JP2020510719A - Oxidative desulfurization and sulfone treatment of petroleum fractions using FCC - Google Patents

Abstract

Embodiments provide methods and apparatus for recovering components from hydrocarbon feedstocks. According to at least one embodiment, the method comprises the step of feeding a hydrocarbon feedstock to an oxidation reactor, the hydrocarbon feedstock selectively selecting sulfur compounds and nitrogen compounds present in the hydrocarbon feedstock in the presence of a catalyst. Oxidizing under conditions sufficient to oxidize the hydrocarbon, the hydrocarbon, the oxidized sulfur compound, and the oxidized nitrogen compound are separated by solvent extraction, the oxidized sulfur compound and the oxidation. Collecting a residual stream containing the generated nitrogen compounds, and supplying the first residual stream to a fluid catalytic cracking unit. The first retentate stream is further fed through a hydrotreating device before feeding the first retentate stream to a fluid catalytic cracking unit.

Description

  Embodiments relate to a method and apparatus for recovering sulfur and nitrogen from a hydrocarbon feed. More specifically, embodiments relate to methods and apparatus for the oxidative desulfurization and denitrification of hydrocarbon streams and subsequent disposal of the resulting oxidized sulfur and nitrogen compounds.

  Crude oil is the world's major source of hydrocarbons used as fuels and petrochemical feedstocks. At the same time, petroleum and petroleum-based products are also major sources of air and water pollution today. To address the growing concern over pollution caused by petroleum and petroleum-based products, many countries have developed permissible concentrations of certain pollutants in petroleum products, particularly in oil refining operations and fuels, such as in gasoline fuels. Strict regulations have been implemented for the required sulfur and nitrogen content. Although the exact composition of natural petroleum or crude oil varies significantly, all crude oils contain some measurable amounts of sulfur compounds and most crudes also contain some measurable amounts of nitrogen compounds. In addition, while crude oil may also contain oxygen, most crude oils have low oxygen content. Generally, the concentration of sulfur in crude oil is less than about 5 weight percent (% by weight), and most crude oils have a sulfur concentration in the range of about 0.5 to about 1.5% by weight. The nitrogen concentration of most crudes is typically less than 0.2% by weight, but can be as high as 1.6% by weight. In the United States, the maximum total sulfur content of automotive gasoline fuels is regulated to be less than 10 parts per million by weight (ppmw) sulfur.

  Crude oil is refined at refineries to produce transportation fuels and petrochemical feedstocks. Typically, transportation fuels are manufactured by processing and blending a distillate fraction from crude oil to meet specific end-use specifications. Because most of the currently available crude oils have high levels of sulfur, distillate fractions typically require desulfurization to obtain a product that meets various performance specifications, environmental standards, or both.

  Sulfur-containing organic compounds present in crude oil and the resulting refined fuel can be a major source of environmental pollution. Sulfur compounds are typically converted to sulfur oxides during the combustion process, which in turn produces sulfur oxoacids, which can contribute to particulate emissions.

  One way to reduce particulate emissions is to add various oxygenated fuel blends, compounds containing little or no carbon-carbon bonds, such as methanol and dimethyl ether, or both. . However, the majority of these compounds have the disadvantage that they can have a high vapor pressure, are almost insoluble in diesel fuel, or have a low ignitability, as indicated by their cetane number, or They have the disadvantages of their combination.

  Diesel fuels that have been treated by chemical hydrotreating or hydrogenation to reduce the content of sulfur and aromatics may have reduced fuel lubricity, which in turn translates into fuel pumps, injectors and Other moving parts that come into contact with the fuel under high pressure may wear excessively.

  For example, middle distillates (i.e., distillates nominally boiling in the range of about 180-370 <0> C) can be used as fuels or fuels used in compression ignition internal combustion engines (i.e., diesel engines). Can be used as a component. The middle distillate fraction typically contains about 1 to 3% by weight of sulfur. The allowable sulfur concentration in middle distillate cuts has been reduced in Europe and the United States since 1993 from 3000 ppmw levels to 5-50 ppmw levels.

  In order to comply with increasingly stringent regulations for ultra-low sulfur content fuels, refiners must produce fuels with much lower sulfur levels at refinery gates so that they can meet specifications after mixing. No.

  A low pressure conventional hydrodesulfurization (HDS) process can be used to remove most of the sulfur from petroleum distillate for refinery transportation fuel blending. However, these units are efficient at removing sulfur from compounds under mild conditions (ie, up to about 30 bar pressure) when the sulfur atom is sterically hindered, such as polycyclic aromatic sulfur compounds. Not. This is especially true where the sulfur heteroatom is hindered by two alkyl groups (eg, 4,6-dimethyldibenzothiophene). Due to the difficulty of removal, hindered dibenzothiophenes occupy low sulfur levels, such as 50 ppmw to 100 ppmw. To remove sulfur from these refractory sulfur compounds, harsh operating conditions (eg, high hydrogen partial pressures, high temperatures or high catalyst volumes) must be utilized. Increasing the hydrogen partial pressure can only be achieved by listing the recycle gas purity, or requires the design of a new base unit, which can be a very costly option. The use of harsh operating conditions typically leads to reduced yields, reduced catalyst life cycles, and product quality degradation (eg, color) and is typically sought to be avoided.

  However, conventional methods of upgrading petroleum suffer from various limitations and disadvantages. For example, hydrogenation processes typically require the supply of large amounts of hydrogen gas from an external source to achieve the desired upgrades and conversions. These processes also have the disadvantage of premature or rapid deactivation of the catalyst, as is usually the case with hydrotreatment of heavy feedstocks or hydrotreatment under harsh conditions, and thus regeneration or renewal of the catalyst. The addition of a catalyst is required, which in turn can lead to downtime of the processing unit. Thermal methods often have the disadvantage of producing large quantities of coke as a by-product and of having a limited ability to remove impurities such as sulfur and nitrogen. Furthermore, thermal methods require specialized equipment suitable for harsh conditions (eg, high temperatures and pressures), require significant energy input, thereby increasing complexity and cost.

  Thus, methods for upgrading hydrocarbon feedstocks, especially hydrocarbon desulfurization, denitrification, or both using low severity conditions, which can also provide a means for recovery and disposal of available sulfur or nitrogen compounds, can be provided. There is a need to provide.

  Embodiments provide methods and apparatus for upgrading hydrocarbon feedstocks that remove most of the sulfur and nitrogen present and then utilize these compounds in related processes.

  According to at least one embodiment, a method of recovering components from a hydrocarbon feedstock, comprising feeding a hydrocarbon feedstock containing a sulfur compound and a nitrogen compound to an oxidation reactor, and providing the hydrocarbon, oxidized sulfur compound and oxidized Hydrocarbons in an oxidation reactor under conditions sufficient to selectively oxidize the sulfur and nitrogen compounds present in the hydrocarbon feed to produce an oxidized hydrocarbon stream containing the reduced nitrogen compounds. A method is provided that includes contacting the raw material with an oxidizing agent. The method separates hydrocarbons, oxidized sulfur compounds and oxidized nitrogen compounds in an oxidized hydrocarbon stream by solvent extraction with a polar solvent to produce an extracted hydrocarbon stream and a mixed stream. Wherein the mixed stream comprises a polar solvent, oxidized sulfur compounds and oxidized nitrogen compounds, and the extracted hydrocarbon stream has a lower concentration of sulfur compounds and nitrogen compounds than the hydrocarbon feed. . The method further comprises separating the mixed stream using a distillation column into a first recovered polar solvent stream and a first retentate stream comprising oxidized sulfur compounds and oxidized nitrogen compounds; The method further includes supplying the stream to a fluid catalytic cracker. The method further includes feeding the first retentate stream through a hydrotreating unit before feeding the first retentate stream to a fluid catalytic cracker. The fluid catalytic cracker operates to catalytically crack oxidized sulfur and oxidized nitrogen to produce a regenerated catalyst and gaseous and liquid products and to recover hydrocarbons from the first residual stream. Is possible.

  According to at least one embodiment, the method includes recirculating at least a portion of the liquid product to an oxidation reactor to selectively oxidize sulfur compounds in the liquid product, the method comprising: The part includes at least one of a light cycle oil and a heavy cycle oil.

  According to at least one embodiment, the method comprises: providing an extracted hydrocarbon stream to a stripper to produce a second recovered polar solvent stream and a stripped hydrocarbon stream; The method further includes recycling the solvent stream and the second polar solvent stream to an extraction vessel for separating hydrocarbons, oxidized sulfur compounds and oxidized nitrogen compounds in the oxidized hydrocarbon stream.

  According to at least one embodiment, the method further comprises recycling a portion of the regenerated catalyst to the fluidized catalytic cracker using a fluidized catalytic cracking feed stream, wherein the recycling comprises removing hydrocarbons from the first residual stream. The method further includes catalytically cracking the fluid catalytic cracking feed stream using a portion of the regenerated catalyst for recovery.

  According to at least one embodiment, the oxidizing agent is selected from the group consisting of air, oxygen, peroxide, hydroperoxide, ozone, nitrogen oxide compounds and combinations thereof.

According to at least one embodiment, contacting the hydrocarbon feed with an oxidizing agent is performed in the presence of a catalyst comprising a metal oxide having the formula M _x O _y , wherein M is group IVB of the periodic table, VB And an element selected from Group VIB and Group VIB.

  According to at least one embodiment, the sulfur compound includes a sulfide, disulfide, mercaptan, thiophene, benzothiophene, dibenzothiophene, an alkyl derivative of dibenzothiophene, or a combination thereof.

  According to at least one embodiment, the oxidation reactor is maintained at a temperature of about 20 to about 350C and a pressure of about 1 to about 10 bar.

  According to at least one embodiment, the ratio of oxidizer to sulfur compound present in the hydrocarbon feed is from about 4: 1 to about 10: 1.

  According to at least one embodiment, the polar solvent has a Hildebrand value greater than about 19.

  According to at least one embodiment, the polar solvent is a group consisting of acetone, carbon disulfide, pyridine, dimethylsulfoxide, n-propanol, ethanol, n-butanol, propylene glycol, ethylene glycol, dimethylformamide, acetonitrile, methanol and combinations thereof. Is selected from

  According to at least one embodiment, the polar solvent is acetonitrile.

  According to at least one embodiment, the polar solvent is methanol.

  According to at least one embodiment, the solvent extraction is performed at a temperature from about 20C to about 60C and a pressure from about 1 to about 10 bar.

  According to at least one embodiment, the method further comprises supplying the extracted hydrocarbon stream to an adsorption column, wherein the adsorption column is suitable for removing oxidized compounds present in the extracted hydrocarbon stream. The adsorbent is charged and a high purity hydrocarbon product stream and a second retentate stream are produced by the adsorption tower, the second retentate stream containing a portion of the oxidized compound.

  According to at least one embodiment, the method further comprises feeding the second residual stream to a fluid catalytic cracker.

  According to at least one embodiment, the sorbent is selected from the group consisting of activated carbon, silica gel, alumina, natural clay, silica-alumina, zeolites and combinations thereof.

  According to at least one embodiment, the sorbent is a polymer coated carrier, wherein the carrier has a high surface area and is selected from the group consisting of silica gel, alumina, silica-alumina, zeolite and activated carbon, wherein the polymer is polysulfone, polyacrylonitrile, polystyrene , Polyester terephthalate, polyurethane and combinations thereof.

  According to at least one embodiment, supplying the first retentate stream to the fluid catalytic cracking unit comprises refining the first retentate stream in the presence of a catalyst to recover hydrocarbons from the first retentate stream. The method further comprises catalytically cracking the fluidized catalytic cracking feed stream in contact with a fluid catalytic cracking feed stream.

  According to at least one embodiment, the fluid catalytic cracking feed stream is vacuum gas oil (VGO), atmospheric distillate bottoms, demetalized oil, whole crude oil, cracked shale oil, liquefied coal, cracked bitumen, heavy coker gas oil, light cycle oil , Heavy cycle oils, clarified slurry oils or combinations thereof.

  According to another embodiment, a method of recovering components from a hydrocarbon feed, comprising feeding a hydrocarbon feed containing a sulfur compound and a nitrogen compound to an oxidation reactor, and providing the hydrocarbon, the oxidized sulfur compound, and the oxidized Carbonization in an oxidation reactor under conditions sufficient to selectively oxidize sulfur and nitrogen compounds present in the hydrocarbon feed to produce an oxidized hydrocarbon stream containing the oxidized nitrogen compounds. A method is provided that includes contacting a hydrogen source with an oxidizing agent. The method separates hydrocarbons, oxidized sulfur compounds and oxidized nitrogen compounds in an oxidized hydrocarbon stream by solvent extraction with a polar solvent to produce an extracted hydrocarbon stream and a mixed stream. Wherein the mixed stream comprises a polar solvent, oxidized sulfur compounds and oxidized nitrogen compounds, and the extracted hydrocarbon stream has a lower concentration of sulfur compounds and nitrogen compounds than the hydrocarbon feed. . The method comprises separating the mixed stream using a distillation column into a first recovered polar solvent stream and a first retentate stream comprising oxidized sulfur compounds and oxidized nitrogen compounds; Further comprising feeding to a fluid catalytic cracker, the fluid catalytic cracker operative to catalytically crack oxidized sulfur and oxidized nitrogen to produce a regenerated catalyst and gas and liquid products. , It is possible to recover hydrocarbons from the first residual stream. Further, the method comprises contacting the first residue stream with a fluid catalytic cracking feed stream in the presence of a catalyst to catalytically crack the fluid catalytic cracking feed stream to recover carbohydrates from the first residue stream. Feeding the first residual stream in contact with the fluidized catalytic cracking feed stream through the hydrotreating unit before supplying the first residual stream to the fluidized catalytic cracking unit.

  According to at least one embodiment, the method further comprises recycling at least a portion of the liquid product to an oxidation reactor to selectively oxidize sulfur compounds in the liquid product, the method comprising: Some include at least one of a light cycle oil and a heavy cycle oil.

  According to at least one embodiment, the method comprises: providing an extracted hydrocarbon stream to a stripper to produce a second recovered polar solvent stream and a stripped hydrocarbon stream; The method further includes recycling the solvent stream and the second polar solvent stream to an extraction vessel for separating hydrocarbons, oxidized sulfur compounds and oxidized nitrogen compounds in the oxidized hydrocarbon stream.

  According to at least one embodiment, the method further comprises recycling a portion of the regenerated catalyst to the fluidized catalytic cracker using a fluidized catalytic cracking feed stream, wherein the recycling comprises removing hydrocarbons from the first residual stream. The method further includes catalytically cracking the fluid catalytic cracking feed stream using a portion of the regenerated catalyst for recovery.

  According to at least one embodiment, the oxidizing agent is selected from the group consisting of air, oxygen, peroxide, hydroperoxide, ozone, nitrogen oxide compounds and combinations thereof.

According to at least one embodiment, contacting the hydrocarbon feed with an oxidizing agent is performed in the presence of a catalyst comprising a metal oxide having the formula M _x O _y , wherein M is group IVB of the periodic table, VB And an element selected from Group VIB and Group VIB.

  According to at least one embodiment, the sulfur compound includes a sulfide, disulfide, mercaptan, thiophene, benzothiophene, dibenzothiophene, an alkyl derivative of dibenzothiophene, or a combination thereof.

  According to at least one embodiment, the oxidation reactor is maintained at a temperature of about 20 to about 350C and a pressure of about 1 to about 10 bar.

  According to at least one embodiment, the ratio of oxidizer to sulfur compound present in the hydrocarbon feed is from about 4: 1 to about 10: 1.

  According to at least one embodiment, the polar solvent has a Hildebrand value greater than about 19.

  According to at least one embodiment, the polar solvent is a group consisting of acetone, carbon disulfide, pyridine, dimethylsulfoxide, n-propanol, ethanol, n-butanol, propylene glycol, ethylene glycol, dimethylformamide, acetonitrile, methanol and combinations thereof. Is selected from

  According to at least one embodiment, the polar solvent is acetonitrile.

  According to at least one embodiment, the polar solvent is methanol.

  According to at least one embodiment, the solvent extraction is performed at a temperature from about 20C to about 60C and a pressure from about 1 bar to about 10 bar.

  According to at least one embodiment, the method further comprises supplying the extracted hydrocarbon stream to an adsorption column, wherein the adsorption column is suitable for removing oxidized compounds present in the extracted hydrocarbon stream. The adsorbent is charged and a high purity hydrocarbon product stream and a second retentate stream are produced by the absorption tower, the second retentate stream containing some of the oxidized compounds.

  According to at least one embodiment, the method further comprises feeding the second residual stream to a fluid catalytic cracker.

  According to at least one embodiment, the sorbent is selected from the group consisting of activated carbon, silica gel, alumina, natural clay, silica-alumina, zeolites and combinations thereof.

  According to at least one embodiment, the sorbent is a polymer-coated carrier, wherein the carrier has a high surface area and is selected from the group consisting of silica gel, alumina and activated carbon, wherein the polymer is polysulfone, polyacrylonitrile, polystyrene, polyester terephthalate, polyurethane, It is selected from the group consisting of silica-alumina, zeolites and combinations thereof.

  According to at least one embodiment, the first retentate stream and the fluid catalytic cracking feed stream are present in a weight ratio to the first retentate stream and the fluid catalytic cracking feed stream ranging from about 1 to about 15.

  According to at least one embodiment, the fluidized catalytic cracking feed stream is VGO, atmospheric distillation bottoms, demetallized oil, whole crude oil, cracked shale oil, liquefied coal, cracked bitumen, heavy coker gas oil, light cycle oil, heavy cycle oil Oils, clarified slurry oils or combinations thereof.

  According to at least one embodiment, contacting the first retentate stream with the fluid catalytic cracking feed stream in the presence of a catalyst is performed at a temperature in the range of about 300C to about 650C.

  According to at least one embodiment, contacting the first retentate stream with the fluid catalytic cracking feed stream in the presence of the catalyst is performed with a residence time of about 0.1 seconds to about 10 minutes.

  According to at least one embodiment, the method further comprises separating the lower boiling components and catalyst particles from the first retentate stream and the fluid catalytic cracking feed stream, and regenerating at least a portion of the catalyst particles.

  According to at least one embodiment, regenerating at least a portion of the catalyst particles comprises regenerating the catalyst in a fluidized bed operated at a condition that produces a gaseous product and a liquid product comprising carbon monoxide and carbon dioxide. Contacting a portion of the particles with an anhydrous oxygen-containing gas.

  To provide a more detailed understanding of the features and advantages of the disclosed method and system, as well as others that will become apparent, a more detailed description of the method and system briefly summarized above is set forth in this specification. This can be done by referring to the embodiments shown in the accompanying drawings, which constitute the part. It should be noted, however, that the drawings are merely illustrative of various embodiments, and thus should not be viewed as limiting in scope, as other valid embodiments may be included as well. Like numbers refer to like elements throughout, and where primed notation is used, to indicate similar elements in alternative embodiments or locations.

1 provides a schematic diagram of one embodiment of a method for upgrading a hydrocarbon feed. 1 provides a schematic diagram of one embodiment of a method for upgrading a hydrocarbon feed. 1 provides a schematic diagram of one embodiment of a method for upgrading a hydrocarbon feed. 1 provides a schematic diagram of the method described in the examples. 5 shows the effect of hydrotreating on FCC performance.

  While the following detailed description includes many specific details for purposes of illustration, those skilled in the art will recognize that many examples, variations, and modifications to the following details are within the scope and spirit of the invention. Understood. Accordingly, the various embodiments described and provided in the accompanying drawings have been described with respect to the appended claims, without loss of generality and without limitation.

  Embodiments address conventional problems associated with conventional methods of upgrading and recovering compounds from hydrocarbon feedstocks, particularly desulfurization, denitrification, or both, of hydrocarbon feedstocks and subsequent removal and recovery of usable hydrocarbons. I do. According to at least one embodiment, a method is provided for removing sulfur and nitrogen compounds from a hydrocarbon feedstock and using oxidized sulfur and oxidized nitrogen species in an FCC process.

  As used, the term "upgrade" or "upgraded" with respect to petroleum or hydrocarbon is lighter (ie, more methane, ethane and propane, etc.) than the original petroleum or hydrocarbon feed. Figure 2 shows a petroleum or hydrocarbon product having at least one of: (low carbon atoms), high API gravity, high middle distillate yield, low sulfur content, low nitrogen content or low metal content.

  FIG. 1 provides one embodiment for recovering hydrocarbons. The hydrocarbon recovery system 100 includes an oxidation reaction device 104, an extraction vessel 112, a solvent regeneration tower 116, a stripper 120, and an FCC device 130.

  According to at least one embodiment, a method is provided for recovering components from a hydrocarbon feedstock, particularly a hydrocarbon feedstock containing a sulfur-containing compound or a nitrogen-containing compound. The method includes feeding a hydrocarbon feed 102 to an oxidation reactor 104 where the hydrocarbon feed is contacted with an oxidant and a catalyst. The oxidant can be supplied to the oxidation reactor 104 via an oxidant supply line 106, and fresh catalyst can be supplied to the reactor via a catalyst supply line 108.

  According to at least one embodiment, hydrocarbon feedstock 102 can be any petroleum hydrocarbon and can include various impurities, such as elemental sulfur, compounds containing sulfur or nitrogen, or both. In some embodiments, the hydrocarbon feed 102 can be a diesel oil having a boiling point between about 150C and about 400C. Alternatively, the hydrocarbon feed 102 may have a boiling point of up to about 450 ° C, or up to about 500 ° C. Alternatively, the hydrocarbon feedstock 102 can have a boiling point between about 100C and about 500C. Optionally, the hydrocarbon feed 102 can have a boiling point up to about 600 ° C., or up to about 700 ° C., or in some embodiments, above about 700 ° C. According to at least one embodiment, the feed is present in a solid state, called residue, after distillation. In some embodiments, hydrocarbon feedstock 102 can include heavy hydrocarbons. As used, heavy hydrocarbons refer to hydrocarbons having a boiling point above about 360 ° C., and can include aromatic hydrocarbons and alkanes and alkenes. In general, in certain embodiments, the hydrocarbon feedstock 102 is a full range crude oil, a top crude oil, a product stream from a refinery, a product stream from a refinery steam cracking process, a liquid product recovered from liquefied coal, petroleum or tar sands. , Bitumen, oil shale, asphaltenes, hydrocarbon fractions such as diesel boiling in the range of about 180 to about 370 ° C and VGO boiling in the range of about 370 to about 520 ° C, and the like, and mixtures thereof.

  Sulfur compounds present in the hydrocarbon feedstock 102 include sulfides, disulfides and mercaptans and aromatic molecules such as thiophene, benzothiophene, dibenzothiophene and alkyl dibenzothiophenes, for example 4,6-dimethyldibenzothiophene. Aromatic compounds are typically present in higher boiling fractions than are found in lower boiling fractions.

硫黄酸化は制限された標的反応であり、その間に窒素酸化が起こることに留意されたい。２つの種類は塩基性窒素と中性窒素と考えられる。 The nitrogen-containing compound present in the hydrocarbon raw material 102 can include a compound having the following structure.

Note that sulfur oxidation is a limited target reaction during which nitrogen oxidation occurs. The two types are considered basic nitrogen and neutral nitrogen.

  According to at least one embodiment, the oxidation reactor 104 can be operated under mild conditions. More specifically, in certain embodiments, the oxidation reactor 104 can be maintained at a temperature from about 30C to about 350C, or from about 45C to about 60C. The operating pressure of the oxidation reactor 104 can be from about 1 bar to about 30 bar, or about 1 bar to about 15 bar, or about 1 bar to about 10 bar, or about 2 bar to about 3 bar. The residence time of the hydrocarbon feed within the oxidation reactor 104 may be from about 1 minute to about 120 minutes, or from about 15 minutes to about 90 minutes, or from about 5 minutes to about 90 minutes, or from about 5 minutes to about 30 minutes. Or about 30 minutes to about 60 minutes, preferably for a time sufficient to oxidize any sulfur or nitrogen compounds present in the hydrocarbon feed. According to at least one embodiment, the residence time of the hydrocarbon feedstock in the oxidation reactor 104 is from about 15 minutes to about 90 minutes.

又はそれらの組合せを含むことができる。 According to at least one embodiment, the oxidation reactor 104 is suitably configured to provide sufficient contact between the hydrocarbon feedstock 102 and the oxidant in the presence of a catalyst for oxidation of the sulfur-containing compound and the nitrogen-containing compound, It can be any reactor. Sulfur and nitrogen compounds present in the hydrocarbon feedstock 102 are oxidized in the oxidation reactor 104 to sulfones, sulfoxides, and oxidized nitrogen compounds, which can subsequently be removed by extraction or adsorption. Various types of reactors can be used. For example, the reactor can be a batch reactor, fixed bed reactor, ebullated bed reactor, lift reactor, fluidized bed reactor, slurry bed reactor, or a combination thereof. Other types of suitable reactors that can be used will be apparent to those skilled in the art and should be considered within the scope of various embodiments. Examples of suitable oxidized nitrogen compounds include pyridine-based compounds and pyrrole-based compounds. It is believed that the nitrogen atom is not oxidized directly, but rather is the carbon atom (s) adjacent to the nitrogen that is actually oxidized. Some examples of oxidized nitrogen compounds are the following compounds:

Or a combination thereof.

  According to at least one embodiment, the oxidant is supplied to the oxidation reactor 104 via an oxidant feed stream 106. Suitable oxidizing agents may include air, oxygen, hydrogen peroxide, organic peroxides, hydroperoxides, organic peracids, peroxo acids, nitrogen oxides, ozone, and the like, and combinations thereof. The peroxide can be selected from hydrogen peroxide and the like. The hydroperoxide can be selected from, for example, t-butyl hydroperoxide. The organic peracid can be selected from peracetic acid and the like.

  According to at least one embodiment, the molar ratio of oxidizer to sulfur present in the hydrocarbon feed is from about 1: 1 to about 50: 1, preferably from about 2: 1 to about 20: 1, more preferably about 4: 1. : 1 to about 10: 1. According to at least one embodiment, the molar feed ratio of oxidizing agent to sulfur can range from about 1: 1 to about 30: 1.

  According to at least one embodiment, the molar feed ratio of the oxidizing agent to the nitrogen compound can be from about 4: 1 to about 10: 1. According to at least one embodiment, the feedstock, such as South American crude, African crude, Russian crude, Chinese crude, or an intermediate refinery stream, such as coker, heat cracking, visbreaking, diesel, FCC cycle oil, etc., has more than sulfur. Of a nitrogen compound.

According to at least one embodiment, the catalyst can be supplied to the oxidation reactor 104 via a catalyst feed stream 108. The catalyst can be a homogeneous catalyst. The catalyst has the formula M _x O _y may comprise at least one metal oxide having the formula, M is a Group IVB of the Periodic Table, a metal selected from Group VB or VIB. The metal can include titanium, vanadium, chromium, molybdenum and tungsten. Molybdenum and tungsten are two particularly effective catalysts that can be used in various embodiments. In certain embodiments, the spent catalyst can be removed from the system along with the aqueous phase after the oxidation vessel (eg, when using an aqueous oxidant).

  According to at least one embodiment, the ratio of catalyst to oil is from about 0.1% to about 10% by weight, preferably from about 0.5% to about 5% by weight. In certain embodiments, the proportion is from about 0.5% to about 2.5% by weight. Alternatively, the proportion is from about 2.5% to about 5% by weight. Other suitable weight ratios of catalyst to oil will be apparent to those skilled in the art and should be considered within the scope of various embodiments.

  The catalyst present in the oxidation reactor 104 increases the rate of oxidation of various sulfur-containing and nitrogen-containing compounds in the hydrocarbon feedstock 102, reduces the amount of oxidizing agent required for the oxidation reaction, or Make both possible. In certain embodiments, the catalyst can be selective for oxidation of sulfur species. In other embodiments, the catalyst can be selective for oxidation of the nitrogen species.

  The oxidation reactor 104 produces an oxidized hydrocarbon stream 110 that can include hydrocarbons and oxidized sulfur-containing and oxidized nitrogen-containing species. The oxidized hydrocarbon stream 110 is provided to an extraction vessel 112 where the oxidized hydrocarbon stream and the oxidized sulfur-containing and oxidized nitrogen-containing species are contacted with an extraction solvent stream 137. Extraction solvent 137 can be a polar solvent, and in certain embodiments, can have a Hildebrand solubility value greater than about 19. In certain embodiments, when selecting a particular polar solvent to use for the extraction of oxidized sulfur-containing species and oxidized nitrogen-containing species, the choice may include, in some non-limiting examples, solvent density, boiling point, , Freezing point, viscosity and surface tension. Suitable polar solvents for use in the extraction step include acetone (Hildebrand value 19.7), carbon disulfide (20.5), pyridine (21.7), dimethyl sulfoxide (DMSO) (26.4), n-propanol (24.9), ethanol (26.2), n-butyl alcohol (28.7), propylene glycol (30.7), ethylene glycol (34.9), dimethylformamide (DMF) (24. 7), acetonitrile (30), methanol (29.7) and similar compositions or compositions having similar physical and chemical properties. In certain embodiments, acetonitrile and methanol are preferred due to their low cost, volatility and polarity. Methanol is a particularly suitable solvent for use in embodiments. In certain embodiments, the solvent comprising sulfur, nitrogen or phosphorus preferably has a relatively high volatility to ensure proper stripping of the solvent from the hydrocarbon feed.

  According to at least one embodiment, the extraction solvent is non-acidic. The use of acids is typically avoided due to the corrosive nature of the acids and the requirement that all equipment be specially designed for corrosive environments. In addition, acids such as acetic acid may be difficult to separate due to the formation of an emulsion.

  According to at least one embodiment, the extraction vessel 112 can be operated at a temperature from about 20C to about 60C, preferably from about 25C to about 45C, and even more preferably from about 25C to about 35C. The extraction vessel 112 can operate at a pressure of about 1 to about 10 bar, preferably about 1 to about 5 bar, more preferably about 1 to about 2 bar. In certain embodiments, the extraction vessel 112 operates at a pressure of about 2 to about 6 bar.

  According to at least one embodiment, the ratio of extraction solvent to hydrocarbon feed may be from about 1: 3 to about 3: 1, preferably from about 1: 2 to about 2: 1, more preferably about 1: 1. The contact time between the extraction solvent and the oxidized hydrocarbon stream 110 can be from about 1 second to about 60 minutes, preferably from about 1 second to about 10 minutes. In certain preferred embodiments, the contact time between the extraction solvent and the oxidized hydrocarbon stream 110 is less than about 15 minutes. In certain embodiments, the extraction vessel 112 is used to extend the contact time of the extraction solvent with the oxidized sulfur-containing hydrocarbon and oxidized nitrogen-containing hydrocarbon stream 110 or to increase the degree of mixing of the two solvents. Various means for causing this to occur can be included. The mixing means may include a mechanical stirrer or stirrer, tray or similar means.

  According to at least one embodiment, the extraction vessel 112 can include an extraction solvent, oxidizing species (eg, oxidized sulfur and nitrogen species originally present in the hydrocarbon feed 102) and traces of the hydrocarbon feed 102. A mixed stream 114 is produced, as well as an extracted hydrocarbon stream 118 that can include a hydrocarbon feed having a lower sulfur and nitrogen content as compared to the hydrocarbon feed 102.

  The mixed stream 114 is fed to a solvent regeneration tower 116 where the extraction solvent is recovered as a first recovered solvent stream 117 and contains a first residual stream 123 containing oxidized sulfur and oxidized nitrogen compounds. Can be separated from Optionally, the mixed stream 114 can be separated into a recovered hydrocarbon stream 124 in a solvent regeneration tower 116, wherein the recovered hydrocarbon stream 124 includes hydrocarbons present in the mixed stream 114 from the hydrocarbon feedstock 102. There is. The solvent regeneration tower 116 can be a distillation tower configured to separate the mixed stream 114 into a first recovered solvent stream 117, a first retentate stream 123, and a recovered hydrocarbon stream 124.

  The extracted hydrocarbon stream 118 can be provided to a stripper 120, which can be like a distillation column or a vessel designed to separate the hydrocarbon product stream from the residual extraction solvent. . In some embodiments, a portion of the mixed stream 114 can be supplied to the stripper 120 via line 122 and optionally combined with the extracted hydrocarbon stream 118. In some embodiments, the solvent regeneration tower 116 can produce a recovered hydrocarbon stream 124, which can be supplied to a stripper 120, where the recovered hydrocarbon stream 124 is separated from the extracted hydrocarbon stream 124. It can optionally be in contact with 118 or a portion of the mixed stream 114, which can be supplied to the stripper 120 via line 122.

  The stripper 120 separates the various streams supplied thereto into a removed oil stream 126 having a reduced sulfur and nitrogen content compared to the hydrocarbon feed 102 and a second recovered solvent stream 128.

  In some embodiments, the first recovered solvent stream 117 can be mixed with the second recovered solvent stream 128 and recycled to the extraction vessel 112. Optionally, a make-up solvent stream 132, which can include fresh solvent, can be provided to the extraction vessel 112 in conjunction with the first recovered solvent stream 117, the second recovered solvent stream 128, or both.

  A first residue stream 123, which contains oxidized compounds such as oxidized sulfur and nitrogen compounds and may also contain low concentrations of hydrocarbon-based materials, can be supplied to the FCC unit 130 where the (CC) ) Liquid product 136 is recovered. According to at least one embodiment, the oxidized sulfur compound, such as a sulfone, and the oxidized nitrogen compound are heavy hydrocarbons, for example, in the range of about 343C to about 524C, or in the range of about 360C to about 550C. Embedded in hydrocarbons with boiling points.

  According to various embodiments in which the first retentate stream 123 is delivered to the FCC unit 130, the first retentate stream 123 is contacted with the FCC feed stream 134 in the presence of a catalyst to catalytically crack the FCC feed stream 134. , Recover the liquid product 136 from the first residual stream 123. According to at least one embodiment, the catalyst can include high temperature solid zeolite active catalyst particles. According to at least one embodiment, the weight ratio of catalyst to FCC feedstream 134 is in the range of about 1 to about 15, and the pressure to form the suspension ranges from about 1 barg (gauge pressure) to about 200 barg. . Other suitable ratios of catalyst to FCC feed stream 134 and operating conditions will be apparent to those skilled in the art and should be considered within the scope of various embodiments.

  According to at least one embodiment, the suspension is then passed through a riser reaction zone or downer at a temperature (not shown) of from about 300 <0> C to less than about 650 <0> C to avoid thermal conversion of the feed stream 134, The FCC feedstream 134 is catalytically cracked, providing a hydrocarbon residence time of 0.1 seconds to about 10 minutes.

  According to at least one embodiment, the lower boiling components and the solid catalyst particles are then separated and recovered. At least a portion of the separated solid catalyst particles are formed in a regenerated catalyst 140 and a fluidized bed operated at conditions producing gaseous products 138 and liquid products 136 consisting essentially of carbon monoxide and carbon dioxide. , Regenerated by anhydrous oxygen containing gas. At least a portion of the regenerated catalyst is returned and combined with the FCC feed stream 134 (not shown).

According to at least one embodiment, the types of components contained in the FCC feed stream 134 may vary. FCC feed 134 may include, but are not limited to, VGO, atmospheric resid, demetalized oil, whole crude, cracked shale oil, liquefied coal, cracked bitumen, heavy coker gas oil and LCO, HCO and CSO It may include heavy FCC products. Table 1 shows representative yields from FCC units. As another example, FCC feed stream 134 delivered to FCC device 130 may have the properties shown in Table 2. Other suitable compounds that can be used in the FCC feed stream 134 delivered to the FCC unit 130 will be apparent to those skilled in the art and should be considered within the scope of various embodiments.

  Various catalysts can be used in the FCC device 130. According to at least one embodiment, the FCC catalyst particles comprise a metal selected from Group IVB, VI, VII, VIIIB, IB, IIB or a compound thereof, and comprise catalyst particles having a nominal diameter of less than 200 microns. Zeolite matrix. Other suitable types of catalysts that can be used in FCC unit 130 will be apparent to those skilled in the art and should be considered within the scope of various embodiments.

  According to at least one embodiment, the operating parameters of the FCC device 130 can be varied depending on the type of FCC feed stream 134 delivered to the FCC device 130. FCC unit 130 operates in a temperature range from about 400C to about 850C. According to another embodiment, the FCC device 130 can operate at a pressure ranging from about 1 barg to about 200 barg. According to another embodiment, the FCC device 130 can operate with a residence time ranging from about 0.1 seconds to about 3600 seconds. Other suitable operating parameters for the FCC unit 130 will be apparent to those skilled in the art and should be considered within the scope of various embodiments. The characteristics of the components recovered from the FCC unit 130 vary depending on the composition of the hydrocarbon FCC feed stream 134.

  FIG. 2 provides one embodiment for recovering hydrocarbons from a feed stream. The hydrocarbon recovery system 200 includes an oxidation reaction device 104, an extraction vessel 112, a solvent regeneration tower 116, a stripper 120, an FCC device 130, and a hydrotreating device 202.

  As described above with respect to the embodiment shown in FIG. 1, a first retentate stream 123 that includes oxidized compounds such as oxidized sulfur and nitrogen compounds and may also include low concentrations of hydrocarbon-based materials is supplied to the FCC unit 130. The FCC unit 130 collects liquid products 136 (including hydrocarbons). According to at least one embodiment, the oxidized sulfur compound, such as a sulfone, and the oxidized nitrogen compound are heavy hydrocarbons, for example, in the range of about 343C to about 524C, or in the range of about 360C to about 550C. Embedded in hydrocarbons with boiling points.

  According to various embodiments, as shown in FIG. 2, a first retentate stream 123 is contacted with an FCC feed stream 134 and subsequently fed through a hydrotreater 202 to reduce sulfur, nitrogen and aromatics. The mixture is hydrotreated. The resulting stream 204 exits the hydrotreater 202 and is fed to the FCC unit 130 in the presence of a catalyst to catalytically crack the resulting stream 204 to remove liquid from the first retentate stream 123 and the resulting stream 204. The product 136 is recovered. According to at least one embodiment, the catalyst can include high temperature solid zeolite active catalyst particles. According to at least one embodiment, the weight ratio of the catalyst to the resulting stream 204 ranges from about 1 to about 15 and the pressure to form the suspension ranges from about 1 barg to about 200 barg. Other suitable ratios of catalyst to resulting stream 204 and operating conditions will be apparent to those skilled in the art and should be considered within the scope of various embodiments.

  Optionally, the first residual stream 123 is sent directly to the FCC unit 130 and the FCC unit 130 contacts the first residual stream 123 with the FCC feed stream 134 in the presence of a catalyst to catalytically crack the FCC feed stream 134. Then, the liquid product 136 is recovered from the first residual stream 123.

  According to at least one embodiment, the suspension is then passed through a riser reaction zone or downer at a temperature (not shown) of from about 300 <0> C to less than about 650 <0> C to avoid thermal conversion of the feed stream 134, The FCC feedstream 134 is catalytically cracked, providing a hydrocarbon residence time of 0.1 seconds to about 10 minutes.

  According to at least one embodiment, the lower boiling components and the solid catalyst particles are then separated and recovered. At least a portion of the separated solid catalyst particles are formed in a regenerated catalyst 140 and a fluidized bed operated at conditions producing gaseous products 138 and liquid products 136 consisting essentially of carbon monoxide and carbon dioxide. , Regenerated by anhydrous oxygen containing gas. At least a portion of the regenerated catalyst is returned and combined with the FCC feed stream 134 (not shown).

  As further shown in FIG. 2, in some embodiments, at least a portion of the liquid product 136 is recycled to the oxidation reactor 104 via line 206, where the liquid product 136 is light cycle oil And at least one of heavy cycle oils. The liquid product 136 is rich in sulfur and can be desulfurized in an oxidative desulfurization step performed in the oxidation reactor 104.

  Various catalysts can be used in the FCC device 130. According to at least one embodiment, the FCC catalyst particles comprise a metal selected from Group IVB, VI, VII, VIIIB, IB, IIB or a compound thereof, and comprise catalyst particles having a nominal diameter of less than 200 microns. Zeolite matrix. Other suitable types of catalysts that can be used in FCC unit 130 will be apparent to those skilled in the art and should be considered within the scope of various embodiments.

  FIG. 3 provides one embodiment for recovering hydrocarbons from a feed stream. The hydrocarbon recovery system 300 includes an oxidation reaction device 104, an extraction vessel 112, a solvent regeneration tower 116, a stripper 120, an FCC device 130, a hydrotreating device 302, and an adsorption tower 306.

  As shown in FIG. 3, in one embodiment, a reject oil stream 126 can be provided to an adsorption tower 306 where the reject oil stream 126 remains in the hydrocarbon product stream after the oxidation and solvent extraction steps. Can be contacted with one or more adsorbents designed to remove one or more of various impurities such as sulfur-containing compounds, oxidized sulfur compounds, nitrogen-containing compounds, oxidized nitrogen compounds and metals. .

  According to various embodiments, the one or more adsorbents include activated carbon, silica gel, alumina, natural clay, silica-alumina, zeolites, and an affinity for removing oxidized sulfur and nitrogen compounds and other inorganic adsorbents. And fresh, used, regenerated or activated catalysts. In certain embodiments, the sorbent can include a polar polymer applied to or coating various high surface area support materials, such as silica gel, alumina, and activated carbon. Examples of polar polymers used to coat various support materials include polysulfone, polyacrylonitrile, polystyrene, polyester terephthalate, polyurethane, other similar polymer species that exhibit an affinity for oxidized sulfur species, and combinations thereof. Is mentioned.

  According to at least one embodiment, adsorption tower 306 can be operated at a temperature from about 20C to about 60C, preferably from about 25C to about 40C, and even more preferably from about 25C to about 35C. In certain embodiments, the adsorption tower can be operated at a temperature from about 10C to about 40C. In certain embodiments, the adsorption tower can be operated at a temperature above about 20 ° C., or at a temperature below about 60 ° C. The adsorption tower 306 can operate at a pressure of up to about 15 bar, preferably up to about 10 bar, and even more preferably from about 1 to about 2 bar. In certain embodiments, adsorption tower 306 can operate at a pressure of about 2 to about 5 bar. According to at least one embodiment, the adsorption tower can be operated at a temperature of about 25C to about 35C and a pressure of about 1 to about 2 bar. The weight ratio of removed oil stream to adsorbent is from about 1: 1 to about 20: 1, or about 10: 1.

  The adsorption tower 306 converts the feed to an extracted hydrocarbon product stream 308 having a very low sulfur content (eg, less than 15 ppmw sulfur) and a very low nitrogen content (eg, less than 10 ppmw nitrogen) and a second residue. Separate into logistics 310. The second retentate stream 310 contains oxidized sulfur-containing compounds and oxidized nitrogen-containing compounds and goes to the FCC unit 130 as shown in FIG. Optionally, stream 310 may be provided to FCC unit 130 in conjunction with first residual stream 123 and processed as described above. As described above with respect to FIG. 2, the first retentate stream 123 is contacted with the FCC feed stream 134 and subsequently fed through the hydrotreater 202 to hydrotreat the mixture to reduce sulfur, nitrogen and aromatics. . The resulting stream 204 exits the hydrotreater 202 and is fed to the FCC unit 130 in the presence of a catalyst to catalytically crack the resulting stream 204 to remove liquid from the first retentate stream 123 and the resulting stream 204. The product 136 is recovered. Further, optionally, the first residual stream 123 is directly sent to the FCC unit 130 and is brought into contact with the FCC feed stream 134 in the presence of a catalyst in the FCC unit 130 to catalytically decompose the FCC feed stream 134 to form a first crack. The liquid product 136 is recovered from the residual stream 123.

  The adsorbent can be regenerated by contacting the used adsorbent with a polar solvent such as methanol or acetonitrile to desorb the adsorbed oxidized compounds from the adsorbent. In certain embodiments, the adsorbed compounds can be easily removed using heat, removal gas, or both. Other suitable methods for removing adsorbed compounds will be apparent to those skilled in the art and should be considered within the scope of various embodiments.

[Example]
FIG. 4 shows a process flow diagram for an oxidative desulfurization (oxidation and extraction step) and FCC unit. Containers 10, 16, 20, and 25 are an oxidation container, an extraction container, a solvent recovery container, and an FCC container, respectively.

A hydrotreated straight run diesel containing 500 ppmw elemental sulfur, 0.28 wt% organic sulfur, and a density of 0.85 kilograms per liter (Kg / l) was oxidatively desulfurized. The reaction conditions were as follows.
Hydrogen peroxide: sulfur molar ratio: 4: 1
Catalyst: Molybdenum Mo (VI)
Reaction time: 30 minutes Temperature: 80 ° C
Pressure: 1 kilogram per square centimeter (Kg / cm ² )

  According to at least one embodiment, the FCC unit was operated at 518 ° C. at a catalyst to oil ratio of 5 to yield a 67 wt% conversion of the feed. In addition to the sulfone produced in the oxidation step, straight run VGO obtained from Arabic crude was used as a compounding component. The feed contained 2.65 wt% sulfur and 0.13 wt% microcarbon residue. The medium boiling point and 95% by weight boiling point of the raw materials were 408 ° C and 455 ° C, respectively.

The FCC conversion of the raw material was calculated as follows using the equation (1).
Conversion = dry gas + LPG + gasoline + coke (1)

The catalyst used was an equilibrium catalyst and was used without treatment. This catalyst has a surface area of 131 square meters per gram (m ² / g) and a pore volume of 0.1878 cubic centimeters per gram (cm ³ / g). The contents of nickel and vanadium are 96 ppmw and 407 ppmw, respectively. The following products were produced by the FCC method, and coke was deposited on the catalyst.

Dry gas H ₂ , CH ₄ , C ₂ H ₆ , C ₂ H ₄
Wet gas C _{3, C 4} compound (LPG)
Liquid product containing gasoline C ₅ -C ₁₂ hydrocarbons.
Typical final boiling point 221 ° C
Light cycle oil containing LCO C ₁₂ -C ₂₀ hydrocarbons.
Typical boiling point 221-343 ° C
HCO Heavy cycle oil coke containing C20 ₊ hydrocarbons with a minimum boiling point of 343 ° C. Solid carbonaceous deposit on catalyst. Typical C / H ratio = 1

The coke produced by the FCC process was 2.5% by weight of the treated raw material. The product yield is shown in Table 5.

According to one example, VGO was hydrodesulfurized over a Co-Mo / alumina catalyst to give a final product with 500 ppmw of sulfur. The conditions are summarized in Table 6.

Due to the rigor of the process, about 19% by weight of VGO is converted to fractions, naphtha and diesel. The product yield from the hydrotreater is summarized below. The hydrodesulfurized VGO is sent to an FCC unit for conversion. Because of the low levels of sulfur in the hydrodesulfurized VGO, the cycle oil produced has a low level of sulfur (i.e., the hydrotreated LCO has a sulfur level of 0.3-0.7% by weight). ), And then, as shown in Table 7, in the oxidation step, desulfurization is facilitated (in other words, the remaining sulfur compounds are in the form of alkyl derivatives of the dibenzothiophene molecule, which is the oxidative desulfurization , It is very easy to react, but it is very difficult to react in the hydrogenation treatment).

FIG. 5 shows the effect of hydrotreating on FCC performance. FIG. 5 illustrates that hydroprocessing can substantially affect gasoline quality (ie, the effect of hydrodesulfurization (HDS) levels on gasoline and SO _X emissions). As further shown in FIG. 5, at desulfurization levels above 90% by weight, gasoline sulfur content can be reduced to below the 100 ppmw level. SO _X emissions from the FCC can also be reduced to less than 500 ppmw.

Table 8 shows operating conditions of the hydrotreating apparatus according to various embodiments.

  It is believed that the methods and systems described herein increase the amount of aromatic sulfur, nitrogen compounds and liquid hydrocarbons from the aromatic stream by coupling the oxidative desulfurization and denitrification steps with a fluid catalytic cracker. . Further, it is believed that there is no efficient way to dispose of oxidation reaction by-products (ie, oxidized sulfur and nitrogen compounds). Embodiments provide a method of disposing of oxidized sulfur and nitrogen compounds without having to dispose of the compounds.

  While various embodiments have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the principles and scope. Accordingly, the scope should be determined by the following claims and their appropriate legal equivalents.

  The singular forms “a”, “an”, and “the” include plural referents unless the context clearly dictates otherwise.

  Arbitrarily or optionally means that the events or situations described below may or may not occur. The description includes when an event or situation occurs and when it does not.

  Ranges can be expressed as from about one particular value to about another particular value. When such a range is expressed, it is to be understood that alternative embodiments are from one particular value, or all other combinations, with all combinations within said range.

Claims (44)

A method for recovering a component from a hydrocarbon feedstock,
Supplying the hydrocarbon raw material containing a sulfur compound and a nitrogen compound to an oxidation reactor;
The hydrocarbon feedstock is selectively treated with a sulfur compound and a nitrogen compound present in the hydrocarbon feedstock to produce an oxidized hydrocarbon stream comprising hydrocarbons, oxidized sulfur compounds and oxidized nitrogen compounds. Contacting with an oxidizing agent in an oxidation reactor under conditions sufficient to oxidize to
Separating the hydrocarbons, the oxidized sulfur compounds and the oxidized nitrogen compounds in the oxidized hydrocarbon stream by solvent extraction with a polar solvent to produce an extracted hydrocarbon stream and a mixed stream Wherein said mixed stream comprises said polar solvent, said oxidized sulfur compound and said oxidized nitrogen compound, and wherein said extracted hydrocarbon stream has a lower concentration of sulfur compounds than said hydrocarbon feedstock. And a step having a nitrogen compound;
Separating the mixed stream into a first recovered polar solvent stream and a first retentate stream using a distillation column, wherein the first retentate stream is the oxidized sulfur compound and the oxidized nitrogen Comprising a compound,
Supplying the first residual stream to a fluid catalytic cracking device, wherein the supply comprises supplying the first residual stream through a hydrotreating device before supplying the first residual stream to the fluid catalytic cracking device. Further comprising providing a retentate stream, wherein the fluid catalytic cracker operates to catalytically crack the oxidized sulfur and the oxidized nitrogen to produce a regenerated catalyst and gaseous and liquid products. Enabling the recovery of hydrocarbons from the first residue stream.   Recirculating at least a portion of the liquid product to the oxidation reactor to selectively oxidize sulfur compounds in the liquid product, wherein a portion of the liquid product is a light cycle The method of claim 1, further comprising the step of including at least one of an oil and a heavy cycle oil. Feeding the extracted hydrocarbon stream to a stripper to produce a second recovered polar solvent stream and a stripped hydrocarbon stream; and the first recovered polar solvent stream and a second polar solvent Recycling a stream to an extraction vessel for separating said hydrocarbons, said oxidized sulfur compounds and said oxidized nitrogen compounds in said oxidized hydrocarbon stream. Or the method of any one of 2.   Recirculating a portion of said regenerated catalyst to said fluid catalytic cracking unit using a fluid catalytic cracking feed stream, said recycling comprising recovering said hydrocarbons from said first retentate stream; The method of any of claims 1 to 3, further comprising catalytic cracking of the fluid catalytic cracking feed stream with a portion of the regenerated catalyst.   The method according to any of the preceding claims, wherein the oxidizing agent is selected from the group consisting of air, oxygen, peroxide, hydroperoxide, ozone, nitrogen oxide compounds and combinations thereof. Contacting the hydrocarbon feed with an oxidizing agent is performed in the presence of a catalyst comprising a metal oxide having the formula M _x O _y , wherein M is from groups IVB, VB and VIB of the periodic table. The method according to any one of claims 1 to 5, which is a selected element.   7. The method of any of the preceding claims, wherein the sulfur compound comprises a sulfide, disulfide, mercaptan, thiophene, benzothiophene, dibenzothiophene, an alkyl derivative of dibenzothiophene, or a combination thereof.   The method according to any of the preceding claims, wherein the oxidation reactor is maintained at a temperature of about 20 to about 350C and a pressure of about 1 to about 10 bar.   The method according to any of the preceding claims, wherein the ratio of the oxidizing agent to the sulfur compound present in the hydrocarbon feed is from about 4: 1 to about 10: 1.   10. The method of any of the preceding claims, wherein the polar solvent has a Hildebrand value greater than about 19.   Wherein the polar solvent is selected from the group consisting of acetone, carbon disulfide, pyridine, dimethyl sulfoxide, n-propanol, ethanol, n-butanol, propylene glycol, ethylene glycol, dimethylformamide, acetonitrile, methanol and combinations thereof. The method according to claim 1.   The method according to claim 1, wherein the polar solvent is acetonitrile.   The method according to claim 1, wherein the polar solvent is methanol.   14. The method according to any of the preceding claims, wherein the solvent extraction is performed at a temperature of about 20C to about 60C and a pressure of about 1 to about 10 bar.   Supplying the extracted hydrocarbon stream to an adsorption tower, wherein the adsorption tower is filled with an adsorbent suitable for removing oxidized compounds present in the extracted hydrocarbon stream, 15. The method of claim 1, further comprising the step of producing a high purity hydrocarbon product stream and a second retentate stream by the adsorption tower, wherein the second retentate stream comprises a portion of the oxidized compound. The method according to any of the above.   15. The method of claim 14, further comprising providing the second residual stream to the fluid catalytic cracker.   16. The method of claim 15, wherein the sorbent is selected from the group consisting of activated carbon, silica gel, alumina, natural clay, silica-alumina, zeolite, and combinations thereof.   The adsorbent is a polymer-coated carrier, wherein the carrier has a high surface area and is selected from the group consisting of silica gel, alumina, silica-alumina, zeolite and activated carbon, and the polymer is polysulfone, polyacrylonitrile, polystyrene, polyester 16. The method of claim 15, wherein the method is selected from the group consisting of terephthalate, polyurethane, and combinations thereof.   Feeding the first retentate stream to the fluid catalytic cracking unit comprises: combining the first retentate stream with a fluid catalytic cracking feed stream in the presence of a catalyst to recover hydrocarbons from the first retentate stream. 19. The method according to any of the preceding claims, further comprising contacting to catalytically crack the fluidized catalytic cracking feed stream.   The fluid catalytic cracking feed stream is vacuum gas oil, atmospheric distillation residue, demetalized oil, whole crude oil, cracked shale oil, liquefied coal, cracked bitumen, heavy coker gas oil, light cycle oil, heavy cycle oil, clarified 20. The method of claim 19, comprising a slurry oil or a combination thereof. A method for recovering a component from a hydrocarbon feedstock,
Supplying the hydrocarbon raw material containing a sulfur compound and a nitrogen compound to an oxidation reactor;
The hydrocarbon feedstock is selectively treated with a sulfur compound and a nitrogen compound present in the hydrocarbon feedstock to produce an oxidized hydrocarbon stream comprising hydrocarbons, oxidized sulfur compounds and oxidized nitrogen compounds. Contacting with an oxidizing agent in an oxidation reactor under conditions sufficient to oxidize to
Separating the hydrocarbons, the oxidized sulfur compounds and the oxidized nitrogen compounds in the oxidized hydrocarbon stream by solvent extraction with a polar solvent to produce an extracted hydrocarbon stream and a mixed stream Wherein said mixed stream comprises said polar solvent, said oxidized sulfur compound and said oxidized nitrogen compound, and wherein said extracted hydrocarbon stream has a lower concentration of sulfur compounds than said hydrocarbon feedstock. And a step having a nitrogen compound;
Separating the mixed stream into a first recovered polar solvent stream and a first retentate stream using a distillation column, wherein the first retentate stream is the oxidized sulfur compound and the oxidized nitrogen Comprising a compound,
Supplying the first residual stream to a fluid catalytic cracking device, wherein the fluid catalytic cracking device acts to catalytically crack the oxidized sulfur and the oxidized nitrogen to form a regenerated catalyst and a gas. Producing a product and a liquid product to enable recovery of hydrocarbons from the first retentate stream;
Contacting a first retentate stream with a fluid catalytic cracking feed stream in the presence of a catalyst to catalytically crack the fluid catalytic cracking feed stream to recover carbohydrates from the first retentate stream;
Feeding said first residual stream in contact with a fluid catalytic cracking feed stream through a hydrotreating apparatus before feeding said first residual stream to said fluid catalytic cracking apparatus.   Recirculating at least a portion of the liquid product to the oxidation reactor to selectively oxidize sulfur compounds in the liquid product, wherein a portion of the liquid product is a light cycle 22. The method of claim 21, further comprising the step of including at least one of an oil and a heavy cycle oil. Feeding the extracted hydrocarbon stream to a stripper to produce a second recovered polar solvent stream and a stripped hydrocarbon stream; and the first recovered polar solvent stream and the second polarity. Recycling a solvent stream to an extraction vessel for separating the hydrocarbon, the oxidized sulfur compound and the oxidized nitrogen compound in the oxidized hydrocarbon stream. 23. The method according to 21 or 22.   Recirculating a portion of the regenerated catalyst to the fluidized catalytic cracker using the fluidized catalytic cracking feed stream, wherein the recirculation recovers the hydrocarbon from the first retentate stream; 24. The method of any of claims 21 to 23, further comprising catalytic cracking of the fluid catalytic cracking feed stream with a portion of the regenerated catalyst.   The method according to any of claims 21 to 24, wherein the oxidizing agent is selected from the group consisting of air, oxygen, peroxide, hydroperoxide, ozone, nitrogen oxide compounds and combinations thereof. Contacting the hydrocarbon feed with an oxidizing agent is performed in the presence of a catalyst comprising a metal oxide having the formula M _x O _y , wherein M is from groups IVB, VB and VIB of the periodic table. The method according to any of claims 21 to 25, wherein the method is a selected element.   27. The method of any one of claims 21 to 26, wherein the sulfur compound comprises a sulfide, disulfide, mercaptan, thiophene, benzothiophene, dibenzothiophene, an alkyl derivative of dibenzothiophene, or a combination thereof.   The method according to any of claims 21 to 27, wherein the oxidation reactor is maintained at a temperature of about 20 to about 350C and a pressure of about 1 to about 10 bar.   29. The method according to any of claims 21 to 28, wherein the ratio of the oxidizing agent to the sulfur compound present in the hydrocarbon feed is from about 4: 1 to about 10: 1.   30. The method of any of claims 21 to 29, wherein the polar solvent has a Hildebrand value greater than about 19.   Wherein the polar solvent is selected from the group consisting of acetone, carbon disulfide, pyridine, dimethyl sulfoxide, n-propanol, ethanol, n-butanol, propylene glycol, ethylene glycol, dimethylformamide, acetonitrile, methanol and combinations thereof. A method according to any of claims 21 to 30.   The method according to any one of claims 21 to 31, wherein the polar solvent is acetonitrile.   The method according to any one of claims 21 to 32, wherein the polar solvent is methanol.   The method according to any of claims 21 to 33, wherein the solvent extraction is performed at a temperature of about 20C to about 60C and a pressure of about 1 bar to about 10 bar.   Supplying the extracted hydrocarbon stream to an adsorption tower, wherein the adsorption tower is filled with an adsorbent suitable for removing oxidized compounds present in the extracted hydrocarbon stream, 35. The method of claim 21, further comprising: producing a high purity hydrocarbon product stream and a second retentate stream by the absorption tower, wherein the second retentate stream includes a portion of the oxidized compound. The method according to any of the above.   The method according to any of claims 21 to 35, further comprising the step of supplying the second residual stream to the fluid catalytic cracker.   37. The method according to claims 21 to 36, wherein the sorbent is selected from the group consisting of activated carbon, silica gel, alumina, natural clay, silica-alumina, zeolites and combinations thereof.   The adsorbent is a polymer-coated carrier, wherein the carrier has a high surface area and is selected from the group consisting of silica gel, alumina and activated carbon, and the polymer is polysulfone, polyacrylonitrile, polystyrene, polyester terephthalate, polyurethane, silica- 38. The method according to any of claims 21 to 37, wherein the method is selected from the group consisting of alumina, zeolites and combinations thereof.   The first retentate stream and the fluid catalytic cracking feed stream are present in a weight ratio to the first retentate stream and the fluid catalytic cracking feed stream ranging from about 1 to about 15. The method according to any one of 21 to 38.   The fluid catalytic cracking feed stream is vacuum gas oil, atmospheric distillation bottoms, demetalized oil, whole crude oil, cracked shale oil, liquefied coal, cracked bitumen, heavy coker gas oil, light cycle oil, heavy cycle oil, clarified 40. The method according to any of claims 21 to 39, comprising a slurry oil or a combination thereof.   41. The method of any of claims 21 to 40, wherein contacting the first retentate stream with a fluid catalytic cracking feed stream in the presence of a catalyst is performed in a temperature range from about 300 <0> C to about 650 <0> C.   42. The method of any of claims 21 to 41, wherein contacting the first retentate stream with a fluid catalytic cracking feed stream in the presence of a catalyst occurs with a residence time of about 0.1 seconds to about 10 minutes. Method. 43. The method of claim 41, further comprising: separating lower boiling components and catalyst particles from the first retentate stream and the fluid catalytic cracking feed stream; and regenerating at least a portion of the catalyst particles. The method according to any of the above.   The step of regenerating at least a portion of the catalyst particles comprises regenerating a portion of the catalyst particles in a fluidized bed operated at a condition that produces a gas product and a liquid product including carbon monoxide and carbon dioxide. 44. The method of claim 43, comprising contacting with a gas containing anhydrous oxygen.

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