Process for oxidative desulfurization and sulfone management by gasification

Abstract

Embodiments provide a method including: supplying the hydrocarbon feedstock to an oxidation reactor, where the hydrocarbon feedstock is oxidized in the presence of a catalyst to selectively oxidize sulfur compounds present in the hydrocarbon feedstock; separating the hydrocarbons and the oxidized sulfur compounds by solvent extraction; collecting a residue stream that includes oxidized sulfur compounds; supplying the residue stream to a gasifier to produce a syngas stream and a hydrogen sulfide stream; supplying the extracted hydrocarbon stream to a stripper to produce a stripped oil stream, which is then supplied to an adsorption column, such that the adsorption column can produce a high purity hydrocarbon product stream, a second residue stream, and a spent adsorbent stream, the spent adsorbent stream containing another portion of the oxidized compounds; and supplying the spent adsorbent stream to the gasifier to produce additional syngas for the syngas stream, thereby disposing of the adsorbent.

Claims

1. A method of upgrading a hydrocarbon feedstock, the method comprising the steps of: supplying the hydrocarbon feedstock to an oxidation reactor, the hydrocarbon feedstock comprising sulfur compounds; contacting the hydrocarbon feedstock with an oxidant in the presence of a catalyst in the oxidation reactor under conditions sufficient to selectively oxidize sulfur compounds present in the hydrocarbon feedstock to produce an oxidized hydrocarbon stream that comprises hydrocarbons and oxidized sulfur compounds; separating the hydrocarbons and the oxidized sulfur compounds in the oxidized hydrocarbon stream by solvent extraction with a non-acidic polar organic solvent, the non-acidic polar organic solvent being dimethylformamide, to produce an extracted hydrocarbon stream and a mixed stream, the mixed stream comprising the non-acidic polar organic solvent and the oxidized sulfur compounds, wherein the extracted hydrocarbon stream has a lower concentration of sulfur compounds than the hydrocarbon feedstock; separating the mixed stream using a distillation column into a first recovered non-acidic polar organic solvent stream and a first residue stream; supplying the first residue stream to a gasifier to produce a syngas stream and a hydrogen sulfide stream; supplying the extracted hydrocarbon stream to a stripper to produce a second recovered non-acidic polar organic solvent stream and a stripped oil stream; recycling the first recovered non-acidic polar organic solvent stream and the second non-acidic polar organic solvent stream to an extraction vessel for the step of separating the hydrocarbons and the oxidized sulfur compounds in the oxidized hydrocarbon stream; supplying the stripped oil stream to an adsorption column, the adsorption column being charged with an adsorbent suitable for the removal of oxidized compounds present in the stripped oil stream, the adsorption column producing a high purity hydrocarbon product stream a second residue stream, the second residue stream containing a portion of the oxidized compounds, and a spent adsorbent stream, the spent adsorbent stream containing another portion of the oxidized compounds; and supplying the spent adsorbent stream to the gasifier to produce additional syngas for the syngas stream, thereby disposing of the adsorbent.

2. The method of claim 1, wherein the spent adsorbent stream is one of continuously or intermittently supplied to the gasifier.

3. The method of claim 1, wherein the adsorbent comprises one of a carbon-based adsorbent or a non-carbon based adsorbent.

4. The method of claim 3, wherein, when the adsorbent is the carbon-based adsorbent, the gasification of the spent adsorbent stream produces syngas with no ash.

5. The method of claim 3, wherein, when the adsorbent is the non-carbon-based adsorbent, the spent adsorbent acts as a slag material to cool reactor walls of the gasifier and the gasification of the spent adsorbent produces syngas with ash.

6. The method of claim 1, wherein the oxidant is selected from the group consisting of air, oxygen, ozone, nitrous oxide, peroxides, hydroperoxides, organic peracids, and combinations thereof.

7. The method of claim 1, wherein the oxidation reactor catalyst is a metal oxide having the formula M.sub.xO.sub.y, wherein M is an element selected from Groups IVB, VB, and VIB of the periodic table.

8. The method of claim 1, wherein the oxidation reactor is maintained at a temperature of between about 20 and 150 C. and at a pressure of between about 1-10 bars.

9. The method of claim 1, wherein the ratio of the oxidant to sulfur compounds present in the hydrocarbon feedstock is between about 4:1 and 10:1.

10. The method of claim 1, wherein the non-acidic polar organic solvent has a Hildebrandt value of greater than about 19.

11. The method of claim 1, wherein the solvent extraction is conducted at a temperature of between about 20 C. and 60 C. and at a pressure of between about 1-10 bars.

12. The method of claim 1, further comprising supplying the second residue stream to the gasifier.

13. The method of claim 1, wherein the adsorbent is selected from the group consisting of activated carbon, silica gel, alumina, natural clays, and combinations of the same.

14. The method of claim 1, wherein the adsorbent is a polymer coated support, wherein the support has a high surface area and is selected from the group consisting of silica gel, alumina, and activated carbon, and the polymer is selected from the group consisting of polysulfone, polyacrylonitrile, polystyrene, polyester terephthalate, polyurethane and combinations of the same.

15. A method of providing a desulfurized hydrocarbon stream, and a syngas stream, from a sulfur-containing hydrocarbon feedstock, the method comprising the steps of: supplying the hydrocarbon feedstock to an oxidation reactor, the hydrocarbon feedstock comprising sulfur compounds; catalytically oxidizing the sulfur compounds present in the hydrocarbon feedstock in the oxidation reactor with an oxidant in the presence of a catalyst under conditions sufficient to selectively oxidize at least a portion of the sulfur compounds present in the hydrocarbon feedstock to sulfones and produce an oxidized hydrocarbon stream comprising hydrocarbons and sulfones; selectively extracting the oxidized hydrocarbon stream with a non-acidic polar organic solvent, the non-acidic polar organic solvent being dimethylformamide, to produce an extracted hydrocarbon stream and a mixed stream, the mixed stream comprising the non-acidic polar organic solvent and the sulfones, wherein the extracted hydrocarbon stream has a lower sulfur concentration than the hydrocarbon feedstock; separating the mixed stream using a distillation column into a first recovered non-acidic polar organic solvent stream and a first residue stream comprising the sulfones; supplying the extracted hydrocarbon stream to a stripper, the stripper being operable to separate the extracted hydrocarbon stream into a stripped oil stream and a second recovered non-acidic polar organic solvent stream; recycling at least one of the first recovered non-acidic polar organic solvent stream and the second recovered non-acidic polar organic solvent stream to the extraction step for the step of separating the hydrocarbons and the oxidized sulfur compounds in the oxidized hydrocarbon stream; supplying the residue stream comprising sulfones to a gasifier and oxidizing the residue stream with an oxidant to produce a syngas stream and a hydrogen sulfide stream; supplying the stripped oil stream to an adsorption column, the adsorption column being charged with an adsorbent suitable for the removal of oxidized compounds present in the stripped oil stream, the adsorption column producing a high purity hydrocarbon product stream a second residue stream, the second residue stream containing a portion of the oxidized compounds, and a spent adsorbent stream, the spent adsorbent stream containing another portion of the oxidized compounds; and supplying the spent adsorbent stream to the gasifier to produce additional syngas for the syngas stream, thereby disposing of the adsorbent.

16. The method of claim 15, further comprising: supplying at least a portion of the syngas stream to a methanol production unit, wherein the syngas stream is catalytically converted into methanol; and supplying the methanol to the dimethylformamide non-acidic polar organic solvent for extraction of the oxidized hydrocarbon stream.

17. The method of claim 15, further comprising: supplying the hydrogen sulfide stream to a Claus unit, wherein the hydrogen sulfide is contacted with a catalyst at elevated temperatures to produce a solid elemental sulfur product.

18. The method of claim 15, wherein the oxidant supplied to the oxidation reactor and the gasifier are oxygen.

19. The method of claim 15, wherein the spent adsorbent stream is one of continuously or intermittently supplied to the gasifier.

20. The method of claim 15, wherein the adsorbent comprises one of a carbon-based adsorbent or a non-carbon based adsorbent.

21. The method of claim 20, wherein, when the adsorbent is the carbon-based adsorbent, the gasification of the spent adsorbent stream produces syngas with no ash.

22. The method of claim 20, wherein, when the adsorbent is the non-carbon-based adsorbent, the spent adsorbent acts as a slag material to cool reactor walls of the gasifier and the gasification of the spent adsorbent produces syngas with ash.

23. A method of providing a desulfurized hydrocarbon stream, and a syngas stream, from a sulfur-containing hydrocarbon feedstock, the method comprising the steps of: supplying the sulfur-containing hydrocarbon feedstock and an oxidant to an oxidation reactor, said oxidation reactor being charged with a catalyst; catalytically oxidizing the sulfur compounds present in the hydrocarbon feedstock under conditions sufficient to selectively oxidize at least a portion of the sulfur compounds present in the hydrocarbon feedstock to sulfones and produce an oxidized hydrocarbon stream comprising hydrocarbons and sulfones; selectively extracting the oxidized hydrocarbon stream with a non-acidic polar organic solvent, the non-acidic polar organic solvent being dimethylformamide, to produce an extracted hydrocarbon stream and a mixed stream, the mixed stream comprising the non-acidic polar organic solvent and the sulfones, wherein the extracted hydrocarbon stream has a lower sulfur concentration than the hydrocarbon feedstock; separating the mixed stream using a distillation column into a first recovered non-acidic polar organic solvent stream and a first residue stream comprising the sulfones; supplying the extracted hydrocarbon stream to a stripper, the stripper being operable to separate the extracted hydrocarbon stream into a stripped oil stream and a second recovered non-acidic polar organic solvent stream; recycling at least one of the first recovered non-acidic polar organic solvent stream and second recovered non-acidic polar organic solvent stream to the extraction step for the step of separating the hydrocarbons and the oxidized sulfur compounds in the oxidized hydrocarbon stream; supplying the stripped oil stream to an adsorber charged with an adsorbent to produce a high purity hydrocarbon product stream, a second residue stream comprising a portion of the oxidized compounds, and a spent adsorbent stream, the spent adsorbent stream containing another portion of the oxidized compounds, the adsorbent being suitable for the removal of oxidized compounds present in stripped oil stream; supplying the residue stream comprising sulfones to a gasifier and oxidizing the residue stream with an oxidant to produce a syngas stream and a hydrogen sulfide stream; supplying the hydrogen sulfide to a catalytically charged Claus reactor to produce elemental sulfur; and supplying the spent adsorbent stream to the gasifier to produce additional syngas for the syngas stream, thereby disposing of the adsorbent.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) So that the manner in which the features and advantages of the method and system disclosed, as well as others which will become apparent, may be understood in more detail, a more particular description of the method and system briefly summarized previously may be had by reference to the embodiments thereof which are illustrated in the appended drawings, which form a part of this specification. It is to be noted, however, that the drawings illustrate only various embodiments and are therefore not to be considered limiting of the scope as it may include other effective embodiments as well.

(2) FIG. 1 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.

(3) FIG. 2 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.

(4) FIG. 3 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.

(5) FIG. 4 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.

(6) FIG. 5 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.

(7) FIG. 6 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.

(8) FIG. 7 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.

(9) FIG. 8 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.

(10) FIG. 9 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock.

DETAILED DESCRIPTION

(11) Although the following detailed description contains many specific details for purposes of illustration, it is understood that one of ordinary skill in the art will appreciate that many examples, variations and alterations to the following details are within the scope and spirit. Accordingly, the exemplary embodiments described and provided in the appended figures are set forth without any loss of generality, and without imposing limitations, relating to the claims.

(12) Embodiments address known problems associated with conventional methods for upgrading a hydrocarbon feedstock, particularly the desulfurization, denitrogenation, or both, of hydrocarbon feedstocks, the subsequent removal and recovery of usable sulfur compounds, and the subsequent disposal of spent adsorbents and catalysts. According to at least one embodiment, there is provided a method for the removal of sulfur from a hydrocarbon feedstock and the use of oxidized sulfur-containing species in a gasification process to produce hydrogen, steam, and energy.

(13) As used, the terms upgrading or upgraded, with respect to petroleum or hydrocarbons refers to a petroleum or hydrocarbon product that is lighter (that is, has fewer carbon atoms, such as methane, ethane, propane, etc.), has a higher API gravity, higher middle distillate yield, lower sulfur content, lower nitrogen content, or lower metal content, than that of the original petroleum or hydrocarbon feedstock.

(14) FIG. 1 provides a schematic diagram of one embodiment of the method of upgrading a hydrocarbon feedstock. Hydrocarbon upgrading system 100 includes oxidation reactor 104, extraction vessel 112, solvent regeneration column 116, stripper 120 and gasifier 130, also referred to as a gasification reactor or a gasification unit.

(15) According to at least one embodiment, there is provided a method for the upgrading of a hydrocarbon feedstock, particularly a hydrocarbon feedstock that includes sulfur-containing compounds. In certain embodiments, the hydrocarbon feedstock can include nitrogen-containing species that can also be oxidized and removed in addition to or instead of the sulfur species. The method includes supplying hydrocarbon feedstock 102 to oxidation reactor 104, where the hydrocarbon feedstock is contacted with an oxidant and a catalyst. The oxidant can be supplied to oxidation reactor 104 via oxidant feed line 106 and fresh catalyst can be supplied to the reactor via catalyst feed line 108. In certain embodiments, the catalyst can be regenerated from this or another process, and supplied along with, or in the place of, fresh catalyst.

(16) According to at least embodiment, hydrocarbon feedstock 102 can be any petroleum-based hydrocarbon, and can include various impurities, such as elemental sulfur, compounds that include sulfur or nitrogen, or both. In certain embodiments, hydrocarbon feedstock 102 can be a diesel oil having a boiling point between about 150 C. and 400 C. Alternatively, hydrocarbon feedstock 102 can have a boiling point up to about 450 C., alternatively up to about 500 C. Alternatively, in certain embodiments, hydrocarbon feedstock 102 can have a boiling point between about 100 C. and 500 C. Optionally, hydrocarbon feedstock 102 can have a boiling point up to about 600 C., alternatively up to about 700 C., or, in certain embodiments, greater than about 700 C. In certain embodiments, hydrocarbon feedstock 102 can include heavy hydrocarbons. As used, heavy hydrocarbons refers to hydrocarbons having a boiling point of greater than about 360 C., and can include aromatic hydrocarbons and naphthenes, as well as alkanes and alkenes. Generally, in certain embodiments, hydrocarbon feedstock 102 can be selected from whole range crude oil, topped crude oil, product streams from oil refineries, product streams from refinery steam cracking processes, liquefied coals, liquid products recovered from oil or tar sand, bitumen, oil shale, asphaltene, and the like, and mixtures thereof.

(17) Exemplary sulfur compounds present in hydrocarbon feedstock 102 can include sulfides, disulfides, and mercaptans, as well as aromatic molecules such as thiophenes, benzothiophenes, dibenzothiophenes, and alkyl dibenzothiophenes, such as 4,6-dimethyldibenzothiophene. Aromatic compounds are typically more abundant in higher boiling fractions, than is typically found in the lower boiling fractions.

(18) As noted previously, in certain embodiments the hydrocarbon feedstock 102 can include nitrogen-containing compounds, and in certain embodiments the nitrogen-containing compounds can include basic and neutral nitrogen compounds, including indoles, carbazoles, anilines, quinolines, acridines, and the like.

(19) According to at least embodiment, oxidation reactor 104 can be operated at mild conditions. More specifically, in certain embodiments, oxidation reactor 104 can be maintained at a temperature of between about 20 C. and about 150 C., alternatively between about 30 C. and about 150 C., alternatively between about 30 C. and about 90 C., or between about 90 C. and about 150 C. In certain embodiments, the temperature is preferably between about 30 C. and about 75 C., more preferably between about 45 C. and 60 C. The operating pressure of oxidation reactor 104 can be between about 1 and 80 bars, alternatively between about 1 and 30 bars, alternatively between about 1 and 15 bars, and preferably between about 2 and 3 bars. The residence time of the hydrocarbon feedstock within oxidation rector 102 can be between about 1 and 180 minutes, alternatively between about 15 and 180 minutes, alternatively between about 15 and 90 minutes, alternatively between about 5 and 60 minutes, alternatively between about 60 and 120 minutes, alternatively between about 120 and 180 minutes, and is preferably for a sufficient amount of time for the oxidation of any sulfur or nitrogen compounds present in the hydrocarbon feedstock. In one embodiment, the residence time of the hydrocarbon feedstock within oxidation rector 104 is between about 15 and 45 minutes. For comparison, conventional hydrodesulfurization of diesel-type feedstocks are typically conducted under harsher conditions, for example, at temperatures of between about 330 and 380 C., pressures of between about 50 and 80 kilograms per square centimeters (Kg/cm.sup.2) and liquid hourly space velocity (LHSV) of between about 0.5 and 2 per hour (h.sup.1).

(20) Oxidation reactor 104 can be any reactor suitably configured to ensure sufficient contacting between hydrocarbon feedstock 102 and the oxidant, in the presence of a catalyst, for the oxidation of at least a portion of the sulfur- and nitrogen-containing compounds in the hydrocarbon feedstock 102. Suitable reactors for oxidation reactor 104 can include batch reactors, fixed bed reactors, ebbulated bed reactors, lifted reactors, fluidized bed reactors, slurry bed reactors, and the like. Certain sulfur- and nitrogen-containing compounds present in hydrocarbon feedstock 102 can be oxidized in oxidation reactor 104 to sulfones, sulfoxides, and various oxidized nitrogen compounds, all of which can be subsequently removed by extraction or adsorption. Exemplary oxidized nitrogen compounds can include pyridine and pyrrole-based compounds or pyridine-difuran compounds. Frequently, during oxidation, the nitrogen atom itself is not oxidized, but rather the compound is oxidized to a compound that is easy to separate from the remaining compounds.

(21) According to at least embodiment, the oxidant is supplied to oxidation reactor 104 via oxidant feed stream 106. Suitable oxidants can include air, oxygen, ozone, hydrogen peroxide, organic peroxides, hydroperoxides, organic peracids, peroxo acids, oxides of nitrogen, such as nitrous oxide, and the like, and combinations thereof. Exemplary peroxides can include hydrogen peroxide, and the like. Exemplary hydroperoxides can include t-butyl hydroperoxide, and the like. Exemplary organic peracids can include peracetic acid, and the like.

(22) According to at least embodiment, the mole ratio of oxidant to sulfur present in the hydrocarbon feedstock can be from about 1:1 to 100:1, preferably between about 1:1 and 30:1, more preferably between about 1:1 and 20:1.

(23) In certain other embodiments, such as in a hydrocarbon feedstock having a greater concentration of nitrogen than sulfur, for example, certain South American crude oils, certain African crude oils, certain Russian crude oils, certain Chinese crude oils, and certain intermediate refinery streams like coker, thermal cracking, visbreaking, FCC cycle oils, and the like, the mole ratio of oxidant to nitrogen present in the hydrocarbon feedstock can be from about 1:1 to 50:1, preferably between about 2:1 and 20:1, more preferably between about 4:1 and 10:1.

(24) According to at least embodiment, the catalyst can be supplied to oxidation reactor 104 via catalyst feed stream 108. The catalyst can include at least one metal oxide having the chemical formula M.sub.xO.sub.y, wherein M is a metal selected from groups IVB, VB, or VIB of the periodic table. Exemplary metals can include titanium, vanadium, chromium, molybdenum, and tungsten. Certain preferred metals include oxides of molybdenum and tungsten. In certain embodiments, such as the use of aqueous oxidants, spent catalyst can be removed from the system with the aqueous phase, after the oxidation vessel.

(25) According to at least one embodiment, the ratio of catalyst to oil is between about 0.1 wt % and about 10 wt %, preferably between about 0.5 wt % and about 5 wt %. In certain embodiments, the ratio is between about 0.5 wt % and about 2.5 wt %. Alternatively, the ratio is between about 2.5 wt % and about 5 wt %. Other suitable weight ratios of catalyst to oil will be apparent to those of skill in the art and are to be considered within the scope of the various embodiments.

(26) Catalyst present in oxidation reactor 104 can increase the rate of oxidation of the various sulfur- and nitrogen-containing compounds in hydrocarbon feedstock 102, thereby achieving completion of the reaction and oxidation of sulfur- and nitrogen-containing compounds in a shorter amount of time, and reducing the amount of oxidant necessary to achieve oxidation of the sulfur- and nitrogen-containing compounds. In certain embodiments, the catalyst can be selective toward the oxidation of sulfur-containing compounds. In accordance with various embodiments, the catalyst is selective to minimizing the oxidation of aromatic hydrocarbons present in the hydrocarbon feedstock.

(27) According to at least embodiment, the composition of spent oxidant will vary based upon what original oxidant is used in the process. For example, in embodiments wherein the oxidant is hydrogen peroxide, water is formed as a by-product of the oxidation reaction. In embodiments wherein the oxidant is an organic peroxide, alcohol is formed as a by-product of the oxidation reaction. By-products are typically removed during the extraction and solvent recovery steps.

(28) Oxidation reactor 104 produces oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream 110, which can include hydrocarbons and oxidized sulfur- and oxidized nitrogen-containing species. Oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream 110 is supplied to extraction vessel 112 where the oxidized sulfur- and oxidized nitrogen-containing hydrocarbon species present with hydrocarbons in hydrocarbon stream 110 can be contacted with extraction solvent stream 137. Extraction solvent 137 can be a polar solvent, and in certain embodiments, can have a Hildebrandt solubility value of greater than about 19. In certain embodiments, when selecting the particular polar solvent for use in extracting oxidized sulfur- and nitrogen-containing species, selection may be based upon, in part, solvent density, boiling point, freezing point, viscosity, and surface tension, as non-limiting examples. Exemplary polar solvents suitable for use in the extraction step can include acetone (Hildebrand value of 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 like compositions or compositions having similar physical and chemical properties. In certain embodiments, acetonitrile and methanol, due to their low cost, volatility, and polarity, are preferred. In certain embodiments, solvents that include sulfur, nitrogen, or phosphorous, preferably have a relatively high volatility to ensure adequate stripping of the solvent from the hydrocarbon feedstock.

(29) 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 acids, and the requirement that all equipment be specifically designed for a corrosive environment. In addition, the use of acids, such as acetic acid, can present difficulties in separation due to the formation of emulsions.

(30) According to at least embodiment, extraction vessel 112 can be operated at a temperature of between about 20 C. and 60 C., preferably between about 25 C. and 45 C., even more preferably between about 25 C. and 35 C. Extraction vessel 112 can operate at a pressure of between about 1 and 10 bars, preferably between about 1 and 5 bars, more preferably between about 1 and 2 bars. In certain embodiments, extraction vessel 112 operates at a pressure of between about 2 and 6 bars.

(31) According to at least embodiment, the ratio of the extraction solvent to hydrocarbon feedstock can be between about 1:3 and 3:1, preferably between about 1:2 and 2:1, more preferably about 1:1. Contact time between the extraction solvent and oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream 110 can be between about 1 second and 60 minutes, preferably between about 1 second and about 10 minutes. In certain preferred embodiments, the contact time between the extraction solvent and oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream 110 is less than about 15 minutes. In certain embodiments, extraction vessel 112 can include various means for increasing the contact time between the extraction solvent and oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream 110, or for increasing the degree of mixing of the two solvents. Means for mixing can include mechanical stirrers or agitators, trays, or like means.

(32) According to at least embodiment, extraction vessel 112 produces mixed stream 114 that can include extraction solvent, oxidized species (for example, the oxidized sulfur and nitrogen species that were originally present in hydrocarbon feedstock 102), and traces of hydrocarbon feedstock 102, and extracted hydrocarbon stream 118, which can include the hydrocarbon feedstock having a reduced sulfur and low nitrogen content, relative to hydrocarbon feedstock 102.

(33) Mixed stream 114 is supplied to solvent regeneration column 116 where extraction solvent can be recovered as first recovered solvent stream 117 and separated from first residue stream 123, which includes oxidized sulfur and nitrogen compounds. Optionally, mixed stream 114 can be separated in solvent regeneration column 116 into a recovered hydrocarbon stream 124, which can include hydrocarbons present in mixed stream 114 from hydrocarbon feedstock 102. Solvent regeneration column 116 can be a distillation column that is configured to separate mixed stream 114 into first recovered solvent stream 117, first residue stream 123, and recovered hydrocarbon stream 124.

(34) Extracted hydrocarbon stream 118 can be supplied to stripper 120, which can be a distillation column or like vessel designed to separate a hydrocarbon product stream from the residual extraction solvent. In certain embodiments, a portion of mixed stream 114 can be supplied to stripper 120 via line 122, and may optionally be combined with extracted hydrocarbon stream 118. In certain embodiments, solvent regeneration column 116 can produce recovered hydrocarbon stream 124, which can be supplied to stripper 120, where recovered hydrocarbon stream 124 can optionally be contacted with extracted hydrocarbon stream 118 or a portion of mixed stream 114, which can be supplied to stripper 120 via line 122.

(35) Stripper 120 separates the various streams supplied thereto into stripped oil stream 126, which includes hydrocarbons present in hydrocarbon feedstock 102 and has a reduced sulfur and nitrogen content relative thereto, and second recovered solvent stream 128.

(36) In certain embodiments, first recovered solvent stream 117 can be combined with second recovered solvent stream 128 and recycled to extraction vessel 112. Optionally, make-up solvent stream 132, which can include fresh solvent, can be combined with first recovered solvent stream 117, second recovered solvent stream 128, or both, and supplied to extraction vessel 112. Alternately, extraction vessel 112 can be supplied completely with a polar solvent recovered from stream 117, stream 128, or both, and supplied to extraction vessel 112.

(37) First residue stream 123, which includes oxidized compounds, such as oxidized sulfur and nitrogen compounds, and which can also include low concentrations of hydrocarbonaceous material, can be supplied to gasifier 130 where the first residue stream is converted to a stream comprising hydrogen, carbon monoxide, and steam, while producing recoverable energy. Specifically, oxidized compounds such as sulfones and sulfoxides are supplied to a gasifier or gasification unit (gasifier 130). Gasifier 130 can be an integrated unit that includes a reactor, an air separation unit, means for syngas quenching and cooling, a shift reactor, means for acid gas removal and recovery, and means for hydrogen recovery. Alternatively, air can be supplied by an air separation unit (not shown) associated with an alternate process. The reactor can include a pressure shell having a reaction zone, and can be bounded in part by a vertically oriented tubular membrane wall. The reaction zone can be a moving bed, fluidized bed, or entrained flow system. The tubular membrane wall can include one or more openings, and can include a slag deflector, optionally positioned above any of said openings. The reactor can include means for providing a cooling medium, such as providing an inlet end for supplying the cooling medium and an outlet end for used cooling medium.

(38) In certain embodiments, gasifier 130 can be operated at a temperature of greater than about 800 C., alternatively greater than about 1000 C., or alternatively between about 1200 C. and 1800 C. In certain embodiments, gasifier 130 is operated at a pressure of between about 10 and 125 bars, alternatively between about 30 and 100 bars, or alternatively between about 25 and 90 bars.

(39) According to at least one embodiment, oxidized sulfur-containing compounds present in the hydrocarbon feedstock, for example as sulfones, are collected as waste (first residue stream 123), supplied to gasifier 130, which converts hydrocarbon into syngas stream 134 (which includes CO+H.sub.2) and hydrogen sulfide stream 136. According to at least one embodiment, first residue stream 123 is contacted with oxygen stream 133 and a catalyst in a reaction zone of gasifier 130 to produce syngas stream 134 and hydrogen sulfide stream 136. Gasification produces no sulfur oxides or sulfur dioxides. First residue stream 123 can include small amounts of hydrocarbons, extraction solvent 137, or both. Oxidized compounds containing oxygen minimize the use of oxygen in the gasification process, thereby reducing the supply and overall consumption of pure oxygen in the gasifier.

(40) Syngas stream 134 can have an H.sub.2:CO ratio of between about 0.85:1 and 1.2:1, alternatively between about 0.85:1 and 1:1, alternatively between about 1:1 and 1.2:1. In certain embodiments, such as for embodiments where syngas stream 134 is supplied to a Fischer Tropsch process, the H.sub.2:CO ratio can be adjusted prior to supplying the syngas stream to an H.sub.2:CO ratio of between about 1.8:1 and 2.2:1, alternatively between about 1.9:1 and 2.1:1.

(41) Syngas stream 134 produced by gasifier 130 can be used to fuel an associated or ancillary chemical production process, such as a methanol synthesis unit, dimethyl ether synthesis unit, acetic acid synthesis unit, or like facility. Alternatively, syngas stream 134 can be supplied to a gas-to-liquid (GTL) facility employing a conventional Fischer-Tropsch process, which converts carbon monoxide and hydrogen into liquid hydrocarbons. Utilization of a GTL facility employing a Fischer-Tropsch process allows maximum recovery of clean liquid hydrocarbons containing no sulfur, without the utilization of hydrogen during these steps, and produces elementary sulfur for further processing, use, or collection.

(42) Within the gasifier, the following chemical reactions having Equations (1)-(6) take place:
C.sub.xH.sub.y+O.sub.2.fwdarw.xCO.sub.2+yH.sub.2O(1)
C.sub.xH.sub.y+O.sub.2.fwdarw.xCO+yH.sub.2(2)
C.sub.xH.sub.y+H.sub.2O.fwdarw.xCO+yH.sub.2(3)
CO+H.sub.2O.fwdarw.CO.sub.2+H.sub.2(4)
C.sub.xH.sub.y+H.sub.2O.fwdarw.xCH.sub.4(5)
H.sub.2+S.fwdarw.H.sub.2S(6)
Note that a small portion of the sulfur present may react to form carbonyl sulfide. Nitrogen that is typically present in the hydrocarbon feedstock forms N.sub.2 (about 90%) and NH.sub.3 (about 10%). Traces of HCN may also be formed in certain embodiments. In a separate reactor, the Water Gas Shift reaction takes place per Equation (7) as follows to produce carbon dioxide and hydrogen gas:
CO+H.sub.2O.fwdarw.CO.sub.2+H.sub.2(7)

(43) Typical product yields for a gasifier that is being supplied with a petroleum-based feed or pitch at rate of about 2,359 metric ton per day (MT/day), are provided in Table 1. In the second column of Table 1, the make-up of the syngas stream exiting the gasifier is provided. In the third column of Table 1, the make-up of a modified syngas stream is provided, after the syngas stream has been sent to a separate reactor and it has undergone a water-gas-shift reaction, to produce a stream having an increased carbon dioxide and hydrogen concentration and a decreased carbon monoxide and water concentration.

(44) TABLE-US-00001 TABLE 1 Raw Syngas, After Water-Gas Shift, Kmol/hour Kmol/hour Component Reactions 1 + 2 Reactions 1 + 2 + 3 CH.sub.4 38 38 H.sub.2 5,244 11,080 CO 6,080 243 CO.sub.2 827 6,663 H.sub.2O 15,845 10,009 H.sub.2S + COS 169 169 N.sub.2 + Misc 43 43 Total 28,246 28,245

(45) Hydrocarbons and hydrocarbonaceous compounds that can be fed to the reactor can be converted into hydrogen and CO.sub.2 and sulfur that can be present as sulfones, and refractory sulfur compounds, in the hydrocarbon feedstock can be converted to H.sub.2S and COS. Hydrogen sulfide produced by gasification can be converted to elemental sulfur according to the Claus process. The Claus process is a multi-step thermal process that converts hydrogen sulfide and oxygen into elemental sulfur and water. The overall reaction is provided as: 2H.sub.2S+O.sub.2.fwdarw.S.sub.2+2H.sub.2O.

(46) FIG. 2 provides another embodiment for the upgrading of hydrocarbons. Hydrocarbon upgrading system 200 includes oxidation reactor 104, extraction vessel 112, solvent regeneration column 116, stripper 120, gasifier 130, and adsorption column 202.

(47) As shown in FIG. 2, in certain embodiments, stripped oil stream 126 can be supplied to adsorption column 202, where the hydrocarbon-containing stream can be contacted with one or more adsorbents designed to remove one or more various impurities, such as sulfur-containing compounds, oxidized sulfur-containing compounds, nitrogen-containing compounds, oxidized nitrogen-containing compounds, and metals remaining in the hydrocarbon product stream after oxidation and solvent extraction steps.

(48) According to various embodiments, the one or more adsorbents can include activated carbon, silica gel, alumina, natural clays, and other inorganic adsorbents. In certain preferred embodiments, the adsorbent can include polar polymers that have been applied to or that coat various high surface area support materials, such as silica gel, alumina, and activated carbon. Example polar polymers for use in coating various support materials can include polysulfones, polyacrylonitrile, polystyrene, polyester terephthalate, polyurethane, other like polymer species that exhibit an affinity for oxidized sulfur species, and combinations thereof.

(49) According to at least one embodiment, adsorption column 202 can be operated at a temperature of between about 20 C. and 60 C., preferably between about 25 C. and 40 C., even more preferably between about 25 C. and 35 C. In certain embodiments, adsorption column 202 can be operated at a temperature of between about 10 C. and 40 C., alternatively between about 35 C. and 75 C. In certain embodiments, adsorption column 202 can be operated at temperatures of greater than about 20 C., or alternatively at temperatures less than about 60 C. Adsorption column 202 can be operated at a pressure of up to about 15 bars, preferably up to about 10 bars, even more preferably between about 1 and 2 bars. In certain embodiments, adsorption column 202 can be operated at a pressure of between about 2 and 5 bars. In an exemplary embodiment, adsorption column 202 can be operated at a temperature of between about 25 C. and 35 C. and a pressure of between about 1 and 2 bars. The weight ratio of stripped oil to adsorbent is between about 1:1 and 20:1, preferably between about 5:1 and 15:1, such as about 10:1.

(50) Adsorption column 202 separates the feed into extracted hydrocarbon product stream 204 having very low sulfur and very low nitrogen content and second residue stream 206. Second residue stream 206 can include oxidized sulfur- and oxidized nitrogen-containing compounds, and can optionally be combined with first residue stream 123 and supplied to gasifier 130 and processed as noted previously.

(51) According to at least one embodiment, the adsorbent can be regenerated by contacting spent adsorbent with a polar solvent, such as methanol or acetonitrile, to desorb the adsorbed oxidized compounds from the adsorbent. In certain embodiments, heat, stripping gas, or both, can also be employed to facilitate the removal of the adsorbed compounds from the adsorbent.

(52) According to another embodiment, as shown in FIG. 3, the adsorbent can be disposed of in gasifier 130, after it completes its cycle. As further shown in FIG. 3, a stream of spent adsorbent containing residual oil is supplied via line 140 from adsorption column 202 to the gasification step in gasifier 130. With gasification, the stream of spent adsorbent can be converted to valuable products. The stream of spent adsorbent may be supplied via line 140 in a continuous or intermittent manner. Additional spent adsorbent or carbon can be added to the gasification unit via stream 141.

(53) According to at least one embodiment, the stream of spent adsorbent containing sulfones 140 is fed to gasifier 130. In this embodiment, the adsorbent is an activated carbon with a pore volume of 0.429 cubic centimeters per gram (cc/g) and surface area of 820.5 square meters per gram (m.sup.2/g). Adsorption column 202 operates in a continuous basis and the amount of adsorbent is calculated from the sulfones to be adsorbed. Adsorption column 202 can be designed to operate in a two-year cycle. The amount of activated carbon adsorbent is calculated to be 109 metric ton (MT) per two years. The amount of spent activated adsorbent fed to gasifier 130 is based on the daily equivalent of the total adsorbent, (so 109 MT/cycle*1 cycle/2 years*1 year/333 days basis). The conditions of gasifier 130 remain the same. The amount of adsorbent is calculated based on 5 kilograms per hour (Kg/h) sulfone fed to the adsorption step. In this example, adsorption column 202 is used as a polishing step to remove the small amount of sulfones left in the stream after the extraction. The sulfur removal process efficiency for both extraction vessel 112 and adsorption column 202 can be balanced or readjusted. In the given example, 98.96 wt % of the sulfones were removed in the extraction step and the remaining portion is removed in the adsorption step. The unit can be designed to remove sulfones at 50 wt % in the extraction and adsorption unit. In this case, there will be more adsorbent needed to separate the sulfones. At 50 wt % sulfur removal rate in the adsorption step, the amount of adsorbent needed is 5,224 MT. At this rate, more adsorbent will be fed to gasifier 130. The balance between the extraction and adsorption steps can be adjusted based on the design of the unit for a given battery limit conditions.

(54) The material balance for the absorption step as a polishing step (removing 5 Kg/h sulfones) are provided in Table 2 as follows:

(55) TABLE-US-00002 TABLE 2 Stream No. 123 124 140 133 131 134 136 Component Kg/h Kg/h Kg/h Kg/h Kg/h Kg/h Kg/h Pitch/ 102.6 1,000 5.0 Sulfone Activated 6.9 Carbon O.sub.2 1,012 CH.sub.4 6.4 H.sub.2 249 CO 70.4 CO.sub.2 3,030.8 H.sub.2O 3,342.8 1,740.6 H.sub.2S 53.2 53.8 COS 10.3 N.sub.2 14.2 NH.sub.3 0.8 Total 102.6 1,000 11.9 1,012 3,342.8 5,175.7 53.8 Pitch/ 102.4 937.1 Sulfone (HC Content)

(56) According to various embodiments, the adsorbent can include carbon-based adsorbents. The carbon-based adsorbents together with the adsorbed residual oil and the contaminants can be gasified in gasifier 130 to produce syngas 134 with no ash produced. In accordance with one embodiment, the carbon-based adsorbent can be used in one cycle and gasified in the gasification step without any solvent regeneration of the adsorbent in the adsorption step.

(57) According to various embodiments, the adsorbent can include a solid, non-carbon-based adsorbent, which acts as slag material to cool reactor walls of gasifier 130, particularly in the membrane wall gasification reactors and end up as ash. The adsorbed residual oil and the contaminants can be gasified in gasifier 130 to produce syngas 134. Examples of the non-carbon-based adsorbent include, for example, silica-alumina, alumina, titania, zeolites, refinery spent catalysts, and natural clays.

(58) Gasifying activated carbon adsorbent will eliminate the disposal issue and generate additional hydrogen yield. It is estimated that an additional 13.4 kg/h or 53 MT/year of hydrogen can be produced.

(59) As shown in FIG. 4, in certain embodiments, extracted hydrocarbon stream 118 can be supplied directly from extraction vessel 112 to adsorption column 202, where the stream can be contacted with one or more adsorbents designed to remove one or more various impurities, such as sulfur-containing compounds, oxidized sulfur-containing compounds, nitrogen-containing compounds, oxidized nitrogen-containing compounds, and metals remaining in the hydrocarbon product stream after oxidation and solvent extraction steps.

(60) Adsorption column 202 can also be supplied with recovered hydrocarbon stream 124, which can include oil recovered from solvent regeneration column 116, wherein the stream can be contacted with the one or more adsorbents described previously.

(61) Adsorption column 202 separates the feed into a high purity extracted hydrocarbon product stream 204 having very low sulfur and very low nitrogen content and second residue stream 206. Second residue stream 206 can include oxidized sulfur and oxidized nitrogen compounds, and can optionally be combined with first residue stream 123 and supplied to gasifier 130 and processed as noted previously.

(62) As shown in FIG. 5, in certain embodiments, the oxygen feed to oxidation reactor 104 can be used to supply gasifier 130, to provide synergy as oxygen can be used as both the oxidant for the desulfurization and as a reactant for the gasification process. More specifically, the oxygen which is used to gasify the vacuum residue or liquid hydrocarbon, can also be used to selectively oxidize the sulfur- or nitrogen-containing compounds in the liquid hydrocarbon.

(63) As shown in FIG. 6, in certain embodiments, all or a portion of syngas steam 134 can be supplied to an alternate process, such as a solvent synthesis unit, to produce a solvent that can be utilized for the extraction of oxidized sulfur and oxidized nitrogen compounds in extraction vessel 112. More specifically, in certain embodiments, all or a portion of syngas stream 134 can be supplied via line 402 to methanol reactor 404 to prepare methanol according to the following reaction: CO+2H.sub.2.fwdarw.CH.sub.3OH. Methanol produced in methanol synthesis unit 404 can be supplied to extraction vessel 112 via line 406, where it can optionally be combined with recycled methanol from lines 117 or 128, or both.

(64) In certain embodiments, methanol reactor 404 can include a catalyst to facilitate the preparation of methanol, such as a copper, zinc oxide, alumina catalyst. Methanol reactor 404 can be maintained at pressures of between about 40 and 125 bars, preferably between about 50 and 100 bars, and a temperature of between about 225 C. and 400 C., preferably between about 250 C. and 350 C. Typically, methanol reactor 404 is operated at relatively mild conditions. Energy produced by the gasifier can be supplied to a power plant, or to an alternate or associated process.

(65) Referring now to FIG. 7, in another embodiment, apparatus 700 is provided for the desulfurization of a hydrocarbon feedstock, with the subsequent recovery of elemental sulfur. Processing of hydrocarbon feedstock 102 proceeds as described previously. Gasifier 130 produces hydrogen sulfide stream 136, which can be supplied to Claus unit 502. Claus unit 502 can include multi-step process equipment that is operable to recover elemental sulfur 504 from hydrogen sulfide stream 136, and also produce water stream 506, which can be a steam stream. Claus unit 502 can include a catalyst to increase elemental sulfur yield. In certain embodiments, the Claus unit catalyst can include activated aluminum (III) oxide or titanium (IV) oxide. In certain embodiments, the Claus reactor can include multiple catalytic stages. Typically, Claus reactors are operated at temperatures of between about 100 C. and 500 C., alternatively between about 150 C. and 400 C. Claus unit 502 can include a sulfur condenser for recovering the elemental sulfur. Steam stream 506 can be condensed, recovered and recycled for an alternate process, or can be used in associated heat exchangers as either a heating or cooling medium.

(66) Referring now to FIG. 8, in another fully integrated embodiment, apparatus 800 is provided for the desulfurization of a hydrocarbon feedstock, with the subsequent recovery of elemental sulfur and the production of methanol for use as an extraction solvent. Hydrocarbon feedstock 102 is processed as described previously. As discussed previously with respect to FIG. 1, first residue stream 123 is supplied to gasifier 130 where it is contacted with oxygen stream 133 and a catalyst in a reaction zone to produce syngas stream 134 and hydrogen sulfide stream 136. All or a portion of syngas stream 134 can be supplied via line 402 to methanol reactor 404 to produce methanol stream 406, which can be supplied to extraction vessel 112. Alternatively, all or a portion of methanol stream 406 can be supplied to an alternate process, or the methanol can be collected for later use. Hydrogen sulfide stream 136 from gasifier 130 can be supplied to Claus unit 502, which in turn catalytically converts the hydrogen sulfide to elemental sulfur 504 and water 506.

(67) Referring now to FIG. 9, another embodiment is provided. Hydrocarbon stream 102, oxidant feed stream 106 and catalyst feed stream 108 are supplied to oxidation reactor 104, which is operated as previously described, to produce oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream 110 and spent catalyst stream 109. Oxidized sulfur- and oxidized nitrogen-containing hydrocarbon stream 110 is supplied to extraction vessel 112 where it is contacted with extraction solvent stream 137 to produce extracted hydrocarbon stream 118, which has a lower concentration of sulfur- and nitrogen-containing compounds than does hydrocarbon stream 102, and mixed stream 114, which includes extraction solvent and oxidized sulfur- and oxidized nitrogen-containing compounds.

(68) Mixed stream 114 is supplied to solvent regenerator 116, which can be a distillation column, where the mixed stream is heated to produce a recovered solvent stream 117 and a residue stream 123, which includes oxidized sulfur- and oxidized nitrogen-containing compounds.

(69) Residue stream 123 can optionally be combined with an alternate sulfone or pitch stream 129, which can be supplied by an alternate process, water 131, and oxygen 133 and supplied to gasifier 130, where the mixture is heated to produce syngas stream 134 and hydrogen sulfide stream 136. Hydrogen sulfide stream 136 can be combined with oxygen 135 and supplied to Claus unit 502, where the hydrogen sulfide and oxygen are heated to produce elemental sulfur 504 and water 506, which may be in the form of steam.

(70) In the embodiment according to FIG. 9, gasification reactor 130, in which Clause unit 502 is included, is supplied with oxidized sulfur-containing stream 123 and separate pitch stream supplied via line 129 to produce synthesis gas and other gaseous products. Gasification reactor 130 is operated at a temperature of about 1045 C. The weight ratio of water to carbon was about 0.6 and the oxygen to pitch ratio was approximately 1. The material balance for the product yields are provided in Table 3 as follows:

(71) TABLE-US-00003 TABLE 3 Oxidation Step Stream No. 102 106 108 109 Component Kg/h Kg/h Kg/h Kg/h Water 852 1,045 MeOH Diesel 171,915 Organic 481 2 Sulfur Acetic Acid 10,641 9,577 Hydrogen 365 Peroxide Solid 860 860 Catalyst Total 172,396 1,217 11,501 11,484

(72) Material balances for the extraction step for the exemplary embodiment according to FIG. 9 are provided in Table 4 that follows.

(73) TABLE-US-00004 TABLE 4 Extraction step Stream No. 110 137 114 118 117 123 Component Kg/h Kg/h Kg/h Kg/h Kg/h Kg/h Water MeOH 266,931 265,240 1,691 265,240 Diesel 171,915 17,191 154,724 17,191 Organic 481 476 5 476 Sulfur Acetic Acid Solid Catalyst Total 172,396 266,931 282,907 156,420 265,420 17,667

(74) In the embodiment according to FIG. 9, gasification reactor 130 is supplied with oxidized sulfur-containing stream 123 and separate pitch stream supplied via line 129. Gasification reactor 130 is operated at a temperature of about 1045 C. The weight ratio of water to carbon was about 0.6, and the oxygen to pitch ratio was approximately 1. Gasifier output 136 is supplied to Claus unit 502. The material balance for the product yields are provided in Table 5 as follows:

(75) TABLE-US-00005 TABLE 5 Product Yields. Stream No. 123 129 133 131 134 136 Component Kg/h Kg/h Kg/h Kg/h Kg/h Kg/h Pitch/ 102.6 1,000 Sulfone O.sub.2 1,000 CH.sub.4 6.2 H.sub.2 229 CO 69.4 CO.sub.2 2,995.9 H.sub.2O 3,176.8 1,738.9 H.sub.2S 52.5 COS 10.3 N.sub.2 14.2 NH.sub.3 0.8 Total 102.6 1,000 1,000 3,176.8 5,064.7 52.5 Pitch/ 102.4 937.1 Sulfone (HC)

(76) Although embodiments have been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope. Accordingly, the scope should be determined by the following claims and their appropriate legal equivalents.

(77) The singular forms a, an and the include plural referents, unless the context clearly dictates otherwise.

(78) Optional or optionally means that the subsequently described event or circumstances may or may not occur. The description includes instances where the event or circumstance occurs and instances where it does not occur.

(79) Ranges may 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 another embodiment is from the one particular value to the other particular value, along with all combinations within said range.

(80) Throughout this application, where patents or publications are referenced, the disclosures of these references in their entireties are intended to be incorporated by reference into this application, in order to more fully describe the state of the art, except when these references contradict the statements made.