US20030075480A1 - Process for controlling oxidation of nitrogen and metals in circulating fluidized solids contacting process - Google Patents

Process for controlling oxidation of nitrogen and metals in circulating fluidized solids contacting process Download PDF

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US20030075480A1
US20030075480A1 US10/252,055 US25205502A US2003075480A1 US 20030075480 A1 US20030075480 A1 US 20030075480A1 US 25205502 A US25205502 A US 25205502A US 2003075480 A1 US2003075480 A1 US 2003075480A1
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solid
regenerator
flue gas
spent
regenerated
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David Bartholic
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Bar-Co Processes Joint Venture
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Bar-Co Processes Joint Venture
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Assigned to BARCO PROCESSES JOINT VENTURE reassignment BARCO PROCESSES JOINT VENTURE ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: BARTHOLIC, DAVID B.
Priority to EP02023878A priority patent/EP1306420A3/fr
Priority to CA002409612A priority patent/CA2409612A1/fr
Publication of US20030075480A1 publication Critical patent/US20030075480A1/en
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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

Definitions

  • This invention relates to an improved circulating fluid particulate solids contacting process for upgrading hydrocarbon feedstocks containing metals, such as vanadium, and/or nitrogen, in which certain regenerator design and operating conditions are employed to (1) reduce the nitrogen oxides (NOx) emissions in regenerator flue gas and/or (2) permit operating with an increased equilibrium solids vanadium level over and above the current state of the art.
  • This invention also relates to an improved fluid catalytic cracking (FCC) process for processing gas oils and residual oils, in which certain FCC unit (FCCU) catalyst regenerator design and operating conditions are employed to reduce the nitrogen oxides (NOx) emissions in the catalyst regenerator flue gas and/or permit operating with an increased equilibrium catalyst vanadium level.
  • FCC fluid catalytic cracking
  • the Fluid Catalytic Cracking (FCC) Process for converting petroleum-derived feed stocks to lower molecular weight hydrocarbon products, has been in operation for over 50 years and has gone through many changes. These changes have been in the catalyst and additives employed in the process, as well as apparatus and process changes.
  • the major objective in refining crude petroleum oil has always been to produce the maximum quantities of the highest value added products and to minimize the production of low value products.
  • the highest value added products of oil refining with the largest market have been transportation fuels, such as gasoline, jet fuel and diesel fuels and Number 2 home heating oil, and historically the lower value products have been associated with the residual oil, defined as the portion of the crude oil boiling above about 1000° F. or 538° C.
  • Catalyst poisons accelerate the deactivation of catalyst, reduce catalyst selectivity, increase regenerator flue gas environmental pollutants, and increase the catalyst and operating costs, so that these residual oil processing methods have only been economical, in most cases, by limiting the amount of residual oil in the feed.
  • FCCU fluid catalytic cracking
  • FCCU is a very cost effective sulfur removal process, in that it converts about 50% of the feed sulfur to H 2 S without hydrogen addition.
  • the buildup of other catalyst poisons on the catalyst can be effectively controlled by using catalyst coolers to negate the effect of coke formation from the asphaltene compounds, using the MSCC process to overcome the problems associated with riser coking and vaporization in a riser type FCC, using regenerator flue gas and product treating to negate the environmental effects of feed sulfur, and using the MSCC process to negate the effects of feed nitrogen and nickel on reactor yields.
  • the use of the teachings of this patent will control the NOx emissions and allow for operation of circulating fluid solids systems at higher levels of vanadium than are currently economical.
  • ECAT Equilibrium catalyst
  • Heavier residual oil feeds that is, feeds with higher Ramsbottom carbon and metals, and residual oil feeds low in hydrogen content, which cannot be economically processed in an FCCU type system are typically processed in cokers, fluid cokers, ebulating bed hydrotreaters, or processes such as those described by my U.S. Pat. No. 4,243,514 (commercially referred as the ART Process) and U.S. Pat. No. 4,859,315 (commercially referred to as the 3D Process).
  • ART and 3D Processes which are referred to herein as hydrocarbon treating processes
  • catalytic inert solids are used as the circulating media in fluid catalytic type equipment to remove the majority of asphaltenes and metals from residual oil feeds at low conversion.
  • one of the major problems encountered with these types of hydrocarbon treating processes is that as the level of vanadium increases on the circulating solids there is a tendency of the particles to agglomerate (stick together and quit flowing) as disclosed in Hettinger's European Patent No. EP0065626.
  • solid is meant to include either a non-catalytic fluid particle such as those employed in the above-mentioned 3D and ART Processes or a catalytic fluid particle such as those employed in FCC type processes.
  • the NOx emissions from the FCCU regenerator are the result of fixation of nitrogen and burning of the nitrogen in the coke.
  • the major components of the regenerator flue gas are O 2 , N 2 , Ar, CO 2 , CO, NOx, H 2 O(v), and SOx, along with catalyst fines.
  • the regenerator flue gas might have some unburned materials, such as H 2 S and C 1 , or C 2 .
  • N 2 , Ar, and O 2 are the primary ingredients of the air pumped into the regenerator as combustion air.
  • the oxygen in the combustion air is primarily consumed in burning of coke in the regenerator. Some of the oxygen is also consumed in the fixation of nitrogen to NOx.
  • the amount of nitrogen fixation in the FCC regenerator will increase with increased regenerator/flue gas temperature and increased oxygen partial pressure.
  • Oxidation promoters such as platinum, vanadium and cerium, will also increase the amount of nitrogen fixation.
  • the flue gas O 2 concentration can vary between 0.1 mol % and 5.0 mol %, a practical upper limit. In those FCCU's without CO Boilers, the oxygen in the flue gas will typically be no lower that that required to meet the CO emission requirements.
  • CO in the regenerator flue gas was first reduced or controlled by installing a boiler or furnace downstream of the FCC regenerator in the FCC regenerator flue gas system to burn the CO in the FCC regenerator flue gas to CO 2 .
  • These were commonly referred to as CO Boilers.
  • Pt combustion promoters were developed and employed in FCCU's as additives to be added to the circulating catalyst inventory (equilibrium catalyst or ECAT) to reduce the FCC regenerator CO emissions without the need for CO Boilers.
  • ECAT Equilibrium catalyst
  • FCC process Another type of FCC process, that can be easily modified to take advantage of the teachings of the present invention, is the one that utilizes a so-called “fast fluid bed” regenerator followed by a transport riser that conveys the regenerated solid and air plus products of combustion into an upper vessel, where the regenerated solid and flue gas are separated, and the separated regenerated solid is maintained in the upper vessel in a dense bed that is fluidized by air.
  • This regenerator type is typically referred to as a combustor.
  • One objective of the present invention is to reduce, and preferably to minimize, the NOx emissions from the FCCU regenerator. Another objective is to reduce the need for NOx additives.
  • Another objective of this invention is to allow for the startup and shutdown and for operation during upsets and during steady state operation in unit operation while maintaining the vanadium oxidation state at less than +5, which will reduce catalyst deactivation or solids agglomeration.
  • Another objective of this invention is to allow the FCC process to economically process residual oil feeds with greater than 30 ppm of metals (Ni+V) in the feed.
  • Another objective is to reduce the effect of vanadium on catalyst activity.
  • a further objective is to reduce the effect of sodium on catalyst activity.
  • Still another objective of the invention is to reduce the requirement for fresh catalyst/solid replacement in hydrocarbon treating processes and FCC units, which will reduce fresh catalyst/solids costs, transportation costs, equilibrium catalyst/solids disposal costs, and unit particulate losses. It is also an objective of this invention to prevent agglomeration of the circulating solids at high (>20,000 ppm) vanadium levels on ECAT. It is also an objective of the present invention to reduce, and preferably to minimize, the NOx emissions from the regenerator used in such processes. Another objective is to reduce the need for NOx additives.
  • regenerator temperature below 1400° F. (704° C.), and still more preferably below 1250° F. (677° C.), that one can also reduce, even in an oxidizing atmosphere, the effect of vanadium and sodium on catalyst activity and agglomeration.
  • the unit can be designed to operate the regenerator in a reducing atmosphere or at a less than the above regenerator temperature to minimize the catalyst deactivation and tendency to agglomerate, combining both these processing conditions will result in the least catalyst deactivation and substantially eliminate the possibility of agglomeration. Therefore, the preferred apparatus has both a means for controlling both the degree of oxidation of the circulating solids and the circulating solids temperature.
  • this entails incorporating a dilute phase ( ⁇ 20 lb/ft3 solids density) regenerator and catalyst cooling.
  • catalyst cooling can be incorporated in the apparatus by use of exchange between circulating catalyst and water to produce steam, it can also be accomplished by using water for solids/catalyst dispersion as discussed in U.S. Pat. Nos. 4,859,315 and 4,985,136, by using water in place of stripping steam, and allowing more or less CO to exit the regenerator in the flue gas.
  • a preferred apparatus employs a dilute phase regenerator and recycle of regenerator flue gas to the dilute phase regenerator to control both particle residence time and oxygen partial pressure in the regenerator.
  • the preferred residence time is less than 60 seconds but greater than 5 seconds.
  • an improved fluidized solids circulating process for reducing NOx emissions and the harmful effects of vanadium which process includes the steps of, contacting a hydrocarbon feed in a contactor with hot regenerated particulate solid under conditions to vaporize the majority of said feedstock and convert said feedstock to a lower molecular weight vapor product vapors and form a spent solid containing carbonaceous deposits; separating a majority of the lower molecular weight hydrocarbon product vapors from the spent solid to form separated product vapors and separated spent solid containing entrained hydrocarbon vapors; processing the separated product vapors into desired product fractions; subjecting the separated spent solid to stripping to remove therefrom a majority of the entrained hydrocarbon vapors; contacting the resulting stripped spent solid in a regenerator with an oxygen-containing regeneration gas under solid regeneration conditions which include a combination of a solid regeneration time, temperature and contact with an oxygen-containing combustion gas which is effective to burn from the spent solid a
  • the philosophy of this invention is contrary to that employed by the major licensors of FCC technology. That is, the current FCC design philosophy of certain licensors is the so-called two stage regenerator, which regenerates the catalyst in two stages, with the second stage having a high temperature, typically greater than 1300° F. (704° C.), and an oxidizing atmosphere. In one commercial process, the spent solid is distributed across the top of the regenerator bed so that the lower part of the fluidized bed where the combustion air is injected into the bed and contacts the hottest catalyst with the highest oxygen concentration. All is contrary to our teaching.
  • FIG. 1 is a schematic flow diagram of a preferred process in accordance with the present invention.
  • a hydrocarbon feed supplied via line 1 is mixed with regenerated solid supplied via line 2 to a reactor 4 of an FCC type or other fluidized solid hydrocarbon treating reaction system.
  • the hydrocarbon feed is a gas oil, residual oil or a mixture thereof.
  • Any type of FCC or fluidized solid hydrocarbon treating reaction system can be employed. However, the reaction system described in U.S. Pat. No.
  • the separated spent solid and entrained hydrocarbon vapors flow downwardly through reactor 4 into stripper section 15 , where, in a preferred method, it is mixed with hot regenerated solid regulated by slide valve 16 to control the stripper temperature at a higher temperature than that of the reactor vapors in line 10 .
  • the now elevated temperature mixture of spent and regenerated solid is subjected to steam stripping in stripper 15 to remove from the solid as much hydrocarbon as possible before it exits reactor 4 through spent solid slide valve 5 , which controls the solid level in the reactor stripper 15 .
  • reactor 4 vapors of the hydrocarbon feedstock intimately contact the particles of solid (catalyst) therein under cracking/treating conditions to produce lower molecular weight hydrocarbon product vapors, while at the same time there is formed spent solid having formed thereon carbonaceous deposits, which typically include compounds of sulfur and nitrogen, as well as metal deposits.
  • the stripped spent solid in line 14 is mixed with recycled flue gas 18 and an oxygen-containing combustion gas, e.g., air, supplied via line 7 in combustor (regenerator) riser 6 , wherein the spent solid and combustion gas flow co-currently and upwardly to form regenerated solid and flue-gas, which pass from the exit of combustor riser 6 into vessel 8 where the regenerated solid is separated from the flue gas.
  • an oxygen-containing combustion gas e.g., air
  • Both the flow rate of recycled flue gas 18 and combustion air 7 used to burn the carbon from the spent solid is regulated to control the degree of regeneration and the regenerator NOx emissions, i.e., the burning of the carbonaceous deposits and the fixation of nitrogen, to produce a regenerated solid and a flue gas having a very low NOx content, with the majority of vanadium being in an oxidation state of less than +5.
  • the oxygen source 7 is usually air but could be another source of oxygen, such as, oxygen from an air plant.
  • Recycled flue gas is used to control the oxygen partial pressure (nitrogen fixation, vanadium oxidation) and time (degree of regeneration) in dilute phase regenerator 6 .
  • the recycled flue gas can be recycled hot or after cooling and treating. It can be supplied from a separate compressor or a controlled amount routed to the air blower suction.
  • the rate of combustion air used to burn the carbon from the spent solid is regulated to control the oxygen in regenerator flue gas at less than 1.0 mol %, more preferably less than 0.7 mol %, and still more preferably less than 0.5 mol %.
  • the lower the temperature of the regenerated solid 2 the higher one can operate the oxygen content of flue gas 9 .
  • the carbon-burning rate is decreased so that it is possible to maintain carbon on regenerated solid 2 (reducing atmosphere) with oxygen exiting combustion riser 6 .
  • This method use of a high velocity (>5 fps) riser, of regeneration is preferred over a fluidized bed regenerator, or a fast fluid regenerator as it minimizes backmixing and minimizes oxygen partial pressure as the carbon on regenerated solid decreases and exposes the metals on the surface of the catalyst to possible oxidation.
  • Use of a high velocity riser regenerator 6 allows for operation at higher regenerated catalyst temperatures that any other method of regeneration. This will result in less coke yield and more product yield. If one employs the more common fluidized bed regenerator or fast fluid regenerator, the regenerator temperature must be lowered to reduce the oxidation potential of the vanadium and sodium.
  • a direct fired air heater 19 that is used instead of torch oil.
  • torch oil which is mainly used on startup and shutdown and during upsets, will help minimize vanadium oxidation during these periods, since torch oil is added to the regenerator into a relatively dense bed of solid with excess oxygen and results in a high flame temperature [>1500° F. (>815° C.)] that increases vanadium oxidation (catalyst deactivation or the tendency to agglomerate) and nitrogen fixation.
  • the combustion mixture and spent solid are mixed, and the combustion of the carbonaceous deposits on the spent solid initiates.
  • the oxygen is consumed as the carbon is burned off the surface of the solid particle. This reduces the oxygen partial pressure that has the effect of limiting the oxidation driving force for the fixation of nitrogen or oxidizing the metals.
  • the burning of carbon also produces CO which inhibits the formation of NOx. Since the metals are mainly on the surface of the particles of solid and the carbon deposited in reactor 4 covers these metals, the metals become exposed and can only be oxidized once they are uncovered and at high temperature. Using a co-current regeneration system, as described here, minimizes the oxidation of the metals.
  • the outlet temperature of combustion riser 6 is controlled at less than 1400° F. (760° C.), preferably less than 1300° F. (704° C.) and more preferably less than 1250° F. (677° C.) to maintain a carbon on regenerated solid 2 of less than 0.4 w %. This is accomplished by mixing regenerated catalyst that has been cooled by catalyst cooler 11 to the upward flowing spent catalyst 5 and combustion air 7 at a point in combustion riser 6 where the temperature of the resulting mixture is less than 1250° F. (677° C.) and preferably less than 1200° F. (649° C.) to minimize the oxidation of metals and carbon burning from the surface of the cooled regenerated solid 13 .
  • the rate of cooled regenerated solids 13 is regulated by slide valve 12 to control the regenerated solids temperature 2 at less than 1400° F., preferably less than 1300° F. (704° C.) and more preferably below 1250° F. (677° C.).
  • regenerator vessel 8 the products of combustion (flue gas 9 ) and the regenerated solid 2 plus cooled regenerated solid 13 are separated.
  • the regenerator flue gas 9 can be further processed for heat recovery and treated for particulate and SOx control before being exhausted to the atmosphere.
  • a gas such as inert gas, or other non-oxidizing gas, or recycled flue gas
  • the inert gas may be supplied by an inert gas generator or, in the case of recycling flue gas, flue gas from line 9 may be compressed and used as the fluidizing media injected through pipe 17 into vessel 8 .
  • the regenerator flue gas is cooled to 500-1000° F. (260-538° C.), preferably 50° F. (28° C.) above the sulfur dew point, before it is compressed and returned as the fluidizing media via pipe 17 into vessel 8 and/or returned to, as a supplemental fluidizing media, regenerator riser 6 along with the combustion oxygen to control both the catalyst residence time, temperature and/or oxygen partial pressure in the riser 6 . It is preferred that the cooled flue gas be injected into the regenerator riser 6 at a point along the riser where the temperature of the upward flowing catalyst and combustion gas from line 7 is at least 1150° F. (621° C.) and more preferably 1200° F. (649° C.).
  • a cooled regenerator flue gas has the advantage of reducing the temperature of the regenerated solid, which will further reduce the NOx emissions.
  • the benefits of this improvement can also be incorporated into a combustor style regenerator by injecting the cooled flue gas at the exit of the fast fluid bed vessel and the entrance to the riser section of the combustor.
  • Use of cooled regenerator flue gas to reduce the outlet temperature of the riser 6 will also lower both the combustion temperatures in the riser and the oxygen partial pressure. This will result in lower NOx emissions and reduce the oxidation of metals.
  • Use of cooled flue gas as the fluidizing media supplied via pipe 17 in upper vessel 8 will also reduce the NOx emissions.
  • This method use of a high velocity (>5 fps) combustor riser, of regeneration is preferred over a conventional fluidized bed regenerator, or a fast fluid regenerator, as it minimizes backmixing and minimizes oxygen partial pressure as the carbon on regenerated solid decreases, which results in lower NOx emissions and metals oxidation.
  • Use of a high velocity riser regenerator 6 allows for operation at higher regenerated solid temperatures without complete regeneration and minimizes production of NOx. This will result in less coke yield and more product yield. If one employs the more common fluidized bed regenerator or fast fluid regenerator, the regenerator temperature must be lowered to reduce the oxidation of nitrogen to NOx.
  • the combustion air which is also the fluidizing media for the fluid bed, is distributed evenly over cross-sectional area of the regenerator.
  • the spent solid normally enters the regenerator from a point source either in the center of the regenerator or somewhere on the outer circumference of the regenerator vessel. This results in a carbon gradient in the fluid bed. In the area where the spent solid enters there is the maximum carbon concentration with a proportional amount of combustion air, and at areas away from the spent solid inlet, the carbon to be burned is decreased but the combustion air is proportional.
  • the cyclone inlets are arranged around the regenerator and combined into a common flue gas line. It is here, where the flue gas from the fluid bed, now with less solid particles, combines, that the excess oxygen reacts with the CO to produce high temperatures and NOx.
  • a fluid bed regenerator could be modified to take advantage of these teachings by arranging the regenerator cyclones so that the inlets to these cyclones are arranged to remove the flue gas exiting the fluid bed from the center of the dilute phase of the regenerator vessel.
  • the flow rate of cooled regenerated solid is regulated by slide valve 12 to control the regenerated solid temperature at, for example, less that 1300° F. (704° C.), and more preferably below 1250° F. (677° C.).
  • the products of combustion the flue gas in line 9
  • the regenerator flue gas 9 can be further processed for heat recovery and treated for particulate removal and SOx control before being exhausted to the atmosphere.
  • the regenerated solid is returned to reactor 4 to vaporize and contact the hydrocarbon feed and to heat the reactor stripper section 15 , and recycled through catalyst cooler 11 and slide valve 12 to combustion riser 6 to control the regenerated solid temperature.
  • the spent solid regeneration conditions in the regenerator i.e. in the combustor riser 6
  • the regenerated solid exposure to oxygen is minimized or eliminated by fluidization with, for example, a non-oxidizing gas, an inert gas or recycled flue gas, before the regenerated solid is conveyed to the reactor.
  • the regenerated solid has a carbon level of not more than about 0.4 wt. %, but at least about 0.05 wt. %, and the flue gas NOx content is less than about 150 ppm, preferably less than 100 ppm, and more preferably below 50 ppm. This can be accomplished by controlling the regenerator temperatures and atmosphere in the regenerator as described herein.
  • the regenerated solid temperature at the outlet of the riser 6 is maintained at not more than 1400° F., preferably less than 1300° F., and more preferably less than 1250° F.;
  • the carbon level on regenerated solid is maintained at not more than 0.4 wt %, preferably less than 0.1 wt %, and more preferably 0.05 wt %;
  • the excess oxygen in the flue gas exiting the riser is maintained at not more than 1.0 mol %, preferably less than 0.7 mol %, and more preferably 0.5 mol % or less.

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  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Catalysts (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Exhaust Gas Treatment By Means Of Catalyst (AREA)
US10/252,055 2001-10-24 2002-09-23 Process for controlling oxidation of nitrogen and metals in circulating fluidized solids contacting process Abandoned US20030075480A1 (en)

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US10/252,055 US20030075480A1 (en) 2001-10-24 2002-09-23 Process for controlling oxidation of nitrogen and metals in circulating fluidized solids contacting process
EP02023878A EP1306420A3 (fr) 2001-10-24 2002-10-24 Procédé de régulation d'oxydation d'azote et de métaux dans un procédé de lit fluidisé
CA002409612A CA2409612A1 (fr) 2001-10-24 2002-10-24 Procede de controle d'oxydation de l'azote et des metaux dans un procede de contact de solides circulant en lit fluidifie

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Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20110020207A1 (en) * 2008-06-06 2011-01-27 Evonik Roehm Gmbh Method for producing hydrogen cyanide in a particulate heat exchanger circulated as a moving fluidized bed
US20110094937A1 (en) * 2009-10-27 2011-04-28 Kellogg Brown & Root Llc Residuum Oil Supercritical Extraction Process
US8415264B2 (en) 2010-04-30 2013-04-09 Uop Llc Process for regenerating catalyst in a fluid catalytic cracking unit
US8618012B2 (en) 2010-04-09 2013-12-31 Kellogg Brown & Root Llc Systems and methods for regenerating a spent catalyst
US8618011B2 (en) 2010-04-09 2013-12-31 Kellogg Brown & Root Llc Systems and methods for regenerating a spent catalyst

Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4243514A (en) * 1979-05-14 1981-01-06 Engelhard Minerals & Chemicals Corporation Preparation of FCC charge from residual fractions
US4284494A (en) * 1978-05-01 1981-08-18 Engelhard Minerals & Chemicals Corporation Control of emissions in FCC regenerator flue gas
US4377470A (en) * 1981-04-20 1983-03-22 Ashland Oil, Inc. Immobilization of vanadia deposited on catalytic materials during carbo-metallic oil conversion
US4859315A (en) * 1987-11-05 1989-08-22 Bartholic David B Liquid-solid separation process and apparatus
US4965232A (en) * 1988-03-09 1990-10-23 Compagnie De Raffinage Et De Distribution Total France Process for fluidized-bed catalyst regeneration
US4985136A (en) * 1987-11-05 1991-01-15 Bartholic David B Ultra-short contact time fluidized catalytic cracking process
US5584986A (en) * 1993-03-19 1996-12-17 Bar-Co Processes Joint Venture Fluidized process for improved stripping and/or cooling of particulate spent solids, and reduction of sulfur oxide emissions

Family Cites Families (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP1043384A3 (fr) * 1999-04-09 2001-05-30 Bar-Co Processes Joint Venture Procédé de craquage catalytique en lit fluidisé avec un catalyseur ayant une résistance ameliorée aux métaux

Patent Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4284494A (en) * 1978-05-01 1981-08-18 Engelhard Minerals & Chemicals Corporation Control of emissions in FCC regenerator flue gas
US4243514A (en) * 1979-05-14 1981-01-06 Engelhard Minerals & Chemicals Corporation Preparation of FCC charge from residual fractions
US4377470A (en) * 1981-04-20 1983-03-22 Ashland Oil, Inc. Immobilization of vanadia deposited on catalytic materials during carbo-metallic oil conversion
US4859315A (en) * 1987-11-05 1989-08-22 Bartholic David B Liquid-solid separation process and apparatus
US4985136A (en) * 1987-11-05 1991-01-15 Bartholic David B Ultra-short contact time fluidized catalytic cracking process
US4965232A (en) * 1988-03-09 1990-10-23 Compagnie De Raffinage Et De Distribution Total France Process for fluidized-bed catalyst regeneration
US5584986A (en) * 1993-03-19 1996-12-17 Bar-Co Processes Joint Venture Fluidized process for improved stripping and/or cooling of particulate spent solids, and reduction of sulfur oxide emissions

Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20110020207A1 (en) * 2008-06-06 2011-01-27 Evonik Roehm Gmbh Method for producing hydrogen cyanide in a particulate heat exchanger circulated as a moving fluidized bed
US20110094937A1 (en) * 2009-10-27 2011-04-28 Kellogg Brown & Root Llc Residuum Oil Supercritical Extraction Process
US8618012B2 (en) 2010-04-09 2013-12-31 Kellogg Brown & Root Llc Systems and methods for regenerating a spent catalyst
US8618011B2 (en) 2010-04-09 2013-12-31 Kellogg Brown & Root Llc Systems and methods for regenerating a spent catalyst
US8415264B2 (en) 2010-04-30 2013-04-09 Uop Llc Process for regenerating catalyst in a fluid catalytic cracking unit

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