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US20030094400A1 - Hydrodesulfurization of oxidized sulfur compounds in liquid hydrocarbons - Google Patents

Hydrodesulfurization of oxidized sulfur compounds in liquid hydrocarbons Download PDF

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US20030094400A1
US20030094400A1 US10/155,590 US15559002A US2003094400A1 US 20030094400 A1 US20030094400 A1 US 20030094400A1 US 15559002 A US15559002 A US 15559002A US 2003094400 A1 US2003094400 A1 US 2003094400A1
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Prior art keywords
sulfur
stream
oxidized
hydrocarbon
sulfur compounds
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Robert Levy
Alkis Stavros
Chakka Sudhakar
Vincent Nero
Stephen DeCanio
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Quadrant Management Inc
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Individual
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Priority to US10/155,590 priority Critical patent/US20030094400A1/en
Priority to PCT/US2002/019486 priority patent/WO2003014266A1/en
Priority to TW091116463A priority patent/TWI258463B/zh
Priority to ARP020102924A priority patent/AR035259A1/es
Assigned to UNIPURE CORPORATION reassignment UNIPURE CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: LEVY, ROBERT E., DECANIO, STEPHEN J., NERO, VINCENT P., RAPPAS, ALKIS S., SUDHAKAR, CHAKKA
Publication of US20030094400A1 publication Critical patent/US20030094400A1/en
Assigned to QUADRANT MANAGEMENT INC. reassignment QUADRANT MANAGEMENT INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: UNIPURE CORPORATION
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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
    • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only
    • C10G67/12—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only including oxidation as the refining step in the absence of hydrogen

Definitions

  • This invention relates to a process for the removal of sulfur from liquid hydrocarbons by hydrotreating the liquid hydrocarbon containing oxidized sulfur compounds.
  • hydrotreating is a process whose primary purpose is to reduce the sulfur and/or nitrogen content without significantly changing the boiling range of the feed. Sulfur is eliminated as hydrogen sulfide and nitrogen as ammonia in hydrotreating. While there are many variations and improvements, this technology requires high temperature and pressure in a hydrogen environment and employs solid catalysts. This process successfully causes the destruction of the majority of the sulfur compounds in hydrocarbons, including most of the thiophenic compounds.
  • DBT dibenzothiophenes
  • hydrotreaters having pressures well in excess of 500 psi. Achieving ultra-low sulfur levels requires that most of these difficult-to-hydrotreat compounds be removed, which could drive many refiners to install new hydrotreaters or carry out expensive revamps of their existing hydrotreaters.
  • One of the largest components of the gasoline pool are cracked naphthas which supply 90% of the sulfur in the gasoline pool.
  • the sulfur in cracked naphthas is relatively easy to remove by hydrotreating.
  • hydrotreating the cracked naphtha stream also hydrogenates olefins in the cracked naphtha to paraffins.
  • the octane rating of paraffins is substantially lower than that of olefins, therefore the octane rating of the gasoline product ends up about 10 points lower than the cracked naphtha feed.
  • the resulting gasoline product would be an ultra-low sulfur product, but would not meet the octane rating necessary to be part of the gasoline pool.
  • U.S. Pat. No. 6,171,478 discloses a desulfurization process of a hydrocarbonaceous oil.
  • the hydrocarbonaceous oil is treated in a hydrodesulfurization unit and then reacted with an oxidizing agent.
  • the effluent stream from the oxidation zone is treated to decompose the oxidizing agent before separation of the oxidized sulfur from the hydrocarbon.
  • the resulting product streams from the process include a stream containing oxidized sulfur compounds and a hydrocarbonaceous oil stream having a reduced concentration of sulfur compounds.
  • the '478 patent does not disclose a suitable method for disposing the stream containing oxidized sulfur compounds.
  • a subsequently issued U.S. Pat. 6,277,271 described a process of the '478 patent mentioned above that included the step of recycling the oxidized sulfur compounds to the hydrodesulfurization reactor to increase the hydrocarbon recovery from the process.
  • the series of separation steps as described in Cabrera '478 continued to be necessary even though the hydrocarbon bound to the oxidized sulfur is now recovered as a hydrocarbon product and the sulfur removed as hydrogen sulfide from the hydrodesulfirization reactor.
  • the hydrotreater catalyst may be any suitable hydrotreating catalyst.
  • the conditions of the hydrotreater are common and well known operating parameters; such as a temperature of from about 100° C. to about 400° C.; a pressure of from about 100 psig to about 1,000 psig; a liquid hourly space velocity (LHSV) from about 0.2 to about 10.0; and a gas flow of from about 100 to about 5,000 SCFB (standard cubic feet per barrel) containing at least about 70% hydrogen.
  • a process for reducing the sulfur in hydrocarbon liquids containing organic sulfur compounds comprises sending substantially the entire hydrocarbon stream through a hydrotreater to produce a reduced sulfur hydrocarbon stream and then oxidizing the reduced sulfur hydrocarbon stream; to produce a hydrocarbon stream with the sulfur being present as oxidized sulfur compounds.
  • the sulfur removed in the hydrotreater from the hydrocarbon liquid depends on the types of organic sulfur present and the conditions of the hydrotreater.
  • the resulting hydrocarbon stream has a reduced sulfur level.
  • the hydrotreater operates at conditions commonly found in today's refineries, to perform the routine hydrodesulfurization reactions.
  • the hydrotreater catalyst may be any suitable hydrodesulfurization catalyst at the operating conditions of the hydrotreater as generally stated above.
  • the reduced sulfur level hydrocarbon is reacted with an oxidation agent to oxidize those organic sulfur compounds not affected by the hydrodesulfurization reaction (like substituted dibenzothiophenes).
  • the oxidation of these sulfur compounds produces the corresponding sulfones in the product stream.
  • the product stream may be further processed to physically remove the sulfones.
  • the product stream containing the oxidized sulfur compounds is recycled to a hydrotreater.
  • Cracked naphtha also contains significant amounts of sulfur. Contrary to the prior art practice of removing this sulfur by hydrotreating, if processing begins by first oxidizing the organic sulfur in the cracked naphtha stream and then feeding the cracked naphtha stream containing the oxidized sulfur to a hydrotreater, the sulfur is easily removed and hydrogenation of olefins is substantially avoided thus maintaining the octane rating. By first oxidizing the sulfur compounds in the cracked naphtha stream, the resulting oxidized sulfur, usually sulfones, can be more easily hydrotreated at relatively mild hydrotreating conditions, to remove the sulfur from the oxidized sulfur compounds.
  • the hydrotreater not only hydrodesulfurizes the cracked naphtha, but also hydrogenates the olefins in the cracked naphtha.
  • hydrotreater By operating the hydrotreater at milder process conditions, such as when compared to the case when the sulfur compounds are not oxidized, hydrodesulfurization of the oxidized sulfur compounds occurs but leaves the majority of the olefins unaffected (not hydrogenated).
  • the product from the process has substantially the same octane rating as the usual cracked naphtha hydrotreater feed.
  • the cracked naphtha may also be hydrotreated first at mild conditions which minimizes the olefin saturation in order to remove 50-80% of the sulfur, followed by oxidation of the remaining sulfur compounds to sulfones/sulfoxides.
  • This stream of oxidized naphtha can be (a) hydrotreated at mild conditions to desulfurize it further to the desired very low sulfur level, without significant olefin saturation; or (b) subjected to a separation process to separate the oxidized sulfur compounds followed by recycling this stream containing oxidized sulfur compounds in to the hydrotreater. Either way, the sulfur is removed and the hydrocarbon added to the low sulfur product, without substantial octane loss.
  • an oxidation process could be placed in the refinery process flow upstream of an existing hydrotreating unit. Then the advantage exists that oxidized sulfur compounds need not be removed from the hydrocarbon stream. Rather, the entire hydrocarbon stream effluent from the oxidation reactor, containing the oxidized sulfur compounds, could be fed to the existing hydrotreater, where the oxidized sulfur would be easily reduced to a hydrogen sulfide gas stream to desulfurize the stream to ultra-low sulfur levels with the hydrocarbon-now free of its sulfur-become part of the product stream.
  • One variation of this configuration would be to oxidize the sulfur in the entire crude oil stream, either at the front-end of the refinery or as part of the crude production process (at a gathering station or crude shipment terminal). Another variation would be to oxidize the lighter fractions of the crude oil after a straight run distillation to separate the higher boiling residual hydrocarbon from more useful products, such as naphtha, diesel, fuel oil or gasoline blend components. These lighter fractions, containing oxidized sulfur compounds, would then be sent to one or more existing hydrotreaters.
  • an oxidation process could be installed downstream of an existing hydrotreating unit.
  • the oxidized sulfur compounds would normally be separated from the hydrocarbon stream and combined with the feed to the existing hydrotreater.
  • the hydrotreater would substantially eliminate the oxidized sulfur from the hydrocarbon stream containing the oxidized sulfur and produce a stream containing a reduced amount of organic sulfur compounds that would subsequently be oxidized.
  • the combination of the existing hydrotreater and the downstream oxidation process would produce a hydrocarbon stream having ultra-low sulfur levels.
  • One variation of this combination would provide for debottlenecking of an existing hydrotreater.
  • the severity of conditions in the hydrotreater could be relaxed somewhat, allowing it to process a larger volume of hydrocarbon and allow more organic sulfur compounds to pass through to the oxidation reactor.
  • the product from the hydrotreater would contain more sulfur than in conventional practice, this sulfur would be oxidized in the downstream oxidation unit, separated from the hydrocarbon stream and recycled back to the hydrotreater.
  • a second hydrodesulfurization reactor maybe utilized to do the final sulfur removal.
  • the hydrotreaters referred to above may operate at conventional hydrotreating conditions, those commonly found in refineries today for desulfurization, or at milder conditions.
  • the hydrotreater catalyst may be any suitable hydrotreating catalyst. Examples of the conditions of the hydrotreater are: a temperature range of about 100° C. to about 400° C.; a pressure range from about 100 psig to about 1,000 psig; a liquid hourly space velocity (LHSV) ranging from about 0.2 to about 10.0; and a gas flow range from about 100 to about 5,000 standard cubic feet per barrel (SCFB) having at least about 70% hydrogen.
  • LHSV liquid hourly space velocity
  • SCFB standard cubic feet per barrel
  • Hydrocarbon streams in a refinery contain a range of organic sulfur compounds and have a total sulfur content from about zero (up to about 2 ppm) up to about 6% (60,000 ppm) or sometimes more.
  • the compounds include, but are not limited to mercaptans, sulfides and thiophenes (including benzothiophene, dibenzothiophene and a wide range of substituted dibenzothiophenes).
  • the compounds also may include complex structures found in crude oils and residues, such as asphaltenes, resins and heavy waxes.
  • oxidized sulfur compounds are produced by an oxidation reaction, such as the one described in U.S. patent application Ser. No. 09/654,016, incorporated by reference, or other sulfur oxidation processes within the art, then the sulfur in those oxidized sulfur compounds is substantially completely converted to hydrogen sulfide in a subsequent hydrotreating unit, regardless of whether the oxidized compounds are processed in admixture with non-oxidized sulfur compounds, or not.
  • FIG. 1 shows a process block flow diagram of an embodiment of the desulfurization of a hydrocarbon stream by the processes of oxidation of organic sulfur in the hydrocarbon followed by hydrodesulfurization of the oxidized organic sulfur.
  • FIG. 2 shows a process block flow diagram of an alternate embodiment of a process for desulfurizing a crude stream using oxidation before an existing crude distillation unit.
  • FIG. 3 a shows a process block flow diagram of an alternate embodiment of a process for desulfurizing a crude stream using oxidation before hydrotreaters.
  • FIG. 3 b shows a process block flow diagram of an alternate embodiment of a process for desulfurizing a crude stream using separate oxidation units before hydrotreaters.
  • Sulfur can be substantially completely removed from hydrocarbon streams such as fuels, gasolines, oils and various distillation products by oxidizing the organic sulfur compounds in the hydrocarbon followed by a hydrodesulfurization step which operates on substantially the entire flow stream. Accordingly, there is no requirement that the oxidized sulfur compounds be separated from the hydrocarbon prior to the hydrodesulfurization step which is substantially quantitative. It works equally effectively on oxidized sulfur species produced from the oxidation treatment of crude oils and crude oil fractions or heavy crudes diluted with aromatic solvents.
  • the oxidized organic sulfur compounds normally are in the form of organic sulfones and sulfoxides which are easily reacted to give off hydrogen sulfide.
  • a hydrocarbon stream containing organic sulfur is oxidized first and then hydrotreated to produce an ultra low sulfur product.
  • the hydrocarbon stream may be any crude oil or fraction thereof.
  • the oxidation of such a hydrocarbon stream produces a hydrocarbon stream containing corresponding sulfones of certain organic sulfurs in the feed which also may contain sulfur compounds that were not oxidized due to the oxidation method and conditions employed.
  • the oxidation of a hydrocarbon stream has been discussed in prior art followed by often-complicated separation steps to remove the relatively small amounts of oxidized sulfur in the forms of sulfones, many of which are significantly hydrocarbon soluble. Further, the disposition of the sulfones produced from such processes remains a problem.
  • the hydrocarbon stream containing oxidized sulfur compounds may be obtained by any suitable oxidative methods, known and unknown, for oxidizing sulfur in hydrocarbon products and crude streams such as, for example, those found in U.S. Pat. No. 6,171,478 (acetic acid/hydrogen peroxide); U.S. Pat. No. 3,551,328 (organic peracids/metal catalyst); U.S. Pat. No. 5,958,224 (peroxometal); U.S. Pat. No. 5,310,479 (formic acid/hydrogen peroxide); and U.S. Pat. No. 6,160,193 (Caro's acid), and U.S. patent application Ser. No.
  • hydrodesulfurization catalyst used herein is not essential to the practice of the invention and can be any commercially available hydroprocessing catalyst known to one skilled in the art. Suitable hydroprocessing catalysts include those disclosed in Oil & Gas Journal, Sep. 27, 1999, pages 50-62, under the headings of “Hydrocracking catalysts,” “Mild hydrocracking catalysts,” “Hydrotreating/hydrogenation/saturation catalysts,” and “Hydrorefining catalysts.”
  • the hydroprocessing catalysts for use herein are well known and preferably deposited on an inorganic oxide carrier material of either synthetic or natural origin.
  • the hydrodesulfurization catalyst can comprise, consist of, or consist essentially of a Group VIII metal selected from the group consisting of iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium, platinum, and combinations of any two or more thereof, and a Group VIB metal selected from the group consisting of chromium, molybdenum, tungsten, and combinations of any two or more thereof.
  • the hydrodesulfurization catalyst comprises cobalt and molybdenum.
  • Catalytic promoters including but not limited to phosphorus, halogens, silica, zeolite, and alkali and alkaline earth metal oxides that are known to those in the art may also be present in the catalyst. Emerging commercial hydroprocessing catalysts are also suitable as catalysts for this purpose. The particle size or shape of the hydroprocessing catalyst required for the process of the present invention is generally dictated by the reactor system utilized for practicing the invention.
  • hydrotreating catalysts of only reasonable catalytic activity are required for the process of the present invention, in order to lower the costs, refinery spent (or used) hydroprocessing catalysts may also be utilized advantageously in this process with respect to some feed streams.
  • a fixed bed reactor system is the preferred reactor system, even though other kinds of reactor systems known to those knowledgeable in the art for hydroprocessing purposes can also be utilized to conduct the present process.
  • the process conditions of the hydrotreating process disclosed herein include a temperature range from about 100° C. to about 400° C. and preferably ranging from about 150° C.
  • a feed 10 is fed to an oxidation section 20 .
  • the feed may be any hydrocarbon stream that contains organic un-oxidized and/or oxidized sulfur compounds.
  • the hydrocarbon stream may be, but is not limited to, crude oil, bottom residues from an atmospheric and vacuum distillation tower (with or without a suitable diluent), fractions from a crude distillation tower such as diesel fuel, gasoline, kerosene, and other hydrocarbon streams within a refinery.
  • the sulfur compounds often found in hydrocarbon streams include, but are not limited to, thiophenic sulfur compounds, benzo and dibenzo thiophenes, mercaptans, sulfides and polysulfides. Asphaltenes and resins often present in crude oil or refinery bottom streams are also likely to have sulfur as a part of some complicated hydrocarbon structure.
  • the oxidized sulfur compounds include, but are not limited to, sulfones and sulfoxides. If the feed 10 is a crude oil or a hydrocarbon having a particularly high viscosity which renders it difficult to pump, then it may preferably be diluted by adding another hydrocarbon stream.
  • This diluent often is a distillate hydrocarbon stream produced in a crude oil distillation unit or a mixture of low-viscosity hydrocarbon streams.
  • the diluent may also be well-head condensate liquids from natural gas produced from the field where the sulfur removal processing unit is located; or any other suitable miscible material may be used as a diluent.
  • the diluent is selected based upon the requirements of the properties of the feed stream and availability of the diluent.
  • the diluent reduces the total sulfur concentration in the feed 10 and is recovered and goes through the process as hydrocarbon product. If the diluent stream itself contains sulfur compounds, these are removed in the practice of this invention. Recovered diluent would then have a lowered sulfur content.
  • the feed 10 may have a sulfur content from about 0.005 (50 ppm) to about 5 wt % and is charged to the oxidation reactor 20 .
  • the oxidation section 20 maybe any known as set forth in the prior art mentioned above or unknown yet to be discovered oxidation processes suitable for use to oxidize sulfur compounds and/or nitrogen compounds in the presence of hydrocarbon.
  • the sulfur containing hydrocarbon fed through line 10 is contacted with an oxidizing solution which oxidizes the sulfur compounds to their corresponding sulfones or sulfoxides.
  • Within the oxidation section 20 are methods for separating the hydrocarbon phase containing oxidized sulfur compounds from an aqueous phase containing the oxidizing agent. These processes normally include, for example, liquid-liquid separation, liquid-liquid extraction, solid-liquid separation, distillation, or combinations thereof.
  • the hydrotreater 50 preferably maybe an existing hydrotreater.
  • the conditions of the hydrotreater 50 are dependent on the feed entering it. Those skilled in the art will be able to select proper conditions for the hydrotreater 50 as required to meet the product standards desired.
  • An example of conditions appropriate for the hydrotreater 50 may be as follows: a temperature ranging from about 100° C. to about 400° C. and preferably ranging from about 150° C.
  • a most preferred range of operating conditions for the hydrotreater 20 are a temperature from about 200° C. to about 380° C. and a pressure from about 200 to about 500psig.
  • gases such as nitrogen, natural gas and fuel gas may also be in the gas stream along with the hydrogen.
  • the hydrotreater 50 produces a hydrocarbon stream substantially free of sulfur compounds, and sulfur exits as hydrogen sulfide gas through line 40 .
  • Line 60 contains the hydrocarbon stream substantially free of any sulfur containing compounds. Since the hydrodesulfurization of the oxidized organic sulfur in the hydrocarbons proceeds at less strenuous conditions than are normally present in a typical hydrodesulfurization reactor, it is possible to use less vigorous hydrodesulfurization conditions in the reactor 50 . The result is to achieve a substantially sulfur-free (0-15 ppm) hydrocarbon and an additional stream of oxidized sulfur compounds.
  • the oxidation reaction carried out in the oxidation section 20 is as described in U.S. patent application Ser. No. 09/654,016, which is incorporated by reference in its entirety herein.
  • the feed entering through line 10 is preferably contacted with an oxidizing solution containing hydrogen peroxide, a C 1 -C 4 carboxylic acid, and a maximum of about 25 percent water.
  • the total amount of hydrogen peroxide in the oxidizing solution is greater than about two times the stoichiometric amount of peroxide necessary to react with the sulfur in the reduced hydrocarbon stream 10 , considering that the reactor 20 may be run as a single unit or as a staged reactor with split streams being used, or as a countercurrent contact flow.
  • the reaction within the oxidation section 20 is carried out at a temperature from about 50° C. to about 130° C. for less than about 15 minutes contact time at close to, or slightly higher than atmospheric pressure, at optimum conditions.
  • the preferred oxidizing solution used in the practice of the invention has, not only a low amount of water, but also small amounts of hydrogen peroxide with the C 1 -C 4 carboxylic acid being the largest constituent as described in the aforementioned patent application (see Ser. No. 09/654,016).
  • the oxidizing solution preferably has a concentration of hydrogen peroxide, which is consumed in the reaction, ranging from about 0.5% to about 4.5% by weight, and most preferably from about 2 to about 3 wt %. The same may not be true where the feed is a crude stream or a rough cut distillation product. Some routine experimentation well within the skill of a refinery engineer would be needed in order to determine the optimum oxidizing solution concentrations.
  • the water content is limited to less than about 25 wt %, but preferably between about 8 and about 20%, and most preferably from about 8 to about 14 wt %.
  • the oxidation/extraction solution contains from about 75 wt % to about 92 wt % of a C 1 to C 4 carboxylic acid, preferably formic acid, and preferably 79 wt % to about 89 wt % formic acid.
  • the molar ratio of acid, preferably formic acid, to hydrogen peroxide is at least about 11 to 1 and from about 12 to 1 to about 70 to 1 in the broad sense, and preferably from about 20 to 1 to about 60 to 1.
  • a second desulfurization reactor may be placed downstream of the oxidation reactor in order to avoid the necessity of building and operating equipment to make the separation of oxygenated sulfur hydrocarbon compound.
  • the oxygenation reactor would be operated in substantially the same manner as that discussed above for the existing hydrotreater 50 .
  • FIG. 2 is an alternative embodiment that utilizes existing refinery process units along with an oxidation section to produce desulfurized hydrocarbon products.
  • the feed 10 is a sulfur-containing crude oil.
  • the oxidation section 20 may include any oxidative process described above, known or unknown, that produces a hydrocarbon stream containing oxidized organic sulfur compounds 70 .
  • the oxidation section 20 is placed before an existing crude distillation tower 130 to pre-treat the organic sulfur and nitrogen in the crude oil stream.
  • the oxidation section 20 produces the hydrocarbon containing oxidized sulfur and nitrogen compounds 70 .
  • the oxidation section 20 may be integrated into a refinery or may be used at a remote production site to upgrade crude oil before being sent to the refinery.
  • the hydrocarbon stream containing oxidized sulfur compounds 70 is processed in existing refinery processes.
  • the oxidation of the feed shifts the boiling point of the sulfur compounds higher.
  • This shift in the boiling point of the sulfur compounds shifts the distribution of oxidized organic sulfur compounds 70 into different distillation fractions relative to un-oxidized sulfur compounds.
  • This shift in the boiling point means that the lighter fractions from the crude distillation tower have a reduced total sulfur concentration which may eliminate the hydrotreating process or the hydrotreating process may operate under relatively milder conditions.
  • the hydrocarbon containing oxidized organic sulfur compounds 70 is fractionated in the crude distillation tower 130 into, but not limited to, for example, a light distillate 140 , a middle distillate 150 , a heavy distillate 160 , and a reduced crude 170 .
  • Those skilled in the art of distillation can specify the operating conditions of the crude distillation tower 130 to produce these well known refinery crude fractions.
  • the light distillate 140 , the middle distillate 150 , and the heavy distillate 160 are sent to existing hydrotreaters 50 .
  • the existing hydrotreaters 50 operate at existing conditions to remove the sulfur in the oxidized sulfur compounds and residual non-oxidized sulfur compounds with minimal hydrocarbon loss with the sulfur being easily removed as hydrogen sulfide and the nitrogen as ammonia.
  • the light distillate 140 becomes a low sulfur gasoline 180 .
  • the low sulfur gasoline 180 has a sulfur content ranging from about 0 to about 50 ppm.
  • the middle distillate 150 becomes a low sulfur diesel/heating oil 190 .
  • the low sulfur diesel/heating oil 190 has a sulfur content ranging from about 0 to about 15 ppm.
  • the heavy distillate 160 becomes a feed 200 to an existing fluid catalytic cracking unit 210 which produces a low sulfur gasoline 220 and a low sulfur diesel/heating oil 230 to combine with the low sulfur gasoline 180 and the low sulfur diesel/heating oil 190 , respectively.
  • Those skilled in the art can determine the operating conditions of the fluid catalytic cracking unit 210 to achieve the desired products.
  • the exit streams 220 and 230 are combined with streams 140 and 150 , respectively, and fed to the appropriate hydrotreater 50 .
  • the reduced crude 170 is sent to existing conversion units, which one skilled in the art can determine.
  • FIGS. 3 a , 3 b , and 3 c depict selected, but not exhaustive examples of alternative embodiments for realizing the advantages of the present invention.
  • FIGS. 3 a and 3 b show oxidation downstream of a crude unit, but upstream of a hydrotreater. This arrangement allows the oxidized sulfones to be treated by the hydrotreater, to release hydrogen sulfide and to produce low sulfur fuel products.
  • the feed 10 is a crude oil fed to the existing crude unit 130 .
  • the existing crude unit 130 produces a light distillate 140 , a heavy distillate 160 and a reduced crude 170 .
  • the reduced crude 170 is sent to existing conversion processes, which one skilled in the art will be able to determine.
  • the heavy distillate 160 is sent to the existing fluid catalytic cracking unit 210 which produces a cracked stream in line 300 .
  • the cracked stream 300 has properties similar to the light distillate 140 .
  • the cracked stream 300 and the light distillate 140 are combined and sent to the oxidation section 20 .
  • the oxidation section may employ any oxidation reaction sequence and agent as mentioned previously which produces a hydrocarbon reaction mixture containing oxidized sulfur and nitrogen compounds which exit in line 70 .
  • the oxidation reaction sequences are those that do not substantially react with olefins (i.e. no octane loss).
  • the oxidant described in U.S. patent application Ser. No. 09/654,016 is incorporated herein by reference for all purposes.
  • the hydrocarbon stream containing oxidized sulfur and nitrogen compounds in line 70 is sent to a product splitter 310 resulting in a gasoline fraction in line 320 and a diesel fraction in line 330 .
  • the gasoline in line 320 and the diesel in line 330 are sent to existing hydrotreater that operate to produce ultra-low sulfur and low nitrogen products from the respective feed streams, releasing gaseous hydrogen sulfide and ammonia.
  • the existing hydrotreaters 50 produce the low sulfur gasoline in product line 180 and the low sulfur diesel/heating oil in product line 190 .
  • Those skilled in the art will be able to determine the operating conditions which produce product streams of the desired specifications.
  • Approximately 40% of the gasoline pool is made up of cracked naphthas produced in either thermal or catalytic cracking units. More than 90% of the sulfur in the entire gasoline pool comes from the sulfur present in the cracked naphthas, such as, for example, mercaptans, sulfides, thiophenes and polysulfides. By desulfurizing the cracked naphthas, an ultra-low sulfur blendstock for gasoline is produced.
  • sulfones can be removed by hydrotreating the corresponding unoxidized sulfur compounds at significantly milder reaction conditions at the lower end of the ranges mentioned above. These milder reactor conditions preserve the octane rating of the cracked naphtha by not saturating the olefins present in the feed.
  • the embodiment shown in FIG. 3 a as described above shows this advantage.
  • the gasoline from line 320 is hydrodesulfurized in the existing hydrotreater 50 at significantly milder process conditions than typical hydrotreaters.
  • the resulting desulfurized gasoline in product line 180 is an ultra-low sulfur blendstock to a pool for gasoline blending whose octane rating is almost equal to that of the gasoline being fed to the process.
  • the hydrogen requirements for the existing hydrotreater 50 are reduced since only a slight amount of hydrogen is consumed in olefin hydrogenation, which provides an additional economic benefit.
  • Those skilled in the art will be able to determine the operating conditions which produce product streams of the desired specifications.
  • the feed in stream 10 is crude oil fed to the existing crude unit 130 .
  • the existing crude unit 130 divides the crude into light distillate in conduit 140 , a middle distillate in conduit 150 , a heavy distillate in conduit 160 and a reduced crude stream 170 .
  • the reduced crude steam 170 is sent to existing conversion processes for further processing, as one skilled in the art will be able to determine.
  • the distillate streams are sent to separate oxidation sections 20 .
  • the oxidation sections are operated using any oxidation process, which oxidizes the organic sulfur compounds to the effluent containing the oxidated sulfur.
  • the oxidation sections 20 are tailored for the particular feed stream it oxidizes.
  • the organic sulfur compounds in the light distillate in line 140 are oxidized in the oxidation section 50 , light distillate stream 440 which contains oxidized sulfur compounds is fed to an existing hydrotreater 50 , where the oxidized sulfur compounds are reacted with hydrogen to remove the sulfur as hydrogen sulfide gas, to produce the desulfurized gasoline exiting through line 180 .
  • the middle distillate in line 150 and the heavy distillate in line 160 are subjected to the oxidation and hydrodesulfurization, in the oxidation section 20 and the hydrotreater section 50 , to produce low sulfur streams in lines 190 and 200 respectively.
  • the desulfurized heavy distillate in line 200 is fed to a conventional, probably existing, fluid catalytic cracking unit 210 which produces the low sulfur gasoline in line 220 and the diesel/heating oil in line 230 which are combined with the desulfurized gasoline in line 180 and the desulfurized diesel/heating oil in line 190 , respectively.
  • a conventional, probably existing, fluid catalytic cracking unit 210 which produces the low sulfur gasoline in line 220 and the diesel/heating oil in line 230 which are combined with the desulfurized gasoline in line 180 and the desulfurized diesel/heating oil in line 190 , respectively.
  • the specific operating conditions of the existing process units are well within the skill in the art requiring little or no experimentation to produce product streams of the desired specifications.
  • Any stream containing organic sulfur in it either before or from a crude distillation unit can be run through the oxidation step of this invention to produce a hydrocarbon effluent stream which contains oxidized organic sulfur compounds that maybe subsequently sent to a suitable hydrotreater for hydrodesulfurization to remove substantially all sulfur from the stream and recover the hydrocarbon, previously part of the sulfur compound, to the stream of useful hydrocarbon, for processing to produce a substantially sulfur free product.
  • Some feed streams could be hydrotreated and then oxidized with the oxidized sulfur compounds being separated and recycled to the hydrotreater.
  • These streams include, but are not limited to, vacuum gas oil, combined coker distillates, combined fluid catalytic cracking (FCC) distillates, combined (or separate) coker and FCC-cracked distillates, combined (or separate) coker and FCC-cracked naphtha, whole crude, and straight run distillate fractions.
  • FCC fluid catalytic cracking
  • a second hydrotreater could be used, or the treatment sequence changed, to place the oxidation step prior to hydrotreating, thus avoiding the inefficiencies inherent in separation processing.
  • the catalyst was presulfided at 350° C. before the catalytic reaction.
  • TPS-37 contains 37% sulfur by weight.
  • the catalyst was heated from room temperature to 350° C. in about two hours time while the sulfiding solution was sent through the reactor at 60 g/hr, at a pressure of about 100 psig, while a flow of 600 cc/min of hydrogen gas was maintained through the reactor.
  • the temperature of the reactor was held at 350° C. for 3 hours, and then the reactor was cooled to room temperature.
  • the sulfiding solution and hydrogen flows were maintained until the temperature of the reactor reached about 200° C. Only hydrogen flow was maintained afterwards.
  • DBT sulfone dibenzothiophene sulfone
  • phenyl hexane solvent a commercially available sample of DBT sulfone.
  • This solution was used as the “feed” for the hydrotreating experiments. The experiment was done at 4 different reaction conditions. The hydrogen flow rate and the “feed” flow rate were kept constant for all the four experiments. The “feed” flow rate was 60 g/hr. At each reaction condition, the product collected during the first 1 hour was rejected. Hourly liquid product samples were collected from each of the experiments and were analyzed using standard GC-MS analysis procedures. Results are shown in Table 1.
  • This example is to provide guidance to the selection of operating parameters for the hydrogenation of oxidized organic sulfur compounds with comparison to the results for direct hydrotreating of the sulfur in like samples.
  • a light atmospheric gas oil (LAGO) test sample containing 435 ppm total sulfur was used as the reactant feed.
  • the pressure, liquid flow rate, and hydrogen flow rate were kept constant at 400 psig, 100 g/hr, and 600 cc/min, respectively, at two different temperatures, 250° C. and 300° C.
  • Product samples were withdrawn at both these conditions, ultrasonicated for 15-20 minutes to expel the dissolved hydrogen sulfide, and were analyzed for sulfur by X-ray fluorescence (XRF) (ASTM D-2622). The results are presented in Table 2 below.
  • XRF X-ray fluorescence
  • the feed was switched to an oxidized LAGO sample.
  • the oxidized LAGO sample was prepared by starting with the same LAGO used above.
  • the LAGO was oxidized using hydrogen peroxide aqueous solution in the presence of formic acid catalyst.
  • the excess peroxide and formic acid were removed by repeated washing with a mild basic solution.
  • the “oxidized LAGO” was dried.
  • the oxidized LAGO contains less sulfur 320 ppm, than the starting LAGO due to the removal of some sulfur compounds with the aqueous phase and during the washing.
  • Table 4 provides the comparison of the results from the hydrotreating experiments using LAGO and oxidize LAGO feeds. It can be seen from the results presented in Table 4 that sulfur removal by conventional catalytic hydrodesulfurization from oxidized middle distillates is not only possible, but also is easier than sulfur removal from the parent unoxidized middle distillate feed. From the foregoing information, the expectation of sulfur removal from the various parameters can be predicted. Those of ordinary skill in the art will be guided toward the determination of parameters for particular feeds and loadings of sulfur.

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