  • the CO combustion promoter assures complete afterburning in the first stage, and the swings in carbon production are accommodated in the second stage by adding more or less air. If the unit gets behind in coke burning, the carbon on catalyst in, and CO content of the flue gas from, the second fluidized bed will both increase. This will lead to an increase in afterburning, which will call for a compensating increase in air addition to the second fluidized bed. Control of coke burning in each stage is also possible by adjusting the amount of catalyst that is recycled from the second fluidized bed to the first.
  • the catalyst will experience two stages of regeneration which are very similar to those of the Fig. 1 embodiment.
  • Flue gas and catalyst discharged from the dilute phase transport riser are charged via line 306 to a cyclone separator 308.
  • Catalyst is discharged down via dipleg 84 to second fluidized bed 82.
  • Flue gas, and water of combustion present in the flue gas are discharged from cyclone 308 via line 320.
  • the flue gas discharged from cyclone 308 mixes with flue gas from the second regeneration stage and passes through a second cyclone separation stage 486.
  • Catalyst recovered in this second stage of cyclone separation is discharged via dipleg 490, which is sealed by being immersed in second fluidized bed 82.
  • the cyclone dipleg could also be sealed with a flapper valve. Flue gas from the second stage cyclone 486 is charged via line 486 to plenum 520, then removed via flue gas outlet 100.
  • the flue gas stream generated by coke combustion in second fluidized bed 82 will be very hot and very dry. It will be hot because the second fluidized bed is usually the hottest place in a high efficiency regenerator. It will be dry because all of the "fast coke" or hydrogen content of the coke will have been burned from the catalyst upstream of the second fluidized bed, and catalyst in the second fluidized bed is fairly well isolated from the water laden flue gas discharged from the first regeneration stage.
  • the coke exiting the transport riser outlet will have an exceedingly low hydrogen content, less than 5%, and frequently less than 2% or even 1%. This coke can be burned in the second fluidized bed without forming much water of combustion.
  • the hot dry flue gas produced by coke combustion in bed 82 usually has a lower fines/catalyst content than flue gas from the transport riser. This can be pronounced when the superficial vapor velocity in bubbling dense bed 82 is much less than the vapor velocity in the fast fluidized bed coke combustor.
  • the coke combustor and transport riser work effectively because all of the catalyst is entrained out of them, while the second fluidized bed works best when none of the catalyst is carried into the dilute phase.
  • This reduced vapor velocity in the second fluidized bed permits use of a single stage cyclone 486 to recover entrained catalyst from dry flue gas above the second fluidized bed. The catalyst recovered is discharged down via dipleg 490 to return to the second fluidized bed.
  • the hot, dry flue gas from the second stage of combustion mixes with the water laden flue gas discharged from the first regeneration stage, and the combined flue gas streams pass through cyclone 486, with the flue gas discharged via cyclone outlet 488, plenum 520, and vessel outlet 100.
  • Fig. 1 and 2 embodiments provide a reliable, straightforward way to run the unit while maintaining complete CO combustion in both the first and second stage - of the regenerator.
  • the Fig. 2 embodiment when operated to adjust secondary air but not catalyst recycle, maintains relatively constant air rates to the first regeneration stage, does not significantly alter - 26 -
  • the Fig 1 embodiment keeps the operation of the second regeneration stage at steady state and modifies the operation of the first stage to accommodate different coke makes.
  • either embodiment can use flue gas analysis, or a dT indicative of a flue gas composition, to adjust operation.
  • Fig. 3 provides a way to optimize coke burning in each stage of regeneration.
  • the Fig. 3 embodiment uses much of the hardware from the Fig. 1 embodiment, i.e., the primary difference in the Fig. 3 embodiment is simultaneous adjustment of both primary and secondary air. Air can e rationed between the two regenerations stages based on an analysis of flue gas compositions, or based on temperature differences.
  • Fig 3 includes symbols indicating temperature differences, e.g., dT-_ means that a signal is developed indicative of the temperature difference between two indicated temperatures, temperature 1 and temperature 2.
  • the amount of air added to the riser mixer is fixed, for simplicity, but this is merely to simplify the following analysis.
  • the riser mixer air is merely part of the primary air, and could vary with any variations in flow of air to the coke combustor. It is also possible to operate the regenerator with no riser mixer at all, in which case spent catalyst, recycled regenerated catalyst, and primary air are all added directly to the coke combustor. The use of a riser mixer is preferred.
  • the control scheme will first be stated in general terms, then reviewed in conjunction with Fig. 3.
  • the overall amount of combustion air i.e., the total air to the regenerator, is controlled based on flue gas compositions or on differential temperature.
  • Controlling the second stage flue gas composition by apportioning the air added to each combustion zone allows unit operation to be optimized even when the operator does not know the individual optima for the first and second stages. If the second fluidized bed, typically a bubbling dense bed with fairly poor contacting efficiency, is being called on to do too much, or if not enough combustion air is added to the second stage, bubbling dense bed, some CO breakthrough may occur.
  • the unit can be controlled by increasing the primary air, the air to the coke combustor.
  • the Fig. 3 embodiment also allows air apportionment based on differences in the fluidized bed temperatures in each stage.
  • the temperature difference between the fast fluidized bed coke combustor (1st stage) and the bubbling dense bed (2nd stage) is an indication of how much coke escaped the first stage and was burned in the second stage.
  • the particulars of each control scheme, as shown in Fig. 3 will now be reviewed.
  • the total air flow, in line 358 is controlled by means of a flue gas analyzer 361 or preferably by dT controller 350 which measures and controls the amount of afterburning above the second fluidized bed.
  • the bubbling dense bed temperature (T2) is sensed by thermocouple 334, and the dilute ph_.se temperature (T3) is monitored by thermocouple 336.
  • T2 The bubbling dense bed temperature
  • T3 the dilute ph_.se temperature
  • control signal is transmitted via transmission means 352 (an air line, or a digital or analogue electrical signal or equivalent signal transmission means) to valve 360 which regulates the total air flow to the regenerator via line 358.
  • transmission means 352 an air line, or a digital or analogue electrical signal or equivalent signal transmission means
  • valve 360 which regulates the total air flow to the regenerator via line 358.
  • flue gas analyzer controller 361 sending a signal via means 362 to valve 360.
  • the apportionment of air between the primary and secondary stages of regeneration is controlled either by the differences in temperature of the two relatively dense phase beds in the regenerator, or by the composition of the flue gas from the primary stage.
  • Apportionment based on dT12 requires measurement of the temperature (TI) in the coke combustor fast fluidized bed as determined by thermocouple 330 and in the second fluidized bed (T2) as determined by thermocouple 332, which can and preferably does share the signal generated by thermocouple 334.
  • Differential temperature controller 338 generates a signal based on dT12, or the difference in temperature between the two beds. Signals are sent via means 356 to valve 372 (primary air to the coke combustor) and via means 354 to valve 72 (secondary air to second fluidized bed) .
  • the dT controller 338 will compensate by sending more combustion air to the coke combustor and less to the second fluidized bed.
  • the operation of the coke combustor can be measured by a fast fluidized bed temperature (as shown) , by a temperature in the dilute phase of the coke combustor or in the dilute phase transport riser, a temperature measured in the primary cyclone or on a flue gas stream or catalyst stream discharged from the primary cyclone.
  • Air apportionment based on the flue gas composition from the coke combustor can also be used to generate a signal indicative of the amount of coke combustion occurring in the fast fluidized bed.
  • flue gas analyzer controller 661 can measure a flue gas composition, usually 02, in the primary flue gas, and send a signal via transmission means 661 to flow control valve 662.
  • the control method of Fig. 3. will be preferred for most refineries.
  • Another method of control is shown in Fig. 4, which can be used as an alternative to the Fig. 3 method.
  • the Fig. 4 control method retains the ability to apportion combustion air between the primary and secondary stages of regeneration, but adjusts feed preheat, and/or feed rate, rather than total combustion air, to maintain complete CO combustion.
  • the Fig. 4 control method is especially useful where a refiner's air blower capacity limits the throughput of the FCC unit. Leaving the air blower at maximum, and adjusting feed preheat and/or feed rate, will maximize the coke burning capacity of the unit by always running the air blower at maximum throughput.
  • the total amount of air added via line 358 is limited solely by the capacity of the compressor or air blower.
  • the apportionment of air between primary and secondary stages of combustion is controlled as in the Fig. 3 embodiment.
  • the feed rate and/or feed preheat are adjusted as necessary to maintain complete CO combustion in both stages. Feed preheat can affect coke make because the FCC reactor usually operates to control riser top temperature.
  • the hydrocarbon feed is mixed with sufficient hot, regenerated catalyst to maintain a given riser top temperature.
  • the temperature can be measured at other places in the reactor, as in the middle of the riser, at the riser outlet, cracked product outlet, or spent catalyst temperature before or after stripping, but usually the riser top temperature is used to control the amount of catalyst added to the base of the riser to crack fresh feed. If the feed is preheated to a very high temperature, and much or all of the feed is added as a vapor, less catalyst will be needed as compared to operation with a relatively cold liquid feed which is vaporized by hot catalyst. High feed preheat reduces the amount of catalyst circulation needed to maintain a given riser top temperature, and this reduced catalyst circulation " rate reduces coke make.
  • a composition based control signal from analyzer controller 361 may be sent via signal transmission means 384 to feed preheater 380 or to valve 390. Decreasing feed preheat, i.e., a cooler feed, increases coke make. Increasing feed rate increases coke make. Either action, or both together, will increase the coke make, and bring flue gas composition back to the desired point.
  • a differential temperature controller 350 may generate an analogous signal, transmitted via means 382 to adjust preheat and/or feed rate.
  • Fig. 5 shows the relative rate of CO burning as compared to the relative rate of carbon or coke burning on FCC catalyst.
  • the significance of the figure is that addition of Pt, or other equivalent CO combustion promoter, greatly increases the rate of CO combustion relative to coke combustion.
  • Most FCC units that operate in complete CO combustion mode operate with 0.1 to 1.0 ppm Pt.
  • the actual amount of Pt is not determinative, because new Pt promoter is more active than old promoter, and some supports make the Pt more effective.
  • Pt promoter typically used in a refinery, it is possible to greatly increase the rate of CO combustion, and achieve complete CO combustion in a high efficiency regenerator, without completely regenerating the catalyst as it passes through the coke combustor and dilute phase transport riser.
  • an operator can completely burn CO formed in the coke combustor and/or transport riser.
  • the operator can limit the amount of coke that is burned by limiting the residence time in the coke combustor, shifting air addition to downstream portions of the coke combustor or into the dilute phase transport riser and/or limiting the temperature in the coke combustor.
  • Residence time can be controlled by adjusting the catalyst holdup in the coke combustor. This can be done by changing the size of the vessels, which is not a practical means of control or by recycling inert gas to increase superficial vapor velocity without increasing oxygen content.
  • Shifting air addition to downstream, i.e., upper regions of the coke combustor or lower or middle regions of the dilute phase transport riser provides a more direct way of limiting coke combustion (to CO in the coke combustor) and then afterburning the CO in the dilute phase, short residence time, transport riser.
  • Control of temperature in the coke combustor will be the easiest way to limit coke combustion in most refineries.
  • All high efficiency regenerators are believed to have catalyst recirculation line, for recycle of hot regenerated catalyst to the coke combustor.
  • This catalyst recycle heats the incoming spent catalyst to a high enough temperature to promote rapid coke combustion in the coke combustor, and rapid CO burning in the dilute phase transport riser.
  • By restricting the amount of hot regenerated catalyst recycled to the coke combustor from the second fluidized bed it is possible to delay coke or retar ⁇ 3 coke combustion in the coke combustor.
  • the CO formed can still be afterburned in the transport riser because of the dilute phase conditions therein, or preferably because of the presence of twice as much, or more, CO combustion promoter as a refinery typically uses.
  • the riser mixer 60 may discharge into a cyclone or other separation means contained within the coke combustor. The resulting flue gas may be separately withdrawn from the unit, without entering the dilute phase transport riser.
  • Such a regenerator configuration is shown in EP A 0259115, published on March 9, 1988 and in US 4,868,144 which is incorporated herein by reference.
  • Any conventional FCC feed can be used.
  • the process of the present invention is especially useful for processing stocks which contain large amounts of sulfur.
  • the feeds may range from the typical, such as petroleum distillates or residual stocks, either virgin or partially refined, to the atypical, such as coal oils and shale oils.
  • the feed frequently will contain recycled hydrocarbons, such as light and heavy cycle oils which have already been subjected to cracking.
  • Preferred feeds are gas oils, vacuum gas oils, atmospheric resids, and vacuum resids.
  • the present invention is most useful with feeds having an initial boiling point above 343*C (650*F) .
  • 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 C0 2 within the FCC regenerator.
  • the catalyst inventory may also contain one or more additives, either present as separate additive particles or mixed in with each particle of the cracking catalyst.
  • Additives can be added to enhance octane (shape selective zeolites, i.e., those having a Constraint Index of 1-12, and typified by ZSM-5, and other materials having a similar crystal structure) or additives can remove Ni and V (Mg and Ca oxides) .
  • CO combustion additives are available from most FCC catalyst vendors.
  • the reactor may be either a riser cracking unit or dense bed unit or both.
  • Riser cracking is highly preferred.
  • Typical riser cracking reaction conditions include catalyst/oil ratios of 0.5:1 to 15:1 and preferably 3:1 to 8:1, and a catalyst contact time of 0.5-50 seconds, and preferably 1-20 seconds.
  • an atomizing feed mixing nozzle in the base of the riser reactor, such as ones available from Bete Fog. More details of use of such a nozzle in FCC processing is disclosed in USSN 424,420, which is incorporated herein by reference.
  • Hot strippers heat spent catalyst by adding some hot, regenerated catalyst to spent catalyst.
  • a good hot stripper design is shown in US 4,820,404 Owen, which is incorporated herein by reference.
  • a catalyst cooler cools the heated catalyst before it is sent to the catalyst regenerator.
  • the FCC reactor and stripper conditions, per se. can be conventional and form no part of the present invention.
  • the process and apparatus of the present invention can use many conventional elements most of which are conventional in FCC regenerators.
  • the present invention will usually use as its starting point a high efficiency regenerator such as is shown in the Figures.
  • the essential elements include a coke combustor, a dilute phase transport riser and a second fluidized bed. These elements are generally known.
  • Preferred regenerator elements include a riser mixer upstream of the coke combustor and quick separation of catalyst from steam laden flue gas exiting the regenerator transport riser.
  • a significantly increased catalyst inventory in the second fluidized bed of the regenerator, and means for adding a significant amount of combustion air for coke combustion in the second fluidized bed are preferably present or added.
  • Each part of the regenerator will be briefly reviewed below, starting with the riser mixer and ending with the regenerator flue gas cyclones.
  • Spent catalyst and some combustion air are charged to the riser mixer 60.
  • Some regenerated catalyst, recycled through the catalyst stripper, will usually be mixed in with the spent catalyst.
  • Some regenerated catalyst may also be directly recycled to the base of the riser mixer 60, either directly or, preferably, after passing through a catalyst cooler.
  • Riser mixer 60 is a preferred way to get the regeneration started.
  • the riser mixer typically burns most of the fast coke (probably representing entrained or adsorbed hydrocarbons) and a very small amount of the hard coke.
  • the residence time in the riser mixer is usually very short. The amount of hydrogen and carbon removed, and the reaction conditions needed to achieve this removal are reported below.
  • the coke combustor 62 contains a fast fluidized bed or perhaps a turbulent fluid bed of catalyst. It is characterized by relatively high superficial vapor velocity, vigorous fluidization, and a relatively low density dense phase fluidized bed. Most of the coke can be burned in the coke combustor. The coke combustor will also efficiently burn "fast coke", primarily unstripped hydrocarbons, on spent catalyst. When a riser mixer is used, a large portion, perhaps most, of the "fast coke” will be removed upstream of the coke combustor. If no riser mixer is used, then the relatively easy job of burning the fast coke will be done in the coke combustor.
  • the dilute phase transport riser 83 forms a dilute phase where efficient afterburning of CO to C0 2 can occur.
  • the riser efficiently transfers catalyst from the fast fluidized bed through a catalyst separation means to the second fluidized bed.
  • Additional air can be added to the inlet of, or the upstream 1/2 of, the dilute phase transport riser to promote CO combustion without increasing the coke burning rate, as would occur if the extra air was added to the coke combustor.
  • Multistage regeneration can be achieved in older high efficiency regenerators which do not have a very efficient means of separating flue gas from catalyst exiting the dilute phase transport riser. Even in these older units a reasonably efficient multistage regeneration of catalyst can be achieved by reducing the air added to the coke combustor and increasing the air added to the second fluidized bed. The reduced vapor velocity in the transport riser, and increased vapor velocity immediately above the second fluidized bed, will more or less segregate the flue gas from the transport riser from the flue gas from the second fluidized bed.
  • the dilute phase mixture is quickly separated into a catalyst rich dense phase and a catalyst lean dilute phase.
  • the quick separation of catalyst and flue gas sought in the regenerator transport riser outlet is similar to the quick separation of catalyst and cracked products sought in the riser reactor outlet.
  • the most preferred separation system is discharge of the regenerator transport riser dilute phase into a closed cyclone system such as that disclosed in US 4,502,947.
  • a closed cyclone system such as that disclosed in US 4,502,947.
  • Acceptable separation means include a capped riser outlet discharging catalyst down through an annular space defined by the riser top and a covering cap.
  • the transport riser outlet may be capped with radial arms, not shown, which direct the bulk of the catalyst into large diplegs leading down into the second fluidized bed of catalyst in the regenerator.
  • a regenerator riser outlet is disclosed in US Patent 4,810,360, which is incorporated herein by reference. - 42 -
  • Well designed closed cyclones can recover in excess of 95, and even in excess of 98% of the catalyst exiting the transport riser. By closing the cyclones, well over 95%, and even more than 98% of the steam laden flue gas exiting the transport riser can be
  • At least 90% of the catalyst discharged from the transport riser preferably is quickly discharged into a second fluidized bed, discussed below. At least 90% of the flue gas exiting the transport riser should be removed from the vessel without further contact with catalyst. This can be achieved to some extent by proper selection of bed geometry above the second fluidized bed, i.e., use of a relatively tall but thin containment vessel 80, and careful control of fluidizing conditions in the second fluidized bed.
  • the second fluidized bed achieves a second stage of catalyst regeneration in a relatively dry atmosphere.
  • the multistage regeneration of catalyst is beneficial from a temperature standpoint alone, i.e., it keeps the average catalyst temperature lower than the last stage temperature.
  • the second fluidized bed bears a superficial resemblance to the second dense bed used in prior art, high efficiency regenerators.
  • refiners add CO combustion promoter to promote total or partial combustion of CO to CO, within the FCC regenerator.
  • excess promoter is present, preferably twice the amount of promoter or twice the CO oxidation activity as measured in standard CO oxidation activity tests.
  • the well stripped catalyst at a temperature of about 621'C (1150*F), combines with air from line 66 in •riser mixer 60 to form an air-catalyst mixture.
  • the mixture rises into the coke combustor fast fluid bed 76.
  • some hot regenerated catalyst is added to the coke combustor, recirculation is restricted to retard somewhat carbon burning.
  • a slightly lower temperature in the coke combustor, of about 1150* -1250*F is preferred
  • the catalyst and combustion air/flue gas mixture elutes up from fast fluid bed 76 through the dilute phase transport riser 83 and into a regenerator vessel 80.
  • the catalyst exiting the riser 83 is separated from steam laden flue gas by closed cyclones 308.
  • a catalyst rich phase passes down through the dipleg 84 to form a second fluidized bed 82.
  • About 5% of the coke on the stripped catalyst burns in the conduit 60, about 40% is burned in the fast fluid bed 62, about 5% in the riser 83, and about 50% in the regenerator vessel 80. Due to the coke burning, the temperature of the catalyst increases as it passes through the unit. Air addition is controlled, using the control method shown in Fig. 3, to ensure complete CO combustion in both stages, and maximize the coke burning capacity of the unit.
  • control method of the present invention can be readily added to existing high efficiency regenerators. Most of the regenerator can be left untouched, as the modifications to install differential temperature probes in the regenerator cyclones, or flue gas analyzers, are minor. Usually only minor modifications will be needed in the second dense bed to accommodate the added air and perhaps to add extra air rings.
  • the riser mixer (if used) , the coke combustor, and the dilute phase transport riser require no modification.
  • the only modification strongly recommended for existing high efficiency regenerators is incorporation of a means at the exit of the dilute phase transport riser to rapidly and completely separate catalyst from steam laden flue gas.
  • the steam laden flue gas should be isolated from the catalyst collected in the second dense bed.
  • a closed cyclone system is used to separate and isolate steam laden flue gas from catalyst.
  • Preferably much, and even most, of the coke combustion occurs in the dry atmosphere of the second dense bed. Temperatures in the second fluidized bed are high, so rapid coke combustion can be achieved even in a bubbling fluidized bed.
  • the process and apparatus of the present invention also permits continuous on stream optimization of the catalyst regeneration process.
  • Two powerful and sensitive methods of controlling air addition rates permit careful fine tuning of the process. Achieving a significant amount of coke combustion in the second dense bed of a high e ficiency regenerator also increases the coke burning capacity of the unit, for very little capital expenditure.
  • Measurement of delta T when cyclone separators are used on the regenerator transport riser outlet, provides a very sensitive way to monitor the amount of afterburning occurring, and provides another way to maximize use of existing air blower capacity. It may be necessary to bring in auxiliary compressors, or a tank of oxygen gas, to supplement the existing air blower. Although many existing high efficiency regenerators can, using the process of the present invention, achieve large increases in coke burning capacity by shifting the coke combustion to the second dense bed, the existing air blowers will almost never be sized large enough to take maximum advantage of the heretofore dormant coke burning capacity of the second dense bed.

Landscapes

  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Organic Chemistry (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Materials Engineering (AREA)
  • General Chemical & Material Sciences (AREA)
  • Combustion & Propulsion (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

Le procédé et l'appareil décrits servent à assurer une régénération multiphase commandée de catalyseurs à craquage catalytique fluidisé (FFC). On utilise à cet effet un régénérateur de catalyseurs hautement efficace modifié, qui comporte une cellule de combustion de coke à lit fluidisé rapide, un conduit montant de transport de phase diluée et un second lit fluidisé et qui régénère le catalyseur dans deux zones au moins, qui travaillent toutes deux avec une combustion complète du CO. La première phase de régénération se produit dans la cellule de combustion du coke. La seconde phase de régénération du catalyseur se produit dans le second lit fluidisé. La quantité de gaz de combustion et/ou la vitesse d'amenée du matériau de base, le préchauffage du matériau de base, la remise en circulation du catalyseur vers la cellule de combustion du coke et la vitesse d'addition du promoteur d'oxydation de CO sont commandés de façon à permettre la conservation d'une combustion complète du CO dans les deux zones. Une telle régénération multiphase commandée réduit la vaporisation ou la désactivation du catalyseur pendant sa régénération, augmente la capacité de combustion de coke du régénérateur et maximise l'efficacité des sorbeurs de SOx.
PCT/US1991/005019 1990-07-17 1991-07-16 Procede et appareil servant a commander la regeneration multiphase de catalyseurs avec combustion complete du co WO1992001511A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US55432290A 1990-07-17 1990-07-17
US554,322 1990-07-17

Publications (1)

Publication Number Publication Date
WO1992001511A1 true WO1992001511A1 (fr) 1992-02-06

Family

ID=24212915

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US1991/005019 WO1992001511A1 (fr) 1990-07-17 1991-07-16 Procede et appareil servant a commander la regeneration multiphase de catalyseurs avec combustion complete du co

Country Status (2)

Country Link
AU (1) AU8293891A (fr)
WO (1) WO1992001511A1 (fr)

Cited By (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0610186A1 (fr) * 1991-10-30 1994-08-17 Mobil Oil Corporation Procede de regeneration d'un catalyseur use de craquage catalytique fluidifie
WO1996029148A1 (fr) * 1995-03-20 1996-09-26 Shell Internationale Research Maatschappij B.V. Procede de regeneration d'un catalyseur
US5766638A (en) * 1995-12-08 1998-06-16 The Dow Chemical Company Hydroxypropyl methocellulose ether compositions for reduction of serum lipid levels
FR2784602A1 (fr) * 1998-10-20 2000-04-21 Eurecat Europ Retrait Catalys Procede de traitement d'un catalyseur ou d'un adsorbant en lit fluidise
US6403515B1 (en) 1998-10-20 2002-06-11 Institut Francais Du Petrole Process for treating a catalyst or an adsorbent in a fluidized bed
WO2013089848A1 (fr) * 2011-12-15 2013-06-20 Uop Llc Zones de calcination multiples avec des boucles de circulation indépendantes
RU2574385C1 (ru) * 2011-12-15 2016-02-10 Юоп Ллк Ряд зон выжигания катализатора с независимыми контурами циркуляции

Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4146463A (en) * 1976-10-12 1979-03-27 Standard Oil Company (Indiana) Removal of carbon monoxide and sulfur oxides from refinery flue gases
US4199287A (en) * 1978-06-12 1980-04-22 Besser Industries, Inc. Method and apparatus for stacking block-like articles
US4211636A (en) * 1975-08-27 1980-07-08 Mobil Oil Corporation FCC Catalyst section control
US4290878A (en) * 1978-12-08 1981-09-22 Chevron Research Company NOx control in platinum-promoted complete combustion cracking catalyst regeneration
US4812430A (en) * 1987-08-12 1989-03-14 Mobil Oil Corporation NOx control during multistage combustion
US4849091A (en) * 1986-09-17 1989-07-18 Uop Partial CO combustion with staged regeneration of catalyst

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4211636A (en) * 1975-08-27 1980-07-08 Mobil Oil Corporation FCC Catalyst section control
US4146463A (en) * 1976-10-12 1979-03-27 Standard Oil Company (Indiana) Removal of carbon monoxide and sulfur oxides from refinery flue gases
US4199287A (en) * 1978-06-12 1980-04-22 Besser Industries, Inc. Method and apparatus for stacking block-like articles
US4290878A (en) * 1978-12-08 1981-09-22 Chevron Research Company NOx control in platinum-promoted complete combustion cracking catalyst regeneration
US4849091A (en) * 1986-09-17 1989-07-18 Uop Partial CO combustion with staged regeneration of catalyst
US4812430A (en) * 1987-08-12 1989-03-14 Mobil Oil Corporation NOx control during multistage combustion

Cited By (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0610186A1 (fr) * 1991-10-30 1994-08-17 Mobil Oil Corporation Procede de regeneration d'un catalyseur use de craquage catalytique fluidifie
EP0610186A4 (fr) * 1991-10-30 1995-02-22 Mobil Oil Corp Procede de regeneration d'un catalyseur use de craquage catalytique fluidifie.
WO1996029148A1 (fr) * 1995-03-20 1996-09-26 Shell Internationale Research Maatschappij B.V. Procede de regeneration d'un catalyseur
AU686937B2 (en) * 1995-03-20 1998-02-12 Shell Internationale Research Maatschappij B.V. Process for catalyst regeneration
CN1079290C (zh) * 1995-03-20 2002-02-20 国际壳牌研究有限公司 催化剂再生的方法
US5766638A (en) * 1995-12-08 1998-06-16 The Dow Chemical Company Hydroxypropyl methocellulose ether compositions for reduction of serum lipid levels
FR2784602A1 (fr) * 1998-10-20 2000-04-21 Eurecat Europ Retrait Catalys Procede de traitement d'un catalyseur ou d'un adsorbant en lit fluidise
EP1002581A1 (fr) * 1998-10-20 2000-05-24 Eurecat Europeenne De Retraitement De Catalyseurs Procédé de traitement d'un catalyseur ou d'un adsorbant en lit fluidise
US6403515B1 (en) 1998-10-20 2002-06-11 Institut Francais Du Petrole Process for treating a catalyst or an adsorbent in a fluidized bed
WO2013089848A1 (fr) * 2011-12-15 2013-06-20 Uop Llc Zones de calcination multiples avec des boucles de circulation indépendantes
RU2574385C1 (ru) * 2011-12-15 2016-02-10 Юоп Ллк Ряд зон выжигания катализатора с независимыми контурами циркуляции

Also Published As

Publication number Publication date
AU8293891A (en) 1992-02-18

Similar Documents

Publication Publication Date Title
US5077252A (en) Process for control of multistage catalyst regeneration with partial co combustion
AU649268B2 (en) Process for control of multistage catalyst regeneration with full then partial CO combustion
EP0420967B1 (fr) Procede et appareil de craquage catalytique de petrole brut lourd
US5000841A (en) Heavy oil catalytic cracking process and apparatus
US5248408A (en) Catalytic cracking process and apparatus with refluxed spent catalyst stripper
US5183558A (en) Heavy oil catalytic cracking process and apparatus
US5077251A (en) Control of multistage catalyst regeneration with both partial and full co combustion
US5128109A (en) Heavy oil catalytic cracking apparatus
EP0610186B1 (fr) Procede de regeneration d'un catalyseur use de craquage catalytique fluidifie
WO1992001511A1 (fr) Procede et appareil servant a commander la regeneration multiphase de catalyseurs avec combustion complete du co
US5126036A (en) Process and apparatus for split feed of spent catalyst to high efficiency catalyst regenerator
EP0415935B1 (fr) Craquage catalytique d'huile lourde
WO1993000673A1 (fr) Procede de rectification et de regeneration d'un catalyseur de craquage catalytique fluidise
WO1993008912A1 (fr) Procede de regeneration d'un catalyseur use de craquage catalytique fluidifie
AU8221391A (en) A process for stripping and regenerating fluidized catalytic cracking catalyst

Legal Events

Date Code Title Description
AK Designated states

Kind code of ref document: A1

Designated state(s): AU CA JP

AL Designated countries for regional patents

Kind code of ref document: A1

Designated state(s): AT BE CH DE DK ES FR GB GR IT LU NL SE

NENP Non-entry into the national phase

Ref country code: CA