EP3601485A1 - Procédé pour la désulfuration oxydante et le rejet de sulfones à l'aide d'un désasphaltage par solvant - Google Patents

Procédé pour la désulfuration oxydante et le rejet de sulfones à l'aide d'un désasphaltage par solvant

Info

Publication number
EP3601485A1
EP3601485A1 EP18714924.0A EP18714924A EP3601485A1 EP 3601485 A1 EP3601485 A1 EP 3601485A1 EP 18714924 A EP18714924 A EP 18714924A EP 3601485 A1 EP3601485 A1 EP 3601485A1
Authority
EP
European Patent Office
Prior art keywords
stream
hydrocarbon
sulfur
containing compounds
oxidized
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP18714924.0A
Other languages
German (de)
English (en)
Inventor
Omer Refa Koseoglu
Abdennour Bourane
Stephane Kressmann
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Saudi Arabian Oil Co
Original Assignee
Saudi Arabian Oil Co
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 US15/465,179 external-priority patent/US10081770B2/en
Application filed by Saudi Arabian Oil Co filed Critical Saudi Arabian Oil Co
Publication of EP3601485A1 publication Critical patent/EP3601485A1/fr
Withdrawn legal-status Critical Current

Links

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
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/003—Solvent de-asphalting
    • 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
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
    • C10G21/12—Organic compounds only
    • C10G21/16—Oxygen-containing compounds
    • 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
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
    • C10G21/12—Organic compounds only
    • C10G21/20—Nitrogen-containing compounds
    • 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
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
    • C10G21/12—Organic compounds only
    • C10G21/22—Compounds containing sulfur, selenium, or tellurium
    • 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
    • C10G27/00—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation
    • C10G27/04—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with oxygen or compounds generating oxygen
    • 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
    • C10G27/00—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation
    • C10G27/04—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with oxygen or compounds generating oxygen
    • C10G27/12—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with oxygen or compounds generating oxygen with oxygen-generating compounds, e.g. per-compounds, chromic acid, chromates
    • 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
    • C10G27/00—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation
    • C10G27/04—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with oxygen or compounds generating oxygen
    • C10G27/14—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with oxygen or compounds generating oxygen with ozone-containing gases
    • 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
    • C10G53/00—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes
    • C10G53/02—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only
    • C10G53/04—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only including at least one extraction step
    • 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
    • C10G53/00—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes
    • C10G53/02—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only
    • C10G53/08—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only including at least one sorption step
    • 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
    • C10G53/00—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes
    • C10G53/02—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only
    • C10G53/14—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only including at least one oxidation step

Definitions

  • Embodiments relate to a method and apparatus for desulfurizing a hydrocarbon feedstock. More specifically, embodiments relate to a method and apparatus for oxidative desulfunzation of a hydrocarbon stream and the subsequent disposal of resulting oxidized sulfur and nitrogen compounds.
  • Crude oil is the world's main source of hydrocarbons used as fuel and petrochemical feedstock.
  • petroleum and petroleum -based products are also a major source for air and water pollution today.
  • the exact compositions of natural petroleum or crude oils vary significantly, all crude oils contain some measurable amount of sulfur compounds and most crude oils also contain some measurable amount of nitrogen compounds.
  • crude oils may also contain oxygen, but the oxygen content of most crude is low.
  • sulfur concentrations in crude oils are less than about 5 percent by weight (wt%), with most crude oils having sulfur concentrations in the range from about 0.5 to about 1.5 wt%.
  • Nitrogen concentrations of most crude oils are usually less than 0.2 wt%, but can be as high as 1.6 wt%.
  • motor gasoline fuel is regulated to have a maximum total sulfur content of less than 10 parts per million weight (ppmw) sulfur, thus the removal of sulfur is a key concern.
  • Crude oils are refined in oil refineries to produce transportation fuels and petrochemical feedstocks.
  • fuels for transportation are produced by processing and blending of distilled fractions from the crude oil to meet the particular end use specifications. Because most of the crudes generally available today have high concentrations of sulfur, the distilled fractions typically require desulfurization to yield products, which meet various performance specifications, environmental standards, or both.
  • the sulfur-containing organic compounds present in crude oils and resulting refined fuels can be a major source of environmental pollution.
  • the sulfur compounds are typically converted to sulfur oxides during the combustion process, which in turn can produce sulfur oxyacids and contribute to particulate emissions, both of which are desired to be reduced.
  • One method for reducing particulate emissions includes the addition of various oxygenated fuel blending compounds, compounds that contain few or no carbon-to-carbon chemical bonds, such as methanol and dimethyl ether, or both. Most of these compounds, however, suffer in that they can have high vapor pressures, are nearly insoluble in diesel fuel, or have poor ignition quality, as indicated by their cetane numbers, or combinations thereof.
  • middle distillates that is, a distillate fraction that nominally boils in the range of about 180-370°C
  • the middle distillate fraction typically includes between about 1 and 3 wt% sulfur. Allowable sulfur concentration in middle distillate fractions were reduced to 5-50 ppmw levels from 3000 ppmw level since 1993 in Europe and United States to between a currently allowed amount of about 5-50 ppmw levels from the 3000 ppmw level.
  • Low pressure conventional hydrodesulfurization (HDS) processes can be used to remove a major portion of the sulfur from petroleum distillates for the blending of refinery transportation fuels. These units, however, are not efficient to remove sulfur from compounds at mild conditions (that is, up to about 30 bar pressure), when the sulfur atom is sterically hindered as in multi-ring aromatic sulfur compounds. This is particularly true where the sulfur heteroatom is hindered by two alkyl groups (for example, 4,6-dimethyldibenzothiophene). Because of the difficulty in the removal, the hindered dibenzothiophenes predominate at low sulfur levels, such as 50 ppmw to 100 ppmw.
  • Severe operating conditions for example, high hydrogen partial pressure, high temperature, or high catalyst volume
  • Increasing the hydrogen partial pressure can only be achieved by increasing the recycle gas purity, or new grassroots units must be designed, which can be a very a costly option.
  • the use of severe operating conditions typically results in decreased yield, lower catalyst life cycle, and product quality deterioration (for example, color), and therefore are typically sought to be avoided.
  • Embodiments provide a method and apparatus for the upgrading of a hydrocarbon feedstock that removes a major portion of the sulfur-containing compounds present in the feedstock and in turn utilizes these sulfur-containing compounds in an associated process. Removal of nitrogen-containing compounds from the feedstock can similarly be achieved by the method and apparatus.
  • a method of upgrading a hydrocarbon feedstock including supplying the hydrocarbon feedstock to an oxidation reactor, where the hydrocarbon feedstock including sulfur-containing compounds and nitrogen- containing compounds; and contacting the hydrocarbon feedstock with an oxidant in the presence of a catalyst in the oxidation reactor under conditions sufficient to selectively oxidize sulfur-containing compounds present in the hydrocarbon feedstock to produce an oxidized hydrocarbon stream that includes hydrocarbons, oxidized sulfur-containing compounds, and oxidized nitrogen-containing compounds.
  • the method further includes separating the hydrocarbons and the oxidized sulfur- and nitrogen-containing compounds in the oxidized hydrocarbon stream by solvent extraction with a polar solvent to produce an extracted hydrocarbon stream and a mixed stream, the mixed stream including the polar solvent, where the oxidized sulfur-containing compounds, and the oxidized nitrogen-containing compounds, wherein the extracted hydrocarbon stream has a lower concentration of sulfur and nitrogen than the hydrocarbon feedstock.
  • the method includes separating the mixed stream using a distillation column into a first recovered polar solvent stream and a first residue stream; and supplying the first residue stream to a deasphalting unit to produce a deasphalted oil stream and a pitch stream, where the pitch stream includes a substantial portion of the oxidized sulfur- containing compounds and the nitrogen-containing compounds removed from the hydrocarbon feedstock.
  • the method further includes supplying the extracted hydrocarbon stream to an adsorption column, the adsorption column being charged with an adsorbent suitable for the removal of oxidized compounds present in the extracted hydrocarbon stream, the adsorption column producing a high purity hydrocarbon product stream and a second residue stream, the second residue stream containing a portion of the oxidized sulfur-containing compounds and the oxidized nitrogen-containing compounds, and a spent adsorbent stream, the spent adsorbent stream containing another portion of the oxidized sulfur-containing compounds and the oxidized nitrogen-containing compounds; and supplying the spent adsorbent stream to the deasphalting unit to remove contaminants from the deasphalted oil in the deasphalting unit.
  • the method further includes recycling a portion of the high purity hydrocarbon product stream to the oxidation reactor.
  • the method further includes supplying the extracted hydrocarbon stream to a stripper to produce a second recovered polar solvent stream and a stripped hydrocarbon stream.
  • the method further includes recycling the first recovered polar solvent stream and the second polar solvent stream to an extraction vessel for the step of separating the hydrocarbons and the oxidized sulfur compounds in the oxidized hydrocarbon stream.
  • the oxidant is selected from the group consisting of air, oxygen, oxides of nitrogen, peroxides, hydroperoxidies, organic peracids, and combinations thereof.
  • the catalyst is a metal oxide having the formula MxOy, wherein M is an element selected from Groups IVB, VB, and VIB of the periodic table.
  • the oxidation reactor is maintained at a temperature of between about 20 °C and about 150°C and at a pressure of between about 1 bar and about 10 bars.
  • the ratio of the oxidant to sulfur containing compounds present in the hydrocarbon feedstock is between about 4: 1 and 10: 1.
  • the polar solvent has a Hildebrandt value of greater than about 19.
  • the polar solvent is selected from the group consisting of acetone, carbon disulfide, pyridine, dimethyl sulfoxide, n-propanol, ethanol, n- butanol, propylene glycol, ethylene glycol, dimethlyformamide, acetonitrile, methanol and combinations of the same.
  • the polar solvent is acetonitrile.
  • the polar solvent is methanol.
  • the solvent extraction is conducted at a temperature of between about 20°C and about 60°C and at a pressure of between about 1 bar and about 10 bars.
  • the method further includes supplying the second residue stream to the deasphalting unit.
  • the adsorbent is selected from the group consisting of activated carbon, silica gel, alumina, natural clays, zeolites; fresh, used, regenerated, or rejuvenated catalysts, and combinations of the same.
  • the adsorbent is a polymer coated support, wherein the support has a high surface area and is selected from the group consisting of silica gel, alumina, and activated carbon, and the polymer is selected from the group consisting of polysulfone, polyacrylonitrile, polystyrene, polyester terephthalate, polyurethane and combinations of the same.
  • the supplying the first residue stream to the deasphalting unit further includes supplying a deasphalting solvent selected from a paraffinic solvent having between 3 and 7 carbon atoms to the deasphalting unit and extracting the first residue stream with the deasphalting solvent at a temperature and pressure at or below the critical temperature and pressure of the paraffinic solvent, wherein the deasphalted oil stream includes a major fraction of the paraffinic solvent.
  • a method of upgrading a hydrocarbon feedstock including supplying the hydrocarbon feedstock to an oxidation reactor, the hydrocarbon feedstock including sulfur-containing compounds; catalytically oxidizing the sulfur-containing compounds in the hydrocarbon feedstock in the oxidation reactor with an oxidant in the presence of a catalyst under conditions sufficient to selectively oxidize the sulfur- containing compounds present in the hydrocarbon feedstock to sulfones and produce a treated hydrocarbon stream including hydrocarbons and sulfones and a waste catalyst stream; and extracting the treated hydrocarbon stream with a polar solvent to produce an extracted hydrocarbon stream and a mixed stream, the mixed stream including the polar solvent and the sulfones, where the extracted hydrocarbon stream has a lower sulfur concentration than the hydrocarbon feedstock.
  • the method further includes separating the mixed stream using a solvent regeneration column into a recovered polar solvent stream and a residue stream including sulfones; supplying the residue stream including sulfones to a deasphalting unit and extracting the residue stream with a paraffinic solvent having between 3 and 7 carbon atoms to produce a deasphalted oil stream and a pitch stream, where the extraction of the residue stream is conducted a temperature and pressure that is at or below the supercritical temperature and pressure of the paraffinic solvent; and supplying the extracted hydrocarbon stream to a distillation column and separating the extracted hydrocarbon stream into a high purity hydrocarbon product stream and a desulfurized deasphalted oil stream.
  • the method further includes recycling the deasphalted oil stream to the oxidation reactor.
  • the hydrocarbon feedstock further includes nitrogen-containing compounds, such that the step of catalytically oxidizing further includes catalytically oxidizing the nitrogen-containing compounds in the hydrocarbon feedstock with the oxidant in the presence of the catalyst, and wherein the residue stream supplied to the deasphalting unit includes the oxidized nitrogen-containing compounds.
  • the oxidation reactor is maintained at a temperature of between about 20 °C and about 150°C and at a pressure of between about 1 bar and about 10 bars and the solvent extraction is conducted at a temperature of between about 20°C and about 60°C and at a pressure of between about 1 bar and about 10 bars.
  • the polar solvent has a Hildebrandt value of greater than about 19.
  • the polar solvent is methanol.
  • the polar solvent is acetonitrile.
  • FIG. 1 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.
  • FIG. 2 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.
  • FIG. 3 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.
  • Embodiments address known problems associated with conventional methods of upgrading and recovering compounds from a hydrocarbon feedstock, particularly the desulfurization, denitrogenation, or both, of hydrocarbon feedstocks, and the subsequent removal and recovery of usable hydrocarbons. According to at least one embodiment, there is provided a method for the removal of sulfur and nitrogen compounds from a hydrocarbon feedstock and the use of oxidized sulfur species and oxidized nitrogen species in a deasphalting process.
  • upgrading or “upgraded,” with respect to petroleum or hydrocarbons refers to a petroleum or hydrocarbon product that is lighter ⁇ that is, has fewer carbon atoms, such as methane, ethane, and propane), has at least one of a higher API gravity, higher middle distillate yield, lower sulfur content, lower nitrogen content, or lower metal content, than does the original petroleum or hydrocarbon feedstock.
  • an oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream refers to a hydrocarbon stream that includes the oxidized sulfur- or oxidized nitrogen-containing compounds, or both.
  • FIG. 1 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.
  • Hydrocarbon upgrading system 100 includes oxidation reactor 104, extraction vessel 112, solvent regeneration column 116, stripper 120, and deasphalting unit 130.
  • a method for the upgrading of a hydrocarbon feedstock particularly a hydrocarbon feedstock that includes sulfur- and nitrogen- containing compounds.
  • the method includes supplying hydrocarbon feedstock 102 to oxidation reactor 104, where the hydrocarbon feedstock is contacted with an oxidant and a catalyst.
  • the oxidant can be supplied to oxidation reactor 104 via oxidant feed line 106 and fresh catalyst can be supplied to the reactor via catalyst feed line 108.
  • the catalyst can be regenerated using the process described below, and supplied along with, or in the place of, fresh catalyst.
  • hydrocarbon feedstock 102 can be any petroleum based hydrocarbon, and can include various impurities, such as elemental sulfur, compounds that include sulfur or nitrogen, or both.
  • hydrocarbon feedstock 102 can be a diesel oil having a boiling point between about 150°C and about 400°C.
  • hydrocarbon feedstock 102 can have a boiling point up to about 450°C, alternatively up to about 500°C.
  • hydrocarbon feedstock 102 can have a boiling point between about 100°C and about 500°C.
  • hydrocarbon feedstock 102 can have a boiling point up to about 600°C, alternatively up to about 700°C, or, in certain embodiments, greater than about 700°C.
  • hydrocarbon feedstock 102 can include heavy hydrocarbons.
  • heavy hydrocarbons refer to hydrocarbons having a boiling point of greater than about 360°C, and can include aromatic hydrocarbons and naphthenes, as well as alkanes and alkenes.
  • hydrocarbon feedstock 102 can be selected from whole range crude oil, topped crude oil, product streams from oil refineries, product streams from refinery steam cracking processes, liquefied coals, hydrocarbon fractions, such as diesel and vacuum gas oil boiling in the range of about 180 to about 370°C and about 370 to about 520°C, respectively, and the like, and mixtures thereof
  • Sulfur compounds present in hydrocarbon feedstock 102 can include sulfides, disulfides, and mercaptans, as well as aromatic molecules such as thiophenes, benzothiophenes, dibenzothiophenes, and alkyl dibenzothiophenes, such as 4,6-dimethyl-dibenzothiophene.
  • Aromatic compounds are typically more abundant in higher boiling fractions, than is typically found in the lower boiling fractions.
  • Nitrogen-containing compounds present in hydrocarbon feedstock 102 can include basic and neutral nitrogen compounds, including indoles, carbazoles, anilines, quinolines, acri dines, and the like, and mixtures thereof .
  • oxidation reactor 104 can be operated at mild conditions, relative to the conditions typically used in conventional hydrodesulfurization processes for diesel type feedstock. More specifically, in certain embodiments, oxidation reactor 104 can be maintained at a temperature of between about 20°C and about 150°C, alternatively between about 30°C and about 150°C, alternatively between about 30°C and about 90°C, or between about 90°C and about 150°C. In certain embodiments, the temperature is preferably between about 30°C and about 75°C, more preferably between about 45°C and about 60°C.
  • the operating pressure of oxidation reactor 104 can be between about 1 bar and about 30 bars, alternatively between about 1 bar and about 15 bars, alternatively between about 1 bar and about 10 bars, and alternatively between about 2 bars and about 3 bars.
  • the residence time of the hydrocarbon feedstock within oxidation rector 102 can be between about 1 minute and about 180 minutes, alternatively between about 15 minutes and about 180 minutes, alternatively between about 15 minutes and about 90 minutes, alternatively between about 5 minutes and about 60 minutes, alternatively between about 30 minutes and about 60 minutes, alternatively between about 60 minutes and about 120 minutes, alternatively between about 120 minutes and about 180 minutes, and is preferably for a sufficient amount of time for the oxidation of any sulfur- or nitrogen-containing compounds present in the hydrocarbon feedstock 102.
  • the residence time of the hydrocarbon feedstock within oxidation rector 104 is between about 15 minutes and about 45 minutes.
  • conventional hydrodesulfurization of a diesel type feedstock is typically conducted under harsher conditions, for example, at temperatures of between about 330°C and about 380°C, pressures of between about 50 bars and about 80 bars, and liquid hourly space velocity (LHSV) of between about 0.5 h "1 and about 2 h "1 .
  • LHSV liquid hourly space velocity
  • oxidation reactor 104 can be any reactor suitably configured to ensure sufficient contacting between hydrocarbon feedstock 102 and the oxidant, in the presence of a catalyst, for the oxidation of the sulfur- and nitrogen-containing compounds.
  • Suitable reactors for oxidation reactor 104 can include, for example, batch reactors, fixed bed reactors, ebullated bed reactors, lifted reactors, fluidized bed reactors, slurry bed reactors, and the like.
  • Sulfur and nitrogen compounds present in hydrocarbon feedstock 102 are oxidized in oxidation reactor 104 to sulfones, sulfoxides, and oxidized nitrogen compounds, which can be subsequently removed by extraction or adsorption.
  • Oxidized nitrogen compounds can include, for example, pyridine and pyrrole-based compounds or pyridine-difuran compounds. Frequently, during oxidation, the nitrogen atom itself is not oxidized, but rather the compound is oxidized to a compound that is easy to separate from the remaining compounds.
  • the oxidant is supplied to oxidation reactor 104 via oxidant feed stream 106.
  • Suitable oxidants can include air, oxygen, hydrogen peroxide, organic peroxides, hydroperoxides, organic peracids, peroxo acids, oxides of nitrogen, ozone, and the like, and combinations thereof.
  • Peroxides can be selected from hydrogen peroxide and the like.
  • Hydroperoxides can be selected from t-butyl hydroperoxide and the like.
  • Organic peracids can be selected from peracetic acid and the like.
  • the mole ratio of oxidant to sulfur present in the hydrocarbon feedstock can be from about 1 : 1 to 50: 1, preferably between about 2: 1 and 20: 1, more preferably between about 4: 1 and 10: 1.
  • the mole ratio of oxidant to nitrogen present in the hydrocarbon feedstock can be from about 1 : 1 to 50: 1, preferably between about 2: 1 and 20: 1, more preferably between about 4: 1 and 10: 1.
  • the catalyst can be supplied to oxidation reactor 104 via catalyst feed stream 108.
  • the catalyst can be a homogeneous catalyst.
  • the catalyst can include at least one metal oxide having the chemical formula M x O y , wherein M is a metal selected from groups IVB, VB, or VIB of the periodic table.
  • Metals can include titanium, vanadium, chromium, molybdenum, and tungsten. Molybdenum and tungsten are two particularly effective catalysts that can be used in various embodiments.
  • the spent catalyst can be rejected from the system with the aqueous phase (for example, when using an aqueous oxidant) after the oxidation vessel.
  • spent catalyst can be removed from the system with the aqueous phase, after the oxidation vessel. Catalyst remaining in the hydrocarbon stream can be removed or disposed of in the solvent deasphalting step. In certain embodiments, the catalyst can be regenerated and recycled. In certain other embodiments, the catalyst is not regenerated and is not recycled.
  • the ratio of catalyst to oil is between about 0.01% by weight and about 10% by weight, preferably between about 0.5% by weight and about 5% by weight. In certain embodiments, the ratio is between about 0.5% by weight and about 2.5% by weight. Alternatively, the ratio is between about 2.5% by weight and about 5% by weight. Other suitable weight ratios of catalyst to oil will be apparent to those of skill in the art and are to be considered within the scope of the various embodiments.
  • Catalyst present in oxidation reactor 104 can increase the rate of oxidation of the various sulfur- and nitrogen-containing compounds in hydrocarbon feedstock 102, thereby achieving completion of the reaction and oxidation of sulfur- and nitrogen-containing compounds in a shorter amount of time, and reducing the amount of oxidant necessary to achieve oxidation of the sulfur- and nitrogen-containing compounds.
  • the catalyst may have increased selectivity toward the oxidation of sulfur-containing or nitrogen-containing species, or both.
  • the catalyst is selective to the minimization of oxidation of aromatic hydrocarbons.
  • the composition of spent oxidant will vary based upon what original oxidant is used in the process.
  • the oxidant is hydrogen peroxide
  • water is formed as a by-product of the oxidation reaction.
  • alcohol is formed as a by-product of the oxidation reaction.
  • By-products are typically removed during the extraction and solvent recovery steps.
  • oxidation reactor 104 produces oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream 110, which can include oxidized sulfur- and oxidized nitrogen-containing hydrocarbon species.
  • Oxidized sulfur- and oxidized nitrogen- containing hydrocarbon stream 110 is supplied to extraction vessel 112 where the oxidized sulfur- and oxidized nitrogen-containing hydrocarbon species are contacted with extraction solvent stream 137.
  • Extraction solvent 137 can be a polar solvent, and in certain embodiments, can have a Hildebrandt solubility value of greater than about 19.
  • selection when selecting the particular polar solvent for use in extracting oxidized sulfur- and oxidized nitrogen- containing species, selection can be based upon, in part, solvent density, boiling point, freezing point, viscosity, and surface tension, as non-limiting examples.
  • Polar solvents suitable for use in the extraction step can include acetone (Hildebrand value of 19.7), carbon disulfide (20.5), pyridine (21.7), dimethyl sulfoxide (DMSO) (26.4), n-propanol (24.9), ethanol (26.2), n-butyl alcohol (28.7), propylene glycol (30.7), ethylene glycol (34.9), dimethylformamide (DMF) (24.7), acetonitrile (30), methanol (29.7), and like compositions or compositions having similar physical and chemical properties.
  • acetonitrile and methanol due to their low cost, volatility, and polarity, are preferred.
  • Methanol is a particularly suitable solvent for use in embodiments.
  • solvents that include sulfur, nitrogen, or phosphorous preferably have a relatively high volatility to ensure adequate stripping of the solvent from the hydrocarbon feedstock.
  • the extraction solvent is non-acidic and the extraction step is conducted in an acid-free environment.
  • acids are typically avoided due to the general corrosive nature of acids, and the requirement that all equipment be specifically designed for a corrosive environment.
  • acids such as acetic acid, can present difficulties in separation due to the formation of emulsions.
  • extraction vessel 112 can be operated at a temperature of between about 20°C and about 60°C, preferably between about 25°C and about 45°C, even more preferably between about 25°C and about 35°C.
  • Extraction vessel 112 can operate at a pressure of between about 1 bars and about 10 bars, preferably between about 1 bar and about 5 bars, more preferably between about 1 bar and about 2 bars. In certain embodiments, extraction vessel 112 operates at a pressure of between about 2 bars and about 6 bars.
  • the ratio of the extraction solvent to hydrocarbon feedstock can be between about 1 :3 and 3 : 1, preferably between about 1 :2 and 2: 1, more preferably about 1 : 1.
  • Contact time between the extraction solvent and the oxidized sulfur and oxidized nitrogen containing hydrocarbon stream 110 can be between about 1 second and 60 minutes, preferably between about 1 second and about 10 minutes. In certain embodiments, the contact time between the extraction solvent and oxidized sulfur and oxidized nitrogen containing hydrocarbon stream 110 is less than about 15 minutes.
  • extraction vessel 112 can include various means for increasing the contact time between the extraction solvent and oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream 110, or for increasing the degree of mixing of the two solvents. Means for mixing can include mechanical stirrers or agitators, trays, or like means.
  • extraction vessel 112 produces mixed stream 114 that can include extraction solvent, oxidized species (for example, the oxidized sulfur and nitrogen containing hydrocarbon species that were originally present in hydrocarbon feedstock 102), and the hydrocarbon feedstock 102, and extracted hydrocarbon stream 118, which can include the hydrocarbon feedstock having a reduced concentration of sulfur- and nitrogen- containing hydrocarbons, relative to hydrocarbon feedstock 102.
  • the hydrocarbon feedstock is only present in mixed stream 114 in trace amounts.
  • Mixed stream 114 can be supplied to solvent regeneration column 116 where extraction solvent can be recovered as first recovered solvent stream 117 and separated from first residue stream 123, which includes oxidized sulfur- and nitrogen-containing hydrocarbon compounds.
  • mixed stream 114 can be separated in solvent regeneration column 116 into a recovered hydrocarbon stream 124, which can include hydrocarbons present in mixed stream 114 from hydrocarbon feedstock 102.
  • Solvent regeneration column 116 can be a distillation column that is configured to separate mixed stream 114 into first recovered solvent stream 117, first residue stream 123, and recovered hydrocarbon stream 124.
  • Extracted hydrocarbon stream 118 can be supplied to stripper 120, which can be a distillation column or like vessel designed to separate a hydrocarbon product stream from residual extraction solvent.
  • stripper 120 can be a distillation column or like vessel designed to separate a hydrocarbon product stream from residual extraction solvent.
  • a portion of mixed stream 114 can optionally be supplied to stripper 120 via line 122, and where it can be combined with extracted hydrocarbon stream 118.
  • solvent regeneration column 116 can produce recovered hydrocarbon stream 124, which can be supplied to stripper 120, where the recovered hydrocarbon stream can optionally be contacted with extracted hydrocarbon stream 118 or a portion of mixed stream 114, which can be supplied to stripper 120 via line 122.
  • Stripper 120 separates the various streams supplied thereto into stripped oil stream 126, which includes hydrocarbons present in hydrocarbon feedstock 102 and has a reduced sulfur and nitrogen content relative thereto, and second recovered solvent stream 128.
  • Stripper 120 separates the various streams supplied thereto into stripped oil stream 126, which includes hydrocarbons present in hydrocarbon feedstock 102 and has a reduced sulfur and nitrogen content relative thereto, and second recovered solvent stream 128.
  • first recovered solvent stream 117 can be combined with second recovered solvent stream 128 and recycled to extraction vessel 112.
  • make-up solvent stream 132 which can include fresh solvent, can be combined with first recovered solvent stream 117, second recovered solvent stream 128, or both, and supplied to extraction vessel 112.
  • extraction vessel 112 can be supplied completely with a polar solvent recovered from stream 1 17, second recovered solvent stream 128, or both.
  • First residue stream 123 which includes oxidized sulfur- and nitrogen-containing compounds, and which can also include low concentrations of hydrocarbonaceous material, can be supplied to deasphalting unit 130 where the solvent deasphalting process can be used to prepare valuable products for use as a source of road asphalt.
  • oxidized compounds such as the oxidized sulfur-containing hydrocarbons, for example sulfones, and oxidized nitrogen-containing compounds, can be included in road asphalt compositions.
  • oxidized sulfur-containing compounds such as sulfones
  • heavy hydrocarbons such as hydrocarbons having a boiling point of greater than about 520°C
  • Solvent deasphalting processes can also be used to produce feedstock for base oil production, or can be used to produce deasphalted or demetallized oil from heavy crude to produce fuel oil.
  • fresh residual oil stream 129 can also be sent to deasphalting unit 130 to assist in the solvent deasphalting process.
  • Solvent deasphalting results, for example, in the separation of compounds based upon solubility and polarity, rather than by boiling point, as is the case with the vacuum distillation processes that are currently used to produce a low-contaminant deasphalted oil (DAO), which can be rich in paraffinic-type hydrocarbon molecules.
  • DAO low-contaminant deasphalted oil
  • the lower molecular weight fractions can then be further processed in conventional conversion units, for example, a fluidic catalytic cracking (FCC) unit or hydrocracking unit.
  • FCC fluidic catalytic cracking
  • Solvent deasphalting usually can be carried out with paraffin solvent streams having between about 3 carbon atoms and about 7 carbon atoms, preferably between about 4 carbon atoms and 5 carbon atoms, at or below the critical conditions of the paraffin solvent.
  • a processed hydrocarbon feed is dissolved in the paraffin solvent, and an insoluble pitch precipitates. Separation of the DAO phase and the pitch phase can occur in an extractor (not shown), which can be designed to efficiently separate the two phases and minimize contaminant entrainment in the DAO phase.
  • the DAO phase is heated to conditions, such that the extraction solvent reaches supercritical conditions. Under these conditions, the separation of the solvent and DAO is relatively easy. Solvent associated with the DAO and the pitch can be then stripped out at low pressure and recycled to the deasphalting unit 130.
  • Solvents for use in deasphalting unit 130 can include normal and isomerized paraffinic solvents having between about 3 carbon atoms and about 7 carbon atoms (that is., from propane to heptane), and mixtures thereof.
  • Deasphalting unit 130 can be operated at or below the supercritical temperature of the solvent (that is, at or below about 97°C, 152°C, 197°C, 235°C, or 267°C for propane, butane, pentane, hexane and heptane, respectively).
  • deasphalting unit 130 can be operated at a pressure at or below the supercritical pressure of the solvent (that is, at or below about 42.5, 38, 34, 30, and 27.5 bars for propane, butane, pentane, hexane and heptane, respectively).
  • Deasphalting unit 130 produces deasphalted oil stream 134, which includes usable hydrocarbons, and pitch stream 136, which can include metals, aromatic compounds, asphaltenes, and the oxidized sulfur and nitrogen compounds.
  • FIG. 2 provides another embodiment for the upgrading of hydrocarbons.
  • Hydrocarbon upgrading system 200 includes oxidation reactor 104, extraction vessel 112, solvent regeneration column 116, stripper 120, deasphalting unit 130, and adsorption column 202.
  • stripped oil stream 126 can be supplied to adsorption column 202, where stripped oil stream 126 can be contacted with one or more adsorbents designed to remove one or more of various impurities, such as sulfur- containing compounds, oxidized sulfur compounds, nitrogen-containing compounds, oxidized nitrogen compounds, and metals remaining in the hydrocarbon product stream after oxidation and solvent extraction steps.
  • adsorption column 202 where stripped oil stream 126 can be contacted with one or more adsorbents designed to remove one or more of various impurities, such as sulfur- containing compounds, oxidized sulfur compounds, nitrogen-containing compounds, oxidized nitrogen compounds, and metals remaining in the hydrocarbon product stream after oxidation and solvent extraction steps.
  • the one or more adsorbents can include activated carbon; silica gel; alumina; natural clays; silica-alumina; zeolites; and fresh, used, regenerated or rejuvenated catalysts having affinity to remove oxidized sulfur and nitrogen compounds and other inorganic adsorbents.
  • the adsorbent can include polar polymers that have been applied to or that coat various high surface area support materials, such as silica gel, alumina, and activated carbon.
  • Example polar polymers for use in coating various support materials can include polysulfones, polyacrylonitrile, polystyrene, polyester terephthalate, polyurethane, other like polymer species that exhibit an affinity for oxidized sulfur species, and combinations thereof.
  • adsorption column 202 can be operated at a temperature of between about 20°C and about 60°C, preferably between about 25°C and about 40°C, even more preferably between about 25°C and about 35°C. In certain embodiments, adsorption column 202 can be operated at a temperature of between about 10°C and about 40°C. In certain embodiments, adsorption column 202 can be operated at temperatures of greater than about 20°C, or alternatively at temperatures less than about 60°C. Adsorption column 202 can be operated at a pressure of up to about 15 bars, preferably up to about 10 bars, even more preferably between about 1 bar and about 2 bars.
  • adsorption column 202 can be operated at a pressure of between about 2 bars and about 5 bars. In accordance with at least one embodiment, adsorption column 202 can be operated at a temperature of between about 25°C and about 35°C and a pressure of between about 1 bar and about 2 bars.
  • the weight ratio of the stripped oil stream to the adsorbent is between about 1 : 1 and about 20: 1, alternately between about 5: 1 and about 15: 1. In alternate embodiments, the ratio is between about 7: 1 and about 13 : 1, with a preferred ratio being about 10: 1.
  • Adsorption column 202 separates the feed into extracted hydrocarbon product stream 204 having very low sulfur content (for example, less than 15 ppmw of sulfur) and very low nitrogen content (for example, less than 10 ppmw of nitrogen), a second residue stream 206, and spent adsorbent.
  • Second residue stream 206 includes oxidized sulfur- and oxidized nitrogen- containing compounds, and as shown in FIG. 2 is directed to deasphalting unit 130.
  • second residue stream 206 can be combined with first residue stream 123 and supplied to deasphalting unit 130 and processed as noted previously.
  • the spent adsorbent can be supplied or recycled via stream 252 to deasphalting unit 130 to remove contaminants (for example, sulfur, nitrogen, metals, and polycyclic aromatics) from the deasphalted oil for improving deasphalted oil quality.
  • contaminants for example, sulfur, nitrogen, metals, and polycyclic aromatics
  • the yield change may depend on the storage capacity left in the spent adsorbent pores.
  • the spent adsorbent for example, about 30 wt% to about 80 wt% partially used adsorbent, in stream 252 is supplied or recycled to deasphalting unit 130 to improve the quality of the deasphalted oil in stream 134, thereby disposing of the spent adsorbents.
  • sulfur can be reduced between about 20 wt% to about 50 wt%
  • nitrogen can be reduced between about 20 wt% to about 70 wt%
  • micro carbon residue can be reduced between about 20 wt% to about 50 wt%, such that the yield loss for the deasphalted oil stream 134 can be between about 5 wt% to about 10 wt%, and the yield gain for the pitch stream 136 can be between about 5 wt% to about 10 wt%.
  • the spent adsorbent can be disposed via stream 254.
  • adsorption column 202 can be semi- continuously operated, such that two columns are used in a swing-mode operation, where one adsorption column is in operation, while another is being prepared. Adsorption column 202 can also be continuously monitored, so that spent adsorbent can be sent to deasphalting unit 130 prior to the completion of the life cycle of the spent adsorbent. According to at least one embodiment, fresh residual oil stream 129 can also be sent to deasphalting unit 130.
  • the spent adsorbent can be supplied at a predefined flow rate to a surge vessel (not shown) before being supplied or recycled to deasphalting unit 130.
  • a portion of the deasphalted oil stream 134 can be recycled via line 235 to oxidation reactor 104, where the portion of the deasphalted oil stream 134 can further be desulfurized in the oxidative desulfurized process occurring in oxidation reactor 104.
  • the adsorbent can be regenerated by contacting spent adsorbent with a polar solvent, such as methanol or acetonitrile, to desorb the adsorbed oxidized compounds from the adsorbent.
  • a polar solvent such as methanol or acetonitrile
  • heat, stripping gas, or both can also be employed to facilitate the removal of the adsorbed compounds.
  • Other suitable methods for removing the absorbed compounds will be apparent to those of skill in the art and are to be considered within the scope of the various embodiments.
  • FIG. 3 provides a schematic diagram of another embodiment of the method of upgrading a hydrocarbon feedstock.
  • Diesel stream 302 which includes sulfur-containing compounds, hydrogen peroxide oxidant stream 306 and catalyst stream 308, including acetic acid and Na 2 W04 solid catalyst, were supplied to oxidation reactor 304, which was operated at conditions suitable to oxidize sulfur-containing compounds present in diesel stream 302, to produce oxidized sulfur-containing diesel stream 310 and waste catalyst stream 311.
  • Oxidation reactor 304 was maintained at a temperature of about 70°C and a pressure of about 1 bar.
  • the hydrogen peroxide to sulfur ratio was about 4: 1, and the reactants were contacted for approximately 60 min.
  • Oxidized sulfur-containing diesel stream 310 was supplied to extraction vessel 312 where diesel stream 302 was contacted with methanol and heated to selectively remove the oxidized sulfur-containing compounds from diesel stream 310.
  • Extraction vessel 312 was operated as described previously and produces extracted diesel stream 318 as a product stream, from which at least a portion of the sulfur-containing compounds have been removed, and mixed stream 314, which includes oxidized sulfur compounds and methanol, and may also include trace amounts of diesel.
  • the extraction was conducted at a temperature of about 25°C and a pressure of about 1 bar, wherein the solvent to feed ratio was approximately 1 : 1 and the contact time between the extraction solvent and the feed was approximately 30 seconds.
  • Mixed stream 314 was supplied to solvent regeneration column 316, where methanol stream 317 is separated from residue stream 320, which includes oxidized sulfur-containing compounds, and may also include heavy hydrocarbons.
  • Solvent regeneration column 316 was operated at a temperature of about 50°C and a pressure of about 1 bar.
  • Residue stream 320 was combined with pentane stream 322 and vacuum residue stream 324 and supplied to solvent deasphalting unit 330 to produce deasphalted oil stream 332, which includes DAO derived primarily from the vacuum residue stream, and asphaltene stream 334, which includes oxidized sulfur-containing compounds.
  • Solvent deasphalting unit 330 was operated at a temperature of about 160°C and a pressure of about 24 bars.
  • the solvent to feed ratio was about 5% by volume.
  • the solvent comprised pentanes, consisting of about 86.8% by volume n-C4, about 2.6% by volume i-C5, and about 0.5% by volume n-C5.
  • Tables 1-3 provide the compositions of the various streams for the Example illustrated with FIG. 3.
  • Table 1 shows the composition of the input and output streams for the oxidation step.
  • Table 2 shows the composition of the input and output streams for the extraction step.
  • Table 3 shows the composition of the input and output streams for the solvent deasphalting step.
  • Example corresponding to FIG. 3 is directed to the desulfurization of diesel fuel, it is understood that the process described can be operated with alternate hydrocarbon fluids or combinations of fluids.
  • residue stream 320 was combined with butane stream 322 and atmospheric residue stream 324 and supplied to solvent deasphalting unit 330 to produce deasphalted oil stream 332, which includes DAO derived primarily from atmospheric residue stream 324, and asphaltene stream 334, which includes oxidized sulfur-containing compounds.
  • Solvent deasphalting unit 330 was operated at a temperature of about 160°C and a pressure of about 24 bars. The solvent to feed ratio was about 5: 1 by volume.
  • the solvent comprised butanes, consisting of about 96.8% by volume n/i-C4, about 2.7% by volume i-C5, and about 0.5% by volume n-C5.
  • the DAO after separation of solvent is sent to oxidation vessel 304 to remove sulfur by oxidation and follow-up separation and oxidized products.
  • a distillation vessel 350 is added to separate desulfurized diesel stream 352, a high purity hydrocarbon product, and desulfurized DAO stream 354.
  • Table 4 provides the compositions of various streams for the Example illustrated in FIG. 3, in which the butane is used in stream 322.
  • Optional or optionally means that the subsequently described event or circumstances may or may not occur.
  • the description includes instances where the event or circumstance occurs and instances where it does not occur.
  • Ranges may be expressed as from about one particular value to about another particular value. When such a range is expressed, it is to be understood that another embodiment is from the one particular value or to the other particular value, along with all combinations within said range.

Landscapes

  • 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

Les modes de réalisation selon la présente invention concernent un procédé et un appareil de valorisation d'une charge hydrocarbonée. Selon au moins un mode de réalisation, le procédé comprend les étapes consistant à (a) introduire une charge hydrocarbonée dans un réacteur d'oxydation, la charge hydrocarbonée étant oxydée en présence d'un catalyseur dans des conditions suffisantes pour oxyder sélectivement les composés à base de soufre et d'azote présents dans la charge hydrocarbonée ; (b) séparer les hydrocarbures et les composés oxydés à base de soufre et d'azote par extraction par solvant ; (c) collecter un premier flux de résidus qui comprend les composés oxydés à base de soufre et d'azote ; (d) introduire le premier flux de résidus dans une unité de désasphaltage ; (e) introduire les hydrocarbures dans une colonne d'adsorption pour produire un produit hydrocarboné de haute pureté et un deuxième flux de résidus ; et (f) introduire l'adsorbant usagé dans l'unité de désasphaltage pour éliminer des polluants supplémentaires du produit hydrocarboné de haute pureté dans l'unité de désasphaltage.
EP18714924.0A 2017-03-21 2018-03-13 Procédé pour la désulfuration oxydante et le rejet de sulfones à l'aide d'un désasphaltage par solvant Withdrawn EP3601485A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US15/465,179 US10081770B2 (en) 2010-09-07 2017-03-21 Process for oxidative desulfurization and sulfone disposal using solvent deasphalting
PCT/US2018/022134 WO2018175143A1 (fr) 2017-03-21 2018-03-13 Procédé pour la désulfuration oxydante et le rejet de sulfones à l'aide d'un désasphaltage par solvant

Publications (1)

Publication Number Publication Date
EP3601485A1 true EP3601485A1 (fr) 2020-02-05

Family

ID=61837852

Family Applications (1)

Application Number Title Priority Date Filing Date
EP18714924.0A Withdrawn EP3601485A1 (fr) 2017-03-21 2018-03-13 Procédé pour la désulfuration oxydante et le rejet de sulfones à l'aide d'un désasphaltage par solvant

Country Status (7)

Country Link
EP (1) EP3601485A1 (fr)
JP (1) JP2020511580A (fr)
KR (1) KR20190126172A (fr)
CN (1) CN110446772B (fr)
SA (1) SA519410030B1 (fr)
SG (1) SG11201908022VA (fr)
WO (1) WO2018175143A1 (fr)

Families Citing this family (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10894923B2 (en) * 2018-10-22 2021-01-19 Saudi Arabian Oil Company Integrated process for solvent deasphalting and gas phase oxidative desulfurization of residual oil
FR3089517B1 (fr) * 2018-12-05 2020-12-25 Total Marketing Services Méthode de séparation de polymères dans un mélange d’hydrocarbures
CN113046109B (zh) * 2021-03-11 2021-12-07 山西中科化美科技有限责任公司 一种低硫低氮环保沥青的制备方法及应用

Family Cites Families (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2001802B1 (fr) * 2006-03-03 2021-06-09 Saudi Arabian Oil Company Procédé catalytique de désulfuration oxydante de carburants de transport liquides
CN101161625A (zh) * 2006-10-12 2008-04-16 高化环保技术有限公司 用均相mc型催化剂和o2/co2混合物制备有机酸或其衍生物的方法
US7566394B2 (en) * 2006-10-20 2009-07-28 Saudi Arabian Oil Company Enhanced solvent deasphalting process for heavy hydrocarbon feedstocks utilizing solid adsorbent
US9574144B2 (en) * 2010-09-07 2017-02-21 Saudi Arabian Oil Company Process for oxidative desulfurization and denitrogenation using a fluid catalytic cracking (FCC) unit
US9598647B2 (en) * 2010-09-07 2017-03-21 Saudi Arabian Oil Company Process for oxidative desulfurization and sulfone disposal using solvent deasphalting
US9574142B2 (en) * 2010-09-07 2017-02-21 Saudi Arabian Oil Company Process for oxidative desulfurization and sulfone management by gasification
SG11201503610PA (en) * 2012-11-09 2015-06-29 Saudi Arabian Oil Co Oxidative desulfurization process and system using gaseous oxidant-enhanced feed
EP3328967B1 (fr) * 2015-07-27 2023-04-12 Saudi Arabian Oil Company Procédé intégré de désalphatage et de cokéfaction au solvant amélioré pour la production de coke vert de pétrole

Also Published As

Publication number Publication date
CN110446772A (zh) 2019-11-12
SA519410030B1 (ar) 2022-10-10
WO2018175143A1 (fr) 2018-09-27
KR20190126172A (ko) 2019-11-08
JP2020511580A (ja) 2020-04-16
CN110446772B (zh) 2021-10-29
SG11201908022VA (en) 2019-10-30

Similar Documents

Publication Publication Date Title
US9598647B2 (en) Process for oxidative desulfurization and sulfone disposal using solvent deasphalting
US9574144B2 (en) Process for oxidative desulfurization and denitrogenation using a fluid catalytic cracking (FCC) unit
US9574143B2 (en) Desulfurization and sulfone removal using a coker
US10081770B2 (en) Process for oxidative desulfurization and sulfone disposal using solvent deasphalting
KR101926217B1 (ko) 수퍼 전자 공여제에 의한 술폰 전환을 위한 공정
WO2012033782A1 (fr) Procédé pour la désulfuration oxydative suivie par la gazéification par extraction par solvant pour produire un gaz de synthèse
EP3583191B1 (fr) Désulfuration et élimination des sulfones à l'aide d'une unité de cokéfaction
CN110446772B (zh) 使用溶剂脱沥青的氧化脱硫和砜处理方法
EP3583192B1 (fr) Désulfuration oxydative de fractions d'huiles et gestion des sulfones à l'aide d'un craquage catalytique fluide
CN110312779B (zh) 使用焦化器脱硫和除砜
EP3551731A1 (fr) Désulfuration oxydative de fractions d'huiles et gestion des sulfones à l'aide d'un craquage catalytique fluide
US10093871B2 (en) Desulfurization and sulfone removal using a coker
US10093872B2 (en) Oxidative desulfurization of oil fractions and sulfone management using an FCC
US10087377B2 (en) Oxidative desulfurization of oil fractions and sulfone management using an FCC
US10093870B2 (en) Desulfurization and sulfone removal using a coker

Legal Events

Date Code Title Description
STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: UNKNOWN

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE INTERNATIONAL PUBLICATION HAS BEEN MADE

PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: REQUEST FOR EXAMINATION WAS MADE

17P Request for examination filed

Effective date: 20190920

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

AX Request for extension of the european patent

Extension state: BA ME

DAV Request for validation of the european patent (deleted)
DAX Request for extension of the european patent (deleted)
STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: EXAMINATION IS IN PROGRESS

17Q First examination report despatched

Effective date: 20210225

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE APPLICATION HAS BEEN WITHDRAWN

18W Application withdrawn

Effective date: 20210621