WO2010101686A2 - Procédé pour éviter une cokéfaction catalysée par un métal - Google Patents

Procédé pour éviter une cokéfaction catalysée par un métal Download PDF

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Publication number
WO2010101686A2
WO2010101686A2 PCT/US2010/022706 US2010022706W WO2010101686A2 WO 2010101686 A2 WO2010101686 A2 WO 2010101686A2 US 2010022706 W US2010022706 W US 2010022706W WO 2010101686 A2 WO2010101686 A2 WO 2010101686A2
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WO
WIPO (PCT)
Prior art keywords
reactor
catalyst
riser
feed
line
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PCT/US2010/022706
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English (en)
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WO2010101686A3 (fr
Inventor
Keith A. Couch
Christopher D. Gosling
Original Assignee
Uop Llc
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
Priority claimed from US12/397,663 external-priority patent/US8124020B2/en
Priority claimed from US12/397,647 external-priority patent/US8124822B2/en
Application filed by Uop Llc filed Critical Uop Llc
Priority to CN201080010494.1A priority Critical patent/CN102341483B/zh
Priority to RU2011140159/04A priority patent/RU2505584C2/ru
Priority to BRPI1009534A priority patent/BRPI1009534A2/pt
Priority to JP2011552955A priority patent/JP5607082B2/ja
Publication of WO2010101686A2 publication Critical patent/WO2010101686A2/fr
Publication of WO2010101686A3 publication Critical patent/WO2010101686A3/fr

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Classifications

    • 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
    • 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
    • C10G70/00—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00
    • C10G70/04—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00 by physical processes
    • C10G70/041—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00 by physical processes by distillation
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/202—Heteroatoms content, i.e. S, N, O, P
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/207—Acid gases, e.g. H2S, COS, SO2, HCN
    • 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
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/20—C2-C4 olefins

Definitions

  • This invention generally relates to an apparatus and process for producing desired products, such as light olefins including propylene.
  • Fluid catalytic cracking is a catalytic hydrocarbon conversion process accomplished by contacting heavier hydrocarbons in a fluidized reaction zone with a catalytic particulate material.
  • the reaction in catalytic cracking, as opposed to hydrocracking, is carried out in the absence of substantial added hydrogen or the consumption of hydrogen.
  • substantial amounts of highly carbonaceous material referred to as coke are deposited on the catalyst to provide coked or spent catalyst.
  • Vaporous lighter products are separated from spent catalyst in a reactor vessel.
  • Spent catalyst may be subjected to stripping over an inert gas such as steam to strip entrained hydrocarbonaceous gases from the spent catalyst.
  • a high temperature regeneration with oxygen within a regeneration zone operation burns coke from the spent catalyst which may have been stripped.
  • Various products may be produced from such a process, including a gasoline product and/or light product such as propylene and/or ethylene.
  • a single reactor or a dual reactor can be utilized. Although additional capital costs may be incurred by using a dual reactor apparatus, one of the reactors can be operated to tailor conditions for maximizing products, such as light olefins including propylene and/or ethylene.
  • Feedstock to the secondary riser may be an FCC recycle or C IQ- material from other process units.
  • MCC Metal Catalyzed Coking
  • the sulfur species in the sulfiding agent is provided as hydrogen sulfide or provides a source of hydrogen sulfide, either by decomposition, liberation, or other chemical reaction, that subsequently forms a metal sulfide layer on the interior metal surface of the reactor internals.
  • the layer of metal sulfide isolates the vapor phase coke precursors from the active metal sites on the internal surface to inhibit coking.
  • FIGURE is a schematic drawing of the present invention. DETAILED DESCRIPTION OF THE DRAWING
  • MCC is characterized by a deposition of carbonaceous solids on hot metal surfaces and develops in processes in excess of 400 0 C, with a peak filamentous carbon formation rate in the range of 550° to 600 0 C.
  • MCC can be a function of thermal decomposition, or catalytic reaction with the active metals and can have a considerable impact on a number of commercial processes including, catalytic steam reforming of methane, steam cracking of paraffmic feed stocks and processes involving carbon monoxide disproportionation reactions. It is well known that certain metals can increase the overall MCC deposition rate by catalyzing the growth of filamentous and graphitic types of deposits.
  • the highest catalytic activity for carbon deposition is exhibited by iron, cobalt and nickel, and alloys containing these metals.
  • An overall catalytic reaction pathway for MCC is generally believed to be the adsorption of ethylene, propylene or butylene onto a metal surface. The adsorbed light olefin then undergoes further dehydrogenation conversion to aromatics and alkyl aromatics which further condense until coke is formed.
  • Typical FCC reactions operate in the range of 500° to 600 0 C, which corresponds to the peak reaction rate for filamentous carbon formation.
  • the most active metals identified to promote MCC are present in an FCC unit.
  • the active hydrocarbon species that promote filamentous carbon formation are ethylene, propylene and butylene which are the target products from high propylene producing FCC technologies. Consequently, we believe the coking problem in secondary FCC riser processes is attributed to MCC.
  • MCC has not historically been observed in FCC operations. Most FCC units process feed stocks with substantial quantities of sulfur, typically 0.1 to 1.0 wt-%. Sulfur present in FCC feed decomposes to hydrogen sulfide which adsorbs on the metal surface to form a metal sulfide layer which isolates gas phase coke precursors from active metal sites on internal FCC reactor surfaces, thereby mitigating coke formation.
  • Sulfur present in FCC feed decomposes to hydrogen sulfide which adsorbs on the metal surface to form a metal sulfide layer which isolates gas phase coke precursors from active metal sites on internal FCC reactor surfaces, thereby mitigating coke formation.
  • the hydrogen sulfide generated by cracking the primary FCC feed is not typically present in the naphtha feed recycled to secondary FCC riser.
  • Organic sulfur in the primary FCC products distributes preferentially to hydrogen sulfide and coke in the reaction products, then distributes preferentially into the heavier products, with the least amount of sulfur remaining in the naphtha and liquefied petroleum gas (LPG).
  • LPG liquefied petroleum gas
  • the naphtha can be largely deficient of contaminant sulfur, resulting in insufficient sulfide layering on the metal in the secondary riser to prevent MCC.
  • Even if sulfur is present in the naphtha unless it is of a form that will thermally decompose to form hydrogen sulfide, it will not form a layer to passivate the active metals that contribute to MCC.
  • the sulfiding agent can be hydrogen sulfide or an organic sulfur compound that decomposes to hydrogen sulfide in a catalytic conversion environment and particularly a fluid catalytic cracking environment.
  • the hydrogen sulfide can be provided in dry gas fed to the secondary reactor prior to amine treating.
  • Hydrogen sulfide may also be provided by adding a commercially available SO x scavenging additive, such as a magnesium aluminum oxide having a spinel structure, to the circulating catalyst inventory.
  • the additive adsorbs SO x in the oxidizing environment of the regenerator and desorbs hydrogen sulfide in the reducing environment of the reactor riser.
  • SO x additive to provide sufficient hydrogen sulfide content in the second reactor is highly dependent on the sulfur content of the feedstock to the first reactor.
  • Preferred organic sulfur sources include commercially available sulfiding agents such as methyl sulfides like dimethyl sulfide (DMS) or dimethyl disulfide (DMDS), mercaptans and polysulfides which have been conventionally used in industrial practice as sulfiding agents for hydroprocessing units and pyro lysis furnaces.
  • organic sulfur sulfiding agents degrade into hydrogen sulfide in a fluid catalytic cracking and other reaction environments.
  • Sulfur containing oils in the FCC product such as LCO, HCO and CSO are not preferred sulfiding agents because they are not expected to effectively thermally decompose to generate the quantities of hydrogen sulfide required to passivate the active metals.
  • these heavy FCC products may be effective.
  • Lighter FCC products such as naphtha and LPG may also be effective sulfiding agents under certain conditions if sulfide compounds are not removed therefrom.
  • the addition of hydrogen sulfide bearing dry gas is preferably added to a fluidizing gas distributor or as an atomizing dispersion media to feed distributors for a riser reactor.
  • the organic sulfur sulfiding agents may be added to a fluidizing gas distributor or preferably to the feed system any point upstream of the feed distributors.
  • the maximum sulfur rate is not limited, but is suitably in the range of 20 to 2000 wppm and preferably 50 to
  • the sulfiding agent should be added on a continuous basis because coking onset is very fast, and the sulfide will adsorb and desorb from the active metals on a continuous basis.
  • the present invention may be described with reference to four components: a primary or first reactor 10, a regenerator vessel 60, a product fractionation section 90 and a second reactor 170.
  • a primary or first reactor 10 a regenerator vessel 60
  • a product fractionation section 90 a product fractionation section 90
  • second reactor 170 a specific embodiment is presented herein by way of example. All other possible embodiments for carrying out the present invention are considered within the scope of the present invention.
  • the first and second reactors 10, 170 are not FCC reactors, one or both of the regenerator vessel 60 and the product fractionation section 90 may be optional.
  • the invention may be embodied in a single FCC reactor 170.
  • the FIGURE shows the first reactor 10 which may be an FCC reactor that includes a first reactor riser 12 and a first reactor vessel 20.
  • a regenerator catalyst pipe 14 in upstream communication with the first reactor riser 12 meaning that that material flow is permitted from the regenerator catalyst pipe 14 to the first reactor riser 12. Communication means that material flow is permitted between enumerated regions.
  • the regenerator catalyst pipe 14 delivers regenerated catalyst from the regenerator vessel 60 at a rate regulated by a control valve 16 to the reactor riser 12 through a regenerated catalyst inlet.
  • a fluidization medium such as steam from a distributor 18 urges a stream of regenerated catalyst upwardly through the first reactor riser 12 at a relatively high density.
  • a plurality of feed distributors 22 in upstream communication with the first reactor riser 12 inject a first hydrocarbon feed 8, preferably with an inert atomizing gas such as steam, across the flowing stream of catalyst particles to distribute hydrocarbon feed to the first reactor riser 12.
  • a first hydrocarbon feed 8 preferably with an inert atomizing gas such as steam
  • the heavier hydrocarbon feed cracks to produce lighter gaseous first cracked products while conversion coke and contaminant coke precursors are deposited on the catalyst particles to produce coked catalyst.
  • a conventional FCC feedstock and higher boiling hydrocarbon feedstock are a suitable first feed 8 to the first FCC reactor.
  • VGO vacuum gas oil
  • Heavy hydrocarbon feedstocks to which this invention may be applied include heavy bottoms from crude oil, heavy bitumen crude oil, shale oil, tar sand extract, deasphalted residue, products from coal liquefaction, atmospheric and vacuum reduced crudes. Heavy feedstocks for this invention also include mixtures of the above hydrocarbons and the foregoing list is not comprehensive.
  • the first feed 8 has a temperature of 140° to 320 0 C.
  • additional amounts of feed may also be introduced downstream of the initial feed point.
  • the first reactor vessel 20 is in downstream communication with the first reactor riser 12 meaning that material flow is permitted from the first reactor riser 12 to the first reactor vessel 20.
  • the resulting mixture of gaseous product hydrocarbons and spent catalyst continues upwardly through the first reactor riser 12 and are received in the first reactor vessel 20 in which the spent catalyst and gaseous product are separated.
  • a pair of disengaging arms 24 may tangentially and horizontally discharge the mixture of gas and catalyst from a top of the first reactor riser 12 through one or more outlet ports 26 (only one is shown) into a disengaging vessel 28 that effects partial separation of gases from the catalyst.
  • a transport conduit 30 carries the hydrocarbon vapors, including stripped hydrocarbons, stripping media and entrained catalyst to one or more cyclones 32 in the first reactor vessel 20 which separates spent catalyst from the hydrocarbon gaseous product stream.
  • the disengaging vessel 28 is partially disposed in the first reactor vessel 20 and can be considered part of the first reactor vessel 20.
  • Gas conduits 34 deliver separated hydrocarbon gaseous streams from the cyclones 32 to a collection plenum 36 in the first reactor vessel 20 for passage to a product line 88 via an outlet nozzle 38 and eventually into the product fractionation section 90 for product recovery.
  • Diplegs 40 discharge catalyst from the cyclones 32 into a lower bed 42 in the first reactor vessel 20.
  • the catalyst with adsorbed or entrained hydrocarbons may eventually pass from the lower bed 42 into an optional stripping section 44 across ports 46 defined in a wall of the disengaging vessel 28. Catalyst separated in the disengaging vessel 28 may pass directly into the optional stripping section 44 via a bed 48.
  • a fluidizing distributor 50 delivers inert fluidizing gas, typically steam, to the stripping section 44.
  • the stripping section 44 contains baffles 52 or other equipment to promote contacting between a stripping gas and the catalyst.
  • the stripped spent catalyst leaves the stripping section 44 of the disengaging vessel 28 of the first reactor vessel 20 with a lower concentration of entrained or adsorbed hydrocarbons than it had when it entered or if it had not been subjected to stripping.
  • the spent catalyst preferably stripped, leaves the disengaging vessel 28 of the first reactor vessel 20 through a spent catalyst conduit 54 and passes into the regenerator vessel 60 at a rate regulated by a slide valve 56.
  • the first reactor riser 12 can operate at any suitable temperature, and typically operates at a temperature of 150° to 58O 0 C, preferably 520° to 58O 0 C at the riser outlet 24. In one exemplary embodiment, a higher riser temperature may be desired, such as no less than 565°C at the riser outlet port 24 and a pressure of from 69 to 517 kPa (gauge) (10 to 75 psig) but typically less than 275 kPa (gauge) (40 psig).
  • the catalyst-to-oil ratio based on the weight of catalyst and feed hydrocarbons entering the bottom of the riser, may range up to 30:1 but is typically between 4:1 and 10:1 and may range between 7:1 and 25:1. Hydrogen is not normally added to the riser. Steam may be passed into the first reactor riser 12 and first reactor vessel 20 equivalent to 2 to 35 wt-% of feed. Typically, however, the steam rate will be between 2 and 7 wt-% for maximum gasoline production and 10 to 15 wt-% for maximum light olefin production. The average residence time of catalyst in the riser may be less than 5 seconds. [0019]
  • the catalyst in the first reactor 10 can be a single catalyst or a mixture of different catalysts.
  • the catalyst includes two components or catalysts, namely a first component or catalyst, and a second component or catalyst.
  • a catalyst mixture is disclosed in, e.g., US 7,312,370 B2.
  • the first component may include any of the well-known catalysts that are used in the art of FCC, such as an active amorphous clay-type catalyst and/or a high activity, crystalline molecular sieve. Zeolites may be used as molecular sieves in FCC processes.
  • the first component includes a large pore zeolite, such as a Y-type zeolite, an active alumina material, a binder material, including either silica or alumina, and an inert filler such as kaolin.
  • the zeolitic molecular sieves appropriate for the first component have a large average pore size.
  • molecular sieves with a large pore size have pores with openings of greater than 0.7 nm in effective diameter defined by greater than 10, and typically 12, member rings. Pore Size Indices of large pores can be above 31.
  • Suitable large pore zeolite components may include synthetic zeolites such as X and Y zeolites, mordenite and faujasite.
  • a portion of the first component, such as the zeolite, can have any suitable amount of a rare earth metal or rare earth metal oxide.
  • the second component may include a medium or smaller pore zeolite catalyst, such as a MFI zeolite, as exemplified by at least one of ZSM-5, ZSM-11, ZSM- 12, ZSM-23, ZSM-35, ZSM-38, ZSM-48, and other similar materials.
  • a medium or smaller pore zeolite catalyst such as a MFI zeolite
  • Other suitable medium or smaller pore zeolites include ferrierite, and erionite.
  • the second component has the medium or smaller pore zeolite dispersed on a matrix including a binder material such as silica or alumina and an inert filler material such as kaolin.
  • the second component may also include some other active material such as Beta zeolite.
  • compositions may have a crystalline zeolite content of 10 to 50 wt-% or more, and a matrix material content of 50 to 90 wt-%.
  • Components containing 40 wt-% crystalline zeolite material are preferred, and those with greater crystalline zeolite content may be used.
  • medium and smaller pore zeolites are characterized by having an effective pore opening diameter of less than or equal to 0.7 nm, rings of 10 or fewer members, and a Pore Size Index of less than 31.
  • the second catalyst component is an MFI zeolite having a silicon to aluminum ratio greater than 15, preferably greater than 75. In one exemplary embodiment, the silicon to aluminum ratio can be 15:1 to 35:1.
  • the total mixture in the first reactor 10 may contain 1 to 25 wt-% of the second component, namely a medium to small pore crystalline zeolite with greater than or equal to 1.75 wt-% of the second component being preferred.
  • the second component contains 40 wt-% crystalline zeolite with the balance being a binder material, an inert filler, such as kaolin, and optionally an active alumina component
  • the mixture may contain 4 to 40 wt-% of the second catalyst with a preferred content of at least 7 wt-%.
  • the first component may comprise the balance of the catalyst composition. In some preferred embodiments, the relative proportions of the first and second components in the mixture may not substantially vary throughout the first reactor 10.
  • the high concentration of the medium or smaller pore zeolite as the second component of the catalyst mixture can improve selectivity to light olefins.
  • the second component can be a ZSM-5 zeolite and the mixture can include 4 to 10 wt-% ZSM-5 zeolite excluding any other components, such as binder and/or filler.
  • the regenerator vessel 60 is in downstream communication with the first reactor vessel 20. In the regenerator vessel 60, coke is combusted from the portion of spent catalyst delivered to the regenerator vessel 60 by contact with an oxygen-containing gas such as air to provide regenerated catalyst.
  • the regenerator vessel 60 may be a combustor type of regenerator as shown in the FIGURE, which may use hybrid turbulent bed-fast fluidized conditions in a high-efficiency regenerator vessel 60 for completely regenerating spent catalyst. However, other regenerator vessels and other flow conditions may be suitable for the present invention.
  • the spent catalyst conduit 54 feeds spent catalyst to a first or lower chamber 62 defined by an outer wall through a spent catalyst inlet.
  • the spent catalyst from the first reactor vessel 20 usually contains carbon in an amount of from 0.2 to 2 wt-%, which is present in the form of coke. Although coke is primarily composed of carbon, it may contain from 3 to 12 wt-% hydrogen as well as sulfur and other materials.
  • An oxygen-containing combustion gas typically air, enters the lower chamber 62 of the regenerator vessel 60 through a conduit and is distributed by a distributor 64. As the combustion gas enters the lower chamber 62, it contacts spent catalyst entering from spent catalyst conduit 54 and lifts the catalyst at a superficial velocity of combustion gas in the lower chamber 62 of perhaps at least 1.1 m/s (3.5 ft/s) under fast fluidized flow conditions.
  • the lower chamber 62 may have a catalyst density of from 48 to 320 kg/m 3 (3 to 20 lb/ft 3 ) and a superficial gas velocity of 1.1 to 2.2 m/s (3.5 to 7 ft/s).
  • the oxygen in the combustion gas contacts the spent catalyst and combusts carbonaceous deposits from the catalyst to at least partially regenerate the catalyst and generate flue gas.
  • the mixture of catalyst and combustion gas in the lower chamber 62 ascend through a frustoconical transition section 66 to the transport, riser section 68 of the lower chamber 62.
  • the riser section 68 defines a tube which is preferably cylindrical and extends preferably upwardly from the lower chamber 62.
  • the mixture of catalyst and gas travels at a higher superficial gas velocity than in the lower chamber 62.
  • the increased gas velocity is due to the reduced cross-sectional area of the riser section 68 relative to the cross-sectional area of the lower chamber 62 below the transition section 66.
  • the superficial gas velocity may usually exceed 2.2 m/s (7 ft/s).
  • the riser section 68 may have a catalyst density of less than 80 kg/m 3 (5 lb/ft 3 ).
  • the regenerator vessel 60 also includes an upper or second chamber 70.
  • the mixture of catalyst particles and flue gas is discharged from an upper portion of the riser section 68 into the upper chamber 70.
  • Substantially completely regenerated catalyst may exit the top of the transport, riser section 68, but arrangements in which partially regenerated catalyst exits from the lower chamber 62 are also contemplated.
  • Discharge is effected through a disengaging device 72 that separates a majority of the regenerated catalyst from the flue gas.
  • catalyst and gas flowing up the riser section 68 impact a top elliptical cap of the riser section 68 and reverse flow.
  • Catalyst densities in the dense catalyst bed 74 are typically kept within a range of from 640 to 960 kg/m ⁇ (40 to 60 lb/fP).
  • a fluidizing conduit delivers fluidizing gas, typically air, to the dense catalyst bed 74 through a fluidizing distributor 86.
  • hot regenerated catalyst from a dense catalyst bed 74 in the upper chamber 70 may be recirculated into the lower chamber 62 via recycle conduit 80.
  • the regenerator vessel 60 may typically require 14 kg of air per kg of coke removed to obtain complete regeneration. When more catalyst is regenerated, greater amounts of feed may be processed in the first reactor 10.
  • the regenerator vessel 60 typically has a temperature of 594° to 704 0 C (1100° to 1300 0 F) in the lower chamber 62 and 649° to 760 0 C (1200° tol400°F) in the upper chamber 70.
  • the regenerated catalyst pipe 14 is in downstream communication with the regenerator vessel 60. Regenerated catalyst from dense catalyst bed 74 is transported through regenerated catalyst pipe 14 from the regenerator vessel 60 back to the first reactor riser 12 through the control valve 16 where it again contacts feed as the FCC process continues.
  • the first reactor 10 can be operated at low hydrocarbon partial pressure in one desired embodiment.
  • a low hydrocarbon partial pressure can facilitate the production of light olefins.
  • the pressure in the first reactor riser 12 can be 170 to 250 kPa with a hydrocarbon partial pressure of 35 to 180 kPa, preferably 70 to 140 kPa.
  • a relatively low partial pressure for hydrocarbon may be achieved by using steam as a diluent, in the amount of 10 to 55 wt-%, preferably to 15 wt-% of the feed.
  • Other diluents, such as dry gas can be used to reach equivalent hydrocarbon partial pressures.
  • the first cracked products stream in the line 88 may be subjected to additional treatment to remove fine catalyst particles or to further prepare the stream prior to fractionation.
  • the line 88 transfers the first cracked products stream to the product fractionation section 90 that in an embodiment may include a main column 100 and a gas concentration section 114. A variety of products are withdrawn from the main column 100. In this case, the main column 100 recovers an overhead stream of light products comprising unstabilized gasoline and lighter gases in an overhead line 102.
  • the overhead stream in overhead line 102 is condensed in a condenser 104 and cooled in a cooler 106 before it enters a receiver 108.
  • a line 110 withdraws a light off-gas stream from the receiver 108.
  • the off- gas contains LPG and dry gas.
  • the dry gas contains hydrogen sulfide which can serve as a sulfiding agent.
  • a bottom liquid stream of light gasoline leaves the receiver 108 via a line 112.
  • Both lines 110 and 112 may be fed to the gas concentration section 114.
  • many streams are separated such as by fractionation to generate a light olefins line 116, a light naphtha line 118 and a dry gas line 120.
  • the dry gas stream may be concentrated predominantly into a hydrogen sulfide stream or may be part of a more comprehensive stream, but will be represented by dry gas line 120. At least a portion of the dry gas stream is taken by recycle dry gas sulfiding agent line 122 to feed dry gas mixing sulfiding agent line 124 and/or dedicated dry gas sulfiding agent line 184.
  • the main column 100 also provides a heavy naphtha stream, a light cycle oil (LCO) stream and a heavy cycle oil (HCO) stream through lines 126, 128 and 130, respectively.
  • LCO light cycle oil
  • HCO heavy cycle oil
  • Parts of the streams in the lines 126, 128 and 130 are all circulated through heat exchangers 132, 134 and 136 and reflux loops 138,140 and 142, respectively, to remove heat from the main column 100.
  • Streams of heavy naphtha, LCO and HCO are transported from the main column 100 through respective lines 144, 146 and 148.
  • a clarified oil (CO) fraction may be recovered from the bottom of the main column 100 via a line 150.
  • Part of the CO fraction is recycled through a reboiler 152 and returned to the main column 100 through a line 154.
  • the CO stream is removed from the main column 100 via a line 156.
  • the light naphtha fraction preferably has an initial boiling point (IBP) below 127 0 C (26O 0 F) in the C5 range; i.e., 35 0 C (95 0 F), and an end point (EP) at a temperature greater than or equal to 127 0 C (26O 0 F).
  • IBP initial boiling point
  • EP end point
  • the boiling points for these fractions are determined using the procedure known as ASTM D86-82.
  • a portion of the light naphtha stream in light naphtha line 118 may be recovered in line 156 for further processing or storage and another portion in feed line 158 regulated by a control valve may be delivered to recycle feed line 166 for recycle as feed to the second reactor 170.
  • the heavy naphtha fraction has an IBP at or above 127 0 C (26O 0 F) and an EP at a temperature above 200 0 C (392°F), preferably between 204° and 221 0 C (400° and 43O 0 F), particularly at 216 0 C (42O 0 F).
  • a portion of the heavy naphtha stream in line 144 may be recovered in line 160 for further processing or storage and another portion in line 162 regulated by a control valve may be delivered to recycle feed line 166 for recycle as feed to the second reactor 170.
  • the LCO stream has an IBP at the EP temperature of the heavy naphtha and an EP in a range of 260° to 371 0 C (500° to 700 0 F) and preferably 288 0 C (55O 0 F).
  • the HCO stream has an IBP of the EP temperature of the LCO stream and an EP in a range of 371° to 427 0 C (700° to 800 0 F), and preferably 399 0 C (75O 0 F).
  • the CO stream has an IBP of the EP temperature of the HCO stream and includes everything boiling at a higher temperature.
  • a less refined separation of dry gas from LPG and/or naphtha streams may be performed to allow hydrogen sulfide containing dry gas to be added to the second reactor 170 in a hydrocarbon feed line containing the LPG and/or naphtha stream instead of by transport through a separate sulf ⁇ ding agent line.
  • the second reactor 170 may be a second FCC reactor. Although the second reactor 170 is depicted as a second FCC reactor, it should be understood that any suitable reactor can be utilized, such as a fixed bed or a fluidized bed.
  • the second hydrocarbon feed may be fed to the secondary FCC reactor in recycle feed line 166 via feed distributor line 168 and/or fluidizing feed line 172 and fluidizing distributor supply line 174.
  • the second feed can at least partially be comprised of C ⁇ Q- hydrocarbons and preferably C4 to C JQ olefins.
  • the second hydrocarbon feed predominantly comprises hydrocarbons with 10 or fewer carbon atoms. Predominantly means over 50 wt-% and preferably over 80 wt-%.
  • the second feed may comprise any hydrocarbon containing feed that is low in sulfur compounds that decompose to hydrogen sulfide such as a pyrolysis oil from a pyrolysis reactor, Fischer- Tropsch wax from a Fischer-Tropsch reactor, reformate from a catalytic reforming reactor, straight run naphtha from a crude column and animal fat and vegetable oils from an appropriate reactor or source.
  • the second feed is preferably a portion of the first cracked products produced in the first reactor 10, fractionated in the main column 100 of the product fractionation section 90 via recycle feed line 166 and provided to the second reactor 170.
  • the second reactor is in downstream communication with the product fractionation section 90 and/or the first reactor 10 which is in upstream communication with the product fractionation section 90.
  • the second reactor 170 can include a second reactor riser 180.
  • the second hydrocarbon feed is contacted with catalyst delivered to the second reactor 170 by a catalyst return pipe 176 in upstream communication with the second reactor riser 180 to produce cracked upgraded products.
  • the present invention contemplates adding a sulfiding agent to the second reactor 170 to inhibit metal catalyzed coking therein.
  • the recycle dry gas sulfiding agent line 122 is a dedicated source of a sulfiding agent in upstream communication with the second reactor riser 180.
  • dry gas and hydrogen sulfide would not be fed to the second reactor 170 except to prevent metal catalyzed coking because they will not convert to desirable hydrocarbon products and will have to be removed from the upgraded products exiting the second reactor 170.
  • the introduction of hydrocarbon feed and sulfiding agent to the second reactor 170 can be performed in several embodiments shown in the FIGURE.
  • the second hydrocarbon feed can be injected into a second reactor riser 180 by a feed distributor 178 in upstream communication with the second reactor riser 180 and in downstream communication with a feed distributor line 168 which is in downstream communication with recycle feed line 166.
  • Feed distributor line 168 may take a portion or all of the recycle feed stream from recycle feed line 166.
  • the recycle feed line 166 is in downstream communication with the overhead line 102 of the main column 100 which is in downstream communication with the first reactor 10.
  • the feed rate in feed distributor line 168 may be regulated by a control valve.
  • the feed distributor 178 may be located above a fluidizing distributor 182 which is in upstream communication with the second reactor riser 180.
  • the fluidizing distributor 182 provides a fluidizing gas, such as steam and/or a light hydrocarbon, to the second reactor riser 180 to fluidize the catalyst.
  • a fluidizing gas such as steam and/or a light hydrocarbon
  • dry gas from recycle dry gas sulfiding agent line 122 may be independently added to the fluidizing distributor 182 in a base of the second reactor riser 180 via dedicated dry gas sulfiding agent line 184 in downstream communication with the recycle dry gas sulfiding agent line 122 and bypassing atomizing dry gas sulfiding agent line 186 in fluidizing sulfiding agent line 188 and fluidizing distributor supply line 174.
  • the dry gas thus serves both as a fluidizing gas and as a sulfiding agent added to the second reactor riser 180 of the second reactor 170.
  • the recycle dry gas sulfiding agent line 122, the dedicated dry gas sulfiding agent line 184 and the fluidizing sulfiding agent line 188 are dedicated sources of a sulfiding agent in upstream communication with the fluidizing distributor 182 and the second reactor 170. Dry gas bearing hydrogen sulfide in recycle dry gas sulfiding agent line 122, dedicated dry gas sulfiding agent line 184 and fluidizing sulfiding agent line 188 can also be used as an inert fluidizing gas for other parts of the second reactor 170.
  • control valves in feed lines 158 and/or 162 and 168 and in sulfiding agent lines 122, 184 and 188 may be open and control valves in feed lines 172 and sulfiding agent lines 124 and 186 may be closed.
  • a dry gas containing hydrogen sulfide may be added to the liquid second feed in the feed distributor 178 to atomize the liquid hydrocarbon second feed and passivate metals in the second reactor.
  • the recycle dry gas sulfiding agent line 122 is a dedicated source of a sulfiding agent in upstream communication with the feed distributor 178 via atomizing dry gas sulfiding agent line 186.
  • Atomizing dry gas sulfiding agent line 186 in downstream communication with dedicated dry gas sulfiding agent line 184 provides dry gas to a gas inlet of the feed distributor 178.
  • Sulfiding agent may be added to the second reactor according to this embodiment in addition to or instead of the way sulfiding agent is added in the first embodiment; i.e., by addition through the fluidizing distributor 182. Consequently, opening of control valve in line 186 in addition to the control valves opened and closed in other embodiments will allow operation according to this second embodiment. Accordingly, at least the control valves in sulfiding agent lines 122, 184 and 186 must be opened to operate under this embodiment.
  • essentially all of the second hydrocarbon feed in recycle feed line 166 i.e., at least 90%, by mole is in a gas phase.
  • the temperature of the second hydrocarbon feed can be 120° to 600 0 C when entering the second reactor riser 180 and, preferably, at least be above the boiling point of the components.
  • the second hydrocarbon feed can be fed directly to the fluidizing distributor 182 in the base of the second riser to fluidize the catalyst and to feed the second reactor riser 180.
  • control valves in sulfiding agent lines 122 and 124 and feed lines 158 and/or 162 and 172 are open to allow dry gas containing hydrogen sulfide in recycle dry gas sulfiding agent line 122 and dry gas mixing sulfiding agent line 124 and light naphtha in light naphtha line 158 and/or heavy naphtha in heavy naphtha line 162 to recycle as secondary feed in recycle feed line 166, fluidizing feed line 172 and fluidizing distributor supply line 174 to be distributed to the riser by fluidizing distributor 182.
  • Valves in feed line 168 and sulf ⁇ ding agent lines 184, 186 and 188 may typically be closed in this embodiment.
  • the dry gas should contain sufficient hydrogen sulfide to passivate the metals that can catalyze coking in the second reactor riser 180 of the second reactor 170.
  • a heat exchanger 190 may be necessary on fluidizing feed line 172 to vaporize the recycled secondary feed.
  • fluidizing distributor supply line 174 serves as a feed line and the fluidizing distributor 182 serves as a feed distributor.
  • Hydrogen sulfide, in dry gas or not, or organic sulfur additives such as methyl sulfides, mercaptans and polysulfides may be suitable additive sulf ⁇ ding agents that are added to the second reactor 170.
  • the additive sulf ⁇ ding agents may be added to the second feed in feed lines 158, 162, 166, 168, 172 or 174 or elsewhere upstream of the second reactor 170.
  • additive sulf ⁇ ding agent line 192 may add a sulfiding agent directly to the fluidizing feed line 172.
  • Sulfiding agents may also be added directly to the second reactor riser 180, to fluidizing gas upstream of the fluidizing distributor 182 or even to the catalyst entering the riser in catalyst return pipe 176. If a SO x scavenger additive is added to the catalyst, hydrogen sulfide adsorbed on the additive may be delivered to the second reactor 170 via pipe 216 and catalyst return pipe 176, making one or both of the catalyst return pipe 176 and pipe 216 a sulf ⁇ ding agent line.
  • the sulfiding agent stream in the sulfiding agent line preferably has a concentration of at least 1000 wppm of hydrogen sulfide or a compound that can convert to hydrogen sulfide in the reactor environment.
  • the concentration of sulfur relative to the fluids in the second reactor 170 should be maintained to be at least 20 wppm and preferably 50 wppm. In a riser reactor, the concentration of sulfur should be maintained to be at least 20 wppm and preferably 50 wppm relative to the hydrocarbon and inert gases in the reactor. In an embodiment, the concentration of sulfur relative to the fluids in the second reactor should be maintained to be no more than 2000 wppm and preferably no more than 500 wppm. In a riser reactor, the concentration of sulfur should be maintained to be no more than 2000 wppm and preferably no more than 500 wppm relative to the hydrocarbon and inert gases in the reactor.
  • the sulfiding agent lines 122, 124, 176, 184, 186, 188 and 192 are distinct from the feed lines 158 and 162.
  • lines 166, 168 and 172 are also feed lines from which sulfiding agent lines 122, 184, 186 and 188 are distinct.
  • fluidizing feed line 172 no longer carries feed but fluidizing distributor supply line 174 becomes a sulfiding agent line from which feed lines 158, 162, 166 and 168 are distinct.
  • the streams in the sulfiding agent lines and feed lines may be mixed in a downstream location, these streams are separate from each other in at least an upstream location. Accordingly, sulfiding agent lines provide a sulfiding agent that is separate from the second hydrocarbon feed upstream of the second reactor 170.
  • the second reactor 170 may operate under conditions to convert the hydrocarbon feed to smaller hydrocarbon products.
  • C ⁇ Q- olefins crack into one or more light olefins, such as ethylene and/or propylene.
  • a second reactor vessel 194 is in downstream communication with the second reactor riser 180 for receiving upgraded products and catalyst from the second reactor riser. The mixture of gaseous, upgraded product hydrocarbons and catalyst continues upwardly through the second reactor riser 180 and is received in the second reactor vessel 194 in which the catalyst and gaseous hydrocarbon, upgraded products are separated.
  • a pair of disengaging arms 196 may tangentially and horizontally discharge the mixture of gas and catalyst from a top of the second reactor riser 180 through one or more outlet ports 198 (only one is shown) into the second reactor vessel 194 that effects partial separation of gases from the catalyst.
  • the catalyst can drop to a dense catalyst bed 200 within the second reactor vessel 194.
  • the upgraded hydrocarbon products can be separated from the catalyst and be removed from the second reactor 170 through an outlet 204 in downstream communication with the second reactor 170 through an upgraded products line 206.
  • the upgraded products in upgraded products line 206 may be directed to one or more cyclones 32 in the first reactor vessel 20 of the first reactor 10.
  • cyclones 32 may be dedicated just to the upgraded products from the second reactor 170 with a dedicated line (not shown) to the product fractionation section 90 or specifically the gas concentration section 114 or may just mix with the products from the first reactor riser 12 and travel together to the product fractionation section 90 in line 88.
  • the second reactor vessel 194 may contain or have one or more cyclones to further separate gaseous upgraded products from catalyst and travel via upgraded products line 206 to the gas concentration section 114 of the product fractionation section 90. Upgraded products line 206 may alternatively deliver upgraded products to line 88 for transport to the main column 100 of the product fractionation section 90.
  • the second reactor 170 can contain a mixture of the first and second catalyst components as described above. In one preferred embodiment, the second reactor 170 can contain less than 20 wt-%, preferably 5 wt-% of the first component and at least 20 wt-% of the second component. In another preferred embodiment, the second reactor 170 can contain only the second component, preferably a ZSM-5 zeolite, as the catalyst. [0040] Separated catalyst may be recycled via a recycle catalyst pipe 208 from the second reactor vessel 194 regulated by a control valve 210 back to the second reactor riser 180 to be contacted with the second feed.
  • catalyst can be provided from the stripping section 44 of the first FCC reactor via a pipe 214 and/or the regenerator vessel 60 via a pipe 216 both regulated by control valves to the second reactor 170.
  • Both pipes 214 and 216 may be in upstream communication with the recycle catalyst pipe 208.
  • Catalyst return pipe 176 may be a part of the recycle catalyst pipe 208.
  • catalyst from the second reactor vessel 194 is delivered by pipe 202 to the first reactor, preferably to the stripping section 44, and is delivered, preferably after stripping, via spent catalyst conduit 54 to the regenerator vessel 60 for regeneration. Regenerated catalyst may be returned by pipe 216 back to the base of the second reactor riser 180 via catalyst return pipe 176.
  • the catalyst in the first and second reactors 10 and 170 are mixed and may be of uniform composition in both reactors.
  • the second reactor 170 is isolated from the regenerator vessel 60, so that regenerated catalyst is only returned to the first reactor 10 and the second reactor 170 does not send catalyst to the regenerator vessel 60 or receive regenerated catalyst therefrom.
  • the second catalyst component by not being exposed to repeated regenerations, retains more of its activity.
  • the second catalyst component can be added to the second reactor 170 and the catalyst in the second reactor vessel 194 can be periodically or continuously dispensed through the pipe 202 regulated by a control valve to the stripping section 44 of the first reactor 10.
  • the dispensed catalyst can combine with the catalyst in the first reactor 10 and provide additional catalyst activity therein. Fresh catalyst can replace dispensed catalyst to maintain activity in the second reactor 170.
  • the second reactor riser 180 can operate in any suitable condition, such as a temperature of 425° to 705 0 C, preferably a temperature of 550° to 600 0 C, and a pressure of 40 to 700 kPa, preferably a pressure of 40 to 400 kPa, and optimally a pressure of 200 to 250 kPa.
  • the residence time of the second reactor riser 180 can be less than 5 seconds and preferably is between 2 and 3 seconds.
  • Exemplary risers and/or operating conditions are disclosed in, e.g., US 2008/0035527 Al and US 7,261,807 B2.

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

Abstract

L'invention porte sur un procédé et un appareil dans lesquels un agent de sulfuration est ajouté à un réacteur de conversion catalytique pour éviter une cokéfaction catalysée par un métal. Le réacteur catalytique peut être en aval d'un premier réacteur de craquage catalytique en lit fluidisé qui fournit des hydrocarbures en C10 en tant qu'alimentation du réacteur catalytique en aval.
PCT/US2010/022706 2009-03-04 2010-02-01 Procédé pour éviter une cokéfaction catalysée par un métal WO2010101686A2 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
CN201080010494.1A CN102341483B (zh) 2009-03-04 2010-02-01 预防金属催化的结焦的方法
RU2011140159/04A RU2505584C2 (ru) 2009-03-04 2010-02-01 Способ предотвращения коксообразования, катализируемого металлом
BRPI1009534A BRPI1009534A2 (pt) 2009-03-04 2010-02-01 processo e aparelho de craqueamento catalítico fluido.
JP2011552955A JP5607082B2 (ja) 2009-03-04 2010-02-01 金属触媒によるコークス化を防止する方法

Applications Claiming Priority (4)

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US12/397,663 2009-03-04
US12/397,663 US8124020B2 (en) 2009-03-04 2009-03-04 Apparatus for preventing metal catalyzed coking
US12/397,647 2009-03-04
US12/397,647 US8124822B2 (en) 2009-03-04 2009-03-04 Process for preventing metal catalyzed coking

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CN105457569A (zh) * 2014-09-09 2016-04-06 中国石油化工股份有限公司 甲醇或二甲醚转化制低碳烯烃和芳烃的双再生器反应装置及其反应方法
US9644150B2 (en) 2014-12-18 2017-05-09 Inaeris Technologies, Llc Method of thermolyzing biomass in presence of hydrogen sulfide
US9663722B2 (en) 2014-11-11 2017-05-30 Uop Llc Fluid catalytic cracking apparatus and methods for cracking hydrocarbons
WO2018125366A1 (fr) * 2016-12-27 2018-07-05 Uop Llc Régénérateur à contre-courant fcc avec colonne montante de régénérateur
WO2018125367A1 (fr) * 2016-12-27 2018-07-05 Uop Llc Régénérateur à contre-courant fcc avec colonne montante de régénérateur
US10385279B2 (en) 2014-03-25 2019-08-20 Uop Llc Process and apparatus for recycling cracked hydrocarbons
WO2020214273A1 (fr) * 2019-04-17 2020-10-22 Saudi Arabian Oil Company Procédé de craquage catalytique fluidisé d'huile de disulfure pour la production d'éthylène servant pour la métathèse de production de propylène

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CN116020356B (zh) * 2021-10-25 2024-10-11 中国石油化工股份有限公司 一种逆流移动床低碳烷烃脱氢的方法和系统

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JP2013542299A (ja) * 2010-11-11 2013-11-21 宝珍 石 接触分解方法及び装置
US10385279B2 (en) 2014-03-25 2019-08-20 Uop Llc Process and apparatus for recycling cracked hydrocarbons
US9181500B2 (en) 2014-03-25 2015-11-10 Uop Llc Process and apparatus for recycling cracked hydrocarbons
CN105457569A (zh) * 2014-09-09 2016-04-06 中国石油化工股份有限公司 甲醇或二甲醚转化制低碳烯烃和芳烃的双再生器反应装置及其反应方法
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US9644150B2 (en) 2014-12-18 2017-05-09 Inaeris Technologies, Llc Method of thermolyzing biomass in presence of hydrogen sulfide
WO2018125366A1 (fr) * 2016-12-27 2018-07-05 Uop Llc Régénérateur à contre-courant fcc avec colonne montante de régénérateur
WO2018125367A1 (fr) * 2016-12-27 2018-07-05 Uop Llc Régénérateur à contre-courant fcc avec colonne montante de régénérateur
WO2020214273A1 (fr) * 2019-04-17 2020-10-22 Saudi Arabian Oil Company Procédé de craquage catalytique fluidisé d'huile de disulfure pour la production d'éthylène servant pour la métathèse de production de propylène
US11124713B2 (en) 2019-04-17 2021-09-21 Saudi Arabian Oil Company Process for fluidized catalytic cracking of disulfide oil to produce ethylene used for metathesis to produce propylene
CN113710774A (zh) * 2019-04-17 2021-11-26 沙特阿拉伯石油公司 流化催化裂化二硫化物油以生产用于复分解生产丙烯的乙烯的方法
CN113710774B (zh) * 2019-04-17 2022-07-05 沙特阿拉伯石油公司 流化催化裂化二硫化物油以生产用于复分解生产丙烯的乙烯的方法

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WO2010101686A3 (fr) 2010-11-04
JP2012519747A (ja) 2012-08-30
CN102341483B (zh) 2014-02-26
RU2505584C2 (ru) 2014-01-27
RU2011140159A (ru) 2013-04-10
CN102341483A (zh) 2012-02-01
JP5607082B2 (ja) 2014-10-15

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