US20060191821A1 - Process for deep desulfurization by adsorption of a gas oil-type hydrocarbon fraction - Google Patents

Process for deep desulfurization by adsorption of a gas oil-type hydrocarbon fraction Download PDF

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US20060191821A1
US20060191821A1 US11/360,586 US36058606A US2006191821A1 US 20060191821 A1 US20060191821 A1 US 20060191821A1 US 36058606 A US36058606 A US 36058606A US 2006191821 A1 US2006191821 A1 US 2006191821A1
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deep desulfurization
adsorbent solid
sulfur
solid
weight
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Alexandre Nicolaos
Thorsten Burkhardt
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IFP Energies Nouvelles IFPEN
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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
    • C10G25/00—Refining of hydrocarbon oils in the absence of hydrogen, with solid sorbents
    • C10G25/06—Refining of hydrocarbon oils in the absence of hydrogen, with solid sorbents with moving sorbents or sorbents dispersed in the oil
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J20/00—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof
    • B01J20/02—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material
    • B01J20/0203—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material comprising compounds of metals not provided for in B01J20/04
    • B01J20/024—Compounds of Zn, Cd, Hg
    • B01J20/0244—Compounds of Zn
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J20/00—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof
    • B01J20/02—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material
    • B01J20/06—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material comprising oxides or hydroxides of metals not provided for in group B01J20/04
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J20/00—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof
    • B01J20/02—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material
    • B01J20/06—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material comprising oxides or hydroxides of metals not provided for in group B01J20/04
    • B01J20/08—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material comprising oxides or hydroxides of metals not provided for in group B01J20/04 comprising aluminium oxide or hydroxide; comprising bauxite
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J20/00—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof
    • B01J20/02—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material
    • B01J20/10—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material comprising silica or silicate
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J20/00—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof
    • B01J20/02—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material
    • B01J20/10—Solid sorbent compositions or filter aid compositions; Sorbents for chromatography; Processes for preparing, regenerating or reactivating thereof comprising inorganic material comprising silica or silicate
    • B01J20/16—Alumino-silicates
    • 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
    • C10G25/00—Refining of hydrocarbon oils in the absence of hydrogen, with solid sorbents
    • C10G25/003—Specific sorbent material, not covered by C10G25/02 or C10G25/03
    • 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
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
    • 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
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
    • C10G45/04—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used
    • C10G45/06—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof

Definitions

  • This invention relates to a process for deep desulfurization of a hydrocarbon fraction of distillate type or of gas oil according to the terminology of one skilled in the art, using a high-temperature sulfur collection unit.
  • a distillate-type fraction is defined as a fraction that is obtained from the distillation of crude or from a conversion unit such as catalytic cracking, and whose distillation interval is between 150° C. and 450° C.
  • This fraction may have any chemical nature, i.e., it may have a distribution between any paraffins, olefins, naphthenes and aromatic compounds.
  • the process according to the invention therefore makes it possible to produce a desulfurized hydrocarbon fraction with contents that are less than or equal to 10 ppm of sulfur, preferably less than 5 ppm of sulfur, and even more preferably less than 1 ppm of sulfur.
  • This invention can be regarded as a new process for deep desulfurization of gas oil fractions that can be applied as of the time that the sulfur content of the feedstock to be treated remains within certain limits or else can be combined with a traditional hydrodesulfurization unit, in which case it will be placed downstream from said hydrodesulfurization unit.
  • Patent U.S. Pat. No. 5,454,933 describes a process for desulfurization of gas oil that consists in linking a standard hydrotreatment for eliminating the so-called “easy sulfur” sulfur-containing compounds (that can be translated by sulfur-containing compounds that are easy to eliminate) with a process for adsorbing difficult sulfur-containing compounds (called “hard sulfur” in the cited patent) on active carbon with a specific surface area of between 800 and 1200 m 2 /g and that exhibits a certain porous structure.
  • the adsorption process that is described in this patent is limited to temperatures that are less than or equal to 175° C., whereas the process according to this invention operates at temperatures of greater than 200° C.
  • the regeneration of the active carbon is carried out in the patent that is cited by means of a solvent, whereas in the process according to this invention, the regeneration of the adsorbent solid is done by a controlled combustion.
  • Patent Application US 2004140244A1 describes a deep desulfurization of gas oil by using an adsorbent solid with a zinc oxide base that employs a promoter in reduced state, whereas the process according to this invention uses a promoter in oxide form, which makes it possible to carry out the regeneration of the adsorbent solid without having to reduce it.
  • FIG. 1 shows the diagram of the process for deep desulfurization treatment, the object of this invention.
  • FIG. 2 shows the diagram of the regeneration of the adsorbent solid used in the process that is the object of the invention.
  • FIG. 3 shows a non-limiting example of integration of the deep desulfurization process according to the invention with a standard process for hydrodesulfurization of gas oil.
  • the invention can be defined as a process for deep desulfurization of a gas oil-type hydrocarbon feedstock, with a distillation interval of between 150° C. and 450° C.
  • the process consists in bringing into contact the feedstock to be treated with an adsorbent solid that contains at least zinc oxide, and another metal oxide, called a promoter, deposited on an inorganic substrate under high temperature conditions, typically higher than 200° C., preferably higher than 300° C., and even more preferably higher than 350° C.
  • adsorbent solid when the adsorbent solid is saturated by sulfur-containing compounds, the process moves on to the regeneration phase of the solid, the latter essentially consisting of a controlled combustion of compounds adsorbed on the surface of the solid.
  • the regenerated solid can then be brought back into contact with the feedstock that is to be treated.
  • the feedstock that is to be treated is a hydrocarbon fraction with a distillation interval of between 150° C. and 450° C., and whose sulfur content should be less than 500 ppmS, preferably less than 200 ppmS, and even more preferably less than 50 ppmS, so as to keep the longest cycle time possible.
  • the contact between the feedstock to be treated and the adsorbent solid should be made in the presence of hydrogen.
  • the amount of hydrogen to be supplied is set by the ratio of the volumetric flow rate of hydrogen, taken under the input conditions, to the liquid volumetric flow rate of the hydrocarbon feedstock that is to be treated. This ratio should be between 5 and 400 and preferably between 50 and 300.
  • the contact between the adsorbent solid and the feedstock that is to be treated under the required conditions brings about the passage of a portion of said solid from the oxide phase to the sulfide phase.
  • the adsorbent solid of the contactor that is considered is stripped with nitrogen to eliminate the gases and the hydrocarbons that are partially converted and that are found in the pore volume of said contactor, before entering into the regeneration phase per se.
  • the process therefore requires at least two adsorbers, working alternately in adsorption/reaction and in regeneration, according to the technique called “swing” reactors that is well known to one skilled in the art.
  • the stripping phase is accompanied by a rise in temperature that makes it possible both to improve the stripping itself and to reach the necessary temperature for bringing back the adsorption solid of the sulfide phase to the oxide phase by a controlled combustion.
  • dilute air is sent into the adsorber so as to carry out the controlled combustion of the adsorbed compounds on the adsorbent solid and thus to bring back the adsorbent solid into oxide phase.
  • the adsorbent solid is stripped again to eliminate the possible unburned compounds that remain at the end of the burning phase and to drop the temperature again to the level required by the adsorption phase.
  • the sulfur content of the gas oil that is obtained will generally be less than 10 ppmS, preferably less than 5 ppmS, and even more preferably less than 1 ppmS, with a weight yield relative to the input feedstock that is generally greater than 95% and preferably greater than 97%.
  • a diagram example that contains 6 adsorbers numbered from A- 1 to A- 6 is presented.
  • the adsorbers A- 1 , A- 2 and A- 3 are in adsorption phase while the adsorbers A- 4 , A- 5 and A- 6 are in regeneration phase.
  • each adsorber takes the place of the one whose number is immediately above it, except for adsorber A- 6 that takes the place of adsorber A- 1 .
  • the cycle time is defined as being the perforation time divided by the number of adsorption columns.
  • the perforation time is defined as being the time during which a gas oil is produced to the specifications required for an adsorbent solid volume that is equal to the sum of the volumes of the adsorbers that work in the adsorption phase.
  • FIG. 1 exhibits the adsorption portion of the deep desulfurization process.
  • the feedstock that is to be treated ( 1 ) is mixed with the hydrogen ( 2 ) that can be obtained from a hydrotreatment or a hydrogen production unit for forming the flow ( 3 ).
  • the gas/liquid mixture ( 3 ) is reheated to the working temperature that is desired in a heat exchanger E- 1 .
  • the working temperature is selected based on the nature of the sulfur-containing compounds that are to be treated. In the case of sulfur-containing compounds such as thiophene, the temperature should be greater than 200° C., whereas in the case of the benzothiophenic compounds, the temperature will preferably be greater than 300° C., and in the case of refractory sulfur-containing compounds of the benzothiophenic type, the temperature will preferably be greater than 350° C.
  • This temperature should, however, be less than the degradation temperature of the feedstock that is used, which is typically 450° C. for a gas oil.
  • the work pressure will be selected in an interval of between 2 and 20 bar, and preferably between 5 and 15 bar.
  • the amount of solid to be used depends on the VVH (hourly volumetric flow rate) that is defined as the ratio between the liquid volumetric flow rate of the feedstock relative to the volume of adsorbent solid that is used.
  • the VVH will be between 0.1 h-1 and 10 h-1, and preferably between 0.5 h-1 and 5 h-1.
  • the effluent flow ( 4 ) from exchanger E 1 can be divided into, for example, three flows ( 4 a ), ( 4 b ) and ( 4 c ) that will each feed an adsorber A- 1 , A- 2 and A- 3 .
  • the effluents ( 5 a ), ( 5 b ) and ( 5 c ) that are obtained from adsorbers A- 1 , A- 2 , and A- 3 are mixed with one another, and the resulting flow ( 5 ) is introduced into a flash tank that works by lowering temperature to separate the hydrogen and to recover the gas oil that is desulfurized to the required specifications.
  • FIG. 2 exhibits the stages for regeneration of the solid that is used for the deep desulfurization process according to the invention.
  • the adsorber A- 4 undergoes a stripping/reheating that makes it possible to evacuate the gas oil feedstock that is present in the pores of the solid.
  • a cover gas such as the input nitrogen ( 6 ) is added to the nitrogen ( 17 a ) that is recycled at the input of the process.
  • the nitrogen flow ( 7 ) that is thus formed is compressed with the aid of the compressor E- 2 .
  • the flow ( 8 ) that is obtained is separated into two flows.
  • the flow ( 9 ) is reheated in the exchanger E- 3 , and the nitrogen flow ( 10 ) that is obtained is used to carry out the stripping and the reheating of the adsorber A- 4 .
  • the effluent ( 11 ) that is obtained at the outlet of the adsorber A- 4 is cooled in the exchanger E- 4 , and the cooled flow ( 12 ) is separated in the separator E- 5 .
  • a gas oil flow ( 13 ) is recovered, and at the top of separator E- 5 , a flow ( 14 ) is recovered in a first step that consists of a mixture ( 15 ) of nitrogen and hydrogen, then in a second step consisting of nitrogen only ( 16 ).
  • the various compounds that remain adsorbed in the adsorbent solid that is contained in the adsorber A- 5 are burned by combustion with air that is most often dilute. To carry out this combustion, an addition of dilute air ( 23 ) is mixed with the recycled air ( 33 ).
  • the flow ( 24 ) that is obtained is compressed in the compressor E- 9 , and the flow ( 25 ) that is obtained is reheated in the piece of equipment E- 10 .
  • the flow ( 26 ) of dilute and reheated air is used to regenerate the adsorber A- 5 by controlled combustion.
  • combustion effluents ( 27 ) that are obtained and that essentially contain SOx and CO2 are cooled in the exchanger E- 11 , and the flow ( 28 ) is washed in a smoke treatment unit E- 12 .
  • the water ( 31 ) that is used in the treatment unit E- 14 as well as the air that is contaminated by residual smoke ( 32 ) are obtained. Residual smoke ( 34 ) is removed from the air ( 32 ) so as to be able to recycle the clean dilute air ( 33 ) at the inlet of compressor E- 9 .
  • the adsorber A- 6 is cooled under nitrogen.
  • the nitrogen flow ( 18 ) that is obtained from flow ( 8 ) is cooled in the exchanger E- 6 .
  • the flow ( 19 ) is used to cool the adsorber A- 6 .
  • the effluents ( 20 ) are cooled in the exchanger E- 7 .
  • the flow ( 21 ) that is obtained is separated in the separator tank E- 8 .
  • the nitrogen ( 17 ) that is recycled at the inlet of the compressor E- 2 is recovered at the top of tank E- 8 , and smoke ( 22 ) is recovered at the bottom of tank E- 8 .
  • the sulfur content of the feedstock that is to be treated should be less than 500 ppmS, preferably less than 350 ppmS, and even more preferably less than 50 ppmS.
  • a preferred manner of using the deep desulfurization process that is described above is to position it downstream from a standard catalytic hydrodesulfurization process (HDS), which will be able to treat feedstocks with a sulfur content that is optionally greater than 500 ppm and to bring the latter back into the range from which this process can be operated.
  • HDS catalytic hydrodesulfurization process
  • a hydrodesulfurization unit transforms the bulk of the sulfur-containing compounds that are contained in a distillate into H2S under temperature conditions of close to 450° C., and pressures of between 20 and 60 bar.
  • a portion of the sulfur-containing compounds is called “refractory” with HDS, because their transformation into H2S requires clearly higher pressure and temperature conditions.
  • refractory molecules are part of the family of the alkylated dibenzothiophenic compounds.
  • the content of post-HDS refractory compounds depends on several parameters including the level of pressure and temperature of the hydrodesulfurization unit, the amounts of catalysts involved, and the VVH used.
  • the content of refractory compounds in the effluent of an HDS unit is in general greater than 15 ppmS, and generally less than 500 ppmS, and even 350 ppmS or 50 ppmS.
  • the sulfur content of the hydrotreated gas oil is less than 500 ppmS, it is possible to allow in an additional amount of sulfur in the form of H2S up to the limit of 500 ppmS.
  • the sulfur content in the form of H2S depends on the operating conditions of the HDS as well as the individual operations (separation, cooling, washing, . . . ) located downstream from the HDS reactor.
  • FIG. 3 exhibits a typical diagram example of a gas oil HDS.
  • This diagram is intended to illustrate the different possibilities of positioning of this invention relative to an existing HDS process.
  • the feedstock that is to be treated ( 1 ) is preheated by an effluent-feedstock exchanger E- 1 .
  • the preheated feedstock ( 2 ) is mixed with the hydrogen ( 7 a ) to form a reheated gas-liquid mixture ( 8 ) in the furnace E- 3 .
  • the feedstock ( 9 ) is sent into the HDS reactor E- 2 at the desired temperature.
  • a staged HDS reactor is used, in which a portion of the hydrogen ( 7 b ) is added.
  • the output effluents ( 10 ) are cooled with the aid of the feedstock-effluent exchanger E- 1 .
  • the partially cooled effluents ( 11 ) are mixed with the input hydrogen ( 3 ) to form a mixture ( 4 ) that feeds a gas-liquid separator E- 4 .
  • the gases ( 5 ) are sent to a treatment with amines E- 5 that makes it possible to withdraw a portion of the H2S that is present and to deacidify it.
  • the treated hydrogen ( 6 ) is compressed in the compressor E- 6 to be brought to the desired working pressure in the HDS ( 7 ).
  • the liquid ( 12 ) that is collected from the separator E- 4 is sent into a separator E- 7 to separate the diesel fuel ( 13 ) and the water ( 14 ).
  • the gas oil that is obtained ( 15 ) is cooled in the exchanger E- 8 and the flow ( 16 ) that is obtained is sent into a stripper E- 9 in which it is mixed with the high-pressure water vapor ( 17 ). This makes it possible to recover light hydrocarbons ( 18 ) at the top and a clean gas oil without H2S ( 19 ) at the bottom.
  • the flow ( 19 ) is cooled in the exchanger E- 10 , and the flow ( 20 ) that is obtained is dried in the piece of equipment E- 11 .
  • a partially desulfurized gas oil ( 21 ) is then obtained at the bottom of the drying apparatus, and water ( 22 ) is then obtained at the top of the drying apparatus.
  • the process for deep desulfurization, object of this invention can be placed on any of the flows ( 4 ), ( 10 ), ( 11 ), ( 12 ), ( 15 ), ( 16 ), ( 19 ), ( 20 ) and ( 21 ) that are found downstream from the HDS reactor E- 2 , provided that the total sulfur content of said flow is less than 500 ppmS.
  • the deep desulfurization process will be placed at a location where the content of formed H2S will be the lowest possible, and the temperature will be the highest possible, and even more preferably greater than 200° C.
  • the adsorbent solid that is used in the deep desulfurization unit generally comprises at least the zinc oxide in the presence of a desulfurization promoter in oxide form, whereby the zinc oxide and the promoter are deposited on a porous substrate or mixed with said porous substrate.
  • the particles of adsorbent solid will generally be spherical in shape, with a diameter of greater than 500 microns. In some cases, they can have the shape of extrudates, the length of the extrudate in this case being greater than 500 microns.
  • the particles can have more elaborate shapes than the one called a “trilobe,” which exhibits three protuberances in the form of petals.
  • an equivalent diameter, in terms of SAUTER is defined as being the diameter of the sphere that has the same surface to volume ratio as the one of the particle being considered.
  • Sauter diameter of the particles will generally be between 500 microns and 6 millimeters, and preferably between 1 and 5 millimeters.
  • the amount of elementary zinc is to be greater than 1% by weight, preferably greater than 5% by weight, and even more preferably greater than 10% by weight of the total solid.
  • the promoter is a metal in oxide form that is selected from among the elements of the following list: titanium, vanadium, chromium, manganese, iron, cobalt, nickel, copper or molybdenum.
  • the promoter will preferably be selected from among the iron or the copper.
  • the amount of promoter varies between 1 and 40% and preferably between 10% and 20% by weight of the total solid.
  • the inorganic porous substrate is used to provide the specific surface area whose value is to be greater than 50 m2/g, and preferably greater than 100 m2/g.
  • the porosity of the substrate is to be essentially of mesoporous type (diameters of pores between 20 and 500 angstroms) and of macroporous type (greater than 500 angstroms) with values of the pore volume of between 0.1 ml/g and 0.6 ml/g for each type of porosity, and preferably between 0.2 and 0.4 ml/g for each type of porosity. It can be selected from among the following list: alumina, silica or a mixture of the two.
  • the zinc can also be incorporated into the substrate by forming, for example, zinc aluminate, zinc silicate or zinc aluminosilicate.
  • the promoter can be incorporated in the substrate to form an aluminate, a silicate or an aluminosilicate of the metal corresponding to the promoter in question.
  • the working temperature can be between 200° C. and the degradation temperature of the feedstock that is to be treated. Typically, this degradation temperature is close to 450° C. for a gas oil.
  • the temperature will preferably be greater than 300° C. and even more preferably greater than 350° C.
  • the working pressure will be between the atmospheric pressure and 60 bar. Work will preferably be performed on a mixture of feedstock/hydrogen that is for the most part evaporated, and preferably completely evaporated.
  • the adsorbent solid particles are spherical and have a diameter of 1.5 mm.
  • a liquid feedstock comprising decane-type model molecules that represents the gas oil matrix, and dibenzothiophene at a concentration of 200 ppmS that is representative of the refractory sulfur-containing compounds remaining after a hydrodesulfurization (HDS) are considered.
  • the test that is carried out makes it possible to produce 60 volumes of desulfurized gas oil with 8 ppm of S per 1 volume of solid used in the reactor. At the end of the test, the solid was partly sulfurized, and the amount of collected sulfur is on the order of 10 mg of S/gram of solid. The gas oil yield is greater than 99%.
  • the adsorbent solid is introduced into a flushed bed that is heated to 450° C. under nitrogen.
  • the solid is flushed by a gas mixture that contains 2% by volume of oxygen in the nitrogen for 3 hours, which makes it possible to return the solid to the oxide phase.
  • the solid is flushed with the nitrogen to cool it and to return to ambient temperature.
  • the solid can then be used again for the adsorption.

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US11/360,586 2005-02-25 2006-02-24 Process for deep desulfurization by adsorption of a gas oil-type hydrocarbon fraction Abandoned US20060191821A1 (en)

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FR05/01.968 2005-02-25
FR0501968A FR2882562B1 (fr) 2005-02-25 2005-02-25 Procede de desulfuration profonde par adsorption d'une coupe hydrocarbonee de type gazole

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US (1) US20060191821A1 (fr)
EP (1) EP1696018B8 (fr)
DE (1) DE602006007248D1 (fr)
ES (1) ES2328621T3 (fr)
FR (1) FR2882562B1 (fr)

Cited By (5)

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Publication number Priority date Publication date Assignee Title
EP2175009A1 (fr) 2008-10-10 2010-04-14 Ifp Mise en oeuvre de solides à base de ferrite de zinc dans un procédé de désulfuration profonde de coupes hydrocarbonées
WO2012066574A3 (fr) * 2010-11-19 2012-09-27 Indian Oil Corporation Ltd. Procédé de désulfuration de gazole à consommation d'hydrogène réduite
US9006508B2 (en) 2012-02-06 2015-04-14 Uop Llc Protected adsorbents for mercury removal and method of making and using same
EP3023481A3 (fr) * 2011-10-18 2016-10-05 Baker Hughes Incorporated Procédé de réduction de formation de sulfure d'hydrogène à partir d'asphalte et d'évolution de sulfure de fiouls lourds à partir d'asphalte et de combustibles lourds
US10370311B2 (en) 2015-05-28 2019-08-06 Evonik Degussa Gmbh Hydrogen-assisted adsorption of sulphur compounds from olefin mixtures

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US5057473A (en) * 1990-04-12 1991-10-15 The United States Of America As Represented By The Administrator Of The National Aeronautics And Space Administration Regenerative Cu La zeolite supported desulfurizing sorbents
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US20030111389A1 (en) * 2001-12-19 2003-06-19 Johnson Marvin M. Desulfurization of middle distillates
US6656877B2 (en) * 2000-05-30 2003-12-02 Conocophillips Company Desulfurization and sorbents for same

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US2998381A (en) * 1958-09-22 1961-08-29 Exxon Research Engineering Co Hydrofining of middle distillate feed stock
US4176090A (en) * 1975-11-18 1979-11-27 W. R. Grace & Co. Pillared interlayered clay materials useful as catalysts and sorbents
US4127470A (en) * 1977-08-01 1978-11-28 Exxon Research & Engineering Company Hydroconversion with group IA, IIA metal compounds
US5057473A (en) * 1990-04-12 1991-10-15 The United States Of America As Represented By The Administrator Of The National Aeronautics And Space Administration Regenerative Cu La zeolite supported desulfurizing sorbents
US5935420A (en) * 1996-08-23 1999-08-10 Exxon Research And Engineering Co. Desulfurization process for refractory organosulfur heterocycles
US6656877B2 (en) * 2000-05-30 2003-12-02 Conocophillips Company Desulfurization and sorbents for same
US20030111389A1 (en) * 2001-12-19 2003-06-19 Johnson Marvin M. Desulfurization of middle distillates

Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2175009A1 (fr) 2008-10-10 2010-04-14 Ifp Mise en oeuvre de solides à base de ferrite de zinc dans un procédé de désulfuration profonde de coupes hydrocarbonées
FR2937044A1 (fr) * 2008-10-10 2010-04-16 Inst Francais Du Petrole Mise en oeuvre de solides a base de ferrite de zinc dans un procede de desulfuration profonde de coupes hydrocarbonees
WO2012066574A3 (fr) * 2010-11-19 2012-09-27 Indian Oil Corporation Ltd. Procédé de désulfuration de gazole à consommation d'hydrogène réduite
EP3023481A3 (fr) * 2011-10-18 2016-10-05 Baker Hughes Incorporated Procédé de réduction de formation de sulfure d'hydrogène à partir d'asphalte et d'évolution de sulfure de fiouls lourds à partir d'asphalte et de combustibles lourds
US9006508B2 (en) 2012-02-06 2015-04-14 Uop Llc Protected adsorbents for mercury removal and method of making and using same
US10370311B2 (en) 2015-05-28 2019-08-06 Evonik Degussa Gmbh Hydrogen-assisted adsorption of sulphur compounds from olefin mixtures

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EP1696018B8 (fr) 2009-08-19
EP1696018A1 (fr) 2006-08-30
ES2328621T3 (es) 2009-11-16
EP1696018B1 (fr) 2009-06-17
FR2882562A1 (fr) 2006-09-01
FR2882562B1 (fr) 2010-05-14
DE602006007248D1 (de) 2009-07-30

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