US20140353208A1

US20140353208A1 - Hydrocarbon conversion processes using ionic liquids

Info

Publication number: US20140353208A1
Application number: US13/906,720
Authority: US
Inventors: Rajeswar R. Gattupalli; Beckay J. Mezza; Alakananda Bhattacharyya; Robert B. James; Massimo Sangalli; Peter Van Opdorp
Original assignee: UOP LLC
Current assignee: Honeywell UOP LLC
Priority date: 2013-05-31
Filing date: 2013-05-31
Publication date: 2014-12-04
Also published as: WO2014193537A1

Abstract

A method of hydrocarbon conversion is described. The hydrocarbon feed is decontaminated using an ionic liquid and introduced into a conversion zone. The conversion of the decontaminated feed is increased compared to the conversion of the contaminated feed and the yield of the desired product made from the decontaminated hydrocarbon feed is increased compared to the yield of the desired product made from the contaminated hydrocarbon feed.

Description

BACKGROUND OF THE INVENTION

Vacuum gas oil (VGO) is a hydrocarbon fraction that may be converted into higher value hydrocarbon fractions such as diesel fuel, jet fuel, naphtha, gasoline, and other lower boiling fractions in refining processes such as hydrocracking and fluid catalytic cracking (FCC). However, hydrocarbon feed streams having higher amounts of contaminants, such as sulfur and nitrogen are more difficult to convert. For example, the degree of conversion, product yields, catalyst deactivation, and/or ability to meet product quality specifications may be adversely affected by the sulfur or nitrogen content of the feed stream.
Therefore, various processes have been developed to remove contaminants from hydrocarbon feed. It is known to reduce the sulfur content of VGO by catalytic hydrogenation reactions such as in a hydrotreating process unit. While the hydrotreating process increases conversion, the hydrotreating process units are very expensive and require substantial amounts of hydrogen.
Various processes using ionic liquids to remove sulfur and nitrogen compounds from hydrocarbon fractions are also known. U.S. Pat. No. 7,001,504 B2 discloses a process for the removal of organosulfur compounds from hydrocarbon materials which includes contacting an ionic liquid with a hydrocarbon material to extract sulfur containing compounds into the ionic liquid. U.S. Pat. No. 7,553,406 B2 discloses a process for removing polarizable impurities from hydrocarbons and mixtures of hydrocarbons using ionic liquids as an extraction medium. U.S. Pat. No. 7,553,406 B2 also discloses that different ionic liquids show different extractive properties for different polarizable compounds.
There remains a need in the art for improved conversion processes for hydrocarbon feeds having contaminants.

SUMMARY OF THE INVENTION

One aspect of the invention is a method of hydrocarbon conversion. In one embodiment, the method includes contacting a hydrocarbon feed containing a contaminant with a hydrocarbon feed-immiscible ionic liquid to form a mixture comprising decontaminated hydrocarbon feed and hydrocarbon feed-immiscible ionic liquid containing the contaminant. The decontaminated hydrocarbon feed is reacted in a conversion zone to produce a desired product selected from gasoline, diesel, naphtha, distillate, jet, light olefins, or combinations thereof. The conversion of the decontaminated hydrocarbon feed is increased compared to the conversion of the contaminated feed under comparable operating conditions, or the yield of the desired product made from the decontaminated hydrocarbon feed is increased compared to the yield of the desired product made from the contaminated hydrocarbon feed under comparable operating conditions, or both.
Another aspect of the invention is a method of fluid catalytic cracking. In one embodiment, the method includes contacting a hydrocarbon feed containing a contaminant with a hydrocarbon feed-immiscible ionic liquid to form a mixture comprising decontaminated hydrocarbon feed and feed-immiscible ionic liquid containing the contaminant, wherein the contaminated feed is selected from the group consisting of vacuum gas oil, coker gas oil, light cycle oil, vacuum residue, or combinations thereof, and wherein the hydrocarbon feed-immiscible ionic liquid comprises at least one of an imidazolium ionic liquid, a phosphonium ionic liquid, and a pyridinium ionic liquid. The mixture is separated into a decontaminated hydrocarbon feed stream and a hydrocarbon feed-immiscible ionic liquid stream containing the contaminant. The decontaminated hydrocarbon feed stream is reacted in a catalytic conversion zone in the presence of a catalyst under catalytic conversion conditions to produce gasoline desired product selected from gasoline, diesel, naphtha, distillate, jet, light olefins, or combinations thereof. The conversion of the decontaminated hydrocarbon feed is increased compared to the conversion of the contaminated hydrocarbon feed under comparable operating conditions, or the yield of the desired product made from the decontaminated hydrocarbon feed is increased compared to the yield of the desired product made from the contaminated hydrocarbon feed under comparable operating conditions, or both.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a simplified flow scheme illustrating various embodiments of the conversion processes.

FIGS. 2A and 2B are simplified flow schemes illustrating different embodiments of an extraction zone that can be used in the conversion processes.

DETAILED DESCRIPTION OF THE INVENTION

The terms “vacuum gas oil”, “VGO”, “VGO phase” and similar terms relating to vacuum gas oil as used herein are to be interpreted broadly to receive not only their ordinary meanings as used by those skilled in the art of producing and converting such hydrocarbon fractions, but also in a broad manner to account for the application of our processes to hydrocarbon fractions exhibiting VGO-like characteristics. Thus, the terms encompass straight run VGO as may be produced in a crude fractionation section of an oil refinery, as well as, VGO product cuts, fractions, or streams that may be produced, for example, by coker, deasphalting, and visbreaking processing units, or which may be produced by blending various hydrocarbons.
In general, VGO comprises petroleum hydrocarbon components boiling in the range of from about 100° C. to about 720° C. In an embodiment, the VGO boils from about 250° C. to about 650° C. and has a density in the range of from about 0.80 g/cm³to about 1.2 g/cm³. In another embodiment, the VGO boils from about 95° C. to about 580° C.; and in a further embodiment, the VGO boils from about 300° C. to about 720° C.
The term “coker gas oil” means the hydrocarbon material boiling in the range between about 260° C. and about 600° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The hydrocarbon material may be more contaminated and contain a greater amount of aromatic compounds than is typically found in refinery products.
The term “heavy coker gas oil” means the hydrocarbon material boiling in the range between about 300° C. and about 620° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The hydrocarbon material may be more contaminated and contain a greater amount of aromatic compounds than is typically found in refinery products.
The term “light cycle oil” means the hydrocarbon material boiling in the range between about 205° C. and about 400° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The hydrocarbon material may be more contaminated and contain a greater amount of aromatic compounds than is typically found in refinery products.
The term “vacuum residue” means the hydrocarbon material boiling of at least about 510° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The hydrocarbon material may be more contaminated and contain a greater amount of aromatic compounds than is typically found in refinery products.
The term “light olefins” means the hydrocarbon material boiling in the range less than 38° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The term “light olefins” includes C₂, C₃, and C₄olefins.
The term “diesel” means the hydrocarbon material boiling in the range between about 150° C. and about 370° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The hydrocarbon material may be more contaminated and contain a greater amount of aromatic compounds than is typically found in refinery products.
The term “naphtha” means the hydrocarbon material boiling in the range between about 10° C. and about 200° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The hydrocarbon material may be more contaminated and contain a greater amount of aromatic compounds than is typically found in refinery products.
The term “gasoline” means the hydrocarbon material boiling in the range between about 10° C. (80° F.) and about 185° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The hydrocarbon material may be more contaminated and contain a greater amount of aromatic compounds than is typically found in refinery products.
The term “distillate” means the hydrocarbon material boiling in the range between about 150° C. and about 420° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The hydrocarbon material may be more contaminated and contain a greater amount of aromatic compounds than is typically found in refinery products.
The term “jet fuel” means the hydrocarbon material boiling in the range between about 120° C. and about 300° C. atmospheric equivalent boiling point (AEBP) as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, all of which are used by the petroleum industry. The hydrocarbon material may be more contaminated and contain a greater amount of aromatic compounds than is typically found in refinery products.
The term “cetane number” means a diesel fuel rating comparable to the octane-number rating for gasoline. Typically, it is the percentage of cetane (C₁₆H₃₄) that is mixed with heptamethylnonane to give the same ignition performance under standard conditions as the fuel in question. The derived cetane number for a diesel fuel can be determined by ASTM D6890-09.
The term “contaminant” means one or more species found in the hydrocarbon material that is detrimental to further processing. Contaminants include, but are not limited to, nitrogen, sulfur, metals (e.g., nickel, iron, and vanadium) and Conradson carbon residue or carbon residue. The metals content of such components, for example, may be in the range of 100 ppm to 2,000 ppm by weight, the total sulfur content may range from 0.1 to 7 wt %, the nitrogen content may be from about 100 ppm to 30,000 ppm, and the API gravity may range from about −5° to about 35°. The Conradson carbon residue of such components is generally less than 30 wt %.
The nitrogen content may be determined using ASTM method D4629-02, Trace Nitrogen in Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and Chemiluminescence Detection. The sulfur content may be determined using ASTM method D5453-00, Ultraviolet Fluorescence; and the metals content may be determined by UOP389-09, Trace Metals in Oils by Wet Ashing and ICP-OES. The Conradson carbon residue may be determined by ASTM D4530. Unless otherwise noted, the analytical methods used herein such as ASTM D5453-00 and UOP389-09 are available from ASTM International, 100 Barr Harbor Drive, West Conshohocken, Pa., USA.
It has been discovered that use of ionic liquids to remove contaminants does not chemically interact with the hydrocarbon feed. It has also been discovered that conversion processes using hydrocarbon feed decontaminated using ionic liquids have improved conversion and/or selectivity compared to conversion processes using contaminated feeds. Conversion is defined in terms of change in endpoint.
Conversion=((EP⁺ _feed−EP⁺ _product)/EP⁺ _feed)×100%
Where EP⁺ indicates the fraction of material in the feed or product boiling above the desired endpoint.
Yield is defined as the rate of formation of desired product relative to the feed rate.
Yield=(Production Rate of Desired Product)/(Feed Rate)×100%
Selectivity is expressed as the yield of desired product relative to conversion.
Selectivity=Yield/Conversion×100%
The conversion of the decontaminated feed can be improved by at least about 0.5 vol % compared to the conversion from the contaminated feed under comparable conditions, or at least about 1%, or at least about 2 vol %, or at least about 3 vol %, or at least about 4 vol %, or at least about 4.5 vol %, or at least about 5 vol %, or at least about 5.5 vol %.
The yield of the desired products can be improved by at least about 0.5 vol %, or at least about 1.0 vol %, or at least about 1.5 vol %, or at least about 2.0 vol %, or at least about 2.5 vol %, or at least about 3.0 vol %, or at least about 3.5 vol %.
The selectivity of the desired products can be improved by at least 0.1 vol % under comparable conditions, or at least 0.5 vol %, or at least 1.0 vol %, or at least 1.5 vol %.
The hydrocarbon feed can be a single hydrocarbon feed stream, or two or more streams may be combined. Suitable hydrocarbon feed streams include, but are not limited to, vacuum gas oil, coker gas oil, light cycle oil, vacuum residue. The density of the hydrocarbon feed is typically in the range of about 0.8 g/cc to about 1.1 g/cc.
All or only a portion of the feed to the conversion zone can be treated with the ionic liquid to remove contaminants. For example, when a highly contaminated feed, such as heavy coker gas oil (HCGO), is combined with a less contaminated feed, such as VGO, treatment of the HCGO stream alone may be sufficient to reduce the contaminant level in the overall feed to an appropriate level for the conversion zone. In this case, a smaller stream of HCGO can be treated, which would reduce the capital and operating costs of the contaminant removal.
In other cases, treatment of both hydrocarbon feed streams may be desirable. If both streams are to be treated, the streams can be combined before the contaminant removal, or the streams can be treated separately and then combined.
In the conversion methods, a hydrocarbon feed containing a contaminant is contacted with a hydrocarbon feed-immiscible ionic liquid to form a mixture comprising decontaminated hydrocarbon feed and hydrocarbon feed-immiscible ionic liquid containing the contaminant. The decontaminated hydrocarbon feed is reacted in a conversion zone to produce a desired product. The product can include gasoline, diesel, naphtha, distillate, jet, light olefins, or combinations thereof. The conversion of the decontaminated hydrocarbon feed is increased compared to the conversion of the contaminated hydrocarbon feed under comparable operating conditions, and/or the selectivity of the desired product made from the decontaminated hydrocarbon feed is increased compared to the selectivity of the desired product made from the contaminated hydrocarbon feed under comparable operating conditions.
The ionic liquid can remove one or more of the contaminants in the hydrocarbon feed. The hydrocarbon feed will usually comprise a plurality of nitrogen compounds of different types in various amounts. Thus, at least a portion of at least one type of nitrogen compound may be removed from the hydrocarbon feed. The same or different amounts of each type of nitrogen compound can be removed, and some types of nitrogen compounds may not be removed. In an embodiment, the nitrogen content of the vacuum gas oil is reduced by at least about 20 wt %, or at least about 30 wt %, or at least 40 wt %, or at least about 50 wt %, or at least about 60 wt %, or at least about 70 wt %, or at least 80 wt %.
The hydrocarbon feed will typically also comprise a plurality of sulfur compounds of different types in various amounts. Thus, at least a portion of at least one type of sulfur compound may be removed from the hydrocarbon feed. The same or different amounts of each type of sulfur compound may be removed, and some types of sulfur compounds may not be removed. In an embodiment, the sulfur content of the hydrocarbon feed is reduced by at least 3 wt %, at least about 15 wt %, or at least 20 wt %, or at least about 30 wt %, or at least about 40 wt %, or at least about 50 wt %, or at least about 60 wt %, or at least about 70 wt %, or at least 80 wt %.
The hydrocarbon feed will usually contain various metals, including, but not limited to, nickel, iron, and vanadium. In an embodiment, the metal content of the hydrocarbon feed can be reduced by at least about 10% on an elemental basis, or at least about 20 wt %, or at least about 25 wt %, or at least about 30 wt %, or at least about 40 wt %, or at least about 50%. In some embodiments, at least about 15% of the nickel and vanadium are removed from the hydrocarbon feed on a combined weight basis, or at least about 25% of the nickel and vanadium from the hydrocarbon feed on a combined weight basis. For example, 40% of the nickel and vanadium can be removed from the hydrocarbon feed on a combined weight basis if the hydrocarbon feed contains 80 ppm-wt nickel and 120 ppm-wt vanadium and the hydrocarbon feed effluent contains 20 ppm-wt nickel and 100 ppm-wt vanadium. The metal removed may be part of a hydrocarbon molecule or complexed with a hydrocarbon molecule.
One or more ionic liquids are used to extract one or more contaminants from the hydrocarbon feed. Generally, ionic liquids are non-aqueous, organic salts composed of ions where the positive ion is charge balanced with a negative ion. These materials have low melting points, often below 100° C., undetectable vapor pressure, and good chemical and thermal stability. The cationic charge of the salt is localized over hetero atoms, such as nitrogen, phosphorous, sulfur, arsenic, boron, antimony, and aluminum, and the anions may be any inorganic, organic, or organometallic species.
Ionic liquids suitable for use in the instant invention are hydrocarbon feed-immiscible ionic liquids. As used herein the term “hydrocarbon feed-immiscible ionic liquid” means the ionic liquid is capable of forming a separate phase from hydrocarbon feed under the operating conditions of the process. Ionic liquids that are miscible with hydrocarbon feed at the process conditions will be completely soluble with the hydrocarbon feed; therefore, no phase separation will be feasible. Thus, hydrocarbon feed-immiscible ionic liquids may be insoluble with or partially soluble with the hydrocarbon feed under the operating conditions. An ionic liquid capable of forming a separate phase from the hydrocarbon feed under the operating conditions is considered to be hydrocarbon feed-immiscible. Ionic liquids according to the invention may be insoluble, partially soluble, or completely soluble (miscible) with water.
In an embodiment, the hydrocarbon feed-immiscible ionic liquid comprises at least one of an imidazolium ionic liquid, a pyridinium ionic liquid, and a phosphonium ionic liquid. In another embodiment, the hydrocarbon feed-immiscible ionic liquid consists essentially of imidazolium ionic liquids, pyridinium ionic liquids, phosphonium ionic liquids and combinations thereof. In still another embodiment, the hydrocarbon feed-immiscible ionic liquid is selected from the group consisting of imidazolium ionic liquids, pyridinium ionic liquids, phosphonium ionic liquids and combinations thereof. Imidazolium and pyridinium ionic liquids have a cation comprising at least one nitrogen atom. Phosphonium ionic liquids have a cation comprising at least one phosphorous atom.
The ionic liquid comprises at least one ionic liquid from at least one of the following ionic liquids: tetraalkylphosphonium dialkylphosphates, tetraalkylphosphonium dialkyl phosphinates, tetraalkylphosphonium phosphates, tetraalkylphosphonium tosylates, tetraalkylphosphonium sulfates, tetraalkylphosphonium sulfonates, tetraalkylphosphonium carbonates, tetraalkylphosphonium metalates, oxometalates, tetraalkylphosphonium mixed metalates, tetraalkylphosphonium polyoxometalates, and tetraalkylphosphonium halides.
In an embodiment, the hydrocarbon feed-immiscible ionic liquid comprises at least one of 1-ethyl-3-methylimidazolium ethyl sulfate, 1-butyl-3-methylimidazolium hydrogen sulfate, 1-ethyl-3-methylimidazolium chloride, 1-butyl-3-methylimidazolium chloride, 1-butyl-3-methylimidazolium trifluoromethanesulfonate, 1-butyl-4-methylpyridinium chloride, N-butyl-3-methylpyridinium methylsulfate, trihexyl(tetradecyl)phosphonium chloride, trihexyl(tetradecyl)phosphonium bromide, tributyl(methyl)phosphonium bromide, tributyl(methyl)phosphonium chloride, tributyl(hexyl)phosphonium bromide, tributyl(hexyl)phosphonium chloride, tributyl(octyl)phosphonium bromide, tributyl(octyl)phosphonium chloride, tributyl(decyl)phosphonium bromide, tributyl(decyl)phosphonium chloride, tetrabutylphosphonium bromide, tetrabutylphosphonium chloride, triisobutyl(methyl)phosphonium tosylate, tributyl(ethyl)phosphonium diethylphosphate, tetrabutylphosphonium methanesulfonate, pyridinium p-toluene sulfonate.
The hydrocarbon feed-immiscible ionic liquid may comprise at least one of 1-butyl-3-methylimidazolium trifluoromethanesulfonate, 1-butyl-4-methylpyridinium chloride, N-butyl-3-methylpyridinium methylsulfate, trihexyl(tetradecyl)phosphonium chloride, trihexyl(tetradecyl)phosphonium bromide, tributyl(hexyl)phosphonium chloride, tributyl(octyl)phosphonium chloride, tetrabutylphosphonium chloride, and tributyl(ethyl)phosphonium diethylphosphate.
The decontamination step can comprise a contacting step and a separating step. In the contacting step, the hydrocarbon feed comprising the contaminant(s) and a hydrocarbon feed-immiscible ionic liquid are contacted or mixed. The contacting may facilitate transfer of one or more contaminants from the hydrocarbon feed to the ionic liquid. Although a hydrocarbon feed-immiscible ionic liquid that is partially soluble in hydrocarbon feed may facilitate transfer or extraction of the contaminants from the hydrocarbon feed to the ionic liquid, partial solubility is not required. Insoluble hydrocarbon feed/ionic liquid mixtures may have sufficient interfacial surface area between the hydrocarbon feed and ionic liquid to be useful. In the separation step, the mixture of hydrocarbon feed and ionic liquid containing the contaminant settles or forms two phases: a decontaminated hydrocarbon feed phase and an ionic liquid phase containing the contaminants. The two phases are then separated to produce a hydrocarbon feed-immiscible ionic liquid effluent containing the contaminants and a decontaminated hydrocarbon feed effluent.
The decontaminated hydrocarbon feed effluent is then sent to a conversion zone where the decontaminated hydrocarbon feed is converted to a desired product. Suitable desired products include, but are not limited to, gasoline, diesel, naphtha, distillate, jet fuel, light olefins, or combinations thereof;
Typical conversion processes include, but are not limited to fluid catalytic cracking (FCC), hydrotreating, and hydrocracking. Typical hydrocracking, hydrotreating, and fluid catalytic cracking processes are described in Chapters 3.1-3.4, 7.1-7.2, and 8.1-8.7 in Robert A. Meyers, ed. HANDBOOK OF PETROLEUM REFINING PROCESSES, Third Edition, McGraw-Hill 2003.
Fluid catalytic cracking (FCC) is a catalytic hydrocarbon conversion process accomplished by contacting heavier hydrocarbons in a fluidized reaction zone with a catalytic particulate material. The reaction in catalytic cracking is carried out in the absence of substantial added hydrogen or the consumption of hydrogen.
The process typically employs a powdered catalyst having the particles suspended in a rising flow of feed hydrocarbons to form a fluidized bed. In representative processes, cracking takes place in a riser, which is a vertical or upward sloped pipe.
Typically, a pre-heated feed is sprayed into the base of the riser via feed nozzles where it contacts hot fluidized catalyst and is vaporized on contact with the catalyst, and the cracking occurs converting the high molecular weight oil into lighter components including liquefied petroleum gas (LPG), gasoline, and a distillate. The catalyst-feed mixture flows upward through the riser for a short period (few seconds) and then the mixture is separated in cyclones. The hydrocarbons are directed to a fractionator for separation into LPG, gasoline, diesel, kerosene, jet fuel, and other possible fractions.
While going through the riser, the cracking catalyst is deactivated because the process is accompanied by formation of deposit coke on the catalyst particles. Contaminated catalyst is separated from the cracked hydrocarbon vapors and is further treated with steam to remove hydrocarbon remaining in the catalyst's pores. The catalyst is then directed into a regenerator where the coke is burned off the catalyst particles surface, thus restoring the catalyst's activity and providing the necessary heat for the next reaction cycle. The process of cracking is endothermic. The regenerated catalyst is then used in the new cycle.
Zeolite-based catalysts are commonly used in FCC reactors, as are composite catalysts which contain zeolites, silica-aluminas, alumina, and other binders.
Typical FCC conditions include a temperature of about 400° C. to about 800° C., a pressure of about 0 to about 688 kPa g (about 0 to 100 psig), and contact times of about 0.1 seconds to about 1 hour. The conditions are determined based on the hydrocarbon feedstock being cracked, and the cracked products desired.
Hydrocracking refers to a process in which hydrocarbons crack in the presence of hydrogen to lower molecular weight hydrocarbons.
Hydrocracking catalysts can include amorphous silica-alumina bases or low-level zeolite bases combined with one or more Group VIII or Group VIB metal hydrogenating components, or a crystalline zeolite cracking base upon which is deposited a Group VIII metal hydrogenating component. Additional hydrogenating components may be selected from Group VIB for incorporation with the zeolite base. The active metals employed in the preferred hydrocracking catalysts of the present invention as hydrogenation components are those of Group VIII, i.e., iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum. In addition to these metals, other promoters may also be employed in conjunction therewith, including the metals of Group VIB, e.g., molybdenum and tungsten. The amount of hydrogenating metal in the catalyst can vary within wide ranges. Broadly speaking, any amount between about 0.05 percent and about 30 percent by weight may be used. In the case of the noble metals, about 0.05 to about 2 wt-% are typically used.
Hydrocracking conditions may include a temperature of about 290° C. (550° F.) to about 468° C. (875° F.), or about 343° C. (650° F.) to about 435C (815F), a pressure of about 3.5 MPa (500 psig) to about 20.7 MPa (3000 psig), a liquid hourly space velocity (LHSV) of about 1.0 to less than about 2.5 hr⁻¹, and a hydrogen rate of about 421 to about 2,527 Nm³/m³oil (2,500-15,000 scf/bbl).
Hydrotreating is a process wherein hydrogen gas is contacted with hydrocarbon in the presence of suitable catalysts which are primarily active for the removal of heteroatoms, such as sulfur, nitrogen and metals from the hydrocarbon feedstock. In hydrotreating, hydrocarbons with double and triple bonds may be saturated. Aromatics may also be saturated. Some hydrotreating processes are specifically designed to saturate aromatics.
Suitable hydrotreating catalysts are any known conventional hydrotreating catalysts and include those which are comprised of at least one Group VIII metal, preferably iron, cobalt and nickel, more preferably cobalt and/or nickel and at least one Group VI metal, preferably molybdenum and tungsten, on a high surface area support material, preferably alumina. Other suitable hydrotreating catalysts include zeolitic catalysts, as well as noble metal catalysts where the noble metal is selected from palladium and platinum. More than one type of hydrotreating catalyst be used in the same vessel. The Group VIII metal is typically present in an amount ranging from about 2 to about 20 wt-%, preferably from about 4 to about 12 wt-%. The Group VI metal will typically be present in an amount ranging from about 1 to about 25 wt-%, preferably from about 2 to about 25 wt-%.
Hydrotreating reaction conditions include a temperature of about 290° C. (550° F.) to about 455° C. (850° F.), or 316° C. (600° F.) to about 427° C. (800° F.) or 343° C. (650° F.) to about 399° C. (750° F.), a pressure of about 3.4 MPa (500 psig), or about 4.1 MPa (600 psig), to about 6.2 MPa (900 psig), a liquid hourly space velocity of about 0.5 hr⁻¹to about 4 hr⁻¹, or about 1.5 to about 3.5 hr⁻¹, and a hydrogen rate of about 168 to about 1,011 Nm³/m³oil (1,000-6,000 scf/bbl).
In addition to the improved conversion, selectivity, and/or yield, the desired product can also have improved research octane number (RON), cetane number, smoke point, nitrogen content, sulfur content, aromatic content, density.
FIG. 1 is a flow scheme illustrating various embodiments of the invention and some of the optional and/or alternate steps and apparatus encompassed by the invention. Contaminated hydrocarbon feed stream 2 and hydrocarbon feed-immiscible ionic liquid stream 4 are introduced to and contacted and separated in contaminant removal zone 100 to produce a hydrocarbon feed-immiscible ionic liquid effluent stream 8 containing the contaminant and a decontaminated hydrocarbon feed effluent stream 6. The ionic liquid stream 4 may be comprised of fresh ionic liquid stream 3 and/or one or more ionic liquid streams which are recycled in the process as described below. In an embodiment, a portion or all of decontaminated hydrocarbon feed stream 6 is passed via conduit 10 to the hydrocarbon conversion zone 800. Hydrocarbon conversion zone 800 may, for example, comprise at least one of an FCC zone, a hydrotreating zone, and a hydrocracking zone, which are well known in the art.
An optional hydrocarbon feed washing step may be used, for example, to recover ionic liquid that is entrained or otherwise remains in the decontaminated hydrocarbon feed effluent stream by using water to wash or extract the ionic liquid from the decontaminated hydrocarbon feed effluent. In this embodiment, a portion or all of the decontaminated hydrocarbon feed effluent stream 6 (as feed) and a water stream 12 (as solvent) are introduced to hydrocarbon feed washing zone 400. The decontaminated hydrocarbon feed effluent and water streams introduced to hydrocarbon feed washing zone 400 are mixed and separated to produce a washed hydrocarbon feed stream 14 and a spent water stream 16, which comprises the ionic liquid. The hydrocarbon feed washing step may be conducted in a similar manner and with similar equipment as used to conduct other liquid-liquid wash and extraction operations discussed below. Various hydrocarbon feed washing step equipment and conditions such as temperature, pressure, times, and solvent to feed ratio may be the same as or different from the contaminant removal zone equipment and conditions. In general, the hydrocarbon feed washing step conditions will fall within the same ranges as given below for the contaminant removal step conditions. A portion or all of the washed hydrocarbon feed stream 14 may be passed to hydrocarbon conversion zone 800 where it is converted to one or more product(s) 32. Unconverted feed can be recycled back to the hydrocarbon conversion zone, if desired (not shown).
An optional ionic liquid regeneration step may be used, for example, to regenerate the ionic liquid by removing the contaminant(s) from the ionic liquid, i.e. reducing the contaminant content of the rich ionic liquid. In an embodiment, a portion or all of hydrocarbon feed-immiscible ionic liquid effluent stream 8 (as feed) comprising the contaminants and a regeneration solvent stream 18 are introduced to ionic liquid regeneration zone 500. The hydrocarbon feed-immiscible ionic liquid effluent and regeneration solvent streams are mixed and separated to produce an extract stream 20 comprising the contaminants, and a regenerated ionic liquid stream 22. The ionic liquid regeneration step may be conducted in a similar manner and with similar equipment as used to conduct other liquid-liquid wash and extraction operations as discussed below. Various ionic liquid regeneration step conditions such as temperature, pressure, times, and solvent to feed may be the same as or different from the contaminant removal conditions. In general, the ionic liquid regeneration step conditions will fall within the same ranges as given for the contaminant removal step conditions.
In an embodiment, the regeneration solvent stream 18 comprises a hydrocarbon fraction lighter than the hydrocarbon feed and which is immiscible with the hydrocarbon feed-immiscible ionic liquid. The lighter hydrocarbon fraction may consist of a single hydrocarbon compound or may comprise a mixture of hydrocarbons. In an embodiment, the lighter hydrocarbon fraction comprises at least one of a naphtha, gasoline, diesel, light cycle oil (LCO), and light coker gas oil (LCGO) hydrocarbon fraction. The lighter hydrocarbon fraction 18A may comprise straight run fractions and/or products from the conversion process 800, such as hydrocracking, hydrotreating, fluid catalytic cracking (FCC), reforming. In this embodiment, extract stream 20 comprises the lighter hydrocarbon regeneration solvent 18A and the contaminant(s).
The extract stream 20 can be further processed in a separation process 900 to separate the contaminants 28 from the light hydrocarbon 30 which can be sent to the conversion process 800. The light hydrocarbon can be separated from the extract by one or more various well known methods including distillation, flash distillation, and steam stripping.
In another embodiment, the regeneration solvent stream 18 comprises water, and the ionic liquid regeneration step produces extract stream 20 comprising the contaminant(s) and regenerated hydrocarbon feed-immiscible ionic liquid 22 comprising water and the ionic liquid. In an embodiment wherein regeneration solvent stream 18 comprises water, a portion or all of spent water stream 16 may provide a portion or all of regeneration solvent stream 18.
Regardless of whether regeneration solvent stream 18 comprises a lighter hydrocarbon fraction or water, a portion or all of regenerated hydrocarbon feed-immiscible ionic liquid stream 22 may be recycled to the contaminant removal step via a conduit not shown consistent with other operating conditions of the process. For example, a constraint on the water content of the hydrocarbon feed-immiscible ionic liquid stream 4 or ionic liquid/hydrocarbon feed mixture in contaminant removal zone 100 may be met by controlling the proportion and water content of fresh and recycled ionic liquid streams.
There can be more than one regeneration solvent stream (e.g., both water 18 and light hydrocarbon 18A) which can be fed separately or together to the ionic liquid regeneration zone 500.
Optional ionic liquid drying step is illustrated by drying zone 600. The ionic liquid drying step may be employed to reduce the water content of one or more of the streams comprising ionic liquid to control the water content of the contaminant removal step as described above. In the embodiment of FIG. 1, a portion or all of regenerated hydrocarbon feed-immiscible ionic liquid stream 22 is introduced to drying zone 600. Although not shown, other streams comprising ionic liquid such as the fresh ionic liquid stream 3, hydrocarbon feed-immiscible ionic liquid effluent stream 8, and spent water stream 16, may also be dried in any combination in drying zone 600. To dry the ionic liquid stream or streams, water may be removed by one or more various well known methods including distillation, flash distillation, and using a dry inert gas to strip water. Generally, the drying temperature may range from about 100° C. to less than the decomposition temperature of the ionic liquid, usually less than about 300° C. The pressure may range from about 35 kPa(g) to about 250 kPa(g). The drying step produces a dried hydrocarbon feed-immiscible ionic liquid stream 24 and a drying zone water effluent stream 26. Although not illustrated, a portion or all of dried hydrocarbon feed-immiscible ionic liquid stream 24 may be recycled or passed to provide all or a portion of the hydrocarbon feed-immiscible ionic liquid introduced to contaminant removal zone 100. A portion or all of drying zone water effluent stream 26 may be recycled or passed to provide all or a portion of the water introduced into hydrocarbon feed washing zone 400 and/or ionic liquid regeneration zone 500.
The contacting and separating steps may be repeated, for example, when the contaminant of the decontaminated hydrocarbon feed effluent is to be reduced further to obtain a desired contaminant level for the ultimate hydrocarbon feed stream for the catalytic conversion process. Each set, group, or pair of contacting and separating steps may be referred to as a contaminant removal step. Thus, there can be one or more contaminant removal steps. A contaminant removal zone may be used to perform a contaminant removal step. As used herein, the term “zone” can refer to one or more equipment items and/or one or more sub-zones. Equipment items may include, for example, one or more vessels, heaters, separators, exchangers, conduits, pumps, compressors, and controllers. Additionally, an equipment item can further include one or more zones or sub-zones. The contaminant removal process or step may be conducted in a similar manner and with similar equipment as is used to conduct other liquid-liquid wash and extraction operations. Suitable equipment includes, for example, columns with: trays, packing, rotating discs or plates, and static mixers. Pulse columns and mixing/settling tanks may also be used.
FIG. 2A illustrates an embodiment of a contaminant removal or extraction zone 100 that comprises a multi-stage, counter-current extraction column 105 wherein contaminated hydrocarbon feed and hydrocarbon feed-immiscible ionic liquid are contacted and separated. The contaminated hydrocarbon feed stream 2 enters extraction column 105 through hydrocarbon feed inlet 102 and lean ionic liquid stream 4 enters extraction column 105 through ionic liquid inlet 104. In the Figures, reference numerals of the streams and the lines or conduits in which they flow are the same. Contaminated hydrocarbon feed inlet 102 is located below ionic liquid inlet 104. The hydrocarbon feed effluent passes through hydrocarbon feed effluent outlet 112 in an upper portion of extraction column 105 to hydrocarbon feed effluent conduit 6. The hydrocarbon feed-immiscible ionic liquid effluent including the contaminant removed from the contaminated hydrocarbon feed passes through ionic liquid effluent outlet 114 in a lower portion of extraction column 105 to ionic liquid effluent conduit 8.
Consistent with common terms of art, the ionic liquid introduced to the contaminant removal step may be referred to as a “lean ionic liquid” generally meaning a hydrocarbon feed-immiscible ionic liquid that is not saturated with one or more extracted contaminants. Lean ionic liquid may include one or both of fresh and regenerated ionic liquid and is suitable for accepting or extracting contaminants from the hydrocarbon feed. Likewise, the ionic liquid effluent may be referred to as “rich ionic liquid”, which generally means a hydrocarbon feed-immiscible ionic liquid effluent produced by a contaminant removal step or process or otherwise including a greater amount of extracted contaminants than the amount of extracted contaminants included in the lean ionic liquid. A rich ionic liquid may require regeneration or dilution, e.g. with fresh ionic liquid, before recycling the rich ionic liquid to the same or another contaminant removal step of the process.
FIG. 2B illustrates another embodiment of contaminant removal or extraction zone 100 that comprises a contacting zone 200 and a separation zone 300. In this embodiment, lean ionic liquid stream 4 and contaminated hydrocarbon feed stream 2 are introduced into the contacting zone 200 and mixed by introducing contaminated hydrocarbon feed stream 2 into the flowing lean ionic liquid stream 4 and passing the combined streams through static in-line mixer 155. Static in-line mixers are well known in the art and may include a conduit with fixed internals such as baffles, fins, and channels that mix the fluid as it flows through the conduit. In other embodiments, not illustrated, lean ionic liquid stream 4 may be introduced into contaminated hydrocarbon feed stream 2, or the lean ionic liquid stream 4 and contaminated hydrocarbon feed stream may be combined such as through a “Y” conduit. In another embodiment, lean ionic liquid stream 4 and contaminated hydrocarbon feed stream 2 are separately introduced into the static in-line mixer 155. In other embodiments, the streams may be mixed by any method well known in the art, including stirred tank and blending operations. The mixture comprising hydrocarbon feed and ionic liquid is transferred to separation zone 300 via transfer conduit 7. Separation zone 300 comprises separation vessel 165 wherein the two phases are allowed to separate into a rich ionic liquid phase containing the contaminants which is withdrawn from a lower portion of separation vessel 165 via ionic liquid effluent conduit 8 and the decontaminated hydrocarbon feed phase which is withdrawn from an upper portion of separation vessel 165 via decontaminated hydrocarbon feed effluent conduit 6. Separation vessel 165 may comprise a boot, not illustrated, from which rich ionic liquid is withdrawn via conduit 8.
Separation vessel 165 may contain a solid media 175 and/or other coalescing devices which facilitate the phase separation. In other embodiments, the separation zone 300 may comprise multiple vessels which may be arranged in series, parallel, or a combination thereof. The separation vessels may be of any shape and configuration to facilitate the separation, collection, and removal of the two phases. In a further embodiment, contaminant removal zone 100 may include a single vessel wherein lean ionic liquid stream 4 and contaminated hydrocarbon feed stream 2 are mixed, then remain in the vessel to settle into the hydrocarbon feed effluent and rich ionic liquid phases. In an embodiment, the process comprises at least two contaminant removal steps. For example, the decontaminated hydrocarbon feed effluent from one decontaminant removal step may be passed directly as the feed to a second contaminant removal step. In another embodiment, the decontaminated hydrocarbon feed effluent from one contaminant removal step may be treated or processed before being introduced as the feed to the second contaminant removal step. There is no requirement that each contaminant removal zone comprises the same type of equipment or the same ionic liquid(s). Different equipment, conditions, and/or ionic liquids may be used in different contaminant removal zones, if desired.
The contaminant removal step may be conducted under contaminant removal conditions including temperatures and pressures sufficient to keep the hydrocarbon feed-immiscible ionic liquid and hydrocarbon feeds and effluents as liquids. For example, the contaminant removal step temperature may range between about 10° C. and less than the decomposition temperature of the ionic liquid; and the pressure may range between about atmospheric pressure and about 700 kPa(g). When the hydrocarbon feed-immiscible ionic liquid comprises more than one ionic liquid component, the decomposition temperature of the ionic liquid is the lowest temperature at which any of the ionic liquid components decompose. The contaminant removal step may be conducted at a uniform temperature and pressure or the contacting and separating steps of the contaminant removal step may be operated at different temperatures and/or pressures. In an embodiment, the contacting step is conducted at a first temperature, and the separating step is conducted at a temperature at least 5° C. lower than the first temperature. In a non limiting example, the first temperature is about 80° C. Such temperature differences may facilitate separation of the hydrocarbon feed and ionic liquid phases.
The above and other contaminant removal step conditions, such as the contacting or mixing time, the separation or settling time, and the ratio of hydrocarbon feed to hydrocarbon feed-immiscible ionic liquid (lean ionic liquid), may vary greatly based, for example, on the specific ionic liquid or liquids employed, the nature of the hydrocarbon feed (straight run or previously processed), the type(s) and amount(s) of the contaminants in the hydrocarbon feed, the degree of contaminant removal required, the number of contaminant removal steps employed, and the specific equipment used. In general, it is expected that contacting time may range from less than one minute to about two hours; settling time may range from about one minute to about eight hours; and the weight ratio of contaminated hydrocarbon feed to lean ionic liquid introduced to the contaminant removal step may range from 1:10,000 to 10,000:1. In an embodiment, the weight ratio of contaminated hydrocarbon feed to lean ionic liquid may range from about 1:1,000 to about 1,000:1; and the weight ratio of contaminated hydrocarbon feed to lean ionic liquid may range from about 1:100 to about 100:1. In an embodiment, the weight of contaminated hydrocarbon feed is greater than the weight of ionic liquid introduced to the contaminant removal step.
As discussed herein, multiple contaminant removal steps can be used to provide the desired amount of contaminant removal. The degree of phase separation between the hydrocarbon feed and ionic liquid phases is another factor to consider as it affects recovery of the ionic liquid and decontaminated hydrocarbon feed. The degree of contaminant removed and the recovery of the decontaminated hydrocarbon feed and ionic liquids may be affected differently by the nature of the hydrocarbon feed, the type and amount of contaminants, the specific ionic liquid or liquids, the equipment, and the contaminant removal conditions such as those discussed above.
The amount of water present in the hydrocarbon feed/hydrocarbon feed-immiscible ionic liquid mixture during the contaminant removal step may also affect the amount of contaminant removed and/or the degree of phase separation, i.e., the recovery of the hydrocarbon feed and ionic liquid. In some embodiments, the hydrocarbon feed/hydrocarbon feed-immiscible ionic liquid mixture has a water content of less than about 10% relative to the weight of the ionic liquid, or less than about 5%, or less than about 2%. In other embodiments, the hydrocarbon feed/hydrocarbon feed-immiscible ionic liquid mixture is water free, i.e. the mixture does not contain water.
The process may be practiced in laboratory scale experiments through full scale commercial operations. The process may be operated in batch, continuous, or semi-continuous mode. Individual process steps may be operated continuously and/or intermittently as needed for a given embodiment, e.g., based on the quantities and properties of the streams to be processed in such steps.
The process encompasses a variety of flow scheme embodiments including optional destinations of streams, splitting streams to send the same composition, i.e., aliquot portions, to more than one destination, and recycling various streams within the process.
Unless otherwise stated, the exact connection point of various inlet and effluent streams within the zones is not essential to the invention. For example, it is well known in the art that a stream to a distillation zone may be sent directly to the column, or the stream may first be sent to other equipment within the zone such as heat exchangers, to adjust temperature, and/or pumps to adjust the pressure. Likewise, streams entering and leaving the zones may pass through ancillary equipment such as heat exchangers within the zones. Streams, including recycle streams, introduced to the various zones may be introduced individually or combined prior to or within such zones.
For example, in a small scale form of the invention, the decontamination can be accomplished by mixing the hydrocarbon feed and a hydrocarbon feed-immiscible ionic liquid in a beaker, flask, or other vessel, e.g., by stirring, shaking, use of a mixer, or a magnetic stirrer. When the mixing or agitation is stopped, the mixture will form a hydrocarbon feed phase and an ionic liquid phase which can be separated, for example, by decanting, centrifugation, or use of a pipette to produce a decontaminated hydrocarbon feed effluent having a lower level of contaminants compared to the incoming hydrocarbon feed. The decontaminated feed can then be poured into a laboratory sized batch reactor, for example.

Example 1

A sample of triisobutylmethylphosphonium tosylate ionic liquid and vacuum gas oil (VGO) containing 1400 ppm of nitrogen were combined in a beaker at a weight ratio of 10:1 hydrocarbon feed: ionic liquid. The beaker was placed onto a heated stir plate and stirred at 80° C. for 30 minutes. After 30 minutes, the stirring was stopped, and the ionic liquid mixture was allowed to settle for 30 minutes. A pipette was used to draw off the extracted hydrocarbon feed from the ionic liquid. The catalyst/oil ratio was adjusted for the ionic liquid treated case to account for the same coke combustion in the regenerator. Analysis showed that 42.3% of the nitrogen was removed from the extracted hydrocarbon feed. This extracted hydrocarbon feed was tested in an FCC pilot plant. The conversion of ionic liquid treated VGO to hydrocarbons boiling below 193° C. (380° F.) increased by 5.0 volume % over that of the untreated hydrocarbon feed. The gasoline yield from ionic liquid treated VGO increased by 3.7 wt % over that of the untreated VGO feed. The operating conditions for the FCC pilot plant and analyses are shown in Table 1.

TABLE 1

	Untreated	Extracted
	VGO	VGO

Barrels/Day	50000	50000
N, wt ppm	1400	808
Reactor Conditions
Temperature, F	1010	1010
Pressure, psig	20	20
CFR, vol/vol	1	1
Cat/Oil, wt/wt	9.06	10.97
Heat of Reaction,
BTU/lb FF	212.6	238.8
193° C. (380F)
Conversion, vol %	75.2	80.22
C5 + Gasoline, vol %	55.25	59.08

Example 2

For comparison purposes a sample made up of 80% untreated VGO was blended with 20% untreated coker gas oil (CGO), the total nitrogen in this blend was 2816 ppm. This blend was tested in an FCC pilot plant. A sample of triisobutylmethylphosphonium tosylate ionic liquid and CGO were combined in a beaker at a weight ratio of 10:1 CGO: ionic liquid. The beaker was placed onto a heated stir plate and stirred at 80° C. for 30 minutes. After 30 minutes, the stirring was stopped, and the ionic liquid mixture was allowed to settle for 30 minutes. A pipette was used to draw off the extracted CGO from the ionic liquid. The catalyst/oil ratio was adjusted for the ionic liquid treated case to account for the same coke combustion in the regenerator. Analysis showed that the extraction removed 34.6% of the nitrogen from the CGO. This extracted CGO was blended with 80% untreated VGO, the total nitrogen in this blend was 2186 ppm. This blend was also tested in an FCC pilot plant. The conversion for the blend with ionic liquid extracted CGO to hydrocarbons boiling below 193° C. (380° F.) increased by 2.55 volume % over that of the untreated VGO/CGO blend. The gasoline yield increased by 1.7 wt %. The operating conditions for the FCC pilot plant and analyses are shown in Table 2.

TABLE 2

		Raw
		VGO w/
		Ionic
	Raw VGO	Liquid
	w/ Raw	treated
	CGO	CGO

Barrels/Day	50000	50000
VGO, wt %	80	80
CGO, wt %	20
Ionic liquid ex-
tracted CGO,
wt %		20
N, wt ppm	2816	2186
Temperature, F	1010	1010
Pressure, psig	20	20
CFR, vol/vol	1	1
Cat/Oil, wt/wt	8.22	9.2
Heat of Reaction,	190.1	190.1
BTU/lb FF
380F Con-	73.7	77.25
version, vol %
C5 + Gas-	54.14	56.75
oline, vol %

Example 3

A sample of triisobutylmethylphosphonium tosylate ionic liquid and vacuum gas oil (VGO) containing 1386 ppm of nitrogen were combined in two beakers at a weight ratio of 20:1 and 2.5:1 hydrocarbon feed: ionic liquid respectively. The beakers were placed onto a heated stir plate and stirred at 80° C. for 30 minutes. After 30 minutes, the stirring was stopped, and the ionic liquid mixture was allowed to settle for 30 minutes. A pipette was used to draw off the extracted hydrocarbon feed from the ionic liquid. Analysis showed that 33% of the nitrogen was removed from the extracted hydrocarbon feed for 20:1 case and 60% of nitrogen was extracted for 2.5:1 case. This extracted hydrocarbon feed was tested in an FCC pilot plant. The conversion of 20:1 ionic liquid treated VGO to hydrocarbons boiling below 193° C. (380° F.) increased by 4.5 vol % over that of the untreated hydrocarbon feed and the conversion of 2.5:1 ionic liquid treated VGO to hydrocarbons boiling below 193° C. (380° F.) increased by 5.8 vol % over that of the untreated hydrocarbon feed. The operating conditions for the FCC pilot plant and analyses are shown in Table 3.

TABLE 3

			2.5:1 IL
	Raw	20:1 IL	Treated
	VGO	Treated VGO	VGO

API	21.03	22	22.2
UOP K	11.61	11.66	11.68
Ni, wt ppm	0.1	0	0
V, wt ppm	0.3	0	0
S, wt %	2.33	2.22	2.22
N, wt ppm	1386	927	464
Carbon Residue,	0.22	0.04	0.04
wt %
650F−, vol %	4	4	4
Feed H, NMR	12.02	12.14	12.2
			(estimated)
Reactor Conditions
Temperature, F	1010	1010	1010
Pressure, psig	20	20	20
CFR, vol/vol	1	1	1
Cat/Oil, wt/wt	9.06	10.02	10.97
Heat of Rxn,	212.6	232.4	238.8
BTU/lb FF
380F Conversion,	75.2	79.7	81.0
vol %

While at least one exemplary embodiment has been presented in the foregoing detailed description of the invention, it should be appreciated that a vast number of variations exist. It should also be appreciated that the exemplary embodiment or exemplary embodiments are only examples, and are not intended to limit the scope, applicability, or configuration of the invention in any way. Rather, the foregoing detailed description will provide those skilled in the art with a convenient road map for implementing an exemplary embodiment of the invention. It being understood that various changes may be made in the function and arrangement of elements described in an exemplary embodiment without departing from the scope of the invention as set forth in the appended claims.

Claims

What is claimed is:

1. A method of hydrocarbon conversion comprising:

contacting a hydrocarbon feed containing a contaminant with a hydrocarbon feed-immiscible ionic liquid to form a mixture comprising decontaminated hydrocarbon feed and hydrocarbon feed-immiscible ionic liquid containing the contaminant;

reacting the decontaminated hydrocarbon feed in a conversion zone to produce a desired product selected from gasoline, diesel, naphtha, distillate, jet, light olefins, or combinations thereof;

wherein a conversion of the decontaminated hydrocarbon feed is increased compared to a conversion of the contaminated hydrocarbon feed under comparable operating conditions, or a yield of the desired product made from the decontaminated hydrocarbon feed is increased compared to a yield of the desired product made from the contaminated hydrocarbon feed under comparable operating conditions, or both.

2. The method of claim 1 wherein the hydrocarbon feed has a density in a range of about 0.8 g/cc to about 1.1 g/cc.

3. The method of claim 1 wherein at least one of research octane number, cetane number, smoke point, nitrogen content, sulfur content, aromatic content, or density of the desired product made from the decontaminated hydrocarbon feed is improved compared to the desired product made from the contaminated hydrocarbon feed.

4. The method of claim 1 further comprising separating the mixture into a decontaminated hydrocarbon feed stream and a hydrocarbon feed-immiscible ionic liquid stream containing the contaminant and wherein introducing the decontaminated hydrocarbon feed into the conversion zone comprises introducing the decontaminated hydrocarbon feed stream into the conversion zone.

5. The method of claim 4 further comprising contacting the hydrocarbon feed-immiscible ionic liquid effluent with a regeneration solvent and separating the hydrocarbon feed-immiscible ionic liquid effluent from the regeneration solvent to produce an extract stream comprising the contaminant and a regenerated hydrocarbon feed-immiscible ionic liquid stream.

6. The method of claim 5 wherein the regeneration solvent comprises one of the desired products from the conversion zone.

7. The method of claim 5 further comprising recycling at least a portion of the regenerated hydrocarbon feed-immiscible ionic liquid stream to the contacting step.

8. The method of claim 1 wherein the hydrocarbon feed-immiscible ionic liquid comprises at least one of an imidazolium ionic liquid, a phosphonium ionic liquid, and a pyridinium ionic liquid.

9. The method of claim 1 wherein the hydrocarbon feed-immiscible ionic liquid comprises at least one of 1-ethyl-3-methylimidazolium ethyl sulfate, 1-butyl-3-methylimidazolium hydrogen sulfate, 1-ethyl-3-methylimidazolium chloride, 1-butyl-3-methylimidazolium chloride, 1-butyl-3-methylimidazolium trifluoromethanesulfonate, 1-butyl-4-methylpyridinium chloride, N-butyl-3-methylpyridinium methylsulfate, trihexyl(tetradecyl)phosphonium chloride, trihexyl(tetradecyl)phosphonium bromide, tributyl(methyl)phosphonium bromide, tributyl(methyl)phosphonium chloride, tributyl(hexyl)phosphonium bromide, tributyl(hexyl)phosphonium chloride, tributyl(octyl)phosphonium bromide, tributyl(octyl)phosphonium chloride, tributyl(decyl)phosphonium bromide, tributyl(decyl)phosphonium chloride, tetrabutylphosphonium chloride, tetrabutylphosphonium bromide, triisobutyl(methyl)phosphonium tosylate, tributyl(ethyl)phosphonium diethylphosphate, tetrabutylphosphonium methanesulfonate pyridinium p-toluene sulfonate.

10. The method of claim 1 wherein the conversion of the decontaminated feed is at least 0.5 vol % higher than the conversion of the contaminated feed, or the yield of the desired product from the decontaminated feed is at least about 0.5 vol % higher than the yield of the desired product from the contaminated feed, or both.

11. The method of claim 1 wherein a selectivity of the desired product from the decontaminated feed is at least 0.1 vol % higher than a selectivity of the desired product from the contaminated feed under comparable operating conditions.

12. The method of claim wherein the decontaminated hydrocarbon feed is mixed with a second hydrocarbon feed.

13. The method of claim 1 wherein the conversion zone is a catalytic cracking conversion zone.

14. A method of fluid catalytic cracking comprising:

contacting a hydrocarbon feed containing a contaminant with a hydrocarbon feed-immiscible ionic liquid to form a mixture comprising decontaminated hydrocarbon feed and feed-immiscible ionic liquid containing the contaminant, wherein the contaminated feed is selected from the group consisting of vacuum gas oil, coker gas oil, light cycle oil, vacuum residue, or combinations thereof, and wherein the hydrocarbon feed-immiscible ionic liquid comprises at least one of an imidazolium ionic liquid, a phosphonium ionic liquid, and a pyridinium ionic liquid;

separating the mixture into a decontaminated hydrocarbon feed stream and a hydrocarbon feed-immiscible ionic liquid stream containing the contaminant;

reacting the decontaminated hydrocarbon feed stream in a catalytic conversion zone in the presence of a catalyst under catalytic conversion conditions to produce desired product selected from gasoline, diesel, naphtha, distillate, jet, light olefins, or combinations thereof;

15. The method of claim 14 wherein the hydrocarbon feed has a density in a range of about 0.8 g/cc to about 1.1 g/cc.

16. The method of claim 14 wherein at least one of research octane number, cetane number, smoke point, nitrogen content, sulfur content, aromatic content, or density of the desired product made from the decontaminated hydrocarbon feed is improved compared to the desired product made from the contaminated hydrocarbon feed.

17. The method of claim 14 further comprising contacting the hydrocarbon feed-immiscible ionic liquid effluent with a regeneration solvent and separating the hydrocarbon feed-immiscible ionic liquid effluent from the regeneration solvent to produce an extract stream comprising the contaminant and a regenerated hydrocarbon feed-immiscible ionic liquid stream.

18. The method of claim 17 further comprising recycling at least a portion of the regenerated hydrocarbon feed-immiscible ionic liquid stream to the contacting step.

19. The method of claim 14 wherein the hydrocarbon feed-immiscible ionic liquid comprises at least one of 1-ethyl-3-methylimidazolium ethyl sulfate, 1-butyl-3-methylimidazolium hydrogen sulfate, 1-ethyl-3-methylimidazolium chloride, 1-butyl-3-methylimidazolium chloride, tetrabutylphosphonium methane sulfonate, pyridinium p-toluene sulfonate, tetrabutylphosphonium chloride, tetrabutylphosphonium bromide, tributyl(octyl)phosphonium chloride, and tributyl(ethyl)phosphonium diethylphosphate, 1-butyl-3-methylimidazolium trifluoromethanesulfonate, 1-butyl-4-methylpyridinium chloride, N-butyl-3-methylpyridinium methylsulfate, trihexyl(tetradecyl)phosphonium chloride, trihexyl(tetradecyl)phosphonium bromide, tributyl(methyl)phosphonium bromide, tributyl(methyl)phosphonium chloride, tributyl(hexyl)phosphonium bromide, tributyl(hexyl)phosphonium chloride, tributyl(octyl)phosphonium bromide, tributyl(decyl)phosphonium bromide, tributyl(decyl)phosphonium chloride, triisobutyl(methyl)phosphonium tosylate, and tetrabutylphosphonium methanesulfonate.

20. The method of claim 14 wherein the conversion of the decontaminated feed is at least 0.5 vol % higher than the conversion of the contaminated feed, or the yield of the desired product made from the decontaminated feed is at least 0.5 vol % higher than the yield of the desired product made from the contaminated feed under comparable operating conditions, or both.