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
  • 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
• • 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
  • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
  • B01J23/70—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper
  • B01J23/74—Iron group metals
  • B01J23/75—Cobalt
• • 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
  • C10G27/10—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with oxygen or compounds generating oxygen in the presence of metal-containing organic complexes, e.g. chelates, or cationic ion-exchange resins
• • 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
• • 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
  • B01J21/00—Catalysts comprising the elements, oxides, or hydroxides of magnesium, boron, aluminium, carbon, silicon, titanium, zirconium, or hafnium
  • B01J21/10—Magnesium; Oxides or hydroxides thereof

Definitions

• Diesel fuels of low lubricity may cause excessive wear of fuel pumps, injectors and other moving parts which come in contact with the fuel under high pressures.
• Distilled fractions used for fuel or a blending component of fuel for use in compression ignition internal combustion engines (diesel engines) are middle distillates that usually contain from about 1 to 3 percent by weight sulfur. In the past a typical specification for diesel fuel was a maximum of 0.5 percent by weight.
• Sulfur is a catalyst poison that reduces catalytic activity.
• high fuel sulfur also creates a secondary problem of particulate emission, due to catalytic oxidation of sulfur and reaction with water to form a sulfate mist. This mist is collected as a portion of particulate emissions.
• Compression ignition engine emissions differ from those of spark ignition engines due to the different method employed to initiate combustion. Compression ignition requires combustion of fuel droplets in a very lean air/fuel mixture. The combustion process leaves tiny particles of carbon behind and leads to significantly higher particulate emissions than are present in gasoline engines. Due to the lean operation the CO and gaseous hydrocarbon emissions are significantly lower than the gasoline engine.
• HDS hydrodesulfurization
• One known method involves the oxidation of petroleum fractions containing at least a major amount of material boiling above very high-boiling hydrocarbon materials (petroleum fractions containing at least a major amount of material boiling above about 550° F.) followed by treating the effluent containing the oxidized compounds at elevated temperatures to form hydrogen sulfide (500° F. to 1350° F.) and/or hydroprocessing to reduce the sulfur content of the hydrocarbon material.
• hydrogen sulfide 500° F. to 1350° F.
• hydroprocessing to reduce the sulfur content of the hydrocarbon material.
• Hinkamp et al. states that an increase in cetane number is obtained by adding both a peroxide and a dihalo compound to middle distillate fuels.
• U.S. Patent No. 2,472,152 (Adalbert Farkas et al.) describes a method for improving the cetane number of middle distillate fractions by the oxidation of saturated cyclic hydrocarbon or naphthenic hydrocarbons in such fractions to form naphthenic peroxides. This patent suggests that the oxidation may be accelerated in the presence of an oil- soluble metal salt as an initiator, but is preferably carried out in the presence of an inorganic base. However, the naphthenic peroxid.es formed are deleterious gum initiators.
• U.S. Patent No. 4,494,961 (Chaya Venkat et al.) relates to improving the cetane number of raw, untreated, highly aromatic, middle distillate fractions having a low hydrogen content by contacting the fraction at a temperature of from 50°C to 350°C and under mild oxidizing conditions in the presence of a catalyst which is either (i) an alkaline earth metal permanganate, (ii) an oxide of a metal of Groups IB, IIB, IIIB, IVB, VB, VIB, VIIB or VIIIB of the periodic table, or a mixture of (i) and (ii).
• a catalyst which is either (i) an alkaline earth metal permanganate, (ii) an oxide of a metal of Groups IB, IIB, IIIB, IVB, VB, VIB, VIIB or VIIIB of the periodic table, or a mixture of (i) and (ii).
• European Patent Application 0 252 606 A2 also relates to improving the cetane rating of a middle distillate fuel fraction which may be hydro-refined by contacting the fraction with oxygen or oxidant, in the presence of catalytic metals such as tin, antimony, lead, bismuth and transition metals of Groups IB, IIB, VB, VIB, VIIB and VIIIB of the periodic table, preferably as an oil-soluble metal salt.
• catalytic metals such as tin, antimony, lead, bismuth and transition metals of Groups IB, IIB, VB, VIB, VIIB and VIIIB of the periodic table, preferably as an oil-soluble metal salt.
• the application states that the catalyst selectively oxidizes benzylic carbon atoms in the fuel to ketones.
• U.S. Patent No. 4,723,963 (William F.
• the light fraction is hydrotreated to remove substantially all of the sulfur therein.
• the desulfurized light fraction is then blended with one half of the heavy fraction to product a low sulfur distillate fuel, for example 85 percent by weight of desulfurized light fraction and 15 percent by weight of untreated heavy fraction reduced the level of sulfur from 663 ppm to 310 ppm.
• a low sulfur distillate fuel for example 85 percent by weight of desulfurized light fraction and 15 percent by weight of untreated heavy fraction reduced the level of sulfur from 663 ppm to 310 ppm.
• U.S. Patent Application Publication No. 2002/0035306 A1 discloses a multi-step process for desulfurizing liquid petroleum fuels that also removes nitrogen-containing compounds and aromatics.
• the process steps are thiophene extraction; thiophene oxidation; thiophene-oxide and dioxide extraction; raffinate solvent recovery and polishing; extract solvent recovery; and recycle solvent purification.
• the Gore et al. process seeks to remove 5-65% of the thiophenic material and nitrogen-containing compounds and parts of the aromatics in the feedstream prior to the oxidation step. While the presence of aromatics in diesel fuel tends to suppress cetane, the Gore et al. process requires an end use for the extracted aromatics. Further, the presence of an effective amount of aromatics serves to increase the fuel density (Btu/gal) and enhance the cold flow properties of diesel fuel. Therefore it is not prudent to extract an inordinate amount of the aromatics.
• the oxidant is prepared in situ or is previously formed.
• Operating conditions include a molar ratio of H 2 O 2 to S between about 1 :1 and 2.2:1; acetic acid content between about 5 and 45% of feed, solvent content between 10 and 25% of feed, and a catalyst volume of less than about 5,000 ppm sulfuric acid, preferably less than 1,000 ppm.
• Gore et al. also discloses the use of an acid catalyst in the oxidation step, preferably sulfuric acid.
• the use of sulfuric acid as an oxidizing acid is problematic in that corrosion is a concern when water is present and hydrocarbons can be sulfonated when a little water is present. According to Gore et al.
• the purpose of the thiophene-oxide and dioxide extraction step is to remove more than 90% of the various substituted benzo- and dibenzo thiophene-oxides and N-oxide compounds plus a fraction of the aromatics with an extracting solvent that is aqueous acetic acid with one or more co-solvents.
• U.S. Patent No. 6,368,495 B1 also discloses a multi-step process for the removal of thiophenes and thiophene derivatives from petroleum fractions.
• This subject process involves the steps of contacting a hydrocarbon feed stream with an oxidizing agent followed by the contact of the oxidizing step effluent with a solid decomposition catalyst to decompose the oxidized sulfur-containing compounds thereby yielding a heated liquid stream and a volatile sulfur compound.
• oxidizing agents such as alkyl hydroperoxides, peroxides, percarboxylic acids, and oxygen.
• WO 02/18518 A1 discloses a two-stage desulfurization process which is utilized downstream of a hydrotreater.
• the process involves an aqueous formic acid based, hydrogen peroxide biphasic oxidation of a distillate to convert thiophenic sulfur to corresponding sulfones.
• some sulfones are extracted into the oxidizing solution. These sulfones are removed from the hydrocarbon phase by a subsequent phase separation step.
• the hydrocarbon phase containing remaining sulfones is then subjected to a liquid-liquid extraction or solid adsorption step.
• the use of formic acid in the oxidation step is not advisable.
• Formic acid is relatively more expensive than acetic acid. Further, formic acid is considered a "reducing" solvent and can hydride certain metals thereby weakening them.
• the process involves a hydrodesulfurization step, an oxidizing step, a decomposition step, and a separation step wherein a portion of the sulfur-oxidated compounds are separated from the effluent stream of the decomposition step.
• the aqueous oxidizing solution used in the oxidizing step preferably contains acetic acid and hydrogen peroxide. Any residual hydrogen peroxide in the oxidizing step effluent is decomposed by contacting the effluent with a decomposition catalyst.
• the separation step is carried out with a selective solvent to extract the sulfur-oxidated compounds.
• the preferred selective solvents are acetonitrile, dimethyl formamide, and sulfolane.
• DMF N,N-Dimethylformamide
• All of the solvents listed in the patent and the paper are desirably immiscible with the diesel. They are all characterized as either polar protic or aprotic solvents.
• WO 01/32809 discloses another process for selectively oxidizing distillate fuel or middle distillates. The subject reference discloses that oxidized distillate fuels such that hydroxyl and or carbonyl groups are chemically bound to paraffinic molecules in the fuel results in a reduction in particulates generated upon combustion of the fuel versus unoxidized fuel.
• the reference discloses a process for selectively oxidizing saturated aliphatic or cyclic compounds in the fuel using in the presence of various titanium containing silicon based zeolites with peroxides, ozone or hydrogen peroxide such that hydroxyl or carbonyl groups are formed.
• U.S. Patent No. 6,402,939 B1 discloses a process for the oxidative desulfurization of fossil fuels using ultrasound. Briefly liquid fossil fuel is combined with an acidic aqueous solution comprising water and an hydroperoxide to form a multiphase reaction mixture followed by applying ultrasound to the multiphase reaction medium for a time sufficient to cause oxidation of sulfides to sulfones with are subsequently extracted.
• U.S. Patent Application Publication No. 2001/0015339 A1 discloses a method of removing sulfur compounds from diesel fuel that involves forming oxidizing gas into sub micron size bubbles and dispersing these bubbles into flowing diesel fuel to oxidize the sulfur compounds into sulfoxides and/or sulfones.
• the present invention provides for a relatively simple process wherein a distillate feedstock is contacted with an oxygen-containing gas at oxidation conditions in the presence of a heterogeneous catalyst comprising a Group VIII metal on a basic support.
• the process of the present invention involves reducing the sulfur and/or nitrogen content of a distillate feedstock to produce a refinery transportation fuel or blending components for refinery transportation fuel by contacting the feedstock with an oxygen-containing gas in an oxidation zone at oxidation conditions in the presence of an oxidation catalyst comprising a Group VIII metal and a basic support to form an oxidation zone effluent stream containing oxidized sulfur-containing and/or nitrogen-containing compounds.
• the oxidized sulfur-containing and/or nitrogen-containing compounds are then separated from the oxidation zone effluent stream by conventional means known to those skilled in the art.
• Suitable feedstocks generally include refinery distillate streams boiling at a temperature range from about 50°C to about 650°C, preferably 150°C to about 400°C, and more preferably between about 175°C and about 375°C at atmospheric pressure for best results.
• These streams include, but are not limited to, virgin light middle distillate, virgin heavy middle distillate, fluid catalytic cracking process light catalytic cycle oil, coker still distillate, hydrocracker distillate, jet fuel, vacuum distillates, and the collective and individually hydrotreated embodiments of these streams.
• These streams further include the collective and individually hydrotreated embodiments of fluid catalytic cracking process, light catalytic cycle oil, coker still distillate, and hydrocracker distillate.
• this invention provides for the production of refinery transportation fuel or blending components for refinery transportation fuel from a hydrotreated petroleum distillate.
• Such a hydrotreated distillate is prepared by hydrotreating a petroleum distillate material boiling between about 50°C and about 650°C by a process which includes reacting the petroleum distillate with a source of hydrogen at hydrogenation conditions in the presence of a hydrogenation catalyst to assist by hydrogenation removal of sulfur and/or nitrogen from the hydrotreated petroleum distillate; optionally fractionating the hydrotreated petroleum distillate by distillation to provide at least one low- boiling blending component consisting of a sulfur-lean, mono-aromatic-rich fraction, and a high-boiling feedstock consisting of a sulfur-rich, mono- aromatic-lean fraction.
• the hydrotreated distillate or the low- boiling component can be used as suitable feedstocks for the process of the present invention.
• useful hydrogenation catalysts comprise at least one active metal, selected from the group consisting of the d-transition elements in the Periodic Table, each incorporated onto an inert support in an amount of from about 0.1 percent to about 30 percent by weight of the total catalyst.
• Suitable active metals include the d-transition elements in the Periodic Table elements having atomic number in from 21 to 30, 39 to 48, and 72 to 78.
• the catalytic hydrogenation process may be carried out under relatively mild conditions in a fixed, moving, fluidized or ebullated bed of catalyst.
• a fixed bed or plurality of fixed beds of catalyst is used under conditions such that relatively long periods elapse before regeneration becomes necessary, for example an average reaction zone temperature of from about 200°C to about 450°C, preferably from about 250°C to about 400°C, and most preferably from about 275°C to about 350°C for best results, and at a pressure within the range of from about 6 to about 160 atmospheres.
• Hydrogen circulation rates generally range from about 500 SCF/Bbl to about 20,000 SCF/Bbl, preferably from about 2,000 SCF/Bbl to about 15,000 SCF/Bbl, and most preferably from about 3,000 to about 13,000 SCF/Bbl for best results.
• the hydrogenation process typically operates at a liquid hourly space velocity of from about 0.2 hr-l to about 10.0 hH , preferably from about 0.5 hr- to about 3.0 hr 1 , and most preferably from about 1.0 hr 1 to about 2.0 hr 1 for best results. Excessively high space velocities will result in reduced overall hydrogenation. As mentioned above further reduction of heteroaromatic sulfur- containing species from a distillate petroleum fraction by hydrotreating would require that the stream be subjected to very severe catalytic hydrogenation in order to convert these compounds into hydrocarbons and hydrogen sulfide (H2S). Typically, the larger any hydrocarbon moiety is, the more difficult it is to hydrogenate the sulfur-containing hydrocarbon.
• the residual organo-sulfur compounds remaining after a hydrotreatment are the larger and most structurally hindered heteroaromatics.
• the refinery stream can be a material boiling between about 200°C and about 425°C.
• the refinery stream can be a material boiling between about 250°C and about 400°C, and more preferably a material boiling between about 275°C and about 375°C.
• Useful distillate fractions can be any one, several, or all refinery streams boiling in a range from about 50°C to about 425°C, preferably 150°C to about 400°C, and more preferably between about 175°C and about 375°C at atmospheric pressure.
• the lighter hydrocarbon components in the distillate product are generally more profitably recovered to gasoline and the presence of these lower boiling materials in distillate fuels is often constrained by distillate fuel flash point specifications.
• Heavier hydrocarbon components boiling above 400°C are generally more profitably processed as fluid catalytic cracker feed and converted to gasoline.
• the presence of heavy hydrocarbon components in distillate fuels is further constrained by distillate fuel end point specifications.
• the distillate fractions for the present invention can comprise high and low sulfur virgin distillates derived from high- and low-sulfur crudes, coker distillates, catalytic cracker light and heavy catalytic cycle oils, and distillate boiling range products from hydrocracker and resid hydrotreater facilities.
• coker distillate and the light and heavy catalytic cycle oils are the most highly aromatic feedstock components, ranging as high as 80 percent by weight.
• the majority of coker distillate and cycle oil aromatics are present as mono-aromatics and di-aromatics with a smaller portion present as tri- aromatics.
• Virgin stocks such as high and low sulfur virgin distillates are lower in aromatics content typically ranging as high as 35 percent by weight aromatics.
• the aromatics content of a feedstock will range from about 5 percent by weight to about 80 percent by weight, more typically from about 10 percent by weight to about 70 percent by weight, and most typically from about 20 percent by weight to about 60 percent by weight.
• Sulfur concentration in distillate fractions is generally a function of the high and low sulfur crude mix, the hydrogenation capacity of a refinery per barrel of crude capacity, and the alternative dispositions of distillate hydrogenation feedstock components.
• the higher sulfur distillate feedstock components are generally virgin distillates derived from high sulfur crude, coker distillates, and catalytic cycle oils from fluid catalytic cracking units processing relatively higher sulfur feedstocks.
• distillate feedstock components can range as high as 2 percent by weight elemental sulfur but generally range from about 0.1 percent by weight to about 0.9 percent by weight elemental sulfur.
• Nitrogen content of distillate fractions for hydrogenation is also generally a function of the nitrogen content of the crude oil, the hydrogenation capacity of a refinery per barrel of crude capacity, and the alternative dispositions of distillate hydrogenation feedstock components.
• the higher nitrogen distillate feedstocks are generally coker distillate and the catalytic cycle oils.
• These distillate feedstock components can have total nitrogen concentrations ranging as high as 2000 ppm, but generally range from about 5 ppm to about 900 ppm.
• sulfur compounds in petroleum fractions include mercaptans, sulfides, and thiophenes such as substituted benzothiophenes and dibenzothiophenes.
• heteroaromatic sulfur compounds could be selectively extracted based on some characteristic attributed only to these heteroaromatics. Even though the sulfur atom in these compounds has two, non-bonding pairs of electrons which would classify them as a Lewis base, this characteristic is still not sufficient for them to be extracted by a Lewis acid.
• selective extraction of heteroaromatic sulfur compounds to achieve lower levels of sulfur requires greater difference in polarity between the sulfur-containing species and the hydrocarbons.
• heterogeneous catalyzed oxidation it is possible to selectively convert these sulfur-containing species into, more polar, Lewis basic, oxygenated sulfur compounds such as sulfoxides and sulfones.
• a compound such as dimethylsulfide is a very non- polar molecule, whereas when oxidized, the molecule is very polar. Accordingly, by selectively oxidizing heteroaromatic sulfides such as benzo- and dibenzothiophene found in a refinery streams, processes of the invention are able to selectively bring about a higher polarity characteristic to these heteroaromatic compounds.
• these unwanted sulfur compounds can be selectively separated by conventional solvent extraction, adsorption, washing or distillation processes while the bulk of the hydrocarbon stream is unaffected.
• the process of the present invention also results in the oxidation of any nitrogen-containing species which can be simultaneously separated with the sulfur-containing species by the conventional solvent extraction, adsorption, washing, or distillation processes mentioned above.
• Other compounds which also have non-bonding pairs of electrons include amines. Heteroaromatic amines are also found in the same stream that the above sulfides are found. Amines are more basic than sulfides.
• this invention provides a process for the production of refinery transportation fuel or blending components for refinery transportation fuel, which includes: providing distillate feedstock comprising a mixture of hydrocarbons and sulfur-containing organic compounds and/or nitrogen- containing organic compounds, contacting the feedstock with an oxygen- containing gas in an oxidation zone in the presence of an oxidation catalyst wherein an oxygen-containing gas such as oxygen depleted air used.
• the concentration of oxygen can be less than about 21 vol. %.
• the oxygen-containing stream preferably should have an oxygen content of at least 0.01 vol. %.
• the gases can be supplied from air and inert diluents such as nitrogen if required. As those skilled in the art readily recognize, certain compositions are explosive and the composition of oxygen-containing stream should be selected to avoid explosive regions.
• the oxygen-containing gas can be circulated in amounts ranging from 200 to 20,000 standard cubic feet per barrel of distillate.
• the pressure in the oxidation zone can range from ambient to 3000 psig preferably from about 100 psig to about 400 psig, more preferably from about 150 psig to about 300 psig and most preferably from about 200 psig to about 300 psig.
• the temperature in the oxidation zone can range from about 150°F to about 350°F, preferably from about 250°F to about 330°F.
• the oxidation process of the present invention operates at a liquid hourly space velocity of from about 0.1 hr 1 to about 100 hr 1 , preferably from about 0.2 hr 1 to about 50 hr 1 , and most preferably from about 0.5 hr 1 to about 10 hr 1 for best results.
• the oxidation process of the present invention begins with a distillate feedstock preheating step.
• the distillate feedstock is preheated in feed/effluent heat exchangers prior to entering a furnace for final preheating to a targeted reaction zone inlet temperature.
• the distillate feedstock can be contacted with an oxygen-containing stream prior to, during, and/or after preheating. Since the oxidation reaction is generally exothermic, interstage cooling, consisting of heat transfer devices between fixed bed reactors or between catalyst beds in the same reactor shell, can be employed. At least a portion of the heat generated from the oxidation process can often be profitably recovered for use in the oxidation process.
• cooling may be performed through cooling utilities such as cooling water or air, or through use of a quench stream injected directly into the reactors.
• Two-stage processes can provide reduced temperature exotherm per reactor shell and provide better oxidation reactor temperature control.
• the reaction zone effluent is generally cooled and the effluent stream is directed to a separator device to remove the oxygen-containing gas which can be recycled back to the process.
• the oxygen-containing gas purge rate is often controlled to maintain a minimum or maximum oxygen content in the gas passed to the reaction zone.
• Recycled oxygen-containing gas is generally compressed, supplemented if required, with "make-up" oxygen or oxygen- containing gas (preferably air), and injected into the process for further oxidation.
• the process of the present invention can be carried out in any sort of gas-liquid-solid reaction zone known to those skilled in the art.
• the reaction zone can consist of one or more fixed bed reactors.
• a fixed bed reactor can also comprise a plurality of catalyst beds.
• the reaction zone can be a fluid bed reactor, slurry, or trickle bed reactor.
• the simplification implied by the use of a heterogeneous catalyst would facilitate a range of less conventional applications for the process of the present invention.
• the process of the invention can be carried out on skid mounted units at terminals or pipelines, garage forecourts and on-board fuel cell containing vehicles where sulphur sensitive hydrocarbon reformers and fuels cells are employed.
• the oxidation catalysts used in the present invention comprise a Group VIII metal component and a basic catalyst support.
• the preferred Group VIII metals suitable for use in the present invention include iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium, and platinum.
• the most preferred Group VIII metal is cobalt. These metals can be present in their elemental form or as oxides, or mixtures thereof.
• the metals are present in an amount ranging from 0.1 wt% to 50 wt.%, preferably about 2 wt% to about 20 wt. % and most preferably about 4 wt. % to about 12 wt. % based on the total catalyst weight.
• the support component of the catalyst used in the process of the present invention is a basic support. Alkali oxides and alkaline earth oxides are the preferred supports, with MgO and CaO being most preferred.
• the catalyst used in accordance with the present invention can be prepared by any of the standard methods of preparation known to those skilled in the art such as the precipitation method and the impregnation method. More specifically, Group VIII component metals can be deposed or incorporated upon the support by impregnation employing heat-decomposable salts of the Group VIII metals or other methods known to those skilled in the art such as ion-exchange, with impregnation methods being preferred.
• Suitable aqueous impregnation solutions include, but are not limited to cobalt nitrate, and nickel nitrate.
• Other impregnating solutions could include aqueous solutions of either metal oxalate, formate, propionate, acetate, chloride, carbonate or bicarbonate.
• the solution may be organic when used with metal compounds that are soluble in organic solvents e.g. metal acetylacetonates or metal naphthenates.
• the oxidized sulfur-containing and/or oxidized nitrogen-containing compounds are then removed from the distillate via any conventional selective separation process such as adsorption, washing, distillation, and solvent extraction.
• Extractions can be carried out with solvents such as DMF, methanol, acetonitrile, sulfolane, and acetic acid.
• Suitable adsorbents include acidic alumina and silica.
• the oxidized sulfur-containing species will have boiling points greater than those in the feed and therefore can be readily distilled from the distillate effluent.
• a suitable distillation cut point is equivalent to the temperature by which 90% of the feed sulphur compounds would boil is sufficient to reject the oxidized sulphur compounds as a residue from the product.
• the process of the present invention also results in a distillate effluent a relatively low TAN number.
• TAN is defined as mg KOH per gram of hydrocarbon sample required to neutralize any acids in the hydrocarbon sample.
• the TAN numbers of products, made in accordance with the process of the present invention are less than about 2.0, preferably less than about 1.0, and most preferably less than about 0.5.
• a high TAN number can result in a corrosive fuel.
• the process of the present invention achieves desulfurization to a level below about less than 5 ppm wt. and achieves denitrogenation to a level of below about less than 10 ppm wt.
• the process was carried out in a batch reactor at 200 psig, 900 rpm and 310 °F.
• the reactor used was a stirred, heated, 1 liter volume autoclave available from Autoclave Engineers having internal cooling coils and a means for continuous gas feed.
• the oxygen- containing gas having an oxygen content of 7 vol.% was added at a flow rate of 1200 standard cubic centimeters per minute.
• the reaction time was 5 hours.
• the distillate feed had the composition set out in Table I below.
• the batch reactor contained 300 grams of distillate feed and 9 grams of catalyst.
• FIGURE I plots the retention times in minutes for the sulfur-containing species signals in millivolts for a feedstock and an oxidation zone effluent stream shown in Table II, with the latter plotted below the feedstock.
• the longer retention times indicate that the sulfur species have been converted to heavier species which are more readily removable from the effluent by a conventional downstream separation process.
• Table II shows the sulfur species present in both the distillate feedstock and the distillate effluent from the oxidation zone for a process carried out in accordance with the present invention as described in this example.
• the feedstock in Table II is the same feedstock as set out in Table I, except sulfur species were analyzed by a sulfur gas chromatograph. As can be seen from the above table, the process of the present invention achieves a shift in sulfur species to a heavier sulfur species which would result in a desulfurization of about 90% achieving sulfur levels after a subsequent separation step to below about 5 ppm.
• Table III shows the efficacy of the invention to reduce nitrogen content in addition to sulfur content when carried out with a feed as described in Table I.
• the runs were carried out in the same equipment described in Example I except the oxidation reaction conditions where as otherwise set forth in Table III.
• the oxidation reaction zone effluent was then extracted 3 times using an 85% acetic acid solvent wherein the effluent to solvent volume ratio was 2:1.
• the extractions were subsequently followed by 2 water washes.

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• Chemical Kinetics & Catalysis (AREA)
• General Chemical & Material Sciences (AREA)
• Materials Engineering (AREA)
• Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

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• 2003
  • 2003-11-21 US US10/718,912 patent/US20050109678A1/en not_active Abandoned
• 2004
  • 2004-11-16 WO PCT/US2004/038440 patent/WO2005052092A1/en active Application Filing
  • 2004-11-16 EP EP04811225A patent/EP1682635A1/de not_active Withdrawn
  • 2004-11-16 AU AU2004293779A patent/AU2004293779B2/en not_active Ceased
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• 2007
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