JP6937832B2 - Oxidative desulfurization of oils and sulfone management using FCC - Google Patents

Description

Embodiments relate to methods and equipment for recovering sulfur and nitrogen from hydrocarbon raw materials. More specifically, embodiments relate to methods and equipment for the oxidative desulfurization and denitrification of hydrocarbon streams and the subsequent disposal of the resulting oxidized sulfur and nitrogen compounds.

Crude oil is the world's leading source of hydrocarbons used as fuel and petrochemical raw materials. At the same time, petroleum and petroleum-based products are also a major source of air and water pollution today. To address growing concerns about pollution caused by petroleum and petroleum-based products, many countries have allowed concentrations of certain pollutants in petroleum products, especially petroleum refining operations and fuels, such as the acceptable sulfur content of gasoline fuels. Has enforced strict regulations on petroleum and nitrogen content. Although the exact composition of natural petroleum or crude oil varies widely, all crude oils contain some measurable amounts of sulfur compounds and most crude oils also contain some measurable amounts of nitrogen compounds. In addition, crude oil may contain oxygen, but most crude oils have a low oxygen content. Generally, the concentration of sulfur in crude oil is less than about 5 weight percent (wt%), and most crude oil has a sulfur concentration in the range of about 0.5 to about 1.5% by weight. The nitrogen concentration of most crude oils is usually less than 0.2% by weight, but can be as high as 1.6% by weight. In the United States, gasoline fuels for automobiles are regulated to have a maximum total sulfur content of less than 10 million parts per weight (ppmw) of sulfur.

Crude oil is refined at refineries that produce transportation fuels and petrochemical raw materials. Typically, fuel for transport is produced by processing and mixing a distilled fraction obtained from crude oil to meet the specifications of a particular end application. Since most of the crude oils commonly available today contain high concentrations of sulfur, distilled fractions usually require desulfurization to obtain products that meet various performance specifications, environmental standards, or both. And.

Sulfur-containing organic compounds present in crude oil and the resulting refined fuels 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 oxygen acids, which can contribute to the emission of particulates.

One method for reducing particulate emissions involves the addition of various oxygenated fuel compounding compounds, compounds containing little or no carbon-carbon chemical bonds, such as methanol, dimethyl ether, or both. However, most of these compounds say that they can have high vapor pressures and are almost insoluble in diesel fuel, or can have poor ignitability as indicated by their cetane numbers. I'm suffering from points, or a combination of them.

Diesel fuels that have been chemically or hydrogenated to reduce the content of sulfur and aromatic compounds can reduce the lubricity of the fuel, resulting in fuel contact with the fuel under high pressure. Pumps, injectors and other moving parts can lead to excessive wear.

For example, intermediate distillates (ie, distillates that nominally boil in the range of about 180-370 ° C.) can be used as fuel or in compression ignition internal combustion engines (ie diesel engines). It can be used as a mixed component of fuel for internal combustion. The intermediate distillate fraction typically contains about 1-3% by weight sulfur. The permissible sulfur concentration of the intermediate distillate distillate has been reduced from 3000 ppmw level to 5-50 ppmw level in Europe and the United States since 1993.

To comply with increasingly stringent regulations on ultra-low sulfur fuels, refiners must produce fuels with much lower sulfur levels at refinery gates so that they can meet specifications after mixing. It doesn't become.

Conventional low pressure hydrodesulfurization (HDS) processes can be utilized to remove most of the sulfur from petroleum distillers to mix refinery transport fuels. However, these devices remove sulfur from compounds under mild conditions (ie, pressures up to about 30 bar) when the sulfur atoms are sterically obstructed, as in polycyclic aromatic sulfur compounds. Not efficient to remove. This is especially true when the sulfur heteroatom is blocked by two alkyl groups (eg, 4,6-dimethyldibenzothiophene). The blocked dibenzothiophene occupies low sulfur levels, such as 50-100 ppmw, because it is difficult to remove. Severe operating conditions (eg, high hydrogen partial pressure, high temperature or high catalytic capacity) must be utilized to remove sulfur from these persistent sulfur compounds. Increasing the hydrogen partial pressure can only be achieved by increasing the recirculating gas purity, or a new grassroots unit must be designed, which can be a very costly option. The use of harsh operating conditions typically results in reduced yields, reduced catalyst life cycles, and deterioration of product quality (eg, color) and is therefore typically required to be avoided. ..

However, customary methods for improving the quality of petroleum have various limitations and drawbacks. For example, hydrogenation methods typically require the supply of large amounts of hydrogen gas from an external source to achieve the desired quality improvement and conversion. These methods can also suffer from premature or rapid deactivation of the catalyst, as is usually the case during hydrogenation of heavy raw materials, or hydrogenation under harsh conditions. Therefore, it is necessary to regenerate the catalyst or add a new catalyst, which may lead to downtime of the process unit. Thermal methods often suffer from the production of large amounts of coke as a by-product and their limited ability to remove impurities such as sulfur and nitrogen. In addition, the thermal method requires specialized equipment suitable for harsh conditions (eg, high temperature and high pressure) and requires significant energy input, which increases complexity and cost.

Therefore, a process for improving the quality of hydrocarbon raw materials utilizing less severe conditions, which can also provide means for the recovery and disposal of usable sulfur and / or nitrogen compounds, especially hydrocarbon desulfurization, desulfurization. There is a need to provide a nitrogen or both process.

Embodiments provide methods and equipment for improving the quality of 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 a component from a hydrocarbon raw material, a step of supplying the hydrocarbon raw material to an oxidation reactor, wherein the hydrocarbon raw material contains a sulfur compound and a nitrogen compound. Sufficient conditions for the process to selectively oxidize the sulfur and nitrogen compounds present in the hydrocarbon feedstock to produce an oxidized hydrocarbon stream containing the hydrocarbon and the oxidized sulfur and the oxidized nitrogen compounds. Below, a method comprising contacting the hydrocarbon raw material with the oxidizing agent in an oxidation reactor is provided. This method is a step of separating a hydrocarbon in a hydrocarbon stream oxidized by solvent extraction using a polar solvent from an oxidized sulfur compound and an oxidized nitrogen compound to generate an extracted hydrocarbon stream and a mixed stream. Further, the step of producing is that the mixed stream contains a polar solvent, an oxidized sulfur compound and an oxidized nitrogen compound, and the extracted hydrocarbon stream contains a sulfur compound and a nitrogen compound having a lower concentration than the hydrocarbon raw material. include. This method is further a step of separating the mixed stream into a first recovered polar solvent stream and a first residual stream using a distillation column, in which the first residual stream is oxidized to an oxidized sulfur compound. A step of separating with a nitrogen compound and a step of supplying the first residual distribution to the fluid cracking unit, in which the cracking cracking unit catalytically cracks oxidized sulfur and oxidized nitrogen to produce a regeneration catalyst. It also includes a feeding step that operates to generate gaseous and liquid products and allow the hydrocarbons to be recovered from the first residual distillation. Further, this method is a step of recirculating at least a part of the liquid product to an oxidation reactor in order to selectively oxidize the sulfur compound in the liquid product. Includes a recirculating step involving at least one of a light cycle oil and a heavy cycle oil.

According to at least one embodiment, the method supplies an extracted hydrocarbon stream to the stripper to produce a second recovered polar solvent stream and a removed hydrocarbon stream, and in the oxidized hydrocarbon stream. It further comprises recirculating the first recovered polar solvent stream and the second polar solvent stream to the extraction vessel to separate the hydrocarbons, the oxidized sulfur compounds, and the oxidized nitrogen compounds.

According to at least one embodiment, the method is a step of recirculating a portion of the regeneration catalyst to the fluidized cracking unit using a fluidized cracking feed stream, the flow catalytic cracking feed stream being a portion of the regeneration catalyst. It further comprises a step of recirculating, further comprising a step of catalytically cracking using and recovering the hydrocarbon from the first residual stream.

According to at least one embodiment, the oxidizing agent is selected from the group consisting of air, oxygen, peroxides, hydroperoxides, ozone, nitrogen-oxidized compounds, and combinations thereof.

According to at least one embodiment, contacting the hydrocarbon feed and an oxidant comprises a metal oxide having the formula M _x O _y, M is a Group IVB of the periodic table is selected from VB and VIB It occurs in the presence of the elemental catalyst.

According to at least one embodiment, the sulfur compound comprises 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 20-150 ° C. and a pressure of about 100-about 1000 kPa ( about 1-about 10 bar ).

According to at least one embodiment , the ratio of the oxidant to the sulfur compound present in the hydrocarbon raw material is 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 protic solvent is from acetone, carbon disulfide, pyridine, dimethyl sulfoxide, n-propanol, ethanol, n-butanol, propylene glycol, ethylene glycol, dimethylformamide, acetonitrile, methanol and combinations thereof. Selected from the group of

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, solvent extraction is carried out at a temperature of about 20 ° C. to about 60 ° C. and a pressure of about 1 to about 10 bar.

According to at least one embodiment, the method is a step of supplying an extracted hydrocarbon stream to an adsorbent, which is an adsorbent suitable for removing oxidized compounds present in the extracted hydrocarbon stream. The adsorption tower further comprises a step of producing a high-purity hydrocarbon production flow and a second residual flow, and supplying the second residual flow containing a part of the oxidized compound.

According to at least one embodiment, the method further comprises supplying a second residual stream to the fluid catalytic cracking unit.

According to at least one embodiment, the adsorbent 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 adsorbent is a polymer coated support, the support having a large surface area, selected from the group consisting of silica gel, alumina, silica-alumina, zeolite, and activated carbon, where the polymer is polysulfone. , Polyacrylonitrile, polystyrene, polyester terephthalate, polyurethane and combinations thereof.

According to at least one embodiment, supplying the first residual stream to the fluidized contact cracking unit causes the first residual stream to come into contact with the fluidized catalytic cracking supply stream in the presence of a catalyst to create a fluidized catalytic cracking supply stream. It further comprises recovering hydrocarbons from the first residual stream by catalytic cracking.

According to at least one embodiment, the fluid contact decomposition feed stream is depressurized gas oil, atmospheric residual oil, demetallized oil, whole crude oil, cracked shale oil, liquefied coal, cracked bitumen, heavy coker light oil, light cycle oil, heavy. Includes quality cycle oils, clarified slurry oils, or combinations thereof.

According to another embodiment, a method of recovering a component from a hydrocarbon raw material, a step of supplying the hydrocarbon raw material to an oxidation reactor, wherein the hydrocarbon raw material contains a sulfur compound and a nitrogen compound. Sufficient conditions for the process to selectively oxidize the sulfur and nitrogen compounds present in the hydrocarbon feedstock to produce an oxidized hydrocarbon stream containing the hydrocarbon and the oxidized sulfur and the oxidized nitrogen compounds. Below, a method comprising contacting the hydrocarbon raw material with the oxidizing agent in an oxidation reactor is provided. The method is a step of separating a hydrocarbon in a hydrocarbon stream oxidized by solvent extraction using a polar solvent from an oxidized sulfur compound and an oxidized nitrogen compound to generate an extracted hydrocarbon stream and a mixed stream. Further, the step of producing the mixed stream containing the polar solvent, the oxidized sulfur compound and the oxidized nitrogen compound, and the extracted hydrocarbon stream containing the sulfur compound and the nitrogen compound having a lower concentration than that of the hydrocarbon raw material. include. The method is further a step of separating the mixed stream into a first recovered polar solvent stream and a first residual stream using a distillation column, wherein the first residual stream is an oxidized sulfur compound and an oxidized nitrogen. A step of separating with a compound and a step of supplying the first residual distribution to the fluid cracking unit, in which the cracking cracking unit catalytically cracks oxidized sulfur and oxidized nitrogen to produce a regeneration catalyst as well. Includes a feeding step that operates to generate gaseous and liquid products and allow the hydrocarbons to be recovered from the first residual stream. Further, the method is a step of contacting the first residual stream with the fluidized cracking feed stream in the presence of a catalyst to catalytically crack the fluid cracking feed stream to recover hydrocarbons from the first residual stream, and a liquid. The step of recirculating at least a portion of the liquid product to an oxidation reactor in order to selectively oxidize the sulfur compounds in the product, some of the liquid products being light cycle oils and heavy cycles. It comprises a step of recirculating containing at least one of the oils.

According to at least one embodiment, the method supplies an extracted hydrocarbon stream to the stripper to produce a second recovered polar solvent stream and a removed hydrocarbon stream, and in the oxidized hydrocarbon stream. It further comprises recirculating the first recovered polar solvent stream and the second polar solvent stream to the extraction vessel to separate the hydrocarbons, the oxidized sulfur compounds, and the oxidized nitrogen compounds.

According to at least one embodiment, the method is a step of recirculating a portion of the regeneration catalyst to the fluidized cracking unit using a fluidized cracking feed stream, the flow catalytic cracking feed stream being a portion of the regeneration catalyst. It further comprises a recirculation step that further comprises a step of catalytically cracking using and recovering the hydrocarbon from the first residual stream.

According to at least one embodiment, the oxidizing agent is selected from the group consisting of air, oxygen, peroxides, hydroperoxides, ozone, nitrogen-oxidized compounds, and combinations thereof.

According to at least one embodiment, contacting the hydrocarbon feed and an oxidant comprises a metal oxide having the formula M _x O _y, M is a Group IVB of the periodic table is selected from VB and VIB It occurs in the presence of the elemental catalyst.

According to at least one embodiment, the sulfur compound comprises 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 350 ° C. and a pressure of about 1 to about 10 bar.

According to at least one embodiment, the ratio of the oxidizing agent to the sulfur compound present in the hydrocarbon raw material is 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 protic solvent is from acetone, carbon disulfide, pyridine, dimethyl sulfoxide, n-propanol, ethanol, n-butanol, propylene glycol, ethylene glycol, dimethylformamide, acetonitrile, methanol and combinations thereof. Selected from the group of

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, solvent extraction is carried out at a temperature of about 20 ° C. to about 60 ° C. and a pressure of about 1 bar to about 10 bar.

According to at least one embodiment, the method is a step of supplying an extraction hydrocarbon stream to the adsorption tower, which is an adsorbent suitable for removing the oxidized compounds present in the extraction hydrocarbon stream. The absorption tower further comprises a step of producing a high-purity hydrocarbon production stream and a second residual stream, the second residual stream containing a portion of the oxidized compound.

According to at least one embodiment, the method further comprises supplying a second residual stream to the fluid catalytic cracking unit.

According to at least one embodiment, the adsorbent 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 adsorbent is a polymer coated support, the support having a large surface area and selected from the group consisting of silica gel, alumina, and activated carbon, the polymer being polysulfone, polyacrylonitrile, polystyrene, It is selected from the group consisting of polyester terephthalates, polyurethanes, silica-alumina, zeolites, and combinations thereof.

According to at least one embodiment, the first residual stream and fluidized cracking feed stream are present in a weight ratio of about 1 to about 15 of the catalyst to the first residual log and fluid cracking feed stream.

According to at least one embodiment, the fluid contact decomposition feed stream is depressurized gas oil, atmospheric residual oil, demetallized oil, whole crude oil, cracked shale oil, liquefied coal, cracked bitumen, heavy coker light oil, light cycle oil, heavy. Includes quality cycle oils, clarified slurry oils, or combinations thereof.

According to at least one embodiment, contact of the first residual stream with the fluidized cracking feed stream in the presence of a catalyst occurs in the temperature range of about 300 ° C to about 650 ° C.

According to at least one embodiment, contact of the first residual stream with the fluidized cracking feed stream in the presence of a catalyst occurs in the range of residence time of about 0.1 seconds to about 10 minutes.

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

According to at least one embodiment, in a fluidized bed in which regeneration of at least a portion of the catalyst particles is operated under conditions that produce a regeneration catalyst and gaseous and liquid products containing carbon monoxide and carbon dioxide. It involves contacting some of the catalyst particles with an anhydrous oxygen-containing gas.

Attachments that form part of this specification provide a more detailed description of the methods and systems already briefly summarized so that the features and benefits of the disclosed methods and systems, as well as others that become apparent, can be understood in more detail. It may be done by referring to the embodiment shown in the drawings of. However, it should be noted that the drawings merely illustrate various embodiments and therefore should not be considered limiting in scope as they may include other valid embodiments as well. Throughout, similar numbers refer to similar elements and, when prime notation is used, indicate similar elements in alternative embodiments or locations.

A schematic diagram of an embodiment of a method for improving the quality of a hydrocarbon raw material is presented. A schematic diagram of an embodiment of a method for improving the quality of a hydrocarbon raw material is presented. A schematic diagram of an embodiment of a method for improving the quality of a hydrocarbon raw material is presented. A schematic diagram of the process described in the examples is presented.

While the detailed description below includes many specific details for illustrative purposes, one of ordinary skill in the art may recognize that many examples, modifications and modifications to the following details are within scope and spirituality. Understood. Accordingly, the various embodiments described and provided in the accompanying drawings are described without any loss of generality and without imposing restrictions on the scope of the claims.

Embodiments are the usual methods for improving the quality of hydrocarbon feedstocks and recovering compounds from hydrocarbon feedstocks, especially desulfurization, denitrification, or both of hydrocarbon feedstocks, and subsequent available hydrocarbons. Address known removal and recovery issues. According to at least one embodiment, there is provided a method of removing sulfur and nitrogen compounds from a hydrocarbon feedstock and using oxidized sulfur and nitrogen species in the FCC process.

As used, the term "improved" or "improved" for petroleum or hydrocarbons is lighter than the original crude oil or hydrocarbon raw material (ie, methane, ethane, and propane). Petroleum or hydrocarbon products with at least one of high API gravity, high intermediate distillate yield, low sulfur content, low nitrogen content, or low metal content). Point to.

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

According to at least one embodiment, a method for recovering a component from a hydrocarbon raw material, particularly a hydrocarbon raw material containing a sulfur-containing compound and a nitrogen-containing compound, is provided. This method involves feeding the hydrocarbon raw material 102 to the oxidation reactor 104, in which the hydrocarbon raw material is brought into contact with an oxidant and a catalyst. The oxidant can be supplied to the oxidation reactor 104 via the oxidant supply line 106 and the fresh catalyst can be supplied to the reactor via the catalyst supply line 108.

According to at least one embodiment, the hydrocarbon feedstock 102 can be any petroleum-based hydrocarbon and can contain various impurities such as elemental sulfur, compounds containing sulfur or nitrogen, or both. In certain embodiments, the hydrocarbon feedstock 102 can be diesel oil having a boiling point of about 150 ° C to about 400 ° C. Alternatively, the hydrocarbon raw material 102 can have a boiling point of up to about 450 ° C. or up to about 500 ° C. Alternatively, the hydrocarbon raw material 102 can have a boiling point of about 100 ° C to about 500 ° C. Optionally, the hydrocarbon raw material 102 can have a boiling point of up to about 600 ° C., or up to about 700 ° C., or in certain embodiments greater than about 700 ° C. According to at least one embodiment, the feedstock exists in a solid state called residue after distillation. In certain embodiments, the hydrocarbon feedstock 102 may contain heavy hydrocarbons. When used, heavy hydrocarbons refer to hydrocarbons having a boiling point above about 360 ° C. and may include aromatic hydrocarbons, as well as alkanes and alkenes. Generally, in certain embodiments, the hydrocarbon feedstock 102 is a full range of crude oil, topped crude oil, refinery-derived product streams, product streams from refined steam cracking processes, liquefied coal, petroleum or tar. Liquid products recovered from sand, bitumen, oil shale, asphaltene, hydrocarbon fractions such as diesel and vacuum gas oil boiling in the range of about 180-about 370 ° C and about 370-about 520 ° C, respectively, and theirs. You can choose from a mixture.

Sulfur compounds present in the hydrocarbon feedstock 102 may include sulfides, disulfides, and mercaptans, as well as aromatic molecules such as thiophene, benzothiophene, dibenzothiophene, and alkyldibenzothiophenes such as 4,6-dimethyldibenzothiophene. .. Aromatic compounds are typically more abundant in higher boiling point fractions than normally found in low boiling point 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つのタイプ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 may include a compound having the following structure.

Note that sulfur oxidation is a restricted 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 operate under mild conditions. More specifically, in certain embodiments, the oxidation reactor 104 can be maintained at a temperature of about 30 ° C to about 350 ° C, or about 45 ° C to about 60 ° C. The working pressure of the oxidation reactor 104 can be from about 1 bar to about 30 bar, or from about 1 bar to about 15 bar, or from about 1 bar to about 10 bar, or from about 2 bar to about 3 bar. The residence time of the hydrocarbon raw material in the oxidation reactor 104 is about 1 minute to about 120 minutes, or about 15 minutes to about 90 minutes, or about 5 minutes to about 90 minutes, or about 5 minutes to about 30 minutes, or It can be from about 30 minutes to about 60 minutes, preferably sufficient time to oxidize any sulfur or nitrogen compound present in the hydrocarbon feedstock. According to at least one embodiment, the residence time of the hydrocarbon raw material in the oxidation reactor 104 is between about 15 minutes and about 90 minutes.

またはそれらの組み合わせ。 According to at least one embodiment, the oxidation reactor 104 ensures sufficient contact between the hydrocarbon feedstock 102 and the oxidant in the presence of a catalyst to oxidize the sulfur-containing and nitrogen-containing compounds. It can be any reactor that is properly configured. The sulfur and nitrogen compounds present in the hydrocarbon feedstock 102 are oxidized to sulfone, sulfoxide, and oxidized nitrogen compounds in the oxidation reactor 104, 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, a fixed bed reactor, a boiling bed reactor, a lift-up reactor, a fluidized bed reactor, a slurry bed reactor, or a combination thereof. Other types of suitable reactors that can be used are apparent to those of skill in the art and should be considered within the scope of various embodiments. Examples of suitable oxidized nitrogen compounds may include pyridine-based compounds and pyrrole-based compounds. It is believed that the nitrogen atom is not directly oxidized, but rather it is the carbon atom next to the nitrogen that is actually oxidized. Some examples of oxidized nitrogen compounds may include the following compounds:

Or a combination of them.

According to at least one embodiment, the oxidant is supplied to the oxidation reactor 104 via the oxidant supply stream 106. Suitable oxidants 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 t-butyl hydroperoxide and the like. The organic peracid can be selected from peracetic acid and the like.

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

According to at least one embodiment, the molar feed ratio of oxidant to nitrogen compound can be from about 4: 1 to about 10: 1. According to at least one embodiment, the feedstock is, for example, South American crude oil, African crude oil, Russian crude oil, Chinese crude oil, and intermediate refined logistics such as coker, pyrolysis, bisbraking, gas oil, FCC cycle oil, etc. It can contain more nitrogen compounds than sulfur, such as.

According to at least one embodiment, the catalyst can be supplied to the oxidation reactor 104 via the catalyst supply stream 108. The catalyst can be a homogeneous catalyst. The catalyst may comprise at least one metal oxide having the formula M _x O _y, in this case M is, IVB of the Periodic Table, a metal selected from Group VB or VIB. The metal may 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 used catalyst can be eliminated 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 catalyst to oil ratio is from about 0.1% to about 10% by weight, preferably from about 0.5% to about 5% by weight. In certain embodiments, the ratio is from about 0.5% to about 2.5% by weight. Alternatively, this ratio is from about 2.5% to about 5% by weight. Other suitable weight ratios of catalyst to oil are 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 oxidation rate of various sulfur-containing compounds and nitrogen-containing compounds in the hydrocarbon raw material 102, reduces the amount of oxidizing agent required for the oxidation reaction, or both. To enable. In certain embodiments, the catalyst may be selective for the oxidation of sulfur species. In other embodiments, the catalyst may be selective for the oxidation of nitrogen species.

The oxidation reactor 104 produces an oxidized hydrocarbon stream 110, which can include hydrocarbons as well as oxidized sulfur-containing and oxidized nitrogen-containing species. The oxidized hydrocarbon stream 110 is supplied to the extraction vessel 112, where the oxidized hydrocarbon stream and the oxidized sulfur-containing and oxidized nitrogen-containing species come into contact with the extraction solvent stream 137. The extraction solvent 137 can be a polar solvent and, in certain embodiments, can have a value of Hildebrand solubility greater than about 19. In certain embodiments, when selecting a particular polar solvent for use in extracting oxidized sulfur-containing and oxidized nitrogen-containing species, the selection is, as a non-limiting example, solvent density, It can be based in part on boiling point, freezing point, viscosity, and surface tension. Suitable polar solvents for use in the extraction process 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), dimethyl formamide (DMF) (24) .7), acetonitrile (30), methanol (29.7), and similar compositions, or compositions with similar physical and chemical properties. In certain embodiments, acetonitrile and methanol are preferred because of their low cost, volatility, and polarity. Methanol is a solvent that is particularly suitable for use in embodiments. In certain embodiments, the solvent containing sulfur, nitrogen, or phosphorus is preferably relatively highly volatile to ensure proper removal of the solvent from the hydrocarbon feedstock.

According to at least one embodiment, the extraction solvent is non-acidic. The use of acids is usually avoided due to the corrosiveness of the acid and the requirement that all equipment be specially designed for corrosive environments. In addition, acids such as acetic acid can make separation difficult due to the formation of emulsions.

According to at least one embodiment, the extraction vessel 112 can operate at a temperature of about 20 ° C. to about 60 ° C., preferably about 25 ° C. to about 45 ° C., and even more preferably about 25 ° C. to about 35 ° C. .. 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 the extraction solvent to the hydrocarbon feedstock is about 1: 3 to about 3: 1, preferably about 1: 2 to about 2: 1, more preferably about 1: 1. obtain. The contact time between the extraction solvent and the oxidized hydrocarbon stream 110 can be between about 1 second and about 60 minutes, preferably between about 1 second and 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 increases the contact time between the extraction solvent and the oxidized sulfur-containing hydrocarbon and oxidized nitrogen-containing hydrocarbon stream 110, or a mixture of the two solvents. It may include various means for increasing. The mixing means may include a mechanical stirrer or stirrer, a tray, or similar means.

According to at least one embodiment, the extraction vessel 112 comprises an extraction solvent, an oxidized species (eg, an oxidized sulfur species and an oxidized nitrogen species originally present in the hydrocarbon raw material 102), and a trace amount of the hydrocarbon raw material. 102, and a mixed stream 114 capable of containing the extracted hydrocarbon stream 118, the extracted hydrocarbon stream 118 is a hydrocarbon feedstock with reduced sulfur and lower nitrogen content as compared to the hydrocarbon feedstock 102. Can include.

The mixed stream 114 is supplied to the solvent regeneration tower 116, where the extraction solvent can be recovered as the first recovery solvent stream 117 and separated from the first residual distribution 123 containing the oxidized sulfur compound and the oxidized nitrogen compound. .. Optionally, the mixed flow 114 can be separated into a recovered hydrocarbon flow 124 at the solvent regeneration tower 116, which can include the hydrocarbons present in the mixed flow 114 from the hydrocarbon raw material 102. The solvent regeneration column 116 may be a distillation column configured to separate the mixed stream 114 into a first recovered solvent stream 117, a first residual physical distribution 123, and a recovered hydrocarbon stream 124.

The extraction hydrocarbon stream 118 can be supplied to the stripper 120, which can be like a distillation column or a container designed to separate the hydrocarbon production stream from the residual extraction solvent. In certain embodiments, a portion of the mixed flow 114 can be fed to the stripper 120 via a line 122 and optionally combined with an extracted hydrocarbon flow 118. In certain embodiments, the solvent regeneration tower 116 can generate a recovered hydrocarbon stream 124, which can be supplied to the stripper 120, which optionally the recovered hydrocarbon stream 118 or It can be brought into contact with a portion of the mixed stream 114, which can be supplied to the stripper 120 via the line 122.

The stripper 120 separates the various streams supplied therein into a removal oil stream 126 and a second recovery solvent stream 128 having a reduced sulfur and nitrogen content compared to the hydrocarbon feedstock 102.

In certain embodiments, the first recovery solvent stream 117 can be mixed with the second recovery solvent stream 128 and recirculated to the extraction vessel 112. Optionally, a replenishment solvent stream 132, which can contain fresh solvent, can be mixed with the first recovery solvent stream 117, the second recovery solvent stream 128, or both and supplied to the extraction vessel 112. ..

The first residual distribution 123, which comprises an oxidized compound such as an oxidized sulfur compound and an oxidized nitrogen compound and can also contain a low concentration hydrocarbon-based material, can be supplied to the FCC unit 130. There, 136 liquid products (including hydrocarbons) can be recovered. According to at least one embodiment, the oxidized sulfur compound such as sulfone and the oxidized nitrogen compound are hydrocarbons having a boiling point in the range of about 343 ° C to about 524 ° C, or about 360 ° C to about 550 ° C. It is embedded in heavy hydrocarbons.

According to various embodiments in which the first residual physical distribution 123 is sent to the FCC unit 130, the first residual physical distribution 123 is brought into contact with the FCC supply stream 134 in the presence of a catalyst, and the liquid from the first residual physical distribution 123. The product 136 is contact-decomposed with the FCC supply stream 134 to recover. According to at least one embodiment, the catalyst may include high temperature solid zeolite active catalyst particles. According to at least one embodiment, at pressures in the range of about 1 barg (gauge pressure) to about 200 barg for forming suspensions, the weight ratio of catalyst to FCC feed stream 134 is in the range of about 1 to about 15. Is. Other suitable ratios and operating conditions of catalyst to FCC feed stream 134 are 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 between about 300 ° C. and less than about 650 ° C. (not shown) to avoid thermal conversion of the feed stream 134. Then, the FCC supply stream 134 is catalytically cracked while providing a hydrocarbon residence time of about 0.1 seconds to about 10 minutes.

According to at least one embodiment, the low boiling point component and the solid catalyst particles are then separated and recovered. At least a portion of the separated solid catalyst particles is a flow operated under conditions that produce a regeneration catalyst 140, a gaseous product 138 essentially consisting of carbon monoxide and carbon dioxide, and a liquid product 136. On the floor, it is regenerated with anhydrous oxygen-containing gas. At least a portion of the regenerated catalyst is returned and mixed with the FCC feed stream 134 (not shown).

According to at least one embodiment, the types of components contained in the FCC supply stream 134 can vary. The FCC feed stream 134 includes, as non-limiting examples, depressurized gas oil, atmospheric residual oil, demetallized oil, whole crude oil, cracked shale oil, liquefied coal, cracked bitumen, heavy coker light oil, and LCO, HCO and CSO. FCC heavy products may be included. Table 1 shows typical yields from FCC units. As another example, the FCC supply stream 134 sent to the FCC unit 130 can have the characteristics shown in Table 2. Other suitable compounds that can be used in the FCC supply stream 134 sent to the FCC unit 130 are apparent to those of skill in the art and should be considered within the scope of various embodiments.

Various types of catalysts can be used in the FCC unit 130. According to at least one embodiment, the FCC catalytic particles are metals selected from the IVB, VI, VII, VIIIB, IB, IIB, or compounds thereof, and have a nominal diameter of less than 200 microns. Includes a zeolite-based matrix with catalytic particles. Other suitable types of catalysts that can be used in the FCC unit 130 should be apparent to those of skill in the art and considered to be within the scope of various embodiments.

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

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

As described above with respect to the embodiment shown in FIG. 1, a first residual distribution which contains an oxidized compound such as an oxidized sulfur compound and an oxidized nitrogen compound and can also contain a low concentration hydrocarbon-based material. The 123 can be supplied to the FCC unit 130, where the liquid product (including hydrocarbons) 136 can be recovered. According to at least one embodiment, the oxidized sulfur compound such as sulfone and the oxidized nitrogen compound are hydrocarbons having a boiling point in the range of about 343 ° C to about 524 ° C, or about 360 ° C to about 550 ° C. It is embedded in heavy hydrocarbons.

According to various embodiments in which the first residual distribution 123 is sent to the FCC unit 130, the first residual distribution 123 is brought into contact with the FCC supply stream 134 in the presence of a catalyst, as shown in FIG. The liquid product 136 is contact-decomposed with the FCC supply stream 134 in order to recover the liquid product 136 from the first residual physical distribution 123. According to at least one embodiment, the catalyst may include high temperature solid zeolite active catalyst particles. According to at least one embodiment, at pressures in the range of about 1 barg to about 200 barg for forming suspensions, the weight ratio of catalyst to FCC feed stream 134 is in the range of about 1 to about 15. Other suitable ratios and operating conditions of catalyst to FCC feed stream 134 are 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 between about 300 ° C. and less than about 650 ° C. (not shown) to avoid thermal conversion of the FCC feed stream 134. Then, the feed stream 134 is catalytically cracked while providing a hydrocarbon residence time of about 0.1 seconds to about 10 minutes.

According to at least one embodiment, the low boiling point component and the solid catalyst particles are then separated and recovered. At least a portion of the separated solid catalyst particles is a flow operated under conditions that produce a regeneration catalyst 140, a gaseous product 138 essentially consisting of carbon monoxide and carbon dioxide, and a liquid product 136. On the floor, it is regenerated with anhydrous oxygen-containing gas. At least a portion of the regenerated catalyst is returned and mixed with the FCC feed stream 134 (not shown).

Further, as shown in FIG. 2, in certain embodiments, at least a portion of the liquid product 136 is returned to the oxidation reactor 104 via line 202 and recirculated, where the liquid product 136 is a light cycle oil. And contains at least one of the heavy cycle oils. The liquid product 136 is high in sulfur and can be desulfurized by the oxidative desulfurization process that takes place in the oxidation reactor 104.

Various types of catalysts can be used in the FCC unit 130. According to at least one embodiment, the FCC catalytic particles are metals selected from the IVB, VI, VII, VIIIB, IB, IIB, or compounds thereof, and have a nominal diameter of less than 200 microns. Includes a zeolite-based matrix with catalytic particles. Other suitable types of catalysts that can be used in the FCC unit 130 should be apparent to those of skill in the art and considered to be within the scope of various embodiments.

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

As shown in FIG. 3, in a particular embodiment, the removal oil stream 126 can be supplied to the adsorption tower 302, where the removal oil stream 126 is supplied with a sulfur-containing compound, an oxidized sulfur compound, a nitrogen-containing compound, and oxidation. It can be contacted with one or more adsorbents designed to remove the nitrogen compounds produced and one or more various impurities such as metals remaining in the hydrocarbon production stream after oxidation and solvent extraction steps.

According to various embodiments, one or more adsorbents can be activated carbon, silica gel, alumina, natural clay, silica-alumina, zeolites, and oxidized sulfur and oxidized nitrogen compounds and other inorganic adsorbents. It may include fresh, used, regenerated or restored catalysts that have an affinity for it. In certain embodiments, the adsorbent can include polar polymers that are applied to or coat various high surface area support materials such as silica gel, alumina, and activated carbon. Examples of polar polymers for use in coating various supporting materials include polysulfone, polyacrylonitrile, polystyrene, polyester terephthalate, polyurethane, other similar polymer species that show affinity for oxidized sulfur species, and The combination thereof can be mentioned.

According to at least one embodiment, the adsorption tower 302 can operate at a temperature of about 20 ° C. to about 60 ° C., preferably about 25 ° C. to about 40 ° C., and even more preferably about 25 ° C. to about 35 ° C. .. In certain embodiments, the adsorption tower can operate at a temperature of about 10 ° C. to 40 ° C. In certain embodiments, the adsorption tower can operate at temperatures above about 20 ° C. or below about 60 ° C. The adsorption tower 302 can operate at a pressure of up to about 15 bar, preferably up to about 10 bar, and even more preferably about 1-2 bar. In certain embodiments, the adsorption tower 302 can operate at a pressure of about 2 to about 5 bar. According to at least one embodiment, the adsorption tower can operate at a temperature of about 25 ° C. to about 35 ° C. and a pressure of about 1 to about 2 bar. The weight ratio of the removed oil stream to the adsorbent is about 1: 1 to about 20: 1, or about 10: 1.

The adsorption tower 302 feeds the feed with an extracted hydrocarbon product stream 304 having a very low sulfur content (eg, less than 15 ppmw sulfur) and a very low nitrogen content (eg, less than 10 ppmw nitrogen). It is separated into the residual physical distribution 306 of 2. The second residual physical distribution 306 contains an oxidized sulfur-containing compound and an oxidized nitrogen-containing compound, and can optionally be mixed with the first residual physical distribution 123 and supplied to the FCC unit 130 and processed as described above. .. The adsorbent can be regenerated by contacting the used adsorbent with a polar solvent such as methanol or acetonitrile to desorb the adsorbed oxidized compound from the adsorbent. In certain embodiments, heat, stripping gas, or both can also be used to facilitate the removal of adsorbed compounds. 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 oxidative desulfurization (oxidation and extraction steps) and FCC unit. Containers 10, 16, 20 and 25 are oxidation, extraction, solvent recovery and FCC containers, respectively.

Hydrogenated straight-run diesel containing 500 ppmw of sulfur element, 0.28 wt% organic sulfur and a density of 0.85 kilograms (Kg / l) per liter was oxidatively desulfurized. The reaction conditions were as follows.
Hydrogen peroxide: sulfur molar ratio: 4: 1
Catalyst: Molybdenum-based 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. with a catalyst to oil ratio of 5, which resulted in a conversion of 67% by weight of feedstock. In addition to the sulfone produced in the oxidation step, a straight-run vacuum gas oil derived from Arabian crude oil was used as a compounding component. The feedstock contained 2.65% by weight sulfur and 0.13% by weight microcarbon residue. The intermediate and 95% by weight boiling points of the feedstock were 408 ° C and 455 ° C, respectively.

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

The catalyst used was an equilibrium catalyst and was used as it was without any treatment. The catalyst has a surface area of 131 square meters (m ² / g) per gram and a pore volume of ^{0.1878 square centimeters (cm 3 / g) per gram.} The contents of nickel and vanadium are 96 ppmw and 407 ppmw, respectively. The FCC process produced the following products to deposit coke on the catalyst.

Dry gas H ₂ , CH ₄ , C ₂ H ₆ , C ₂ H ₄
Moist gas C _{3, C 4} compound (LPG)
Gasoline C _{5 to} C ₁₂ A liquid product containing hydrocarbons.
Typical final boiling point is 221 ° C
A light cycle oil containing hydrocarbons from LCO C _{12 to} C _20.
A typical boiling point is 221-343 ° C.
A solid carbonaceous deposit of a heavy cycle oil coke catalyst containing _{C 20} + hydrocarbons with a minimum HCO boiling point of 343 ° C. Typical C / H ratio = 1

The coke produced by the FCC process was 2.5% by weight of the processed feedstock. The product yields are shown in Table 5.

According to one example, the LCO boils in the same distillation range as the diesel used in the example, so the LCO was recirculated to the oxidation step. It should be noted that the FCC unit is designed to process 10,000 kg / hour of reduced gas oil for illustration purposes. The FCC unit can be designed in any capacity, as will be apparent to those skilled in the art and will be considered within the scope of various embodiments, and design changes will oxidize / extract to handle additional supplies. Can be done for the process. The mass balance is proportional to the amount of feedstock processed. The treatment steps, oxidation, extraction and FCC are shown in Tables 6-8, respectively.

The methods and systems described herein increase the amount of aromatic sulfur, nitrogen compounds, and liquid hydrocarbons from aromatic streams by linking oxidative desulfurization and denitrification processes with fluid catalytic cracking units. It is thought that it will cause. Moreover, it is believed that there is no efficient way to dispose of oxidation reaction by-products (ie, oxidized sulfur compounds and oxidized nitrogen compounds). The embodiment provides a method of disposing of oxidized sulfur compounds and oxidized nitrogen compounds without the need to dispose of the compounds.

Although the various embodiments have been described in detail, it should be understood that various modifications, replacements, and modifications can be made without departing from this principle and scope. Therefore, the scope should be determined by the appended claims and their appropriate legal equivalents.

The singular forms "a", "an" and "the" include a plurality of referents unless the context clearly indicates otherwise.

Optional or optional 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 occur.

The range can be expressed as approximately one particular value to approximately another specific value. When such a range is represented, it should be understood that other embodiments, along with all combinations within that range, are from one particular value to or from the other. ..

Claims (42)

A method of recovering components from hydrocarbon raw materials,
Wherein a hydrocarbon feed is feeding the oxidation reactor, wherein the hydrocarbon feedstock contains sulfur compounds and nitrogen compounds, as Engineering,
Conditions sufficient to selectively oxidize the sulfur compound and nitrogen compound present in the hydrocarbon raw material to generate an oxidized hydrocarbon stream containing the hydrocarbon and the oxidized sulfur compound and the oxidized nitrogen compound. In the step of bringing the hydrocarbon raw material into contact with the oxidizing agent in the oxidation reactor,
It is a step of separating the hydrocarbon in the oxidized hydrocarbon stream from the oxidized sulfur compound and the oxidized nitrogen compound by solvent extraction using a polar solvent to generate an extracted hydrocarbon stream and a mixed stream. The mixed stream contains the polar solvent, the oxidized sulfur compound and the oxidized nitrogen compound, and the extracted hydrocarbon stream contains a sulfur compound and a nitrogen compound having a concentration lower than that of the hydrocarbon raw material . as Engineering,
A step of separating the mixed stream into a first recovered polar solvent stream and a first residual stream using a distillation column, wherein the first residual stream is the oxidized sulfur compound and the oxidized nitrogen. and a compound as including engineering,
In the step of supplying the first residual logistics to the fluid cracking unit, the cracking cracking unit catalytically decomposes an oxidized sulfur compound and an oxidized nitrogen compound to generate a regeneration catalyst and gaseous and liquid products. operative to generate an object makes it possible to recover hydrocarbons from the first residue stream, as engineering, and to selectively oxidize the sulfur compounds of said liquid product, the liquid product a step of recycling at least a portion of an object to the oxidation reactor, a portion of the liquid product comprises at least one of the light cycle oil and heavy cycle oil, engineering as <br / > A method characterized by. The step of feeding the extracted hydrocarbon stream to the stripper to produce a second recovered polar solvent stream and a removed hydrocarbon stream, and the hydrocarbon in the oxidized hydrocarbon stream, the oxidized sulfur. A step of recirculating the first recovered polar solvent stream and the second polar solvent stream to the extraction vessel in order to separate the compound and the oxidized nitrogen compound.
The method according to claim 1, further comprising. A step of recirculating a part of the regeneration catalyst to the flow catalytic cracking unit using a fluidized cracking feed stream, wherein the fluidized cracking feed stream is catalytically cracked using a part of the regeneration catalyst. The method according to any one of claims 1 or 2, further comprising a step of recovering the hydrocarbon from the first residual cracking, further comprising a step of recirculating the hydrocarbon. The method according to any one of claims 1 to 3, wherein the oxidizing agent is selected from the group consisting of air, oxygen, peroxide, hydroperoxide, ozone, nitrogen-oxidized compounds, and combinations thereof. .. That the contacting with the oxidizing agent the hydrocarbon feedstock comprises a metal oxide having the formula M _x O _y, the presence of a catalyst an element M is Group IVB of the periodic table is selected from VB and VIB The method according to any one of claims 1 to 4, which occurs below. The method according to any one of claims 1 to 5, wherein the sulfur compound comprises a sulfide, a disulfide, a mercaptan, a thiophene, a benzothiophene, a dibenzothiophene, an alkyl derivative of dibenzothiophene, or a combination thereof. The oxidation reactor is maintained at a pressure of 2 0 to 3 50 ° C. temperature and 100～1000KPa, method according to any one of claims 1 to 6. The method according to any one of claims 1 to 7, wherein the ratio of the oxidant to the sulfur compound present in the hydrocarbon raw material is 4 : 1 to 10: 1. The method according to any one of claims 1 to 8, wherein the polar solvent has a hildebrant value greater than 19. The protic 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 any one of claims 1 to 9. The method according to any one of claims 1 to 10, wherein the polar solvent is acetonitrile. The method according to any one of claims 1 to 11, wherein the polar solvent is methanol. Wherein the solvent extraction is carried out at a temperature and 100~1000kPa pressure of 2 0 ℃ ~6 0 ℃, the method according to any one of claims 1 to 12. In the step of supplying the extracted hydrocarbon stream to the adsorption tower, the adsorption tower is charged with an adsorbent suitable for removing the oxidized compound present in the extracted hydrocarbon stream, and the adsorption tower is charged with an adsorbent suitable for removing the oxidized compound. 1. The method described in item 1. The method according to claim 14, further comprising a step of supplying the second residual physical distribution to the fluidized catalytic cracking unit. 14. The method of claim 14, wherein the adsorbent 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 support, the support having a large surface area and selected from the group consisting of silica gel, alumina, silica-alumina, zeolite, and activated carbon, wherein the polymer is polysulfone, polyacrylonitrile, polystyrene. It is selected from polyurethane and combinations thereof the method of claim 14. Supplying the first residual stream to the flow catalytic cracking unit causes the first residual stream to come into contact with the fluid catalytic cracking supply stream in the presence of a catalyst to catalytically crack the fluid cracking supply stream. The method according to any one of claims 1 to 17, further comprising recovering a hydrocarbon from the first residual physical distribution. Fluid contact decomposition supply flow is reduced pressure light oil, normal pressure residual oil, demetallized oil, total crude oil, decomposed shale oil, liquefied coal, decomposed bitumen, heavy coker light oil, light cycle oil, heavy cycle oil, clarified slurry oil. , Or a combination thereof, according to claim 18. A method of recovering components from hydrocarbon raw materials,
Wherein a hydrocarbon feed is feeding the oxidation reactor, wherein the hydrocarbon feedstock contains sulfur compounds and nitrogen compounds, as Engineering,
Conditions sufficient to selectively oxidize the sulfur compound and nitrogen compound present in the hydrocarbon raw material to generate an oxidized hydrocarbon stream containing the hydrocarbon and the oxidized sulfur compound and the oxidized nitrogen compound. In the step of bringing the hydrocarbon raw material into contact with the oxidizing agent in the oxidation reactor,
It is a step of separating the hydrocarbon in the oxidized hydrocarbon stream from the oxidized sulfur compound and the oxidized nitrogen compound by solvent extraction using a polar solvent to generate an extracted hydrocarbon stream and a mixed stream. The mixed stream contains the polar solvent, the oxidized sulfur compound and the oxidized nitrogen compound, and the extracted hydrocarbon stream contains a sulfur compound and a nitrogen compound having a concentration lower than that of the hydrocarbon raw material . as Engineering,
A step of separating the mixed stream into a first recovered polar solvent stream and a first residual stream using a distillation column, wherein the first residual stream is the oxidized sulfur compound and the oxidized nitrogen. and a compound as including engineering,
In the step of supplying the first residual logistics to the fluid cracking unit, the fluid cracking unit catalytically decomposes the oxidized sulfur compound and the oxidized nitrogen compound to generate a regeneration catalyst and gaseous and gaseous. It operates to allow the to produce a liquid product to recover hydrocarbons from the first residue stream, as Engineering,
A step of contacting the first residual stream with a fluidized cracking feed stream in the presence of a catalyst to catalytically crack the fluid cracking supply stream to recover hydrocarbons from the first residual stream, and the liquid. A step of recirculating at least a portion of the liquid product to the oxidation reactor in order to selectively oxidize the sulfur compound in the product, wherein the portion of the liquid product is a light cycle oil and. wherein the extent of at least 1 Tsuo含free Engineering of heavy cycle oil. The step of feeding the extracted hydrocarbon stream to the stripper to produce a second recovered polar solvent stream and a removed hydrocarbon stream, and the hydrocarbon in the oxidized hydrocarbon stream, the oxidized sulfur. A step of recirculating the first recovered polar solvent stream and the second polar solvent stream to the extraction vessel in order to separate the compound and the oxidized nitrogen compound.
The method according to claim 20, further comprising. A step of recirculating a part of the regeneration catalyst to the flow catalytic cracking unit using the fluidized catalytic cracking supply stream, wherein the fluidized cracking feed stream is catalytically cracked using a part of the regeneration catalyst. It further characterized the step of recovering the hydrocarbon from the first residue stream, the method according to any one of claims 20-21. The method according to any one of claims 20 to 22, wherein the oxidizing agent is selected from the group consisting of air, oxygen, peroxide, hydroperoxide, ozone, nitrogen-oxidized compounds, and combinations thereof. .. That the contacting with the oxidizing agent the hydrocarbon feedstock comprises a metal oxide having the formula M _x O _y, the presence of a catalyst an element M is Group IVB of the periodic table is selected from VB and VIB The method of any one of claims 20-23, which occurs below. The method according to any one of claims 20 to 24, wherein the sulfur compound comprises a sulfide, a disulfide, a mercaptan, a thiophene, a benzothiophene, a dibenzothiophene, an alkyl derivative of dibenzothiophene, or a combination thereof. The oxidation reactor is maintained at a pressure of 2 0 to 3 50 ° C. temperature and 100～1000KPa, method according to any one of claims 20 to 25. The method according to any one of claims 20 to 26, wherein the ratio of the oxidant to the sulfur compound present in the hydrocarbon raw material is 4 : 1 to 10: 1. The method according to any one of claims 20 to 27, wherein the polar solvent has a hildebrant value greater than 19. The protic 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 any one of claims 20 to 28. The method according to any one of claims 20 to 29, wherein the polar solvent is acetonitrile. The method according to any one of claims 20 to 30, wherein the polar solvent is methanol. Wherein the solvent extraction is carried out at a pressure of temperature and 100~1000kPa of 2 0 ℃ ~6 0 ℃, the method according to any one of claims 20 to 31. In the step of supplying the extracted hydrocarbon stream to the adsorption tower, the adsorption tower is charged with an adsorbent suitable for removing the oxidized compound present in the extracted hydrocarbon stream, and the absorption is carried out. 20. The method according to any one item. 33. The method of claim 33, further comprising a step of supplying the second residual physical distribution to the fluidized catalytic cracking unit. 33. The method of claim 33, wherein the adsorbent is selected from the group consisting of activated carbon, silica gel, alumina, natural clay, silica-alumina, zeolites, and combinations thereof. Wherein the adsorbent is a polymer-coated support, said support having a large surface area, silica gel, is selected alumina, and from the group consisting of activated carbon, the polymer is polysulfone, polyacrylonitrile, polystyrene, Polyurethane, silica - 33. The method of claim 33, selected from the group consisting of alumina, zeolite, and combinations thereof. Any of claims 20 to 36, wherein the first residual physical distribution and the fluidized catalytic cracking supply stream are present in a weight ratio of 1 to 15 between the catalyst and the first residual physical distribution and the fluidized catalytic cracking supply stream. The method described in item 1. The fluidized contact cracking feed stream is decompressed gas oil, atmospheric residual oil, demetallized oil, whole crude oil, cracked shale oil, liquefied coal, cracked bitumen, heavy coker light oil, light cycle oil, heavy cycle oil, clarified slurry. The method of any one of claims 20-37, comprising oil, or a combination thereof. Thereby the said first residue stream and fluid catalytic cracking feed stream contacted in the presence of a catalyst occurs at a range of temperature of 3 00 ℃ ~6 50 ℃, according to any one of claims 20-38 the method of. The contact of the first residual stream with the fluidized cracking feed stream in the presence of a catalyst is 0 . The method according to any one of claims 20 to 39, which occurs with a residence time of 1 second to 10 minutes. The catalyst contains solid catalyst particles
10. The method described in item 1. In a fluidized bed in which regeneration of at least a portion of the catalyst particles is actuated under conditions that produce a regeneration catalyst and a gaseous product containing carbon monoxide and carbon dioxide, and a liquid product, the catalyst particles. 41. The method of claim 41, comprising contacting a portion of the above with an anhydrous oxygen-containing gas.

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