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WO2001059032A1 - Procédé de désulfuration d'alimentations de pétrole - Google Patents

Procédé de désulfuration d'alimentations de pétrole Download PDF

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Publication number
WO2001059032A1
WO2001059032A1 PCT/US2000/042756 US0042756W WO0159032A1 WO 2001059032 A1 WO2001059032 A1 WO 2001059032A1 US 0042756 W US0042756 W US 0042756W WO 0159032 A1 WO0159032 A1 WO 0159032A1
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WO
WIPO (PCT)
Prior art keywords
hydrogen
hydrodesulfurization
organic sulfur
sulfur compounds
naphtha
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.)
Ceased
Application number
PCT/US2000/042756
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English (en)
Inventor
Gary G. Podrebarac
Gary R. Gildert
Willibrord A. Groten
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Catalytic Distillation Technologies
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Catalytic Distillation Technologies
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 US09/502,509 external-priority patent/US6303020B1/en
Application filed by Catalytic Distillation Technologies filed Critical Catalytic Distillation Technologies
Priority to MXPA02007375A priority Critical patent/MXPA02007375A/es
Priority to AU2001247166A priority patent/AU2001247166A1/en
Publication of WO2001059032A1 publication Critical patent/WO2001059032A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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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
    • C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes only
    • C10G65/02—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only
    • C10G65/04—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only including only refining steps

Definitions

  • the present invention relates to a process for the desulfurization of a full boiling range fluid catalytic cracked naphtha by the reaction of hydrogen with the organic sulfur compounds present in a feed in the presence of a hydrodesulfunzation catalysts.
  • the present invention may employ catalytic distillation steps which reduce sulfur to very low levels, makes more efficient use of hydrogen and causes less olefin hydrogenation for a full boiling range naphtha stream.
  • Petroleum distillate streams contain a variety of organic chemical components. Generally the streams are defined by their boiling range which determines the composition.
  • the processing of the streams also affects the composition.
  • products from either catalytic cracking or thermal cracking processes contain high concentrations of olefinic materials as well as saturated (alkanes) materials and polyunsaturated materials (diolefins). Additionally, these components may be any of the various isomers of the compounds.
  • the composition of untreated naphtha as it comes from the crude still, or straight run naphtha is primarily influenced by the crude source. Naphthas from paraffinic crude sources have more saturated straight chain or cyclic compounds. As a general rule most of the "sweet" (low sulfur) crudes and naphthas are paraffinic. The naphthenic crudes contain more unsaturates and cyclic and polycylic compounds. The higher sulfur content crudes tend to be naphthenic. Treatment of the different straight run naphthas may be slightly different depending upon their composition due to crude source.
  • Reformed naphtha or reformate generally requires no further treatment except perhaps distillation or solvent extraction for valuable aromatic product removal.
  • Reformed naphthas have essentially no sulfur contaminants due to the severity of their pretreatment for the process and the process itself.
  • the sulfur impurities may require removal, usually by hydrotreating, in order to comply with product specifications or to ensure compliance with environmental regulations. Some users wish the sulfur of the final product to be below 50 wppm.
  • HDS hydrodesulfurization
  • the product may be fractionated or simply flashed to release the hydrogen sulfide and collect the now desulfurized naphtha.
  • the loss of olefins by incidental hydrogenation is detrimental by the reduction of the octane rating of the naphtha and the reduction in the pool of olefins for other uses.
  • the cracked naphthas are often used as sources of olefins in other processes such as etherifications.
  • the conditions of hydrotreating of the naphtha fraction to remove sulfur will also saturate some of the olefinic compounds in the fraction reducing the octane and causing a loss of source olefins.
  • the predominant light or lower boiling sulfur compounds are mercaptans while the heavier or higher boiling compounds are thiophenes and other heterocyclic compounds.
  • the separation by fractionation alone will not remove the mercaptans.
  • the mercaptans have been removed by oxidative processes involving caustic washing.
  • a combination oxidative removal of the mercaptans followed by fractionation and hydrotreating of the heavier fraction is disclosed in U.S. patent 5,320,742. In the oxidative removal of the mercaptans the mercaptans are converted to the corresponding disulfides.
  • U.S. Pat. No. 5,597,476 discloses a two step process in which naphtha is fed to a first distillation column reactor which acts as a depentanizer or dehexanizer with the lighter material containing most of the olefins and mercaptans being boiled up into a first distillation reaction zone where the mercaptans are reacted with diolefins to form sulfides which are removed in the bottoms along with any higher boiling sulfur compounds.
  • the bottoms are subjected to hydrodesulfurization in a second distillation column reactor where the sulfur compounds are converted to H 2 S and removed.
  • Recombinant sulfur means new organic sulfur compounds, mainly mercaptans, that are formed by the reverse reaction of H 2 S from the preceding hydrodesulfurization or hydrodesulfurizations in succeeding hydrodesulfurizations with olefins in the feed.
  • the H 2 S can recombine to form mercaptans thus increasing the amount of sulfur in the product.
  • the presence of H 2 S can cause more of the olefins to be saturated losing octane and consuming hydrogen.
  • the product from the sequential multibed hydrodesulfurizations does of course have lower sulfur content than a feed having less treatment, but each subsequent treatment has been less efficient than expected because of the recombinant sulfur.
  • the efficiency of a subsequent treatment has been increased by stripping the H 2 S from the treated feed prior to passing the feed to a subsequent hydrodesulfurization .
  • the present invention is in a process of hydrodesulfurization of a petroleum feed containing organic sulfur compounds and preferably olefins by at least two sequential treatments of the feed by contact with hydrogen in the presence of a hydrodesulfurization catalyst to convert a portion of the organic sulfur compounds to H 2 S, wherein the improvement is the removal of H 2 S from the feed after each said treatment.
  • a full boiling range naphtha is subjected to a two stage process for the removal of organic sulfur by hydrodesulfurization.
  • the full boiling range naphtha is desulfurized in a distillation column reactor which acts as a splitter taking a hydrodesulfurized light naphtha overhead along with the H 2 S produced in the reactor.
  • a significant portion of the H 2 S is removed from the overhead accumulator/separator.
  • the heavier fraction is hydrodesulfurized and removed as a bottoms.
  • the bottoms and overheads are then fed to an H 2 S stripper wherein the remainder of the H 2 S is stripped from the desulfurized naphtha.
  • the bottoms from the H 2 S stripper are then fed to a second reactor (either a standard single pass reactor or a second distillation column reactor).
  • a second reactor either a standard single pass reactor or a second distillation column reactor.
  • the removal of the H 2 S serves two purposes. It prevents the formation of recombinant organic sulfur compounds and allows for less severe conditions for the same sulfur removal while preventing hydrogenation of olefins.
  • distillation column reactor means a distillation column which also contains catalyst such that reaction and distillation are going on concurrently in the column.
  • the catalyst is prepared as a distillation structure and serves as both the catalyst and distillation structure.
  • Fig. 1 is a flow diagram in schematic form using two straight pass hydrodesulfurization reactors in sequence and having H 2 S removal between the two reactors.
  • Fig. 2 is a flow diagram in schematic form using two hydrodesulfurization reactors in sequence, the first being a catalytic distillation reactor which has two hydrodesulfurization zones, one for a lighter fraction and one for the heavies, which are separately treated then combined in a stripper to remove H 2 S before going to a straight pass hydrodesulfurization unit.
  • the feed to the process comprises a sulfur-containing petroleum fraction particularly from a fluidized bed catalytic cracking unit (FCCU) which boils in the gasoline boiling range (C 5 to 420 °F).
  • FCCU fluidized bed catalytic cracking unit
  • the process is useful on the naphtha boiling range material from catalytic cracker products because they contain the desired olefins and unwanted sulfur compounds.
  • Straight run naphthas have very little olefinic material, and unless the crude source is "sour", very little sulfur.
  • the sulfur content of the catalytically cracked fractions will depend upon the sulfur content of the feed to the cracker as well as the boiling range of the selected fraction used as feed to the process. Lighter fractions will have lower sulfur contents than higher boiling fractions.
  • the front end of the naphtha contains most of the high octane olefins but relatively little of the sulfur.
  • the sulfur components in the front end are mainly mercaptans and typical of those compounds are: methyl mercaptan (b.p.43 °F), ethyl mercaptan (b.p. 99°F), n-propyl mercaptan (b.p. 154°F), iso-propyl mercaptan (b.p. 135-140°F), iso-butyl mercaptan (b.p.
  • Typical sulfur compounds found in the heavier boiling fraction include the heavier mercaptans, thiophenes, sulfides and disulfides.
  • hydrodesulfurization The reaction of organic sulfur compounds in a refinery stream with hydrogen over a catalyst to form H 2 S is typically called hydrodesulfurization.
  • Hydrotreating is a broader term which includes saturation of olefins and aromatics and the reaction of organic nitrogen compounds to form ammonia.
  • hydrodesulfurization is included and is sometimes simply referred to as hydrotreating.
  • Catalysts which are useful for the hydrodesulfurization reaction include Group VIII metals such as cobalt, nickel, palladium, alone or in combination with other metals such as molybdenum or tungsten on a suitable support which may be alumina, silica-alumina, titania- zirconia or the like. Normally the metals are provided as the oxides of the metals supported on extrudates or spheres and as such are not generally useful as distillation structures.
  • the catalysts may additionally contain components from Group V and VIB metals of the Periodic Table or mixtures thereof.
  • the Group VIII metal provides increased overall average activity.
  • Catalysts containing a Group VIB metal such as molybdenum and a Group VIII such as cobalt or nickel are preferred.
  • Catalysts suitable for the hydrodesulfurization reaction include cobalt-molybdenum, nickel-molybdenum and nickel-tungsten.
  • the metals are generally present as oxides supported on a neutral base such as alumina, silica-alumina or the like. The metals are reduced to the sulfide either in use or prior to use by exposure to sulfur compound containing streams.
  • the catalyst typically is in the form of extrudates having a diameter of 1/8, 1/16 or 1/32 inches and an L/D of 1.5 to 10.
  • the catalyst also may be in the form of spheres having the same diameters. In their regular form they form too compact a mass and are preferably prepared in the form of a catalytic distillation structure.
  • the catalytic distillation structure must be able to function as catalyst and as mass transfer medium. Catalytic distillation structures useful for this purpose are disclosed in U.S. patents 4,731,229, 5,073,236, 5,431 ,890 and 5,266,546 which are incorporated by reference.
  • reaction distillation system catalytic distillation reduces the deactivation and provides for longer runs than the fixed bed hydrogenation units and is preferable for the first reactor.
  • the distillation column reactor is advantageously used to react the heavier or higher boiling sulfur compounds.
  • the overhead pressure is maintained at about 0 to 250 psig with the corresponding temperature in the distillation reaction zone of between 400 to 700°F.
  • Hydrogen partial pressures of 0.1 to 70 psia may be used. In one preferred embodiment hydrogen partial pressure of 0.1 to 10 is used. Generally hydrogen partial pressures in the range of 0.5 to 50 psia give optimum results.
  • the second reactor can be a vapor phase single pass downflow reactor because the major portion of the sulfur compounds has been removed. Because the H 2 S and more difficult sulfur compounds have already been removed, the reactor can be operated at milder conditions, for instance at about 200 psig pressure, 500 °F reactor temperature and 3 liquid hourly space velocity.
  • a second distillation column If a second distillation column is used, a lower total pressure in the range of 25 to less than 300 psig is required for the hydrodesulfurization and hydrogen partial pressure of less than 150 psi, preferably down to 0.1 psi can be employed preferably about 15 to 50 psi.
  • the temperature in the distillation reaction zone is in the range from 400 to 750 °F.
  • Hydrogen for the second distillation column reactor is fed in the range of one to ten standard cubic feet (SCF) per pound of feed. Nominal liquid hourly space velocities (liquid volume of feed per unit volume of catalyst) in the second column are in the range of 2-5.
  • SCF standard cubic feet
  • Nominal liquid hourly space velocities (liquid volume of feed per unit volume of catalyst) in the second column are in the range of 2-5.
  • Typical conditions in a reaction distillation zone (second and subsequent columns) of a naphtha hydrodesulfurization distillation column reactor are:
  • distillation column reactor results in both a liquid and vapor phase within the distillation reaction zone.
  • a considerable portion of the vapor is hydrogen while a portion is vaporous hydrocarbon from the petroleum fraction. Actual separation may only be a secondary consideration.
  • the mechanism that produces the effectiveness of the hydrogenation in the distillation column reactor is the condensation of a portion of the vapors in the reaction system, which occludes sufficient hydrogen in the condensed liquid to obtain the requisite intimate contact between the hydrogen and the sulfur compounds in the presence of the catalyst to result in their hydrogenation.
  • sulfur species concentrate in the liquid while the olefins and H 2 S concentrate in the vapor allowing for high conversion of the sulfur compounds with low conversion of the olefin species.
  • the result of the operation of the process in the distillation column reactor is that lower hydrogen partial pressures (and thus lower total pressures) may be used.
  • any distillation there is a temperature gradient within the distillation column reactor.
  • the temperature at the lower end of the column contains higher boiling material and thus is at a higher temperature than the upper end of the column.
  • the lower boiling fraction which contains more easily removable sulfur compounds, is subjected to lower temperatures at the top of the column which provides for greater selectivity, that is, less hydrocracking or saturation of desirable olefinic compounds.
  • the higher boiling portion is subjected to higher temperatures in the lower end of the distillation column reactor to crack open the sulfur containing ring compounds and hydrogenate the sulfur.
  • H 2 S stripper In between the two reactors is an H 2 S stripper which effectively removes all of the product H 2 S from the first column. This prevents contact of the H 2 S and olefins with the catalyst and the resultant formation of recombinant organic sulfur compounds and allows for less severe conditions in the second reactor for the same sulfur removal while preventing hydrogenation of olefins.
  • FIG. 1 there is shown a schematic flow diagram of one embodiment of the invention.
  • Naphtha is fed to a first single pass fixed bed reactor 10 via flow line 1 and hydrogen is fed to the reactor 10 via flow line 2.
  • the reactor 10 contains a bed 11 of appropriate hydrodesulfurization catalyst.
  • a portion of the organic sulfur compounds reacts with hydrogen to form H 2 S.
  • the conditions in the first reactor are mild by hydrodesulfurization standards. For example the temperature is in the range of 550 to 600°F, the pressure is in the range 50 to 150 psig and the liquid hourly space velocity (LHSV) is in the range of 5 to 10 volumes of naphtha per volume of catalyst. The degree of desulfurization is thus somewhat less than normal, about 95 %.
  • the effluent from the first reactor 10 is fed to a first stripping column 20 wherein the
  • H 2 S and excess hydrogen are stripped out in the overheads via flow line 4.
  • the condensible materials in the overheads are condensed in condenser 21 and separated from the H 2 S and hydrogen in separator 22.
  • the excess hydrogen and H 2 S are removed via flow line 12.
  • the condensed material is returned to the stripper as reflux via flow line 13.
  • the bottoms from the stripper 20 are fed to a second single pass fixed bed reactor 20 via flow line 5 with make up hydrogen being fed to the reactor 20 via flow line 2.
  • the reactor 20 contains a second bed 21 of an appropriate hydrodesulfurization catalyst. The conditions in the second reactor are adjusted to give the desired degree of desulfurization.
  • the effluent from the second reactor 20 is fed to a second stripper 40 where excess hydrogen and the H 2 S produced in the second reactor 20 is stripped out with the overheads via flow line 8. Again the condensible materials in the overheads are condensed in condenser 41 and separated from the hydrogen and H 2 S in separator 42 and returned to the second stripper via flow line 14 as reflux. The excess hydrogen and H 2 S are removed via flow line 14.
  • the final product is removed as bottoms via flow line 9. Since the H 2 S is removed between the reactors milder conditions may be used in the second reactor and thus the olefins are not subject to hydrogenation conditions.
  • the first reactor is a distillation column reactor 10 containing two beds 11a and l ib of a hydrodesulfurization catalyst in the form of catalytic distillation structures.
  • the naphtha is fed between the beds via flow line 1 and hydrogen is fed below the beds via flow line 2.
  • the catalytic distillation column may be operated at lower pressures less of the olefins will be saturated.
  • the catalytic distillation column is more efficient at hydrogenating the heavy sulfur compounds such as the thiophenes and benzothiophenes.
  • a light naphtha is taken overheads via flow line 4 along with excess hydrogen and most of the H 2 S produced in the beds.
  • the condensible material is condensed in condenser 50 and collected in separator 60 where the vapors, including the H 2 S and excess hydrogen, are removed via flow line 12.
  • a portion of the condensed liquids is returned to the distillation column reactor 10 as reflux via flow line 13.
  • the remainder of the liquid overheads is fed into the upper portion of a stripper column 20.
  • the bottoms from the distillation column reactor 10 are also fed to the stripper column 20 but into the lower section via flow line 3.
  • the stripper column strips out the H 2 S in the overheads via flow line 15.
  • the condensible materials in the overheads are condensed in condenser 21 and collected in separator 22 where it is separated from the excess hydrogen and H 2 S.
  • the excess hydrogen and H 2 S are removed from the separator via flow line 16 while the liquid is returned to the stripper as reflux via flow line 23.
  • Final product is removed as bottoms via flow line 9.
  • a side stream is taken from the stripper 20 via flow line 5 and fed to a fixed bed single pass reactor 30 containing a bed 31 of a suitable hydrodesulfurization catalyst where the lighter organic sulfur compounds are reacted with hydrogen which is fed via flow line 6.
  • Effluent from the reactor 20 is fed via flow line 32 to flash drum 40 where the hydrogen and H 2 S are flashed form the effluent and fed to the upper portion of the stripper 20 via flow line
  • DC- 130 cobalt/molybdenum catalyst placed in the catalyst structures as disclosed in U.S. Pat. No. 5,730,843 disposed in a 3" nominal diameter in two sections of a 50 foot column with 15.1 feet of catalyst below the feed point and 18.7 feet of catalyst above the feed point. The hydrocarbon feed entered between the two catalyst beds. Feed Description
  • EXAMPLE 2 The feed as described in Example 1 was processed in the distillation column reactor of Example 1. Only the overheads were stripped of H 2 S and excess hydrogen and processed at the following in the conditions in the polishing reactor to achieve a naphtha containing 27 wppm:
  • the catalytic distillation column was run at 195 psig overhead pressure giving a catalyst bed temperature of 590°F.
  • the catalytic distillation column running alone produced 98.98% sulfur removal with a 66.15% loss in olefins. However, the total sulfur content was about 24 wppm.

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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)

Abstract

La présente invention concerne un procédé d'hydrodésulfuration d'un courant de naphta de craquage (1) dans lequel très peu d'oléfines précieuses sont saturées. Ce procédé est un procédé à deux étapes dans lequel le H2S est extrait entre ces étapes via les conduites (12, 16) pour empêcher la formation de mercaptans recombinés. Etant donnée que le H2S est extrait entre ces deux étapes, on peut utiliser des conditions plus douces dans le réacteur de polissage de la seconde étape pour atteindre les mêmes niveaux de désulfuration avec moins de pertes d'oléfines.
PCT/US2000/042756 2000-02-11 2000-12-12 Procédé de désulfuration d'alimentations de pétrole Ceased WO2001059032A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
MXPA02007375A MXPA02007375A (es) 2000-02-11 2000-12-12 Proceso para la desulfuracion de alimentaciones de petroleo.
AU2001247166A AU2001247166A1 (en) 2000-02-11 2000-12-12 Process for the desulfurization of petroleum feeds

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US09/502,509 2000-02-11
US09/502,509 US6303020B1 (en) 2000-01-07 2000-02-11 Process for the desulfurization of petroleum feeds

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WO2001059032A1 true WO2001059032A1 (fr) 2001-08-16

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PCT/US2000/042756 Ceased WO2001059032A1 (fr) 2000-02-11 2000-12-12 Procédé de désulfuration d'alimentations de pétrole

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CN (1) CN1264957C (fr)
AR (1) AR027010A1 (fr)
AU (1) AU2001247166A1 (fr)
EG (1) EG22319A (fr)
MX (1) MXPA02007375A (fr)
RU (1) RU2241021C2 (fr)
SA (1) SA01220321B1 (fr)
TW (1) TW522168B (fr)
WO (1) WO2001059032A1 (fr)
ZA (1) ZA200007804B (fr)

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2003025095A3 (fr) * 2001-09-17 2003-09-18 Catalytic Distillation Tech Procede de desulfuration d'un naphtha fcc leger
CN100457860C (zh) * 2001-09-28 2009-02-04 催化蒸馏技术公司 Fcc石脑油的脱硫工艺
US8628656B2 (en) 2010-08-25 2014-01-14 Catalytic Distillation Technologies Hydrodesulfurization process with selected liquid recycle to reduce formation of recombinant mercaptans
WO2021034632A1 (fr) * 2019-08-20 2021-02-25 Uop Llc Processus d'hydrotraitement de naphta avec lit de garde au soufre

Families Citing this family (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7638041B2 (en) * 2005-02-14 2009-12-29 Catalytic Distillation Technologies Process for treating cracked naphtha streams
RU2402594C1 (ru) * 2006-07-19 2010-10-27 Юоп Ллк Способ десульфуризации углеводородов
US8486258B2 (en) * 2010-04-01 2013-07-16 Catalytic Distillation Technologies Gasoline hydrodesulfurization and membrane unit to reduce mercaptan type sulfur
EP2816094B1 (fr) * 2013-06-19 2020-04-29 IFP Energies nouvelles Procédé de production d'une essence à basse teneur en soufre et en mercaptans
US10526550B2 (en) * 2016-11-23 2020-01-07 Haldor Topsøe A/S Kgs. Process for desulfurization of hydrocarbons

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US3349027A (en) * 1965-02-08 1967-10-24 Gulf Research Development Co Multi-stage hydrodesulfurization process
US4166026A (en) * 1977-07-15 1979-08-28 Chiyoda Chemical Engineering & Construction Co., Ltd. Two-step hydrodesulfurization of heavy hydrocarbon oil
US4243519A (en) * 1979-02-14 1981-01-06 Exxon Research & Engineering Co. Hydrorefining process
US4392945A (en) * 1982-02-05 1983-07-12 Exxon Research And Engineering Co. Two-stage hydrorefining process
US4430203A (en) * 1982-02-05 1984-02-07 Chevron Research Company Hydrotreating or hydrocracking process
US5720872A (en) * 1996-12-31 1998-02-24 Exxon Research And Engineering Company Multi-stage hydroprocessing with multi-stage stripping in a single stripper vessel

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RU2087524C1 (ru) * 1995-06-27 1997-08-20 Всероссийский научно-исследовательский институт по переработке нефти Способ облагораживания бензиновых дистиллятов

Patent Citations (6)

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Publication number Priority date Publication date Assignee Title
US3349027A (en) * 1965-02-08 1967-10-24 Gulf Research Development Co Multi-stage hydrodesulfurization process
US4166026A (en) * 1977-07-15 1979-08-28 Chiyoda Chemical Engineering & Construction Co., Ltd. Two-step hydrodesulfurization of heavy hydrocarbon oil
US4243519A (en) * 1979-02-14 1981-01-06 Exxon Research & Engineering Co. Hydrorefining process
US4392945A (en) * 1982-02-05 1983-07-12 Exxon Research And Engineering Co. Two-stage hydrorefining process
US4430203A (en) * 1982-02-05 1984-02-07 Chevron Research Company Hydrotreating or hydrocracking process
US5720872A (en) * 1996-12-31 1998-02-24 Exxon Research And Engineering Company Multi-stage hydroprocessing with multi-stage stripping in a single stripper vessel

Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2003025095A3 (fr) * 2001-09-17 2003-09-18 Catalytic Distillation Tech Procede de desulfuration d'un naphtha fcc leger
CN1325614C (zh) * 2001-09-17 2007-07-11 催化蒸馏技术公司 轻fcc石脑油的脱硫方法
CN100457860C (zh) * 2001-09-28 2009-02-04 催化蒸馏技术公司 Fcc石脑油的脱硫工艺
US8628656B2 (en) 2010-08-25 2014-01-14 Catalytic Distillation Technologies Hydrodesulfurization process with selected liquid recycle to reduce formation of recombinant mercaptans
WO2021034632A1 (fr) * 2019-08-20 2021-02-25 Uop Llc Processus d'hydrotraitement de naphta avec lit de garde au soufre
US11124710B2 (en) 2019-08-20 2021-09-21 Uop Llc Naphtha hydrotreating process with sulfur guard bed having controlled bypass flow

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TW522168B (en) 2003-03-01
SA01220321B1 (ar) 2006-11-14
MXPA02007375A (es) 2002-12-16
CN1264957C (zh) 2006-07-19
EG22319A (en) 2002-12-31
AR027010A1 (es) 2003-03-12
CN1425053A (zh) 2003-06-18
RU2241021C2 (ru) 2004-11-27
AU2001247166A1 (en) 2001-08-20
RU2002124137A (ru) 2004-01-10
ZA200007804B (en) 2001-06-21

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