Hydrodesulfurization of oxidized sulfur compounds in liquid hydrocarbons

Abstract

A process for removing sulfur from hydrocarbon streams is described. The organic sulfur compounds are first oxidized to create oxidized sulfur in the hydrocarbon stream and then processing the hydrocarbon stream with hydrogen at hydrodesulfurization conditions to reduce the sulfur to hydrogen sulfide, leaving a hydrocarbon gas stream substantially free of sulfur.

Description

FEDERALLY SPONSORED RESEARCH STATEMENT

[0002] Not applicable.

REFERENCE TO MICROFICHE APPENDIX

[0003] Not applicable.

FIELD OF THE INVENTION

[0004] This invention relates to a process for the removal of sulfur from liquid hydrocarbons by hydrotreating the liquid hydrocarbon containing oxidized sulfur compounds.

BACKGROUND OF THE INVENTION

[0005] The presence of sulfur in hydrocarbons has long been a significant problem from the exploration, production, transportation, and refining all the way to the consumption of hydrocarbons as a fuel, especially to power automobiles and trucks. As government regulations throughout the world increasingly restrict sulfur levels in fuels, the problem of sulfur reduction is being felt by producers, refiners, transporters and marketers of the full range of fuel products, from gasoline and diesel fuel to jet fuel, kerosene, heating oil and heavier fuels. In Western Europe, North America, Japan and other industrial nations the sulfur restrictions on gasoline and on-highway diesel fuel are moving to the ultra-low levels of 50, 30, 15 or even 10 ppm. Consequently, producers, refiners and marketers are seeking low-cost technologies for producing ultra-low sulfur products, with maximum use of existing facilities.

[0006] The process technology for removing sulfur that is in almost universal use today is hydrotreating, sometimes referred to as hydrodesulfurization. Hydrotreating, as used herein, 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. However, the sulfur in substituted dibenzothiophenes (DBT), especially those having steric hindrance of the sulfur, is particularly difficult to remove and requires high severity 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.

[0007] 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. However, 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. The decrease in octane rating is unacceptable due to the large percentage of the gasoline pool that the cracked naphtha contributes. Therefore a process for removing the sulfur from a cracked naphtha stream to produce an ultra-low sulfur product while maintaining the octane rating is needed. Cracking may be thermal cracking, hydrocracking, catalytic cracking, or any known cracking process to one skilled in the art.

[0008] As disclosed in U.S. patent application Ser. No. 09/654,016the difficult-to-hydrotreat thiophenic sulfur compounds are readily oxidized in a novel process that converts these compounds to the corresponding sulfones and sulfoxides. In this process, the desulfurization is ultimately achieved by removing the sulfoxides and sulfones from the hydrocarbon product through a series of chemical processing steps. The reference gives no details on the methods for ultimate disposal of the sulfoxides and sulfones.

[0009] U.S. Pat. No. 6,171,478 (Cabrera, et al.) 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. The concept of first hydrotreating a hydrocarbon feed containing sulfur compounds followed by an oxidation step to facilitate the removal of hard to hydrotreat thiophenic compounds was described earlier by Frances M. Collins et al. in the Journal of Molecular Catalysis A: chemical 117(1997), 397-403.

[0010] A subsequently issued U.S. Pat. 6,277,271 (Kocal) 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. In this particular patent 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.

[0011] Against the foregoing background, in order to achieve the predicted low sulfur levels in fuels and other hydrocarbon products, there is a need to develop a process that can maximize the effectiveness of existing hydrodesulfurization units with minimal or no modification. Additionally, there is a need for processes for convenient treatment of hydrocarbons having oxidized sulfur compounds to remove and dispose of the sulfur without hydrocarbon yield loss and without the expensive and often inefficient steps of solvent extraction and distillation and the like.

SUMMARY OF THE INVENTION

[0012] It has been discovered that the conventional hydrodesulfurization process for removal of sulfur compounds in hydrocarbon streams can be used to hydrotreat entire hydrocarbon streams containing oxidized sulfur compounds as well. In the case of hydrocarbon streams containing organic sulfur compounds, such as dibenzothiophenes, some of the organic sulfur is converted to hydrogen sulfide and hydrocarbon in the hydrotreater, to an extent dependent on the severity of the hydrotreating conditions. In the case of hydrocarbon streams containing oxidized sulfur compounds, such as dibenzothiophene sulfones, virtually all of the sulfur compounds can be converted to hydrogen sulfide and desulfurized hydrocarbon product in the hydrotreater, even at mild hydrotreating conditions. Hydrotreating of hydrocarbon streams containing both non-oxidized and oxidized sulfur compounds results in a product stream containing substantially no oxidized sulfur compounds and a reduced level of non-oxidized sulfur compounds.

[0013] It has been discovered that by sending a stream of hydrocarbon liquids containing oxidized sulfur compounds through a conventional hydrotreater, the sulfur in the oxidized sulfur compounds is reduced and removed as hydrogen sulfide. If the hydrocarbon liquid has other organic sulfurs present, the reaction in the hydrotreater also removes the sulfur from them depending on the types of organic sulfur present and the conditions of the hydrotreater. The resulting hydrocarbon stream would be substantially free of oxidized sulfur compounds and have a low level of residual organic sulfur compounds. The hydrotreater may operate at hydrotreating conditions such as those commonly found in use in today's refineries. If the only sulfur present is oxidized organic sulfur compounds, the operating conditions can be even milder. The milder conditions result in equivalent capacity and gives the additional advantage of less hydrogenation of the olefins. 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.

[0014] Alternatively, 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. After exiting the hydrotreater, 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. Alternatively, the product stream containing the oxidized sulfur compounds is recycled to a hydrotreater. Thus, a hydrocarbon product with ultra low levels of sulfur can be produced.

[0015] 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. In conventional operation, the hydrotreater not only hydrodesulfurizes the cracked naphtha, but also hydrogenates the olefins in the cracked naphtha. 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). By not hydrogenating the olefins, the product from the process has substantially the same octane rating as the usual cracked naphtha hydrotreater feed. Alternatively, 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.

[0016] This invention has dramatic implications for achieving ultra-low sulfur (zero to 50 ppm, depending on the regulatory requirements) hydrocarbon products cost-effectively by making better use of existing hydrodesulfurization units. There are at least two basic configurations for implementing this invention and many variations of each that could be envisioned by those skilled in the art.

[0017] First, 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.

[0018] Second, an oxidation process could be installed downstream of an existing hydrotreating unit. In this configuration, after the oxidation step, 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. Although 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. As an alternative to an extensive separation of the oxidized sulfur for recycle, a second hydrodesulfurization reactor maybe utilized to do the final sulfur removal.

[0019] Those skilled in refining technology would be able to readily design a variety of systems involving various combinations of existing hydrotreaters and added oxidation reactors to achieve a broad slate of ultra-low sulfur hydrocarbon products.

[0020] 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. When the hydrotreater is operated at conditions usual in the refinery absent to pre-oxidation of the sulfurs, it has been surprisingly discovered that the rate of throughput to the reactor can be increased. Equivalent production is realized at milder temperatures and pressure. These lower temperatures and pressure conditions produce the extra advantage of preserving the olefin content of the hydrocarbon stream in the case of cracked naphtha feeds.

[0021] 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. When these streams are processed in hydrodesulfurization units, the level of sulfur is reduced by an amount dependent on the specific sulfur compounds present, the severity of the hydrotreating, the formulation of the catalyst and many other factors related to the design and operation of the unit. If 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.

[0022] While the following describes this invention in some detail, it must be understood by those skilled in the art that there is no intention on the part of the inventors hereof to abandon any part of the concepts of this invention with respect to the oxidation of the organic sulfur in crude oils, refinery intermediate streams or hydrocarbon products, whether they be fuels, chemical feedstocks or other.

BRIEF DESCRIPTION OF THE DRAWINGS

[0023] The following drawings to aid in the consideration of the description of the process of this invention show the main operating features of the refinery involved. Of course those skilled in the refinery art understand that miscellaneous equipment such as pumps and valves, heat exchangers, sensors, instrumentation and the like are all part of the successful operation of the process described herein. Those skilled in the refinery art will know and understand how to incorporate such equipment into the process.

[0024] 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.

[0025] 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.

[0026] 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.

[0027] 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.

DETAILED DESCRIPTION OF THE INVENTION

[0028] The invention summarized above will be more completely described as set forth hereinafter. 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.

[0029] 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.

[0030] 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. 09/654,016 (carboxylic acid/hydrogen peroxide), all of which are incorporated in their entirety herein by reference. All those processes disclose methods for producing a hydrocarbon stream containing oxidized organic sulfur compounds. The oxidation reaction may be described as contacting the hydrocarbon stream containing the organic sulfur compounds with an effective amount of an alkaline earth metal peroxide stream which, upon activation by an effective amount of an acid stream, produces hydrogen peroxide in situ to form a reaction mixture in which the organic sulfur present in the hydrocarbon stream reacts to form organic sulfones and sulfoxides corresponding to the sulfur compounds in the hydrocarbon stream.

[0031] In the practice of this invention a hydrocarbon stream containing oxidized sulfur compounds is hydrotreated in a conventional hydrotreater. The 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. Preferred carrier materials maybe selected from alumina, silica-alumina, activated carbon, silica, titania, magnesia and mixtures thereof. Particularly, 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. Preferably, 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.

[0032] Since 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. to about 380° C.; a pressure range from about 100 psig to about 1,000 psig and preferably ranging from about 200 psig to about 500 psig; a liquid hourly space velocity (LHSV) range from about 0.2 to about 10.0; and a gas flow range from about 100 to about 5,000 SCFB (Standard cubic feet per barrel) having at least about 70% hydrogen. Other gases such as nitrogen, natural gas and fuel gas may also be present along with hydrogen. Those skilled in refinery operations are able to readily select conditions which would be successful. The product hydrocarbon oil from the process, after removing the dissolved hydrogen sulfide by methods that are generally practiced, and well known in the art, is directly used for blending into the respective product streams. The hydrotreating conditions are dictated by the feed stream and the quality of the product stream desired.

[0033] In addition to providing a simple method for processing sour crudes to achieve almost sulfur free, motor fuels other advantages of this invention become evident. Oxidized sulfur compounds do not have to be separated since they can be reacted in the hydrotreater in the presence of the entire hydrocarbon stream to create a hydrogen sulfide gas stream which is easy to dispense of. Also, the organic moiety to which the sulfur was attached becomes part of the product. Nowhere in the art is this result taught.

[0034] This invention is adaptable to many refinery process configurations but only a few will be discussed here. Those skilled in the art will perceive many other permutations and conbinations of process based upon this description. Referring to FIG. 1 showing a general block diagram of the process of this invention, 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.

[0035] 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.

[0036] 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.

[0037] The hydrocarbon exiting the oxidation reactor 20 through line 30 and is introduced into hydrotreater 50. 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. to about 380° C.; a pressure ranging from about 100 psig to about 1,000 psig and preferably ranging from about 200 psig to about 500 psig; a liquid hourly space velocity (LHSV) ranging from about 0.2 to about 10.0; and a gas flow ranging from about 100to about 5,000 SCFB (standard cubic feet per barrel) having at least about 70% hydrogen. 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. Other 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.

[0038] In a preferred embodiment, 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. Within the oxidation section 20, the feed entering through line 10 is preferably contacted with an oxidizing solution containing hydrogen peroxide, a C1-C4 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 C1-C4 carboxylic acid being the largest constituent as described in the aforementioned patent application (see Ser. No. 09/654,016). Where fuel products are involved, 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 C1 to C4 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. Of course, in the event that the oxidizing section is constructed downstream of an existing hydrodesulfurization reactor, in order to oxidize the organic sulfur containing hydrocarbons which are difficult to remove by hydrodesulfurization, 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. This, of course, would be an economic consideration but well within the pervue of those of ordinary skill in the art. The oxygenation reactor would be operated in substantially the same manner as that discussed above for the existing hydrotreater 50.

[0039] 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. As stated, if heavy, viscous or has high sulfur content, a diluent can be appropriately used. 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. In a preferred embodiment, 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. Those skilled in the art of hydrotreating will be able to select conditions of the hydrotreaters 50 that accomplish the hydrodesulfurization to desired product qualities. After hydrotreating, 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. After hydrotreating, 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. After hydrotreating, 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. In an alternate embodiment, if there is no hydrotreater 50 to pre-treat the heavy distillate 160 prior to the catalytic cracker 210, 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.

[0040] FIGS. 3 a , 3b, and 3c depict selected, but not exhaustive examples of alternative embodiments for realizing the advantages of the present invention. FIGS. 3a and 3b 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.

[0041] In FIG. 3a, 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. Those skilled in the art will be able to determine the operating conditions of the existing crude unit to produce these standard refinery streams according to the product mix of the refinery and the crude oil stream for which it was designed. 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. Preferably, 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. Those skilled in the art will be able to determine the operating conditions of the product splitter 310 to achieve the product desired streams. The gasoline in line 320 and the diesel in line 330, still containing the oxidized sulfur and nitrogen compounds, 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.

[0042] 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. Under conventional refinery practice, it is very easy to hydrotreat the cracked naphthas to remove sulfur, but in the process, the olefins in the cracked naphtha are hydrogenated to paraffins, reducing the value as a gasoline component, since olefins have a higher octane rating than paraffins. This hydrogenation of olefins to paraffins significantly reduces the octane number of the desulfurized cracked naphtha. It is a particular advantage of the present invention that this process to remove sulfur from cracked naphtha minimizes the hydrogenation of the olefins, thereby maintaining the octane number. The oxidized sulfur compounds, i.e. 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. 3a 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.

[0043] In the alternative embodiment shown in FIG. 3b, 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. Those skilled in the art will be able to determine the conditions of the existing crude unit to produce these standard well-known refinery streams. 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. Similiarly, 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. 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.

[0044] 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. However, if there is a desire to avoid the separation of two hydrocarbon streams, usually by an extraction process, 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.

[0045] By employing both the oxidation and hydrotreating processes in various sequences, a product stream substantially free of sulfur is possible with substantially no hydrocarbon yield loss. With the current prospect of regulations reducing the maximum sulfur content of fuels, such as gasoline or diesel fuel, to 5 to 50 ppm or less, the practice of this invention provides a relatively inexpensive and very beneficial disposal practice for sulfur. This is particularly so in view of the low levels of sulfur, approaching zero, that are obtainable through the combined practice of the oxidation and hydrotreating processes. Those skilled in the art of refinery operations can readily select a process flow through the refinery that would produce extremely low sulfur content products.

[0046] The foregoing results are further demonstrated by the following examples, which are offered for purposes of illustration of the practice of this invention and for the understanding; not for the limitation thereof.

EXAMPLES

[0047] Unless otherwise stated, the following general experimental procedure applies to all of the examples. The feed was a sulfur-containing liquid hydrocarbon containing oxidized organic sulfur compounds.

Example 1

[0048] An alumina supported Ni-Mo hydrosulfurization catalyst from Criterion Catalyst Company, Houston, Tex., in the form of {fraction (1/16)}′ extrudates was used in a tubular fixed bed reactor. A stainless steel laboratory reactor having 19 mm inner diameter and 40 cm length was used for all of the experiments. The reactor tube had no internal structures. 30 cc of catalyst was loaded in the center of the reactor, undiluted. The rest of the length of the reactor was packed with glass beads and glass wool. The reactor was heated with a four-zone clamshell furnace, each zone independently controllable by electronic temperature programmer/controllers. The reactor effluent went through a gas-liquid separator and entered a collection vessel at reactor pressure, from which samples were withdrawn.

[0049] The catalyst was presulfided at 350° C. before the catalytic reaction. A 2 weight % solution of a commercially available sulfiding agent TPS-37 in hexadecane, available from Atofina Chemicals, Philadelphia, Pa., was used for sulfiding the catalyst. 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.

[0050] A solution of dibenzothiophene sulfone (DBT sulfone)containing a 250 ppm concentration of sulfur in phenyl hexane solvent was prepared using 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.

TABLE 1
Experiment	Reaction-conditions	Observations
1	350° C. and 500 psig	100% conversion of DBT sulfone. No DBT or DBT sulfone were
		detected in product, indicating complete hydrodesulfurization.
		Biphenyl, the main reaction product of DBT sulfone was detected.
		Some solvent hydrogenation observed.
2	300° C. and 500 psig	100% conversion of DBT sulfone. No DBT or DBT sulfone were
		detected in product, indicating complete hydrodesulfurization.
		Biphenyl, the main reaction product of DBT sulfone was detected.
3	250° C. and 200 psig	100% conversion of DBT sulfone. Approximately 25% DBT and
		75% Biphenyl, were produced.
4	200° C. and 200 psig	100% conversion of DBT sulfone. However, approximately 50%
		DBT sulfone was converted into DBT, which is a sulfur compound.
		The remaining DBT sulfone was converted into biphenyl. This
		indicates less hydrodesulfurization (HDS) under these extremely
		mild reaction conditions.

[0051] The above experiments show oxidized sulfur compounds are converted under all reactor conditions. In Examples 1 and 2, all DBT sulfones were removed and no sulfur products were detected in the product after gas separation to remove the hydrogen sulfide. In Experiments 3 and 4, at much milder conditions, approximately 25 to 50% of the DBT sulfones are converted to the corresponding thiophenes, thus sulfur is still present in the product. Therefore, the milder conditions of the hydrotreater may convert the oxidized sulfur compounds but not all the sulfur from the hydrocarbon product. Surprisingly, 75% of DBT sulfones can be hydrodesulfurized at relatively mild reaction conditions of 250 ° C. and 250 psig pressure. The conditions depend on the purpose and nature of the feed stream and demonstrate the flexibility of the process of this invention such that those skilled in the art may adapt same to use in the alternative embodiments described above as well as variants thereof.

Example 2

[0052] 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.

[0053] An alumina supported Co-Mo catalyst from Criterion Catalyst Company, in the form of 1.6 mm trilobe shaped extrudates was used in the tubular fixed bed reactor system as described in Example 1 was loaded, undiluted. The reactor was packed with 40 cc of catalyst and alpha alumina beads. The procedure for presulfiding the catalyst as described in Example 1 was followed except that the flow rate of the sulfiding solution was about 90 g/hr.

[0054] In order to stabilize the activity of the catalyst before test samples are hydrotreated, an atmospheric gas oil containing 1.4 weight percent sulfur was hydrotreated over the sulfided catalyst for approximately 9 hours at a liquid hourly space velocity (LHSV) of 3.0, at a temperature of 350° C., at a pressure of 400 psig, while hydrogen was flowing at 600 cc/min. At the end of the 9 hours, the flow was switched to a finished diesel fuel containing approximately 300 ppm sulfur under identical reaction conditions and was continued for another two hours before the reactor was cooled down in hydrogen flow. Product samples were periodically withdrawn and were analyzed for their sulfur content in order to assure that the catalyst had attained stable activity. The reactor was cooled to about 200° C. when the diesel flow was cut off. The hydrogen flow was continued until the reactor was cooled down to about 100° C. and the reactor was sealed off.

[0055] 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.

TABLE 2
Temp (C)	Feed Sulfur Content (ppm)	Product Sulfur Content (ppm)
250	435	198
300	435	77 and 60

[0056] At the end of the run the reactor was cooled down to about 100° C. in a similar way as before and was sealed off.

[0057] 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.

[0058] The hydrotreating experiments with the oxidized LAGO were conducted at four different temperatures with the other parameters remaining the same; that is, a pressure of 400 psig, a flow rate of 100 g/hr, and a hydrogen flow rate of 600 cc/min. At each temperature, after an hour of stabilization, two product sample cuts were at half an hour intervals before the temperature was increased to the next higher test temperature. Product samples were ultrasonicated for 15-20 minutes to expel the dissolved hydrogen sulfide for sulfur by X-ray fluorescence (XRF). The results are presented in Table 3 below.

TABLE 3
Temp (C)	Feed Sulfur Content (ppm)	Product Sulfur Content (ppm)
225	320	155 and 153
250	320	109 and 103
275	320	88 and 79
300	320	64 and 55

[0059] 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.

	TABLE 4
	Feed Sulfur	Product Sulfur	% Sulfur
	Content (ppm)	Content (ppm)	Removal
Temp		Oxidized		Oxidized		Oxidized
(C)	LAGO	LAGO	LAGO	LAGO	LAGO	LAGO
225		320		153		52.2
250	435	320	198	103	54.5	67.8
300	435	320	60	55	86.2	82.8

[0060] The foregoing description of the invention and the specific examples described demonstrate the benefits of the hydrotreating of oxidized sulfur compounds. The above-described description is offered for purposes of disclosing the advantages of the instant invention for use in desulfurizing the aforementioned fuel oils. Having been taught such process by the above discussion and examples, one of ordinary skill in the art could make modifications and adaptations to such process without departing from the scope of the claims appended hereto. Accordingly, such modification, variations and adaptations of the above-described process and compositions are to be construed within the scope of the claims which follow.

Claims

1. A process for removing sulfur from organic sulfur compounds of a feed hydrocarbon stream comprising the steps of: contacting the hydrocarbon stream with a sufficient amount of an oxidizing agent at oxidation conditions to oxidize the organic sulfur compounds in the feed hydrocarbon stream; contacting the feed hydrocarbon stream containing oxidized organic sulfur compounds with sufficient amounts of hydrogen at hydrodesulfurization conditions over a hydrodesulfurization catalyst to produce hydrocarbon stream with substantially lower sulfur content and a gas stream containing hydrogen sulfide; and recovering the hydrocarbon stream containing substantially less sulfur than the feed hydrocarbon.

2. The process of claim 1, wherein oxidizing the organic sulfur compounds to produce substantially oxidized organic sulfur compounds comprises the steps of: contacting the hydrocarbon stream with an aqueous oxidizing agent for oxidizing organic sulfur compounds comprising: from about 0.5% to about 4.5% hydrogen peroxide; from about 75 wt % to about 92 wt % of a C1 to C4 carboxylic acid; and water in an amount not to exceed about 25 wt %; and extracting at least part of the oxidized organic sulfur compounds from the hydrocarbon stream into the aqueous oxidizer composition; and separating the aqueous oxidizing agent from the hydrocarbon stream prior to the hydrodesulfurization step.

3. The process of claim 1 which comprises contacting the hydrocarbon containing oxidized sulfur compounds in the presence of a hydrotreating catalyst at a temperature greater than about 100° C., at a pressure greater than about 100 psig, at a liquid hourly space velocity of from about 0.2 to about 10.0, and at a gas flow rate of from about 100 to about 5,000 standard cubic feet per barrel having at least about 70% hydrogen.

4. The process of claim 3, wherein the temperature is from about 100° C. to about 400° C. and the pressure is from about 100 psig to about 1000 psig.

5. The process of claim 1, wherein the hydrocarbon stream with substantially lowered sulfur content which is recovered contains less than about 50 ppm by weight of sulfur.

6. A process for removing sulfur from a hydrocarbon stream boiling in the diesel full range comprising the steps of: contacting the hydrocarbon stream containing organic sulfur compounds at a temperature of from about 90° C. to about 105° C. for a period of time up to about 15 minutes with an oxidizing agent comprising: from about 79 wt % to about 89 wt % formic acid, from about 2 wt % to about 3 wt % hydrogen peroxide, and from about 8 wt % to about 14 wt % water: in an amount such that the molar ratio of formic acid to hydrogen peroxide is from about 12:1 to about 60:1, wherein the amount of oxidizing agent added is such that there is a stoichiometric excess of hydrogen peroxide over that which is necessary to oxidize the sulfur present in the hydrocarbon creating an aqueous phase and a hydrocarbon phase; separating the aqueous phase and recovering the hydrocarbon phase containing oxidized sulfur compounds; contacting the recovered hydrocarbon stream containing the oxidized sulfur compounds with a hydrodesulfurization catalyst at a temperature of from about 100° C. to about 400° C., at a pressure of from about 100psig to about 1,000 psig, at a liquid hourly space velocity of from about 0.2 to about 10.0, and at a gas flow rate of from about 100 to about 5,000 standard cubic feet per barrel having at least 70% hydrogen to produce a diesel product stream containing less than about 5 ppm sulfur and a gas stream containing hydrogen sulfide; and recovering the diesel product.

7. A process for reducing the sulfur content of a hydrocarbon stream which comprises the steps of: contacting the hydrocarbon stream containing the organic sulfur compounds with an effective amount of an alkaline earth metal peroxide stream which, upon activation, produces hydrogen peroxide in situ to form a reaction mixture in which the organic sulfur can be oxidized; and an effective, activating amount of an acid which reacts with the peroxide to generate hydrogen peroxide in situ, which reacts with the organic sulfur present in the hydrocarbon stream to form organic sulfones and sulfoxides corresponding to the sulfur compounds in the hydrocarbon stream; recovering a hydrocarbon stream having substantially all sulfur as oxidized sulfur compounds from the reaction mixture; hydrotreating the hydrocarbon stream having substantially all sulfur as oxidized sulfur compounds to produce a hydrogen sulfide stream and a substantially sulfur free hydrocarbon product; and recovering the substantially sulfur free hydrocarbon product.

8. A process for removing sulfur from a hydrocarbon stream containing organic oxidized sulfur compounds comprising the steps of: contacting the hydrocarbon stream containing up to about 6 wt % total sulfur as organic sulfones or sulfoxides with a hydrodesulfurization catalyst at hydrodesulfurization conditions with a gas stream containing at least about 70% hydrogen to form a gas stream containing substantial amounts of hydrogen sulfide and a hydrocarbon stream substantially free of sulfur.

9. The process of claim 8 wherein hydrodesulfurization conditions comprises contacting the hydrocarbon containing oxidized sulfur compounds with a hydrotreating catalyst at a temperature from about 100° C. to about 400° C., at a pressure greater than about 100 psig, at a liquid hourly space velocity of from about 0.2 to about 10.0, and at a gas flow rate of from about 100 to about 5,000 standard cubic feet per barrel.

10. A process for removing sulfur from a hydrocarbon stream comprising the steps of: oxidizing the sulfur compounds in the hydrocarbon stream to produce organic oxidized sulfur compounds comprising the steps of: contacting the hydrocarbon stream with an oxidizer composition for oxidizing organic sulfur compounds comprising from about 0.5% to about 4.5% hydrogen peroxide, from about 75 wt % to about 92 wt % of a C1-C4 carboxylic acid, water in an amount not to exceed about 25 wt %, and during such oxidation, extracting at least part of the oxidized organic sulfur compounds from hydrocarbon in an aqueous spent oxidizer phase; and recovering the hydrocarbon containing the oxidized sulfur compounds from the aqueous spent oxidizer; and contacting the hydrocarbon containing oxidized sulfur compounds with a hydrotreating catalyst at a temperature greater than about 100° C., at a pressure greater than about 100 psig, at a liquid hourly space velocity of from about 0.2 to about 10.0, and at a gas flow rate of from about 100 to about 5,000 standard cubic feet per barrel having at least about 70% hydrogen to form hydrogen sulfide gas and a hydrocarbon stream substantially free of sulfur; and recovering the hydrocarbon stream having a sulfur content of from about 0.0001% to about 1 wt %.

11. A process for removing sulfur from a sulfur containing cracked naphtha without substantially hydrogenating the olefins of the cracked naphtha comprising the steps of: oxidizing the sulfur compounds in the cracked naphtha to produce oxidized organic sulfur compounds; and then hydrodesulfurizing the oxidized organic sulfur compounds to produce a hydrogen sulfide stream and a substantially sulfur free naphtha product.

12. The process of claim 11, wherein oxidizing the sulfur compounds to produce oxidized organic sulfur compounds comprises the steps of: contacting the sulfur containing cracked naphtha with an effective amount of an aqueous oxidizer composition comprising: from about 0.5% to about 4.5% hydrogen peroxide; from about 75 wt % to about 92 wt % of a C1-C4 carboxylic acid; and water in an amount not to exceed about 25 wt %; and during such oxidation, extracting at least some of the oxidized organic sulfur compounds from the cracked naphtha into the aqueous oxidizer composition.

13. The process of claim 11 wherein hydrotreating the naphtha comprises contacting the naphtha containing oxidized sulfur compounds with a hydrotreating catalyst at a temperature from about 100° C. to about 400° C., at a pressure greater than about 100 psig, at a liquid hourly space velocity of from about 0.2 to about 10.0, and at a gas flow rate of from about 100 to about 5,000 standard cubic feet per barrel having at least about 70% hydrogen.

14. The process of claim 13, wherein oxidizing the sulfur compounds in the naphtha to produce an oxidized organic naphtha stream comprises the steps of: contacting the sulfur containing naphtha with an effective amount of an aqueous oxidizer composition comprising: from about 0.5% to about 4.5% hydrogen peroxide; from about 75 wt % to about 92 wt % of a C1-C4 carboxylic acid; and water in an amount not to exceed about 25 wt %; and during such oxidation, extracting at least some of the oxidized organic sulfur compounds from the cracked naphtha into the aqueous oxidizer.

15. A process for removing organic sulfur from crude oil comprising; oxidizing the organic sulfur in the crude oil stream containing organic sulfur compounds to produce an oxidized sulfur containing crude stream; distilling the oxidized sulfur containing crude stream containing the oxidized sulfur to produce a light distillate, a medium distillate, a heavy distillate and a reduced crude; hydrotreating the light distillate to produce low sulfur gasoline and a hydrogen sulfide gas stream; hydrotreating the medium distillate to produce desulfurized diesel and heating oil and a hydrogen sulfide gas stream; and hydrotreating the heavy distillate to produce a desulfurized reduced crude feed stream to a fluid catalytic cracker feed and a hydrogen sulfide gas stream; separating the hydrogen sulfide gas stream from the desulfurized gasoline, diesel, and heating oil; and cracking the reduced crude feed stream to produce low sulfur gasoline and low sulfur diesel and heating oil.

16. A process for removing sulfur from a crude oil stream to form low sulfur hydrocarbon products comprising the steps of; distilling the crude stream to produce a light distillate, a medium distillate, a heavy distillate and a reduced crude; cracking the heavy distillate to produce a cracked naphtha stream; oxidizing the light distillate, medium distillate and cracked naphtha to produce an oxidized product stream; separating the oxidized product stream to produce a gasoline stream and diesel stream; hydrotreating the gasoline to produce low sulfur gasoline and a gas stream containing hydrogen sulfide; hydrotreating the diesel stream to produce low sulfur diesel and heating oil and a gas stream containing hydrogen sulfide; and recovering the gasoline, diesel and heating oil as low sulfur product streams.

17. A process for refining a crude oil stream containing sulfur to produce low sulfur hydrocarbon products comprising the steps of; distilling the crude stream to produce a light distillate, a medium distillate, a heavy distillate and a reduced crude the sulfur in the; oxidizing the sulfur containing compounds in the light distillate, the medium distillate, and the heavy distillate to produce an oxidized gasoline, an oxidized diesel and heating oil; and an oxidized feed stream, respectively; hydrotreating the oxidized gasoline to produce low sulfur gasoline; hydrotreating the oxidized diesel and heating oil to produce low sulfur diesel and heating oil; hydrotreating the oxidized feed stream to a feed stream; and cracking and separating the feed stream into a low sulfur gasoline and a low sulfur diesel/heating oil.