EP2022838A1 - Process and apparatus for heating regeneration gas in Fluid Catalytic Cracking - Google Patents

Process and apparatus for heating regeneration gas in Fluid Catalytic Cracking Download PDF

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Publication number
EP2022838A1
EP2022838A1 EP08252577A EP08252577A EP2022838A1 EP 2022838 A1 EP2022838 A1 EP 2022838A1 EP 08252577 A EP08252577 A EP 08252577A EP 08252577 A EP08252577 A EP 08252577A EP 2022838 A1 EP2022838 A1 EP 2022838A1
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EP
European Patent Office
Prior art keywords
stream
product
line
catalyst
gas
Prior art date
Legal status (The legal status 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 status listed.)
Withdrawn
Application number
EP08252577A
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German (de)
English (en)
French (fr)
Inventor
Xin Xiong Zhu
Keith Allen Couch
James Patrick Glavin
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Honeywell UOP LLC
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UOP LLC
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Filing date
Publication date
Priority claimed from US11/832,152 external-priority patent/US7727486B2/en
Priority claimed from US11/832,147 external-priority patent/US7727380B2/en
Application filed by UOP LLC filed Critical UOP LLC
Publication of EP2022838A1 publication Critical patent/EP2022838A1/en
Withdrawn legal-status Critical Current

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    • 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
    • C10G11/185—Energy recovery from regenerator effluent gases
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K13/00—General layout or general methods of operation of complete plants

Definitions

  • the field of the invention is power recovery from a fluid catalytic cracking (FCC) unit.
  • FCC fluid catalytic cracking
  • FCC technology now more than 50 years old, has undergone continuous improvement and remains the predominant source of gasoline production in many refineries.
  • This gasoline, as well as lighter products, is formed as the result of cracking heavier (i.e. higher molecular weight), less valuable hydrocarbon feed stocks such as gas oil.
  • the FCC process comprises a reactor that is closely coupled with a regenerator, followed by downstream hydrocarbon product separation. Hydrocarbon feed contacts catalyst in the reactor to crack the hydrocarbons down to smaller molecular weight products. During this process, the catalyst tends to accumulate coke thereon, which is burned off in the regenerator.
  • the heat of combustion in the regenerator typically produces flue gas at temperatures of 677° to 788°C (1250° to 1450°F) and at a pressure range of 138 to 276 kPa (20 to 40 psig). Although the pressure is relatively low, the extremely high temperature, high volume of flue gas from the regenerator contains sufficient kinetic energy to warrant economic recovery.
  • flue gas may be fed to a power recovery unit, which for example may include an expander turbine.
  • the kinetic energy of the flue gas is transferred through blades of the expander to a rotor coupled either to a main air blower, to produce combustion air for the FCC regenerator, and/or to a generator to produce electrical power.
  • the flue gas typically discharges with a temperature drop of approximately 125° to 167°C (225 to 300°F).
  • the flue gas may be run to a steam generator for further energy recovery.
  • a power recovery train may include several devices, such as an expander turbine, a generator, an air blower, a gear reducer, and a let-down steam turbine.
  • first and second stage separators such as cyclones, located in the regenerator.
  • Some systems also include a third stage separator (TSS) or even a fourth stage separator (FSS) to remove further fine particles, commonly referred to as "fines".
  • TSS third stage separator
  • FSS fourth stage separator
  • the FCC process produces around 30% of the dry gas produced in a refinery.
  • Dry gas mainly comprises ethane, methane and other light gases. Dry gas is separated from other FCC products at high pressures.
  • FCC dry gas is heavily olefinic and typically used as fuel gas throughout a refinery. Olefinic dry gas, such as dry gas having over 10 wt-% olefins is not viable for use in gas turbines in which the olefins can cause internal fouling particularly due to the presence of diolefins.
  • FCC units produce more dry gas than the refinery consumes. The excess dry gas can be flared which is an environmental concern.
  • the riser temperature can be reduced, adversely affecting the product slate, or throughput can be reduced, adversely affecting productivity.
  • Olefinic dry gas can also be obtained from other unit operations such as those that are hydrogen deficient like cokers and steam crackers.
  • the process and apparatus involve combusting product gas with oxygen before adding oxygen or an oxygen-containing gas, typically air, to an FCC regenerator.
  • the regenerator is less likely to produce NOx and CO in the flue gas stream when heated air is supplied to the regenerator.
  • the process and apparatus may involve expanding the high pressure product gas obtained from an FCC product stream to lower pressure to recover power before combustion.
  • the preferred product gas is dry gas which may be obtained from many hydrocarbon processing reactions which are hydrogen deficient.
  • the process and apparatus can enable the FCC unit to utilize a low value product stream to produce gasses that are more environmentally friendly.
  • FIG. 1 is a schematic drawing of an FCC unit, a power recovery train and an FCC product recovery system in a refinery.
  • FIG. 2 is a schematic of an alternate embodiment of the invention of FIG. 1 .
  • FIG. 1 illustrates a refinery complex 100 that is equipped for processing streams form an FCC unit for power recovery.
  • the refinery complex 100 generally includes an FCC unit section 10, a power recovery section 60 and a product recovery section 90.
  • the FCC unit section 10 includes a reactor 12 and a catalyst regenerator 14.
  • Process variables typically include a cracking reaction temperature of 400° to 600°C and a catalyst regeneration temperature of 500° to 900°C. Both the cracking and regeneration occur at an absolute pressure below 5 atmospheres.
  • FIG. 1 shows a typical FCC process unit of the prior art, where a heavy hydrocarbon feed or raw oil stream in a line 16 is contacted with a newly regenerated cracking catalyst entering from a regenerated catalyst standpipe 18.
  • This contacting may occur in a narrow riser 20, extending upwardly to the bottom of a reactor vessel 22.
  • the contacting of feed and catalyst is fluidized by gas from a fluidizing line 24. Heat from the catalyst vaporizes the oil, and the oil is thereafter cracked to lighter molecular weight hydrocarbons in the presence of the catalyst as both are transferred up the riser 20 into the reactor vessel 22.
  • the cracked light hydrocarbon products are thereafter separated from the cracking catalyst using cyclonic separators which may include a rough cut separator 26 and one or two stages cyclones 28 in the reactor vessel 22.
  • Product gases exit the reactor vessel 10 through a product outlet 31 to line 32 for transport to a downstream product recovery section 90. Inevitable side reactions occur in the riser 20 leaving coke deposits on the catalyst that lower catalyst activity.
  • Coked catalyst after separation from the gaseous product hydrocarbon, falls into a stripping section 34 where steam is injected through a nozzle to purge any residual hydrocarbon vapor. After the stripping operation, the coked catalyst is fed to the catalyst regenerator 14 through a spent catalyst standpipe 36.
  • FIG. 1 depicts a regenerator 14 known as a combustor.
  • a stream of oxygen-containing gas such as air
  • a main air blower 50 is driven by a driver 52 to deliver air or other oxygen containing gas from line 51 into the regenerator 14.
  • the driver 52 may be, for example, a motor, a steam turbine driver, or some other device for power input.
  • the catalyst regeneration process adds a substantial amount of heat to the catalyst, providing energy to offset the endothermic cracking reactions occurring in the reactor conduit 16.
  • the power recovery section 60 is in downstream communication with the flue gas outlet 47 via line 48. "Downstream communication" means that at least a portion of the fluid from the upstream component flows into the downstream component. Many types of power recovery configurations are suitable, and the following embodiment is very well suited but not necessary to the present invention.
  • Line 48 directs the flue gas to a heat exchanger 62, which is preferably a high pressure steam generator (e.g., a 4137 kPa (gauge) (600 psig)). Arrows to and from the heat exchanger 62 indicate boiler feed water in and high pressure steam out.
  • the heat exchanger 62 may be a medium pressure steam generator (e.g., a 3102 kPa (gauge) (450 psig)) or a low pressure steam generator (e.g., a 345 kPa (gauge) (50 psig)) in particular situations.
  • a boiler feed water (BFW) quench injector 64 may be provided to selectively deliver fluid into conduit 48.
  • a supplemental heat exchanger 63 may also be provided downstream of the heat exchanger 62.
  • the supplemental temperature reduction would typically be a low pressure steam generator for which arrows indicate boiler feed water in and low pressure steam out.
  • the heat exchanger 63 may be a high or medium pressure steam generator in particular situations.
  • conduit 66 provides fluid communication from heat exchanger 62 to the supplemental heat exchanger 63. Flue gas exiting the supplemental heat exchanger 63 is directed by conduit 69 to a waste flue gas line 67 and ultimately to an outlet stack 68, which is preferably equipped with appropriate environmental equipment, such as an electrostatic precipitator or a wet gas scrubber.
  • conduit 69 may be equipped to direct the flue gas through a first multi-hole orifice (MHO) 71, a first flue gas control valve (FGCV) 74, and potentially a second FGCV 75 and second MHO 76 on the path to waste flue gas line 67 all to reduce the pressure of the flue gas in conduit 69 before it reaches the stack 68.
  • MHO multi-hole orifice
  • FGCV first flue gas control valve
  • FGCV's 74, 75 are typically butterfly valves and may be controlled based on a pressure or temperature reading from the regenerator 14.
  • the power recovery section 60 further includes a power recovery expander 70, which is typically a steam turbine, and a power recovery generator (“generator”) 78. More specifically, the expander 70 has an output shaft that is typically coupled to an electrical generator 78 by driving a gear reducer 77 that in turn drives the generator 78. The generator 78 provides electrical power that can be used as desired within the plant or externally. Alternatively, the expander 70 may be coupled to the main air blower 50 to serve as its driver, obviating driver 52, but this arrangement is not shown.
  • the power recovery expander 70 is located in downstream communication with the heat exchanger 62.
  • a heat exchanger may be upstream or downstream of the expander 70.
  • a conduit 79 feeds flue gas through an isolation valve 81 to a third stage separator (TSS) 80, which removes the majority of remaining solid particles from the flue gas. Clean flue gas exits the TSS 80 in a flue gas line 82 which feeds a flue gas stream to a combine line 54 which drives the expander 70.
  • TSS third stage separator
  • an expander inlet control valve 83 and a throttling valve 84 may be provided upstream of the expander 70 to further control the gas flow entering an expander inlet.
  • the order of the valves 83, 84 may be reversed and are preferably butterfly valves. Additionally, a portion of the flue gas stream can be diverted in a bypass line 73 from a location upstream of the expander 70, through a synchronization valve 85, typically a butterfly valve, to join the flue gas in the exhaust line 86.
  • the clean flue gas in line 86 joins the flowing waste gas downstream of the supplemental heat exchanger 63 in waste flue gas line 67 and flows to the outlet stack 68.
  • An optional fourth stage separator 88 can be provided to further remove solids that exit the TSS 80 in an underflow stream in conduit 89. After the underflow stream is further cleaned in the fourth stage separator 88, it can rejoin the flue gas in line 86 after passing through a critical flow nozzle 72 that sets the flow rate therethrough.
  • the gaseous FCC product in line 32 is directed to a lower section of an FCC main fractionation column 92.
  • Several fractions may be separated and taken from the main column including a heavy slurry oil from the bottoms in line 93, a heavy cycle oil stream in line 94, a light cycle oil in line 95 and a heavy naphtha stream in line 96.
  • Any or all of lines 93-96 may be cooled and pumped back to the main column 92 to cool the main column typically at a higher location.
  • Gasoline and gaseous light hydrocarbons are removed in overhead line 97 from the main column 92 and condensed before entering a main column receiver 99.
  • An aqueous stream is removed from a boot in the receiver 99.
  • a condensed light naphtha stream is removed in line 101 while a gaseous light hydrocarbon stream is removed in line 102. Both streams in lines 101 and 102 may enter a vapor recovery section 120 of the product recovery section 90.
  • the vapor recovery section 120 is shown to be an absorption based system, but any vapor recovery system may be used including a cold box system.
  • the gaseous stream in line 102 is compressed in compressor 104. More than one compressor stage may be used, but typically a dual stage compression is utilized.
  • the compressed light hydrocarbon stream in line 106 is joined by streams in lines 107 and 108, chilled and delivered to a high pressure receiver 110.
  • An aqueous stream from the receiver 110 may be routed to the main column receiver 99.
  • a gaseous hydrocarbon stream in line 112 is routed to a primary absorber 114 in which it is contacted with unstabilized gasoline from the main column receiver 99 in line 101 to effect a separation between C 3 + and C 2 - .
  • a liquid C 3 + stream in line 107 is returned to line 106 prior to chilling.
  • An off-gas stream in line 116 from the primary absorber 114 may be used as a selected product stream of the plurality of product streams separated from the FCC product in the present invention or optionally be directed to a secondary absorber 118, where a circulating stream of light cycle oil in line 121 diverted from line 95 absorbs most of the remaining C 5 + and some C 3 -C 4 material in the off-gas stream.
  • Light cycle oil from the bottom of the secondary absorber in line 119 richer in C 3 + material is returned to the main column 92 via the pump-around for line 95.
  • the overhead of the secondary absorber 118 comprising dry gas of predominantly C 2 - hydrocarbons with hydrogen sulfide, amines and hydrogen is removed in line 122 and may be used as a selected product stream of the plurality of product streams separated from the FCC product in the present invention. It is contemplated that another stream may also comprise a selected product stream of the plurality of product streams separated from the FCC product in the present invention
  • Liquid from the high pressure receiver 110 in line 124 is sent to a stripper 126. Most of the C 2 - is removed in the overhead of the stripper 126 and returned to line 106 via overhead line 108. A liquid bottoms stream from the stripper 126 is sent to a debutanizer column 130 via line 128. An overhead stream in line 132 from the debutanizer comprises C 3 -C 4 olefinic product while a bottoms stream in line 134 comprising stabilized gasoline may be further treated and sent to gasoline storage.
  • a selected product stream line, preferably line 122 comprising the secondary absorber off-gas containing dry gas may be introduced into an amine absorber unit 140.
  • a lean aqueous amine solution is introduced via line 142 into absorber 140 and is contacted with the flowing dry gas stream to absorb hydrogen sulfide, and a rich aqueous amine absorption solution containing hydrogen sulfide is removed from absorption zone 140 via line 144 and recovered.
  • a selected product stream line preferably comprising a dry gas stream having a reduced concentration of hydrogen sulfide is removed from absorption zone 140 via line 146.
  • lines carrying product from the FCC reactor 12 including lines 116 or 122 and 146 may serve as selected product lines in communication with the downstream power recovery section 60 to transport a selected product stream from the gas recovery section 120 of the product recovery section 90 to the power recovery section 60.
  • dry gas may be delivered to the power recovery section 60 from any other source in the refinery 100 such as a coker unit or a steam cracker unit.
  • the selected FCC product gas from the product recovery section 90 in line 146 can be used in the power recovery section 60 in a continuous process and in the same refinery complex.
  • the power recovery section 60 is in downstream communication with the vapor recovery section of the product recovery section 90 via line 146.
  • the selected product gas may be let down in pressure at a volume increase across an expander 150 to recover pressure energy from the gas.
  • the selected gas is still at the high pressure utilized in the vapor recovery section 120 of the product recovery section 90 when delivered to the expander 150 due to operation of the compressor 104.
  • the selected gas exits expander 150 in exhaust line 152.
  • the expander is connected by a shaft 154 to an electrical generator 78 for generating electrical power that can be used in the refinery or exported. Beside connection by shaft 154 to the electrical generator, the expander 150 may alternatively or additionally be connected by a shaft (not shown) to the main air blower 50 for blowing air to the regenerator 14 obviating the need for driver 52.
  • a gear reducer may be provided on the shaft 154 between the expander 150 and the generator 78 in which case the gear reducer (not shown) would connect two shafts of which shaft 154 is one.
  • the expander 150 may be in downstream communication with the selected product line 146 and with vapor recovery section 120 of the product recovery section 90 via line 146.
  • an additional steam expander may be connected by an additional shaft or the same shaft 154 to further turn electrical generator 78 and produce additional electrical power or power the main air blower 50.
  • the additional steam expander would be fed by surplus steam in the refinery.
  • the additional expander could be either an extraction or induction turbine. In the latter case, the additional expander could take the form of an additional chamber in expander 150 or 70 with the surplus steam feeding the additional chamber (not shown).
  • the additional expander may be coupled by a gear reducer (not shown) to the additional shaft or the same shaft 154.
  • expanders 70 and 150 could be the same expander with induction feed from line 82, 54 or 146, respectively, introducing a stream to an intermediate chamber of the expander.
  • the selected product gas may be used as a regeneration gas preheating media. A portion of the selected product gas may be diverted for other purposes in line 151. After, before or instead of routing the selected product gas to the expander 150 for power recovery, the selected gas is routed to the regeneration gas preheater 156 in expander exhaust line 152 if the expander 150 is utilized. Heat from combusting the selected product gas serves to preheat regeneration gas before contacting the coked FCC catalyst in the regenerator 14 serving to minimize production of nonselective flue gas components such as NOx and CO.
  • the preheated regeneration gas should be heated to a temperature of between about 350 and about 800°F (177 to 427°C).
  • a regeneration gas delivery line 158 is in downstream communication with the main air blower 50 and delivers oxygen-containing regeneration gas such as air to the regeneration gas preheater 156 which is in downstream communication with the line 158 and the blower 50.
  • the regeneration gas preheater 156 is in downstream communication with the vapor recovery section 120 of the product recovery section 90 via lines 116, 122, 146 and/or 152, and the regenerator 14 is in downstream communication with the regeneration gas heater 156.
  • the line 158 may be in downstream communication with line 152 thereby combining the oxygen-containing regeneration gas stream from the blower 50 and at least a portion of the selected product gas in line 152 before they both enter the regeneration gas preheater 156.
  • the oxygen-containing regeneration gas and the selected product gas are ignited continuously to combust the selected product gas in the regeneration gas preheater 156 and achieve an elevated temperature in a combusted gas stream.
  • the regeneration gas preheater 156 is in downstream communication with the selected product lines 116, 122, 146 and/or 152.
  • the flow rate of oxygen from blower 50 should be sufficient to combust the selected gas in the regeneration gas heater 156 and combust coke from catalyst in the regenerator 14.
  • the combust gas stream in line 160 will contain excess oxygen-containing regeneration gas and combusted selected product gas.
  • the preheater 156 may be in downstream communication with the expander 150.
  • a combust line 160 is in downstream communication with the preheater 156.
  • the preheated regeneration gas containing combusted selected gas enter the regenerator 14 through combust line 160 at elevated temperature preferably through distributor 38.
  • the distributor 38 of the regenerator 14 is in downstream communication with the product recovery section 90, the blower 50 and the regeneration gas preheater 156.
  • This arrangement is economically attractive as it may maximize utilization of existing assets, but it also allows for the burning of olefin rich dry gas from the FCC reactor 12 or other reactor in which hydrogen is deficient, which is not viable for use in gas turbines in which the olefins can cause internal fouling.
  • FIG. 2 shows an alternative embodiment in which most elements are the same as in FIG. 1 indicated by like reference numerals but with differences in configuration indicated by designating the reference numeral with a prime symbol (""').
  • the flue gas heater 156' is in downstream communication with the vapor recovery section 120 of the product recovery section 90 via lines 116, 122, 146 and/or 152'.
  • An oxygen-containing gas stream in line 158 is combined with at least a portion of the selected product gas in line 152'. Together or separately, the oxygen-containing stream and the selected product gas stream enter into the regeneration gas preheater 156', are ignited and a combust stream of combusted selected product gas at elevated temperature exit the preheater 156' in combust line 160'.
  • a regeneration gas delivery line 30' in downstream communication with the blower 50 delivers an oxygen-containing regeneration gas.
  • a combine line 163 is in downstream communication with the regeneration gas delivery line 30' and the combust line 160' carrying the combust stream in downstream communication with the preheater 156'.
  • the combust stream heats the regeneration gas in the combine line 163 to provide regeneration gas at elevated temperature to the distributor 38 in regenerator 14 both in parallel downstream communication with the blower 50 via delivery line 30' and the preheater 156' via line 160'.
  • the preheated regeneration gas delivered to the regenerator 14 in combine line 163 contacts the coked catalyst at elevated temperature to minimize the generation of undesirable combustion products while combusting coke from the coked catalyst.
  • a further combust line 162 may carry combusted selected product gas to the heat exchanger 61 in downstream communication with the preheater 156'.
  • a back pressure valve 161 may regulate flow so that combusted gas in excess of that necessary to achieve the desired temperature of regeneration gas in combine line 163 is diverted to additional heat exchange preferably for the generation of steam in heat exchanger 61.
  • the combust line may feed flue gas lines 48 or 66 to boost heat exchange and preferably steam generation in heat exchangers 62 and 63 that may be in downstream communication with preheater 156'. It is also envisioned that this embodiment may be applicable to the embodiment of FIG. 1 .

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  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Combustion & Propulsion (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Catalysts (AREA)
EP08252577A 2007-08-01 2008-07-29 Process and apparatus for heating regeneration gas in Fluid Catalytic Cracking Withdrawn EP2022838A1 (en)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US11/832,152 US7727486B2 (en) 2007-08-01 2007-08-01 Apparatus for heating regeneration gas
US11/832,147 US7727380B2 (en) 2007-08-01 2007-08-01 Process for heating regeneration gas

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Publication Number Publication Date
EP2022838A1 true EP2022838A1 (en) 2009-02-11

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EP08252577A Withdrawn EP2022838A1 (en) 2007-08-01 2008-07-29 Process and apparatus for heating regeneration gas in Fluid Catalytic Cracking

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EP (1) EP2022838A1 (es)
BR (1) BRPI0802436A2 (es)
CO (1) CO6110134A1 (es)
MX (1) MX2008009844A (es)

Cited By (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2077310A1 (en) * 2007-12-21 2009-07-08 Uop Llc Method and system of recovering energy from a fluid catalytic cracking unit for overall carbon dioxide reduction
EP2077157A1 (en) * 2007-12-21 2009-07-08 Uop Llc Method and system of heating a fluid catalytic cracking unit for overall CO2 reduction
US7699974B2 (en) 2007-12-21 2010-04-20 Uop Llc Method and system of heating a fluid catalytic cracking unit having a regenerator and a reactor
US7767075B2 (en) 2007-12-21 2010-08-03 Uop Llc System and method of producing heat in a fluid catalytic cracking unit
US7932204B2 (en) 2007-12-21 2011-04-26 Uop Llc Method of regenerating catalyst in a fluidized catalytic cracking unit
US7935245B2 (en) 2007-12-21 2011-05-03 Uop Llc System and method of increasing synthesis gas yield in a fluid catalytic cracking unit
US20130137909A1 (en) * 2011-07-27 2013-05-30 Christopher F. Dean Fluidized catalytic cracking of paraffinic naphtha in a downflow reactor

Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4542114A (en) * 1982-08-03 1985-09-17 Air Products And Chemicals, Inc. Process for the recovery and recycle of effluent gas from the regeneration of particulate matter with oxygen and carbon dioxide
EP1935966A1 (en) * 2006-12-21 2008-06-25 Uop Llc System and method of reducing carbon dioxide emissions in a fluid catalytic cracking unit
EP1939269A1 (en) * 2006-12-21 2008-07-02 Uop Llc Preheating process and apparatus for FCC regenerator

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4542114A (en) * 1982-08-03 1985-09-17 Air Products And Chemicals, Inc. Process for the recovery and recycle of effluent gas from the regeneration of particulate matter with oxygen and carbon dioxide
EP1935966A1 (en) * 2006-12-21 2008-06-25 Uop Llc System and method of reducing carbon dioxide emissions in a fluid catalytic cracking unit
EP1939269A1 (en) * 2006-12-21 2008-07-02 Uop Llc Preheating process and apparatus for FCC regenerator

Cited By (13)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2077310A1 (en) * 2007-12-21 2009-07-08 Uop Llc Method and system of recovering energy from a fluid catalytic cracking unit for overall carbon dioxide reduction
EP2077157A1 (en) * 2007-12-21 2009-07-08 Uop Llc Method and system of heating a fluid catalytic cracking unit for overall CO2 reduction
US7699974B2 (en) 2007-12-21 2010-04-20 Uop Llc Method and system of heating a fluid catalytic cracking unit having a regenerator and a reactor
US7699975B2 (en) 2007-12-21 2010-04-20 Uop Llc Method and system of heating a fluid catalytic cracking unit for overall CO2 reduction
US7767075B2 (en) 2007-12-21 2010-08-03 Uop Llc System and method of producing heat in a fluid catalytic cracking unit
US7811446B2 (en) 2007-12-21 2010-10-12 Uop Llc Method of recovering energy from a fluid catalytic cracking unit for overall carbon dioxide reduction
US7921631B2 (en) 2007-12-21 2011-04-12 Uop Llc Method of recovering energy from a fluid catalytic cracking unit for overall carbon dioxide reduction
US7932204B2 (en) 2007-12-21 2011-04-26 Uop Llc Method of regenerating catalyst in a fluidized catalytic cracking unit
US7935245B2 (en) 2007-12-21 2011-05-03 Uop Llc System and method of increasing synthesis gas yield in a fluid catalytic cracking unit
US20130137909A1 (en) * 2011-07-27 2013-05-30 Christopher F. Dean Fluidized catalytic cracking of paraffinic naphtha in a downflow reactor
KR20140049033A (ko) * 2011-07-27 2014-04-24 사우디 아라비안 오일 컴퍼니 하향류 반응기에서 파라핀계 나프타의 유동접촉분해 방법
US9458394B2 (en) * 2011-07-27 2016-10-04 Saudi Arabian Oil Company Fluidized catalytic cracking of paraffinic naphtha in a downflow reactor
KR101954472B1 (ko) 2011-07-27 2019-03-05 사우디 아라비안 오일 컴퍼니 하향류 반응기에서 파라핀계 나프타의 유동접촉분해 방법

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MX2008009844A (es) 2009-02-27
BRPI0802436A2 (pt) 2009-10-20

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