WO2004005435A1 - Improved hydrocarbon desulfurization with pre-oxidation of organosulfur compounds - Google Patents

Abstract

A process is provided for removing sulfur compounds, such as 4, 6 - dimethyldibenzothiophene, etc., out of hydrocarbon fluids, such as middle distillates, cracked gasoline, etc., by passing the sulfur compound-contaminated hydrocarbon fluid and an oxidizing agent, such as a peroxide, etc., into an oxidizer (10) where the oxidizing agent oxidizes the sulfur compounds into species, such as sulfones and sulfoxides. The resulting hydrocarbon fluid is transferred into a desulfurization reactor (12) containing a fluidized bed of a sorbent comprising a zinc-based solid solution of the formula MaZnb, where M is a metal such as nickel, cobalt, iron, etc., where the sorbent removes sulfur compound contaminants out of the hydrocarbon fluid to provide a desulfurized hydrocarbon fluid. The spent sorbent is regenerated in a regenerator (14), activated in a reducer (16), and then returned to the desulfurization reactor (12).

Description

HYDROCARBON DESULFURIZATION WITH PRE-OXLDATION OF ORGANOSULFUR COMPOUNDS

This invention relates to a process for removing sulfur from hydrocarbon- containing fluid streams. In another aspect, the invention concerns an improved hydro- carbon desulfurization process wherein certain organosulfur compounds in a hydrocarbon-containing fluid stream are oxidized prior to sulfur removal.

Hydrocarbon-containing fluids such as gasoline and diesel fuels typically contain a quantity of sulfur. High levels of sulfur in such automotive fuels are undesirable because oxides of sulfur present in automotive exhaust may irreversibly poison noble metal catalysts employed in automobile catalytic converters. Emissions from such poisoned catalytic converters may contain high levels of non-combusted hydrocarbons, oxides of nitrogen, and/or carbon monoxide, which, when catalyzed by sunlight, form ground level ozone, more commonly referred to as smog.

Much of the sulfur present in the final blend of most gasolines originates from a gasoline blending component commonly known as "cracked-gasoline". Thus, reduction of sulfur levels in cracked-gasoline will inherently serve to reduce sulfur levels in most gasolines, such as, automobile gasolines, racing gasolines, aviation gasolines, boat gasolines, and the like. Many conventional processes exist for removing sulfur from cracked-gasoline. However, most conventional sulfur removal processes, such as hydrodesulfurization, tend to saturate olefins and aromatics in the cracked-gasoline and thereby reduce its octane number (both research and motor octane number). Thus, there is a need for a process wherein desulfurization of cracked-gasoline is achieved while the octane number is maintained.

In addition to the need for removing sulfur from cracked-gasoline, there is also a need to reduce the sulfur content in diesel fuel. In removing sulfur from diesel fuel by hydrodesulfurization, the cetane is improved but there is a large cost in hydrogen consumption. Such hydrogen is consumed by both hydrodesulfurization and aromatic hydrogenation reactions. Thus, there is a need for a process wherein desulfurization of diesel fuel is achieved without significant consumption of hydrogen so as to provide a more economical desulfurization process.

Certain sulfur compounds are more difficult to remove from hydrocarbon fluids than others. Traditionally, thiols (RSH) and thioethers (R₂S) have been relatively easy to remove, while thiophenes, benzothiophenes, and dibenzothiophenes have been more difficult to remove. In particular, dibenzothiophenes with alkyl groups in the 4 and 6 position (i.e., 4,6 dimethyldibenzothiophene) are typically the most difficult sulfur compounds to remove. Diesel fuels typically contain more "hard-to-remove" sulfur compounds than cracked-gasoline. In view of the increasingly stringent regulations on sulfur levels in fuels, a substantial portion of the hard-to-remove sulfur compounds must be removed from fuels in order to comply with government regulations. Thus, a process for removing such hard-to-remove sulfur compounds from hydrocarbon-containing fluids (e.g., diesel fuel or cracked-gasoline) with minimal octane loss, minimal cetane loss, and/or minimal hydrogen consumption would be a significant contribution to the art and to the economy.

Accordingly, it is desirable to provide a hydrocarbon desulfurization system for removing sulfur compounds that are difficult to remove using conventional techniques.

Again it is desirable to provide a hydrocarbon desulfurization system which minimizes octane loss, cetane loss, and/or hydrogen consumption while providing enhanced sulfur removal.

It should be noted that the above-listed desires need not all be accomplished by the invention claimed herein and other objects and advantages of this invention will be apparent from the following description of the preferred embodiments and appended claims.

Accordingly, in one embodiment of the present invention, there is provided a desulfurization process comprising the steps of: (a) contacting a hydrocarbon- containing fluid containing sulfur compounds with an oxidizing agent under oxidation conditions sufficient to oxidize at least a portion of the sulfur compounds, thereby providing an oxidized hydrocarbon-containing fluid comprising oxidized sulfur compounds; and (b) contacting the oxidized hydrocarbon-containing fluid with a sorbent comprising a promoter metal component and zinc oxide under desulfurization conditions sufficient to remove at least a portion of the oxidized sulfur compounds from the oxidized hydrocarbon-containing fluid. In another embodiment of the present invention, there is provided a desulfurization process comprising the steps of: (a) contacting a middle distillate containing thiophene compounds with an oxidizing agent under oxidizing conditions sufficient to convert at least a portion of the thiophene compounds to oxidized sulfur compounds selected from the group consisting of sulfones, sulfoxides, and mixtures thereof, thereby providing an oxidized middle distillate; and (b) contacting the oxidized middle distillate with a sorbent comprising a promoter metal component and zinc oxide under desulfurization conditions sufficient to remove at least a portion of the oxidized sulfur compounds from the oxidized middle distillate. In still another embodiment of the present invention, there is provided a desulfurization process comprising the steps of: (a) contacting a hydrocarbon-containing fluid containing sulfur compounds with an oxidizing agent under oxidation conditions sufficient to oxidize at least a portion of the sulfur compounds, thereby providing an oxidized hydrocarbon-containing fluid comprising oxidized sulfur compounds; (b) contacting the oxidized hydrocarbon-containing fluid with a sorbent comprising a promoter metal component and zinc oxide under desulfurization conditions sufficient to remove at least a portion of the oxidized sulfur compounds from the oxidized hydrocarbon-containing fluid, thereby providing a desulfurized hydrocarbon-containing fluid and a sulfur-loaded sorbent; (c) contacting at least a portion of the sulfur-loaded sorbent with an oxygen-containing regeneration stream under regeneration conditions sufficient to remove sulfur from the sulfur-loaded sorbent and oxidize the promoter metal component, thereby providing a regenerated sorbent comprising an oxidized promoter metal component; and (d) contacting at least a portion of the regenerated sorbent with a hydrogen-containing regeneration stream under reducing conditions sufficient to reduce at least a portion of the oxidized promoter metal component, thereby providing a reduced sorbent.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a schematic diagram of a desulfurization unit constructed in accordance with the principals of the present invention, particularly illustrating the flow of a hydrocarbon-containing fluid through an oxidation vessel and a reactor, as well as the circulation path of regenerable solid sorbent particulates through the reactor, a regenerator, and a reducer.

FIG. 2 is a chromatogram of an unoxidized diesel fuel containing 523 ppmw sulfur.

FIG. 3 is a chromatogram of the diesel shown in FIG. 2, after oxidation. Referring initially to FIG. 1, a desulfurization unit 8 is illustrated as generally comprising an oxidizer 10, a reactor 12, a regenerator 14, and a reducer 16. In oxidizer 10, a hydrocarbon-containing fluid stream, such as cracked-gasoline or diesel fuel, is contacted with an oxidizing agent under oxidizing conditions sufficient to oxidize at least a portion of the sulfur compounds in the hydrocarbon-containing fluid. In reactor 12, the oxidized hydrocarbon-containing fluid stream is contacted with solid sorbent particulates which remove sulfur from the oxidized fluid stream. The desulfurized hydrocarbon-containing fluid then exits reactor 12, while the "sulfur-loaded" sorbent particulates are transported from reactor 12 to regenerator 14 for sulfur removal, and subsequently to reducer 16 for activation. The solid sorbent particulates are circulated through reactor 12, regenerator 14, and a reducer 16 to provide for continuous sulfur removal from the hydrocarbon-containing fluid as well as continuous sorbent regeneration.

The hydrocarbon-containing fluid charged to oxidizer 10 can be any hydrocarbon-containing fluid containing a quantity of organosulfur compounds. Preferably, the hydrocarbon-containing fluid charged to oxidizer 10 is selected from the group consisting of middle distillates, gasoline, cracked-gasoline, and mixtures thereof. More preferably, the hydrocarbon-containing fluid is a middle distillate that boils (ASTM D86-00) in the range of from about 148.8 to about 398.8°C (about 300 to about 750°F), more preferably from about 176.6 to about 385°C (about 350 to about 725°F). The middle distillate preferably has a mid-boiling point (ASTM D86-00) of at least about

176.6°C (about 350°F), more preferably at least about 204.4°C (about 400°F), and most preferably at least about 232.2°C (about 450°F). The middle distillate preferably has an API gravity (ASTM D287-92) in the range of from about 20 to about 50, more preferably from about 25 to about 45. The middle distillate preferably has a minimum flash point (ASTM D93-99) of at least about 26.6°C (about 80°F), more preferably at least 32.2°C

(about 90°F). Examples of suitable middle distillates include, but are not limited to, diesel fuel, jet fuel, kerosene, light cycle oil, and the like, and mixtures thereof. Most preferably, the middle distillate charged to oxidizer 10 is diesel fuel boiling in the range of from 190.5 to 371.1°C (375 to 700°F), having a mid-boiling point of at least 260°C (500°F), having an API gravity in the range of from 30 to 38, and having a minimum flash point of at least 37.7°C (100°F).

As used herein, the term "gasoline" denotes a mixture of hydrocarbons boiling in a range of from about 37.7°C to about 204.4°C (about 100°F to about 450°F), or any fraction thereof. Examples of suitable gasolines include, but are not limited to, hydrocarbon streams in refineries such as naphtha, straight-run naphtha, coker naphtha, catalytic gasoline, visbreaker naphtha, alkylates, isomerate, reformate, and the like, and mixtures thereof.

As used herein, the term "cracked-gasoline" denotes a mixture of hydrocarbons boiling in a range of from about 37.7°C to about 204.4°C (about 100°F to about 450°F), or any fraction thereof, that are products of either thermal or catalytic processes that crack larger hydrocarbon molecules into smaller molecules. Examples of suitable thermal processes include, but are not limited to, coking, thermal cracking, visbreaking, and the like, and combinations thereof. Examples of suitable catalytic cracking processes include, but are not limited to, fluid catalytic cracking, heavy oil cracking, and the like, and combinations thereof. Thus, examples of suitable cracked- gasolines include, but are not limited to, coker gasoline, thermally cracked gasoline, visbreaker gasoline, fluid catalytically cracked gasoline, heavy oil cracked-gasoline and the like, and combinations thereof. In some instances, the cracked-gasoline may be fractionated and/or hydrotreated prior to desulfurization when used as the sulfur- containing fluid in the process in the present invention. The hydrocarbon-containing fluid charged to oxidizer 10 may comprise a quantity of aromatics, olefins, and sulfur, as well as paraffins and naphthenes. The amount of aromatics in the hydrocarbon-containing fluid is preferably in the range of from about 10 to about 90 weight percent aromatics based on the total weight of the hydrocarbon-containing fluid, more preferably from about 20 to about 80 weight percent aromatics. The amount of olefins in the hydrocarbon-containing fluid is preferably less than about 10 weight percent based on the total weight of the hydrocarbon-containing fluid, more preferably less than about 5 weight percent olefins, and most preferably less than 2 weight percent olefins. The amount of atomic sulfur, as sulfur, in the hydrocarbon- containing fluid is at least about 50 parts per million by weight (ppmw) atomic sulfur, more preferably in the range of from about 100 to about 50,000 ppmw atomic sulfur, and most preferably from 150 to 3,000 ppmw atomic sulfur prior to treatment of the hydrocarbon-containing fluid with the process of the present invention. It is preferred for at least about 50 weight percent of the atomic sulfur present in the hydrocarbon- containing fluid employed in the present invention to be in the form of organosulfur compounds. More preferably, at least about 75 weight percent of the atomic sulfur present in the hydrocarbon-containing fluid is in the form of organosulfur compounds, and most preferably at least 90 weight percent of the atomic sulfur is in the form of organosulfur compounds. As used herein, the term "sulfur" used in conjunction with "ppmw sulfur" or "atomic sulfur" denotes the amount of atomic sulfur (about 32 atomic mass units) in the sulfur-containing fluid, not the atomic mass, or weight, of a sulfur compound, such as an organosulfur compound.

As used herein, the term "sulfur" denotes sulfur in any form normally present in a sulfur-containing hydrocarbon such as cracked-gasoline or diesel fuel. Examples of such sulfur which can be removed from a sulfur-containing hydrocarbon fluid through the practice of the present invention include, but are not limited to, hydrogen sulfide, carbonyl sulfide (COS), carbon disulfide (CS₂), mercaptans (RSH), organic sulfides (R-S-R), organic disulfides (R-S-S-R), thiophene, substituted thiophenes, organic trisulfides, organic tetrasuffides, benzothiophene, alkyl thiophenes, alkyl benzothiophenes, alkyl dibenzothiophenes, and the like, and combinations thereof, as well as heavier molecular weights of the same which are normally present in sulfur-containing hydrocarbons of the types contemplated for use in the desulfurization process of the present invention, wherein each R can be an alkyl, cycloalkyl, or aryl group containing 1 to 10 carbon atoms.

The oxidizing agent charged to oxidizer 10 can be any substance capable of selectively oxidizing at least a portion of the organosulfur compounds present in the hydrocarbon-containing fluid under oxidizing conditions. Preferably, the oxidizing agent is a substance selected from the group consisting of bromine, bromates, chlorinated isocyanurates, chlorates, chromates, dichromates, hydroperoxides, hypochlorites, inorganic peroxides, ketone peroxides, nitrates, nitric acid, nitrites, perborates, perchlorates, perchloric acid, periodates, permanganates, peroxides, peroxyacids, persulphates, and mixtures thereof. More preferably, the oxidizing agent is a peroxide. Still more preferably, the oxidizing agent is an organic peroxide. Yet still more preferably, the oxidizing agent comprises a peroxyacid. Most preferably, the oxidizing agent is a mixture of peroxyacid and acetic acid.

Oxidizer 10 can be any vessel suitable for continuously contacting the hydrocarbon-containing fluid with the oxidizing agent under controlled oxidization conditions. Oxidizer 10 is preferably a continuous stirred tank reactor wherein the hydrocarbon-containing fluid and oxidizing agent are continuously mixed in a liquid phase reaction. The proportion of the hydrocarbon-containing fluid and the oxidizing agent contacted in oxidizer 10 is preferably a proportion such that about one to about four equivalents of the oxidizing agent are provided for each sulfur equivalent in the hydrocarbon-containing feed. More preferably, two to three equivalents of the oxidizing agent are provided for each sulfur equivalent in the hydrocarbon-containing feed. The oxidation conditions at which oxidizer 10 is maintained during contacting of the hydrocarbon-containing fluid and oxidizing agent therein, can be any oxidizing conditions sufficient to provide oxidation of at least a portion of the organo- sulfur compounds (particularly 4,6-dimethyldibenzothiophene) in the hydrocarbon- containing fluid, while providing only minimal oxidation of non-sulfur compounds. Preferably, such oxidation conditions include an oxidation temperature in the range of from about 10°C to about 93.3°C (about 50 to about 200°F), an oxidation pressure in the range of from about 0 to about 50 psia, and an oxidation contact time in the range of from about 15 minutes to about three hours.

After oxidation in oxidizer 10, it is preferred for the oxidized hydrocarbon- containing fluid and the oxidizing agent to be separated prior to introducing the oxidized hydrocarbon-containing fluid into reactor 12. The oxidized and separated hydrocarbon- containing fluid charged to reactor 12 for contacting therein with finely divided (i.e., < 500 micron) solid sorbent particulates. Prior to introduction into reactor 12, it is preferred for the oxidized hydrocarbon-containing fluid to be combined with hydrogen so that the hydrogen to hydrocarbon molar ratio of the fluid stream entering reactor 12 is in the range of from about 0.1 : 1 to about 10: 1, more preferably in the range of from 0.5 : 1 to 3 : 1. Reactor 12 is preferably a fluidized bed reactor in which the upwardly flowing gaseous oxidized hydrocarbon-containing fluid stream is contacted with finely divided reduced solid sorbent particulates under a set of desulfurization conditions sufficient to produce a desulfurized hydrocarbon and sulfur-loaded solid sorbent particulates. The flow of the hydrocarbon-containing fluid stream is sufficient to fluidize the bed of solid sorbent particulates located in reactor 12. The desulfurization conditions in reactor 12 include temperature, pressure, weighted hourly space velocity (WHSN), and superficial velocity. The preferred ranges for such desulfurization conditions are provided below in Table 1.

In contrast to many conventional sulfur removal processes (e.g., hydrodesulfurization), it is preferred that substantially none of the sulfur in the oxidized hydrocarbon-containing fluid is converted to, and remains as, hydrogen sulfide during desulfurization in reactor 12. Rather, it is preferred that the fluid effluent from reactor 12 (generally comprising the desulfurized hydrocarbon and hydrogen) comprises less than the amount of hydrogen sulfide, if any, in the fluid feed charged to reactor 12 (generally comprising the sulfur-containing hydrocarbon and hydrogen). The fluid effluent from reactor 12 preferably contains less than about 50 weight percent of the amount of sulfur in the fluid feed charged to reactor 12, more preferably less than about 20 weight percent of the amount of sulfur in the fluid feed, and most preferably less than 5 weight percent of the amount of sulfur in the fluid feed. It is preferred for the total sulfur content of the fluid effluent from reactor 12 to be less than about 50 parts per million by weight (ppmw) of the total fluid effluent, more preferably less than about 30 ppmw, still more preferably less than about 15 ppmw, and most preferably less than 10 ppmw. The solid sorbent particulates employed in desulfurization unit 8 can be any sufficiently fluidizable, circulatable, and regenerable zinc oxide-based composition having sufficient desulfurization activity and sufficient attrition resistance. A description of such a sorbent composition is provided in U.S. Patent Application Ser. No. 09/580,611 and U.S. Patent Application Ser. No. 10/072,209, the entire disclosures of which are incorporated herein by reference. The reduced solid sorbent particulates contacted with the oxidized hydrocarbon-containing stream in reactor 12 preferably initially (i.e., immediately prior to contacting with the oxidized hydrocarbon-containing fluid stream) comprise zinc oxide and a reduced- valence promoter metal component. Though not wishing to be bound by theory, it is believed that the reduced- valence promoter metal component of the reduced solid sorbent particulates facilitates the removal of sulfur from the oxidized hydrocarbon-containing stream, while the zinc oxide operates as a sulfur storage mechanism via its conversion to zinc sulfide.

The reduced-valence promoter metal component of the reduced solid sorbent particulates preferably comprises a promoter metal selected from the group consisting of nickel, cobalt, iron, manganese, tungsten, silver, gold, copper, platinum, zinc, tin, ruthenium, molybdenum, antimony, vanadium, indium, chromium, palladium. More preferably, the reduced- valence promoter metal component comprises nickel as the promoter metal. As used herein, the term "reduced- valence" when describing the promoter metal component, shall denote a promoter metal component having a valence which is less than the valence of the promoter metal component in its common oxidized state. More specifically, the reduced solid sorbent particulates employed in reactor 12 should include a promoter metal component having a valence which is less than the valence of the promoter metal component of the regenerated (i.e., oxidized) solid sorbent particulates exiting regenerator 14. Most preferably, substantially all of the promoter metal component of the reduced solid sorbent particulates has a valence of 0.

In a preferred embodiment of the present invention the reduced-valence promoter metal component comprises, consists of, or consists essentially of, a substitutional solid metal solution characterized by the formula: M_AZn_B, wherein M is the promoter metal and A and B are each numerical values in the range of from 0.01 to 0.99. In the above formula for the substitutional solid metal solution, it is preferred for A to be in the range of from about 0.70 to about 0.97, and most preferably in the range of from about 0.85 to about 0.95. It is further preferred for B to be in the range of from about 0.03 to about 0.30, and most preferably in the range of from about 0.05 to 0.15. Preferably, B is equal to (1-A). Substitutional solid solutions have unique physical and chemical properties that are important to the chemistry of the sorbent composition described herein. Substitutional solid solutions are a subset of alloys that are formed by the direct substitution of the solute metal for the solvent metal atoms in the crystal structure. For example, it is believed that the substitutional solid metal solution (M_AZn_B) found in the reduced solid sorbent particulates is formed by the solute zinc metal atoms substituting for the solvent promoter metal atoms. There are three basic criteria that favor the formation of substitutional solid solutions: (1) the atomic radii of the two elements are within 15 percent of each other; (2) the crystal structures of the two pure phases are the same; and (3) the electronegativities of the two components are similar. The promoter metal (as the elemental metal or metal oxide) and zinc oxide employed in the solid sorbent particulates described herein preferably meet at least two of the three criteria set forth above. For example, when the promoter metal is nickel, the first and third criteria, are met, but the second is not. The nickel and zinc metal atomic radii are within 10 percent of each other and the electronegativities are similar. However, nickel oxide (NiO) preferentially forms a cubic crystal structure, while zinc oxide (ZnO) prefers a hexagonal crystal structure. A nickel zinc solid solution retains the cubic structure of the nickel oxide. Forcing the zinc oxide to reside in the cubic structure increases the energy of the phase, which limits the amount of zinc that can be dissolved in the nickel oxide structure. This stoichiometry control manifests itself microscopically in a 92:8 nickel zinc solid solution (Ni₀₉₂Zn_{0 og}) that is formed during reduction and microscopically in the repeated regenerability of the solid sorbent particulates.

In addition to zinc oxide and the reduced- valence promoter metal component, the reduced solid sorbent particulates employed in reactor 12 may further comprise a porosity enhancer and an aluminate. The aluminate of the reduced-valence promoter metal component preferably comprises, consists essentially of, or consists of a promoter metal-zinc aluminate substitutional solid solution characterized by the formula: M_zZn₍₁._Z)Al₂O₄, wherein Z is a numerical value in the range of from 0.01 to 0.99. The porosity enhancer, when employed, can be any compound which ultimately increases the macroporosity of the solid sorbent particulates. Preferably, the porosity enhancer is perlite. The term "perlite" as used herein is the petrographic term for a siliceous volcanic rock which naturally occurs in certain regions throughout the world.

The distinguishing feature, which sets it apart from other volcanic minerals, is its ability to expand four to twenty times its original volume when heated to certain temperatures. When heated above 871.1°C (1600°F), crushed perlite expands due to the presence of combined water with the crude perlite rock. The combined water vaporizes during the heating process and creates countless tiny bubbles in the heat softened glassy particles. It is these diminutive glass sealed bubbles which account for its light weight. Expanded perlite can be manufactured to weigh as little as 40kg/m³ (2.5 lbs per cubic foot). Typical chemical analysis properties of expanded perlite are: silicon dioxide 73%, aluminum oxide 17%, potassium oxide 5%, sodium oxide 3%, calcium oxide 1%, plus trace elements. Typical physical properties of expanded perlite are: softening point 871.1 -

1,093.3°C (1600-2000°F), fusion point 1,260°C - 1,343.3°C (2300°F-2450°F), pH 6.6-6.8, and specific gravity 2.2-2.4. The term "expanded perlite" as used herein refers to the spherical form of perlite which has been expanded by heating the perlite siliceous volcanic rock to a temperature above 871.1°C (1600°F). The term "particulate expanded perlite" or "milled perlite" as used herein denotes that form of expanded perlite which has been subjected to crushing. The term "milled expanded perlite" is intended to mean the product resulting from subjecting expanded perlite particles to milling or crushing.

The reduced solid sorbent particulates initially contacted with the oxidized hydrocarbon-containing fluid stream in reactor 12 can comprise zinc oxide, the reduced- valence promoter metal component (M_AZn_B), the porosity enhancer (PE), and the promoter metal-zinc aluminate (M_zZn₍₁__zAl₂O₄) in the ranges provided below in Table 2.

The physical properties of the solid sorbent particulates which significantly affect the particulates suitability for use in desulfurization unit 8 include, for example, particle shape, particle size, particle density, and resistance to attrition. The solid sorbent particulates employed in desulfurization unit 8 preferably comprise microspherical particles having a mean particle size in the range of from about 20 to about 150 microns, more preferably in the range of from about 50 to about 100 microns, and most preferably in the range of from 60 to 80 microns. The density of the solid sorbent particulates is preferably in the range of from about 0.5 to about 1.5 grams per cubic centimeter (g/cc), more preferably in the range of from about 0.8 to about 1.3 g/cc, and most preferably in the range of from 0.9 to 1.2 g/cc. The particle size and density of the solid sorbent particulates preferably qualify the solid sorbent particulates as a Group A solid under the Geldart group classification system described in Powder Technol., 7, 285-292 (1973). The solid sorbent particulates preferably have high resistance to attrition. As used herein, the term "attrition resistance" denotes a measure of a particle's resistance to size reduction under controlled conditions of turbulent motion. The attrition resistance of a particle can be quantified using the Davison Index. The Davison Index represents the weight percent of the over 20 micrometer particle size fraction which is reduced to particle sizes of less than 20 micrometers under test conditions. The Davison Index is measured using a jet cup attrition determination method. The jet cup attrition determination method involves screening a 5 gram sample of sorbent to remove particles in the 0 to 20 micrometer size range. The particles above 20 micrometers are then subjected to a tangential jet of air at a rate of 21 liters per minute introduced through a 1.587 mm (0.0625 inch) orifice fixed at the bottom of a specially designed jet cup (2.54 cm I.D. x 5.08 cm height) (1 " I.D. X 2" height) for a period of 1 hour. The Davison Index (DI) is calculated as follows:

_ Wt. of 0-20 Micrometer Formed During Test

DI = — — , _ . . . , „„ _ ,. : — r. — 7 X 100 X Correction Factor

Wt. or Original + 20 Micrometer Fraction Being Tested

The correction factor (presently 0.30) is determined using a known calibration standard to adjust for differences in jet cup dimensions and wear. The solid sorbent particulates employed in the present invention preferably have a Davison Index value of less than about 30, more preferably less than about 20, and most preferably less than 10.

When the reduced solid sorbent particulates are contacted with the oxidized hydrocarbon-containing stream in reactor 12 under desulfurization conditions, sulfur compounds, particularly organosulfur compounds, present in the hydrocarbon- containing fluid stream are removed from such fluid stream. At least a portion of the sulfur removed from the hydrocarbon-containing fluid stream is employed to convert at least a portion of the zinc oxide of the reduced solid sorbent particulates into zinc sulfide.

After desulfurization in reactor 12, the desulfurized hydrocarbon fluid, preferably desulfurized cracked-gasoline or desulfurized diesel fuel, can thereafter be separated and recovered from the fluid effluent and preferably liquified. The liquification of such desulfurized hydrocarbon fluid can be accomplished by any method or manner known in the art. The resulting liquified, desulfurized hydrocarbon preferably comprises less than about 50 weight percent of the amount of sulfur in the sulfur-containing hydrocarbon (e.g., cracked-gasoline or diesel fuel) charged to the reaction zone, more preferably less than about 20 weight percent of the amount of sulfur in the sulfur-containing hydro- carbon, and most preferably less than 5 weight percent of the amount of sulfur in the sulfur-containing hydrocarbon. The desulfurized hydrocarbon preferably comprises less than about 50 ppmw sulfur, more preferably less than about 30 ppmw sulfur, still more preferably less than about 15 ppmw sulfur, and most preferably less than 10 ppmw sulfur. After desulfurization in reactor 12, at least a portion of the sulfur-loaded sorbent particulates are transported to regenerator 14 via a first transport assembly 18. In regenerator 14, the sulfur-loaded solid sorbent particulates are contacted with an oxygen- containing regeneration stream. The oxygen-containing regeneration stream preferably comprises at least 1 mole percent oxygen with the remainder being a gaseous diluent. More preferably, the oxygen-containing regeneration stream comprises in the range of from about 1 to about 50 mole percent oxygen and in the range of from about 50 to about 95 mole percent nitrogen, still more preferable in the range of from about 2 to about 20 mole percent oxygen and in the range of from about 70 to about 90 mole percent nitrogen, and most preferably in the range of from 3 to 10 mole percent oxygen and in the range of from 75 to 85 mole percent nitrogen.

The regeneration conditions in regenerator 14 are sufficient to convert at least a portion of the zinc sulfide of the sulfur-loaded solid sorbent particulates into zinc oxide via contacting with the oxygen-containing regeneration stream. The preferred ranges for such regeneration conditions are provided below in Table 3.

When the sulfur-loaded solid sorbent particulates are contacted with the the oxygen-containing regeneration stream under the regeneration conditions described above, at least a portion of the promoter metal component is oxidized to form an oxidized promoter metal component. Preferably, in regenerator 14 the substitutional solid metal solution (M_AZn_B) and/or sulfided substitutional solid metal solution (M_AZn_BS) of the sulfur-loaded sorbent is converted to a substitutional solid metal oxide solution characterized by the formula: M_xZn_YO, wherein M is the promoter metal and X and Y are each numerical values in the range of from 0.01 to about 0.99. In the above formula, it is preferred for X to be in the range of from about 0.5 to about 0.9 and most preferably from 0.6 to 0.8. It is further preferred for Y to be in the range of from about 0.1 to about 0.5, and most preferably from 0.2 to 0.4. Preferably, Y is equal to (1-X).

The regenerated solid sorbent particulates exiting regenerator 14 can comprise zinc oxide, the oxidized promoter metal component (M_xZn_YO), the porosity enhancer (PE), and the promoter metal-zinc aluminate (M_zZn₍₁._z)Ai₂θ₄) in the ranges provided below in Table 4.

After regeneration in regenerator 14, the regenerated (i.e., oxidized) solid sorbent particulates are transported to reducer 16 via a second transport assembly 20. In reducer 16, the regenerated solid sorbent particulates are contacted with a hydrogen- containing reducing stream. The hydrogen-containing reducing stream preferably comprises at least 50 mole percent hydrogen with the remainder being cracked hydrocarbon products such as, for example, methane, ethane, and propane. More preferably, the hydrogen-containing reducing stream comprises about 70 mole percent hydrogen, and most preferably at least 80 mole percent hydrogen. The reducing conditions in reducer 16 are sufficient to reduce the valence of the oxidized promoter metal component of the regenerated solid sorbent particulates. The preferred ranges for such reducing conditions are provided below in Table 5.

When the regenerated solid sorbent particulates are contacted with the hydrogen-containing reducing stream in reducer 16 under the reducing conditions described above, at least a portion of the oxidized promoter metal component is reduced to form the reduced- valence promoter metal component. Preferably, at least a substantial portion of the substitutional solid metal oxide solution (M_xZn_YO) is converted to the reduced-valence promoter metal component (M_AZn_B).

After the solid sorbent particulates have been reduced in reducer 16, they can be transported back to reactor 12 via a third transport assembly 22 for recontacting with the hydrocarbon-containing fluid stream in reactor 12. Referring again to FIG. 1, first transport assembly 18 generally comprises a reactor pneumatic lift 24, a reactor receiver 26, and a reactor lockhopper 28 fluidly disposed between reactor 12 and regenerator 14. During operation of desulfurization unit 8 the sulfur-loaded sorbent particulates are continuously withdrawn from reactor 12 and lifted by reactor pneumatic lift 24 from reactor 12 to reactor receiver 18. Reactor receiver 18 is fluidly coupled to reactor 12 via a reactor return line 30. The lift gas used to transport the sulfur-loaded sorbent particulates from reactor 12 to reactor receiver 26 is separated from the sulfur-loaded sorbent particulates in reactor receiver 26 and returned to reactor 12 via reactor return line 30. Reactor lockhopper 26 is operable to transition the sulfur-loaded sorbent particulates from the high pressure hydrocarbon environment of reactor 12 and reactor receiver 26 to the low pressure oxygen environment of regenerator

14. To accomplish this transition, reactor lockhopper 28 periodically receives batches of the sulfur-loaded sorbent particulates from reactor receiver 26, isolates the sulfur-loaded sorbent particulates from reactor receiver 26 and regenerator 14, and changes the pressure and composition of the environment surrounding the sulfur-loaded sorbent particulates from a high pressure hydrocarbon environment to a low pressure inert (e.g., nitrogen) environment. After the environment of the sulfur-loaded sorbent particulates has been transitioned, as described above, the sulfur-loaded sorbent particulates are batch-wise transported from reactor lockhopper 28 to regenerator 14. Because the sulfur-loaded solid particulates are continuously withdrawn from reactor 12 but processed in a batch mode in reactor lockhopper 28, reactor receiver 26 functions as a surge vessel wherein the sulfur-loaded sorbent particulates continuously withdrawn from reactor 12 can be accumulated between transfers of the sulfur-loaded sorbent particulates from reactor receiver 26 to reactor lockhopper 28. Thus, reactor receiver 26 and reactor lockhopper 28 cooperate to transition the flow of the sulfur-loaded sorbent particulates between reactor 12 and regenerator 14 from a continuous mode to a batch mode. Second transport assembly 20 generally comprises a regenerator pneumatic lift 32, a regenerator receiver 34, and a regenerator lockhopper 36 fluidly disposed between regenerator 14 and reducer 16. During operation of desulfurization unit 8 the regenerated sorbent particulates are continuously withdrawn from regenerator 14 and lifted by regenerator pneumatic lift 32 from regenerator 14 to regenerator receiver 34. Regenerator receiver 34 is fluidly coupled to regenerator 14 via a regenerator return line

38. The lift gas used to transport the regenerated sorbent particulates from regenerator 14 to regenerator receiver 34 is separated from the regenerated sorbent particulates in regenerator receiver 34 and returned to regenerator 14 via regenerator return line 38. Regenerator lockhopper 36 is operable to transition the regenerated sorbent particulates from the low pressure oxygen environment of regenerator 14 and regenerator receiver 34 to the high pressure hydrogen environment of reducer 16. To accomplish this transition, regenerator lockhopper 36 periodically receives batches of the regenerated sorbent particulates from regenerator receiver 34, isolates the regenerated sorbent particulates from regenerator receiver 34 and reducer 16, and changes the pressure and composition of the environment surrounding the regenerated sorbent particulates from a low pressure oxygen environment to a high pressure hydrogen environment. After the environment of the regenerated sorbent particulates has been transitioned, as described above, the regenerated sorbent particulates are batch-wise transported from regenerator lockhopper 36 to reducer 16. Because the regenerated sorbent particulates are continuously withdrawn from regenerator 14 but processed in a batch mode in regenerator lockhopper

36, regenerator receiver 34 functions as a surge vessel wherein the sorbent particulates continuously withdrawn from regenerator 14 can be accumulated between transfers of the regenerated sorbent particulates from regenerator receiver 34 to regenerator lockhopper 36. Thus, regenerator receiver 34 and regenerator lockhopper 36 cooperate to transition the flow of the regenerated sorbent particulates between regenerator 14 and reducer 16 from a continuous mode to a batch mode. The following examples are presented to further illustrate this invention and are not to be construed as unduly limiting the scope of this invention.

EXAMPLE I This example demonstrates that 4,6-dimethyldibenzothiophene can be oxidized to its sulfoxide and or sulfone derivative by contacting it with a mixture of peroxyacetic acid and acetic acid.

A mixture of 0.67g of a 32 weight percent mixture of peroxyacetic acid (CH₃CO₃H) acetic acid in 64.04g of toluene was prepared and charged to a 300 mL Hastelloy^® C autoclave. The contents of the autoclave were then stirred at 500 rpm. A solution of 0.601g pure 4,6-dimethyldibenzothiophene (DMDBT) in 35.95g toluene was prepared and added to the autoclave initially at room temperature (23-3°C) (74°F). After the addition was complete, the autoclave was then heated to 60.38°C (140.7°F) over 70 minutes, then held at 60-60.5°C (140-141°F) for an additional 30 minutes.

The autoclave was allowed to cool, then disassembled. The contents were transferred to a suitable beaker, and solid material was observed. The mixture was washed with 5% NaHCO₃ and filtered to obtain 0.224g of solids.

The toluene layer was analyzed by gas chromatography/mass spectrometry and three distinct peaks were observed. The mass spectrometer showed the first peak to be unreacted DMDBT (8.5%, base peak at m/e 212), followed by the di-oxo DMDBT (sulfone derivative, 22.3%, base peak at m e 244) and the mono-oxo DMDBT (sulfoxide derivative, 69.2%, base peak at m/e 228). The toluene was removed by rotary evaporation, and the solids redissolved in warm EtOH/CH2CI2 solution. Upon cooling, crystals were obtained and removed by filtration (0.18g crystals). By comparison of the mass spectrometer results to standard solutions in toluene, a 68% conversion of the starting compound was obtained. The remaining EtOH/CH2CL2 was removed by rotary evaporation to yield 0.258g of solid (total solids recovery = 0.50g). The infrared spectrum of the crude solids obtained from the stripping of the solvents showed the presence of strong vibrational bands at ~ 1300 and 1150 wavenumbers, which are assigned to the asymmetric and symmetric stretches, respectively, of a sulfone (SO2 group). The infrared spectrum of the recrystallized material showed medium intensity bands at 1300 and 1150 wavenumbers but also a very strong band at 1009 wavenumbers. This band was believed to result from a sulfoxide (S=O group). Thus, the unrecrystallized solids were primarily the sulfone and the recrystallized material was enriched in the sulfoxide product. These results show the given conditions were sufficient to oxidize 4,6-DMDBT to the sulfoxide and or sulfone derivative(s). EXAMPLE 2

This example demonstrates that sulfur compounds in diesel fuel can be oxidized by contacting it with a mixture of peroxyacetic acid and acetic acid.

An 85.68g sample of diesel fuel was charged to a 300mL autoclave. The diesel fuel contained 547 ppmw sulfur and 119 ppmw nitrogen as measured by an ANTEK Model #9000 sulfur/nitrogen analyzer (available from ANTEK Instruments L.P. ,

Houston, Texas). Stirring was initiated at 500 rpm with heating to 57.7°C (136°F). Over a one minute period was added a mixture of 0.90g of 32 weight percent CH3C03H/acetic acid with 19.75g toluene. The contents of the reactor were then allowed to stir for 2 hours, holding the temperature between 59.00°C and 60 - 22°C (138.2 and 140.4°F). At this time, heating was stopped and the reactor allowed to cool for 30 minutes. After disassembly of the autoclave, an equal volume of 5% NaHC03 solution in water was added and the contents transferred to a separatory funnel. The lower aqueous phase was decanted. The upper hydrocarbon phase was washed with another volume of water, dried over anhydrous MgSO4, and filtered. The filtrate was collected and volatiles removed by rotary evaporation at 70°C and reduced pressure 71.12 cm

((28") water vacuum). A residual liquid mass of 86.02g was obtained. The residual material was analyzed by the Antek instrument, described above, and found to contain 518 ppmw total sulfur and 97.1 ppmw total nitrogen.

Both the feed and oxidized product were analyzed by gc using a sulfur specific detector. The resultant chromatograms (see FIGS. 2 and 3) show the oxidized material to contain more sulfur species between the retention times of about 36 minutes and 45 minutes. This indicates an increase in higher boiling sulfur species, in agreement with an expected increase in boiling point due to the incorporation of oxygen into the sulfur species. EXAMPLE 3

This example demonstrates that the oxidized diesel fuel provided in Example 2 can be desulfurized with a reduced-valence, nickel promoted, zinc oxide- based sorbent.

A 1000 mL quantity of the oxidized diesel obtained in Example 2 was blended with 1000 mL of a diesel fuel containing less than 5 ppmw sulfur. The resulting oxidized diesel mixture was analyzed by the ANTEK instrument (described above in

Example 2) and determined to contain 55.19 ppmw sulfur and 83.06 ppmw nitrogen.

The oxidized diesel mixture was then desulfurized by contacting the diesel mixture with a calcined and reduced sorbent composition in a fixed bed reactor. The reactor was a standard steel reactor having a 19.0 mm (3/4 inch) inner diameter and a 6.35 mm (1/4 inch) thermowell. The exact composition of the sorbent was not analyzed, but the initial sorbent ingredients were as follows: zinc oxide (41 weight percent), silica (33 weight percent), alumina (8 weight percent), and nickel (22 weight percent). In view of detailed compositional analyses performed on similarly prepared sorbents, it is postulated that upon calcination of the sorbent, at least a portion of the nickel and zinc oxide components combined to form a substitutional solid metal oxide solution (Ni_xZnO_Y) and at least a portion of the nickel, zinc oxide, and alumina components combined to form a nickel-zinc aluminate substitutional solid solution (Ni_zZn_(1-z)Al₂O₄). Upon reduction of the sorbent it is further postulated that at least a portion of the substitutional solid metal oxide solution (Ni_xZnO_Y) was reduced to a substitutional solid metal solution (Ni_AZn_B). The sorbent used in the reactor was in the form of 1/16 inch extrudates.

The reactor loading (from bottom up) was as follows: (1) 5 inches of R268 alundum; (2) 39 grams of 36 grit alundum; (3) dry packed bed of diluted sorbent - 30.5 grams of the sorbent mixed with 109 grams of 30/40 grit alundum; and (4) 26 grams of 36 grit alundum (pre-heat section). The reaction conditions under which the oxidized diesel mixture was contacted with the calcined and reduced sorbent included a temperature of about 398.8°C (750°F), a pressure of about 3,546 kPa (500 psig), and a diesel flow rate of about 2 LHSN. As used herein, LHSN is liquid hourly space velocity and is the numerical ratio of the rate at which hydrocarbon feedstock is charged to the reactor in volume per hour divided by the volume of sorbent contained in the reactor to which the hydrocarbon feedstock is being charged, i.e., volume/volume/hour (hr ¹). Prior to contacting the oxidized diesel with the sorbent, the oxidized diesel was mixed with hydrogen flowing at a rate of 5000 SCFB, wherein SCFB is defined as standard cubic feet of gas per barrel of hydrocarbon feed, at 21.1°C (70°F) one atmosphere pressure. Samples of the desulfurized reactor effluent were taken at 7 and 19 hours on stream. The samples were then analyzed with the ANTEK instrument and the results are shown in Table 6.

The results displayed in Table 6 demonstrate that sulfur levels of diesel can be dramatically reduced by first oxidizing certain sulfur compounds in the diesel fuel and then contacting the oxidized diesel fuel with a sulfur sorbent.

Reasonable variations, modifications, and adaptations may be made within the scope of this disclosure and the appended claims without departing from the scope of this invention.

Claims

C L A I M S

1. A desulfurization process comprising the steps of:

(a) contacting a hydrocarbon-containing fluid containing sulfur compounds with an oxidizing agent under oxidation conditions sufficient to oxidize at least a portion of said sulfur compounds, thereby providing an oxidized hydrocarbon- containing fluid comprising oxidized sulfur compounds; and

(b) contacting said oxidized hydrocarbon-containing fluid with a sorbent comprising a promoter metal component and zinc oxide under desulfurization conditions sufficient to remove at least a portion of said oxidized sulfur compounds from said oxidized hydrocarbon-containing fluid.

2. A desulfurization process in accordance with claim 1, wherein said oxidizing agent is selected from the group consisting of bromine, bromates, chlorinated isocyanurates, chlorates, chromates, dichromates, hydroperoxides, hypochlorites, inorganic peroxides, ketone peroxides, nitrates, nitric acid, nitrites, perborates, perchlorates, perchloric acid, periodates, permanganates, peroxides, peroxyacids, persulphates, and mixtures thereof.

3. A desulfurization process in accordance with claim 1, wherein said oxidizing agent comprises a peroxide.

4. A desulfurization process in accordance with claim 1, wherein said oxidizing agent comprises an organic peroxide.

5. A desulfurization process in accordance with claim 1, wherein said oxidizing agent comprises a peroxyacid.

6. A desulfurization process in accordance with claim 1, wherein said oxidizing agent is a mixture of peroxyacid and acetic acid.

7. A desulfurization process in accordance with claim 1, wherein said hydrocarbon-containing fluid is selected from the group consisting of middle distillates, cracked-gasoline, gasoline, and mixtures thereof, and wherein said hydrocarbon-containing fluid comprises at least about 50 ppmw of said sulfur compounds. 8. A desulfurization process in accordance with claim 7, wherein said hydrocarbon-containing fluid is a middle distillate boiling in the range of from about

148.8 to about 398.8°C (about 300 to about 750°F) and having a mid-boiling point of more than about 176.6°C (about 350°F), and wherein at least about 50 weight percent of said sulfur compounds are organosulfur compounds.

9. A desulfurization process in accordance with claim 8, wherein said hydrocarbon-containing fluid is diesel fuel boiling in the range of from 190.5 to 371.1 °C

(375 to 700°F) and having a mid-boiling point of at least 260°C (500°F), wherein said organosulfur compounds include thiophenes, and wherein at least a portion of said thiophenes are oxidized to their corresponding sulfones or sulfoxides during step (a).

10. A desulfurization process in accordance with claim 1 , wherein said sulfur compounds include 4,6-dimethyldibenzothiophene and wherein at least a portion of the

4,6-dimethyldibenzothiophene is oxidized into its corresponding sulfone or sulfoxide during step (a).

11. A desulfurization process in accordance with claim 1 , wherein said oxidation conditions include an oxidation temperature in the range of from about 10 to about 93.3°C (about 50 to about 200°F) and an oxidation pressure in the range of from about 0 to about 50 psia, and wherein said desulfurization conditions include a desulfurization temperature in the range of from about 121.1 to about 648.8°C (about 250 to about 1200°F) and a desulfurization pressure in the range of from about 273.5 to about 5,269 kPa (about 25 to about 750 psig).

12. A desulfurization process in accordance with claim 1, wherein said sorbent comprises said promoter metal component in an amount in the range of from about 5 to about 80 weight percent and said zinc oxide in an amount in the range of from about 5 to about 80 weight percent.

13. A desulfurization process in accordance with claim 1 , wherein at least a portion of said zinc oxide is converted to zinc sulfide with sulfur from said oxidized sulfur compounds during step (b).

14. A desulfurization process in accordance with claim 1 , wherein said promoter metal component comprises a promoter metal selected from the group consisting of nickel, cobalt, iron, manganese, copper, zinc, molybdenum, tungsten, silver, antimony, and vanadium.

15. A desulfurization process in accordance with claim 14, wherein said promoter metal is nickel.

16. A desulfurization process in accordance with claim 1 , wherein said promoter metal component comprises a substitutional solid metal solution characterized by the formula M_AZn_B, wherein M is a promoter metal and A and B are each numerical values in the range of 0.01 to 0.99.

17. A desulfurization process in accordance with claim 4, wherein A is in the range of from about 0.70 to about 0.97 and B is in the range of from about 0.03 to about 0.30.

18. A desulfurization process in accordance with claim 17, wherein said promoter metal is nickel.

19. A desulfurization process in accordance with claim 1, wherein said sorbent further comprises perlite.

20. A desulfurization process in accordance with claim 1, wherein said sorbent further comprises an aluminate.

21. A desulfurization process in accordance with claim 20, wherein said aluminate is a promoter metal-zinc aluminate substitutional solid solution characterized by the formula M_zZn₍₁._z)Al₂O₄, wherein M is a promoter metal and Z is a numerical value in the range of from 0.01 to 0.99.

22. A desulfurization process comprising the steps of: (a) contacting a middle distillate containing thiophene compounds with an oxidizing agent under oxidizing conditions sufficient to convert at least a portion of said thiophene compounds to oxidized sulfur compounds selected from the group consisting of sulfones, sulfoxides, and mixtures thereof, thereby providing an oxidized middle distillate; and (b) contacting said oxidized middle distillate with a sorbent comprising a promoter metal component and zinc oxide under desulfurization conditions sufficient to remove at least a portion of said oxidized sulfur compounds from said oxidized middle distillate.

23. A desulfurization process in accordance with claim 22, wherein said middle distillate comprises at least about 50 ppmw of sulfur compounds, and wherein at least about 50 weight percent of said sulfur compounds are organosulfur compounds.

24. A desulfurization process in accordance with claim 23, wherein said thiophene compounds include dimethyldibenzothiophenes and wherein said oxidizing agent is selected from the group consisting of bromine, bromates, chlorinated isocyanurates, chlorates, chromates, dichromates, hydroperoxides, hypochlorites, inorganic peroxides, ketone peroxides, nitrates, nitric acid, nitrites, perborates, perchlorates, perchloric acid, periodates, permanganates, peroxides, peroxyacids, persulphates, and mixtures thereof.

25. A desulfurization process in accordance with claim 24, wherein said thiophene compounds include 4,6-dimethyldibenzothiophene and wherein said oxidizing agent is a peroxide.

26. A desulfurization process in accordance with claim 22, wherein said middle distillate boils in the range of from about 148.8 to about 398.8°C (about 300 to about 750°F), has a mid-boiling point of at least about 176.6°C (about 350°F), and comprises in the range of from about 100 to about 50,000 ppmw of sulfur compounds, and wherein at least about 75 weight percent of said sulfur compounds are organosulfur compounds.

27. A desulfurization process in accordance with claim 26, wherein said middle distillate is diesel fuel boiling in the range of from 190.3 to 371.1°C (375 to 700°F), having a mid-boiling point of at least 260°C (500°F), having an API gravity in the range of from 30 to 38, and having a minimum flash point of at least 37.7°C (100°F).

28. A desulfurization process in accordance with claim 22, wherein said promoter metal component is a reduced- valence promoter metal component.

29. A desulfurization process in accordance with claim 22, wherein said promoter metal component comprises said promoter metal component in an amount in the range of from about 5 to about 80 weight percent and said zinc oxide in an amount in the range of from about 5 to about 80 weight percent.

30. A desulfurization process in accordance with claim 29, wherein said promoter metal component comprises a promoter metal selected from the group consisting of nickel, cobalt, iron, manganese, copper, zinc, molybdenum, tungsten, silver, antimony, and vanadium.

31. A desulfurization process in accordance with claim 30, wherein said promoter metal is nickel.

32. A desulfurization process in accordance with claim 22, wherein said promoter metal component comprises a substitutional solid metal solution characterized by the formula M_AZn_B, wherein M is a promoter metal and A and B are each numerical values in the range of 0.01 to 0.99.

33. A desulfurization process in accordance with claim 32, wherein said promoter metal is selected from the group consisting of nickel, cobalt, iron, manganese, copper, zinc, molybdenum, tungsten, silver, antimony, and vanadium, wherein A is in the range of from about 0.70 to about 0.97, and wherein B is in the range of from about 0.03 to about 0.30.

34. A desulfurization process in accordance with claim 33, wherein said promoter metal is nickel, wherein A is in the range of from about 0.85 to about 0.95, and wherein B is in the range of from about 0.05 to about 0.15.

35. A desulfurization process comprising the steps of: (a) contacting a hydrocarbon-containing fluid containing sulfur compounds with an oxidizing agent under oxidation conditions sufficient to oxidize at least a portion of said sulfur compounds, thereby providing an oxidized hydrocarbon- containing fluid comprising oxidized sulfur compounds;

(b) contacting said oxidized hydrocarbon-containing fluid with a sorbent comprising a promoter metal component and zinc oxide under desulfurization conditions sufficient to remove at least a portion of said oxidized sulfur compounds from said oxidized hydrocarbon-containing fluid, thereby providing a desulfurized hydrocarbon-containing fluid and a sulfur-loaded sorbent;

(c) contacting at least a portion of said sulfur-loaded sorbent with an oxygen-containing regeneration stream under regeneration conditions sufficient to remove sulfur from said sulfur-loaded sorbent and oxidize said promoter metal component, thereby providing a regenerated sorbent comprising an oxidized promoter metal component; and

(d) contacting at least a portion of said regenerated sorbent with a hydrogen-containing regeneration stream under reducing conditions sufficient to reduce at least a portion of said oxidized promoter metal component, thereby providing a reduced sorbent.

36. A desulfurization process in accordance with claim 35, wherein said oxidizing agent is selected from the group consisting of bromine, bromates, chlorinated isocyanurates, chlorates, chromates, dichromates, hydroperoxides, hypochlorites, inorganic peroxides, ketone peroxides, nitrates, nitric acid, nitrites, perborates, perchlorates, perchloric acid, periodates, permanganates, peroxides, peroxyacids, persulphates, and mixtures thereof.

37. A desulfurization process in accordance with claim 36, wherein said hydrocarbon-containing fluid is selected from the group consisting of middle distillates, cracked-gasoline, gasoline, and mixtures thereof.

38. A desulfurization process in accordance with claim 37, wherein said hydrocarbon-containing fluid comprises at least about 50 ppmw of said sulfur compounds, and wherein at least about 50 weight percent of said sulfur compounds are organosulfur compounds.

39. A desulfurization process in accordance with claim 35, wherein said oxidizing agent is a peroxide.

40. A desulfurization process in accordance with claim 39, wherein said hydrocarbon-containing fluid is a middle distillate boiling in the range of from about 148.8°C to about 398.8°C (about 300 to about 750°F) and having a mid-boiling point of more than about 176.6°C (350°F).

41. A desulfurization process in accordance with claim 40, wherein said hydrocarbon-containing fluid comprises in the range of from about 100 to about 50,000 ppmw of said sulfur compounds, and wherein at least about 75 weight percent of said sulfur compounds are organsulfur compounds.

42. A desulfurization process in accordance with claim 41 , wherein said organosulfur compounds include thiophenes.

43. A desulfurization process in accordance with claim 35, wherein step (d) includes converting at least a portion of said zinc oxide to zinc sulfide, and wherein step (c) includes converting at least a portion of said zinc sulfide to zinc oxide.

44. A desulfurization process in accordance with claim 35, further comprising the step of: (e) contacting said reduced sorbent with said oxidized hydrocarbon- containing fluid under said desulfurization conditions.

45. A desulfurization process in accordance with claim 35, wherein said promoter metal component comprises a promoter metal selected from the group consisting of nickel, cobalt, iron, manganese, copper, zinc, molybdenum, tungsten, silver, antimony, and vanadium.

46. A desulfurization process in accordance with claim 45, wherein said promoter metal component comprises a substitutional solid metal solution characterized by the formula M_AZn_B, wherein M is said promoter metal and A and B are each numerical values in the range of 0.01 to 0.99.

47. A desulfurization process in accordance with claim 46, wherein said oxidized promoter metal component comprises a substitutional solid metal oxide solution characterized by the formula M_xZn_YO, wherein M is said promoter metal and X and Y are each numerical values in the range of from 0.01 to 0.99.

48. A desulfurization process in accordance with claim 47, wherein step (d) includes converting at least a portion of said substitutional solid metal oxide solution to said substitutional solid metal solution.

49. A desulfurized hydrocarbon-containing fluid produced by the process of claim 1.

50. A desulfurized middle distillate produced by the process of claim 22.

51. A desulfurized hydrocarbon-containing fluid produced by the process of claim 35.