US20100264065A1

US20100264065A1 - Membrane desulfurization of liquid hydrocarbon feedstreams

Info

Publication number: US20100264065A1
Application number: US12/741,261
Authority: US
Inventors: Esam Zaki Hamad; Ahmad Abdullah Bahamdan
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2007-12-24
Filing date: 2008-12-23
Publication date: 2010-10-21
Also published as: WO2009082493A1

Abstract

The process of the present invention is directed to the desulfurization of a sulfur-containing unrefined hydrocarbon stream with a membrane separation apparatus, where sulfur compounds are concentrated in a sulfur-rich stream on a permeate side of the membrane, and a sulfur-lean stream is recovered as a retentate. The sulfur-rich stream, which has a small volume relative to the original unrefined hydrocarbon stream, is conveyed to a subsequent desulfurization apparatus or system, such as a hydrotreating system, to recover the hydrocarbons associated with the organosulfur compounds. The stream desulfurized by conventional processes, such as hydrotreating, and the hydrocarbons desulfurized by the membrane separation apparatus may be combined to provide a low sulfur hydrocarbon effluent with minimal or no loss of the original volume.

Description

CROSS REFERENCE TO RELATED APPLICATION

This patent application claims the benefit of U.S. Provisional Application Ser. No. 61/009,016, filed Dec. 24, 2007, the content of which is incorporated by reference herein in its entirety.

FIELD OF THE INVENTION

The invention relates to processes for desulfurization of a hydrocarbon feed using membrane separation, and more particularly to desulfurization of an unrefined hydrocarbon feed using membrane separation.

BACKGROUND OF THE INVENTION

Compositions of natural petroleum or crude oils vary significantly, generally based upon the source. However, virtually all crude oils contain some level of sulfur compounds, including inorganically combined sulfur and organically combined sulfur, i.e., organosulfur compounds. Whole crude oil that contains a substantial concentration of sulfur compounds, such as hydrogen sulfide, sulfur dioxide, and organosulfur compounds such as mercaptans, thiophenes, benzothiophenes, and dibenzothiophenes is referred to as “sour,” whereas whole crude oil that does not contain a substantial concentration of sulfur compounds is referred to as “sweet.”
Crude oil is generally converted in refineries by distillation, followed by cracking and/or hydroconversion processes, to produce various fuels, lubricating oil products, chemicals, and chemical feedstocks. Fuels for transportation are generally produced by processing and blending distilled fractions from crude oil to meet the particular product specifications. Conventionally, distilled fractions are subject to various hydrocarbon desulfurization processes to make sulfur-containing hydrocarbons more marketable, attractive to customers and environmentally acceptable.
The evolution of sulfur compounds during processing and end-use of the petroleum products derived from sour crude oil poses safety and environmental problems. Laws have been enacted to reduce sulfur content of fuels, including diesel and gasoline. For instance, in 2007 the United States Environmental Protection Agency required sulfur content of highway diesel fuel to be reduced 97%, from 500 parts per million (low sulfur diesel) to 15 parts per million (ultra low sulfur diesel). The European Union has enacted even more stringent standards, requiring diesel and gasoline fuels sold in 2009 to contain less than 10 parts per million of sulfur.
Furthermore, the price differential between sour crude oil and sweet crude oil (crude oil having relatively low level of sulfur compounds) favors sweet crude oil. sweet crude oil commands a higher price than sour crude oil because it has fewer environmental problems and requires less refining to meet sulfur standards imposed on end product fuels. Hydrocarbon desulfurization processes are required to reduce the sulfur content. However, most desulfurization processing occurs after varying levels of refining of the crude oil.
The most common hydrocarbon desulfurization process is hydrotreating, or hydrodesulfurization. In typical hydrotreating processes, oil and hydrogen are introduced to a fixed bed reactor that is packed with a hydrodesulfurization catalyst, commonly under elevated operating conditions, including temperatures of about 300 to 400° C. and pressures of about 30 to 130 atmospheres. The temperatures and pressures in hydrotreating processes must be further elevated to achieve the low and ultra low sulfur content requirements. However, under these more severe conditions, hydrocarbons are typically converted to less desirable intermediates or products.
Typical advances in the industry for minimizing these undesirable effects include development of more robust hydrotreating catalysts and advanced hydrodesulfurization reactor designs. Alternative processes are also being developed to meet the requirements of decreased sulfur levels in fuels and other petrochemical products.
One alternate desulfurization process that has been proposed for treating various refined fractions of hydrocarbons is membrane separation. In general, membrane separation technology involves selective transport of a material through the membrane, a permeate, leaving behind a retentate on the feed side of the membrane. Permeated components of the mixture are removed by various driving forces. Membrane processes that rely upon pressure driving forces are known as pervaporation processes, and membrane processes that rely upon concentration gradients across the membrane are known as perstraction processes. Membrane separation often relies on the affinity of a specific compound or class of compounds for the membrane. Components in a mixture having affinity for the membrane will permeate the membrane. Membrane separation has been used for desulfurization of refined hydrocarbon fractions.
Saxton et al. U.S. Pat. No. 6,702,945 and Minhas et al. U.S. Pat. No. 6,649,061, both assigned to ExxonMobil, disclose reducing the sulfur content in a hydrocarbon fraction, particularly light cracked naphtha. The membrane system is operated under pervaporation conditions in the examples. In addition, the process discloses a transport agent (such as methanol) as an additive to the hydrocarbon mixture to enhance the permeate flux through the membrane.
White et al. U.S. Pat. No. 6,896,796, and related U.S. Pat. Nos. 7,018,527, 7,041,212 and 7,048,846, all assigned to W.R. Grace & Co., disclose a method for lowering the sulfur content of an FCC light cat naphtha feed under pervaporation conditions. The process proposes to minimize olefin and naphthene hydrogenation during hydrotreating, particularly problematic in hydrotreating FCC naphtha since the high olefin content is again prone to hydrogenation.
Balko U.S. Pat. No. 7,267,761, also assigned to W.R. Grace & Co., describes another process for treating naphtha streams from an FCC unit, where the feedstream is treated in a fractionation zone to produce a low boiling point fraction and a second fraction, both containing sulfur. The low boiling point fraction is treated in a membrane separation zone, where the sulfur-enriched permeate is combined with the second fraction for treatment in a hydrodesulfurization zone.
Plummer et al. U.S. Pat. No. 6,736,961, assigned to Marathon Oil Company, discloses a process employing a solid membrane process containing a transport facilitating liquid, identified as amines, hydroxyamines, and alcohols. The feed is described as a refinery hydrocarbon product such as naphtha or diesel.
Importantly, the hydrocarbon feed streams in all of the above-mentioned references are products of upstream distillation and cracking processes and/or other refining operations. However, the use of unrefined petroleum products (e.g., crude oil) as a feedstream to a membrane separation process remains heretofore unknown to the inventors.
Another desulfurization process is described in Schoonover U.S. Pat. No. 7,001,504, where hydrocarbon materials are contacted with an ionic liquid to extract organosulfur compounds into the ionic liquid. The ionic liquid is regenerated by various methods including heating, gas stripping, oxidation, or extraction with another solvent or supercritical carbon dioxide. However, this process does not utilize membrane separation units to provide relatively compact and efficient separation.
Therefore, it is an object of the invention to utilize membrane separation to desulfurizing unrefined hydrocarbon streams.
It is a further object of the invention to utilize membrane separation for desulfurizing an unrefined hydrocarbon stream, and to thereafter desulfurize the sulfur-rich retentate employing conventional desulfurization processes such as hydrotreating.
A still further object of the invention is to utilize membrane separation to desulfurize an unrefined hydrocarbon stream, and to desulfurize the sulfur-rich retentate using conventional desulfurization processes such as hydrotreating, while minimizing the required capacity of the hydrotreating process.
Yet another object of the invention is to separate heteroatom compounds such as sulfur compounds from a liquid unrefined hydrocarbon into a liquid permeate and a liquid retentate.
As used herein, the term “unrefined hydrocarbon” is to be understood to mean a distillate product of crude oil (including impurities such as sulfur) that has not been subjected to hydroprocessing, hydrodesulfurization, hydrodenitrogenation, catalytic processing, or cracking, and includes crude oil, unrefined diesel, unrefined naphtha, unrefined gas oil, or unrefined vacuum gas oil. Additionally, as used herein, the term “crude oil” is to be understood to include a mixture of petroleum liquids and gases (including impurities such as sulfur) as distinguished from refined fractions of hydrocarbons.

SUMMARY OF THE INVENTION

The process of the present invention is directed to desulfurization of a sulfur-containing unrefined hydrocarbon stream with a membrane separation apparatus, where sulfur compounds are concentrated in a sulfur-rich stream on a permeate side of the membrane, and a sulfur-lean stream is recovered as a retentate. The sulfur-rich stream, which has a small volume relative to the original unrefined hydrocarbon stream, is subsequently conveyed to a desulfurization apparatus or system, such as a hydrotreating system, to recover the hydrocarbons associated with the organosulfur compounds. The stream desulfurized by conventional processes, such as hydrotreating, and the hydrocarbon stream desulfurized by the membrane separation apparatus can be combined to provide a low sulfur hydrocarbon effluent with minimal or no significant loss of the original volume.

BRIEF DESCRIPTION OF THE DRAWINGS

Further advantages and features of the present invention will become apparent from the detailed description of a preferred embodiment of the invention and reference to the accompanying drawings, in which:

FIG. 1 is a schematic diagram of a combined membrane separation and alternate desulfurization process according to embodiments of the invention; and

FIG. 2 is a schematic diagram of a membrane separation system used in the experimental analysis described herein.

DETAILED DESCRIPTION OF THE INVENTION

With reference to FIG. 1, a schematic overview of a desulfurization process 10 is described. An unrefined hydrocarbon feedstream 12 containing organosulfur compounds is introduced into a membrane separation unit 14 where the feedstream 12 is separated into streams 16, 18. Sulfur-containing hydrocarbon compounds permeate a membrane of the membrane separation system 14 and are concentrated into an unrefined sulfur-rich hydrocarbon stream 16. The portion of the feedstream remaining on the feed side of the membrane, the retentate, is conveyed as an unrefined sulfur-lean hydrocarbon stream 18. The unrefined sulfur-lean hydrocarbon stream 18 has a substantially reduced concentration of sulfur-containing compounds as compared to the feedstream 12. The unrefined sulfur rich stream 16, typically a small volume relative to the original feedstream 12, is transferred to a second stage desulfurization system 20, such as a hydrotreating unit, to recover useful hydrocarbons associated with the organosulfur compounds. Effluent from the second stage desulfurization system 20, a second stage unrefined sulfur-lean stream 22, and the membrane desulfurized unrefined hydrocarbon stream 18, can be combined to provide a low sulfur unrefined hydrocarbon stream 24 with minimal or no loss in volume. In an alternative embodiment of the process, the second stage unrefined sulfur-lean stream 22 that may be rich in aromatics is transferred to one or more subsequent processing steps.
The combined membrane separation process 10 described herein advantageously is conducted as a liquid separation process. The unrefined hydrocarbon feedstream 12, the unrefined sulfur-rich hydrocarbon stream 16 and the unrefined sulfur-lean hydrocarbon stream 18 are all maintained in the liquid phase. The feedstream 12, which can be a crude oil feedstream, an unrefined diesel feedstream, an unrefined naphtha feedstream, an unrefined gas oil feedstream, or an unrefined vacuum gas oil feedstream, is generally in the liquid phase initially, and the permeate and retentate remain in the liquid phase, without conversion into vapors and subsequent condensation, thereby conserving energy. A majority of hydrocarbon gases that are in the feedstream, in particular a crude oil feedstream, are generally dissolved in the liquid and do not pass through the membrane, thus remain in the unrefined sulfur-lean hydrocarbon stream 18. Accordingly, the prior art pervaporation operations described relating to processes for separation of particular fractions using sulfur-selective membranes and which consume large amounts of energy due to vaporization and vacuum maintenance, are not required.
The sequence of a membrane separation zone followed by second stage desulfurization zone is also conducive to integration with existing commercial hydrotreating units. This sequence realizes substantial economic savings, since the cost of operating a hydrotreating unit is proportional to the feed volume and is generally not sensitive to the sulfur content of the feed. The cost of a membrane separation unit is generally much less than the cost of a hydrotreating unit; therefore, technically mature hydrodesulphurization units can be employed with the attendant economic savings. The use of common and well understood processing units in combination will facilitate the capability for rapid scale-up or development of unrefined hydrocarbon feedstream desulfurization.
The overall performance of the integrated process and system generally depends on the performance of the membrane separation unit, which in turn is enhanced by the selectivity and permeability of the membrane used. Accordingly, the membrane material is selected based on the permeation rate and selectivity for the range of sulfur compounds that are present in the unrefined hydrocarbon stream. The selection of the type of membrane can also increase efficiency and reliability of the separation unit, and hence increase efficiency and reliability of the overall process.
The membrane is generally a substrate coated with a solid or a liquid material that is selective for the sulfur compounds present in the unrefined feedstream. The coating may be upon the major surfaces of the substrate and/or within pores of the substrate. Coating within the pores preferably is a relatively thin layer, to maintain pore openings and minimize mass transfer resistance and thereby increase flux. Furthermore, desired sulfur selective materials used as coatings exhibit effective adhesion to the substrate. Liquid coatings preferably include molecules with functional groups that cause them to be anchored to the substrate, thereby minimizing or avoid the loss of liquid sulfur-selective material over the life of the membrane.
Substrate materials upon or within which the selective sulfur compounds can be coated include ultrafiltration and microfiltration membranes, for instance, formed of polymeric materials such as polyethersulfone (PES), polycarbonate, polytetrafluoroethylene (PTFE), polyvinylidene fluoride (PVDF), including hydrophilic PVDF, polyester, fluorinated polyimide, polyethyl-oxazoline, Nafion®, nylon, hydrophobically modified nylon, and polyether terephthalate (PET).
The substrate has pore sizes of about 0.01 to about 2 micrometers, preferably about 0.05 to about 1 micrometer and more preferably about 0.1 to about 0.5 micrometers. Suitable substrates have molecular weight cut-off values of about 5,000 to about 1,000,000, preferably about 30,000 to about 500,000, and more preferably about 30,000 to about 100,000. The substrate can also be hydrophilic, for instance, with the inclusion of wetting agents such as polyvinylpyrrolidone (PVP)). The thickness of the substrate can be from about 100 to about 500 micrometers, preferably about 100 to about 300 micrometers, and more preferably about 100 to about 200 micrometers. The area of the membrane (e.g., diameter in the case of circular membranes in flat mounted sheet configurations) can be selected based upon the requisite processing volume demands.
The sulfur selective compounds suitable for use as membrane coating materials can include functionalities with affinity to the aromatic sulfur compounds, complexation agents, or acidic functional groups. For example, sulfur selective compounds can comprise ionic liquids including, but not limited to, N-butyl-3-methyl-pyridinium methyl sulfate, imidazolium-based ionic liquids, and methyl-pyridinium based ionic liquids. In certain preferred embodiments, the sulfur selective compounds are selective to organosulfur compounds including thiophenes, dibenzothiophenes and other refractory sulfur compounds commonly found in untreated hydrocarbon feedstreams.
The driving force for separation can be a concentration gradient across the membrane, which is enhanced by a sweep stream on the permeate side. Suitable sweep stream liquids include paraffins such as isooctane, dodecane and hexadecane; or liquid hydrocarbon mixtures such as naphtha and desulfurized diesel. The particular sweep liquid should be low in organic sulfur compounds, of paraffinic origin and be a liquid at room temperature and ambient pressure conditions.
In contrast to pervaporation techniques commonly known in the art, the membrane separation system for separating sulfur compounds from unrefined hydrocarbon feeds can operate at temperatures of about 15° C. to about 60° C., preferably about 20° C. to about 50° C., more preferably about 25° C. to about 35° C., and pressures of 1 pound per square inch (psi) to about 30 psi, preferably about 5 psi to about 20 psi, more preferably about 10 psi to about 15 psi.
In alternative embodiments, the driving force for separation is a pressure gradient across the membrane. Notably, the pressure gradient required is not as severe as that required for pervaporation conditions, as the feed, retentate and permeate are maintained in liquid phase. For instance, suitable pressure gradients across the membrane can be about 1 psi to about 15 psi, preferably about 5 psi to about 15 psi, and more preferably about 5 psi to about 10 psi.
Operating temperatures in embodiments using a pressure gradient as the driving force for separation can be about 15° C. to about 60° C., preferably about 20° C. to about 50° C., more preferably about 25° C. to about 35° C. In this embodiment, where liquid supported membranes are employed, it is desirable that the liquid be chemically anchored to the substrate to prevent the loss of mobile liquid. Suitable liquids coatings for membranes operating under pressure gradients include any of the ionic liquids mentioned above coated after plasma treatment of the mentioned substrates.
The membrane unit can be in any suitable configuration. For instance, the membrane unit can be in a spirally wound configuration, a hollow fiber configuration, a plate and frame configuration, or a tubular configuration. In certain preferred embodiments, the membrane unit is in a spirally wound or a hollow fiber configuration. In addition, a plurality of membrane units can optionally be operated in parallel or series. In the parallel configuration, one or more membrane units can be decommissioned for maintenance without disrupting the continuity of the desulfurization process.
The stream desulfurized by conventional processes, such as hydrotreating, and the hydrocarbons desulfurized by the membrane separation apparatus, can be combined to provide a low sulfur hydrocarbon effluent with minimal or no loss of the original volume. This low sulfur hydrocarbon effluent can serve as a feedstream for subsequent fractioning in a downstream process. Alternatively, the low sulfur hydrocarbon effluent may be sold as sweet crude oil, thereby taking advantage of the price differential between sweet and sour crude oils.

EXAMPLES

The following tests were conducted using the membrane substrate/coating combinations described below in a membrane separation system 50 configured as shown in FIG. 2. In particular, the system 50 included a membrane 52 having a retentate side 54 and a permeate side 56. The apparatus included a sulfur-lean portion 58 in for receiving retentate from the retentate side 54, and a sulfur-rich portion 60 for receiving permeate from the permeate side 56. A reservoir 62 initially included the feedstream that is conveyed to the membrane, which was converted into an unrefined sulfur-lean hydrocarbon retentate. A reservoir 64 initially included a sweep solution, and the unrefined sulfur-rich hydrocarbon permeate filled the reservoir 64. The feedstream was pumped to the membrane retentate side 54 with a gear pump 66. The sweep solution was pumped via a gear pump 68 across the permeate side 56 of the membrane 52.
In the following examples, the selected membranes were coated with ionic liquid (N-butyl-3-methyl pyridinium) using a spin coater. The prepared membranes were mounted in a testing flow cell as illustrated in FIG. 2. The three feeds were (1) a model solution, (2) an unrefined diesel, and (3) crude oil obtained from a refinery. The respective feeds were pumped to contact the membrane surface tangentially on the retentate side 54.

Example 1

A polyethersulfone ultrafiltration filter, with a molecular weight cutoff of 100,000 and having a 47 millimeter diameter (commercially available from GE Osmonics Labstore, Minnetonka, Minn., USA) was coated with the ionic liquid. This ionic liquid exhibits an affinity for aromatic sulfur compounds. The membrane was configured in a system schematically shown in FIG. 2.
Untreated diesel with 1% total sulfur content (10,000 parts per million) is introduced tangentially to the retentate side of a membrane cell shown in FIG. 2 that included the membrane prepared as described above. A liquid sweep stream of light treated naphtha with 100 ppm sulfur was conveyed across the membrane in the permeate side. After 72 hours of operation, the sweep stream sulfur concentration increased to 1000 ppm, yielding a sulfur-compound flux of 0.1 kg/hr/m².

Example 2

Example 1 was repeated using a feed consisting of Arabian crude oil having an American Petroleum Institute (API) gravity of about 27 and a sulfur concentration of 2.85%. After 72 hours of operation, the average sulfur-compound flux of 0.05 kg/hr/m²is achieved.

Example 3

A polycarbonate membrane filter with 0.1 micron pores having a diameter of 47 millimeters (GE PCTE commercially available from GE Osmonics Labstore, Minnetonka, Minn., USA) was prepared. The membrane included polyvinylpyrrolidone (PVP) as a wetting agent that imparts hydrophilicity. The membrane was coated with ionic liquid and tested with a seven component model feed described in Table 1, using a dodecane carrier. The receiving side (permeate) included a dodecane solution to sweep accumulated permeate from the surface of the membrane. A gear pump was connected to each side while samples were extracted from the reservoirs to measure the change in composition on both sides. The samples collected were analyzed by gas chromatography, and for total sulfur by the ASTM D 5453 method. The process was performed at a low flow rate (10 milliliters per min) for 48 hours.

	TABLE 1

	Feed temperature (° C.)	24
	Cyclohexane, parts per million (ppm)	4029
	Iso-octane, ppm	7290
	Toluene, ppm	5611
	N-Hexanes, ppm	4826
	DBT, ppm	7874
	Thiophene, ppm	4559
	Total Sulfur, ppm	2265
	Permeate flux, kilograms sulfur per	0.0013
	hour per square meter (kgS/hr/m²)
	Selectivity of Thiophene/Hexanes	156
	Selectivity of DBT/Hexanes	142
	Selectivity of Thiophene/Toluene	2.8
	Selectivity of DBT/Toluene	2.6

Example 4

A PTFE membrane filter with 0.2 micron pores having a diameter of 47 millimeters (Omnipore™ commercially available from Millipore, Billerica, Mass.) was prepared. The membrane was coated with ionic liquid and tested with a seven component model feed described in Table 2 using a dodecane carrier. The receiving side (permeate) included a dodecane solution to sweep accumulated permeate on the surface of the membrane. A gear pump was connected to each side while samples were extracted from the reservoirs to measure the change in composition on both sides. The samples collected were analyzed by gas chromatography, and total sulfur methods. The process was performed at a low flow rate (10 milliliters per min) for 48 hours.

	TABLE 2

	Feed temperature (° C.)	24
	Cyclohexane, ppm	2723
	Iso-octane, ppm	4208
	Toluene, ppm	2859
	N-Hexanes, ppm	2859
	DBT, ppm	8764
	Thiophene, ppm	1618
	Total Sulfur, ppm	2889
	Permeate flux, kgS/hr/m²	0.001
	Selectivity of Thiophene/Hexanes	139
	Selectivity of DBT/Hexanes	38
	Selectivity of Thiophene/Toluene	7.3
	Selectivity of DBT/Toluene	2.0

The results set forth in Tables 1 and 2 above indicate that aromatic sulfur compounds can be selectively removed from the feed without removing aliphatic compounds. Selectivity is expressed as the ratio of organosulfur compound to the other mixture components in the permeate. The coated ionic liquid membrane exhibited selective permeation for thiophene and dibenzothiophene (DBT) over other aliphatic and aromatic compounds.
The process of the invention has been described and explained with reference to the schematic process drawings and examples. Additional variations and modifications will be apparent to those of ordinary skill in the art based on the above description and the scope of the invention is to be determined by the claims that follow.

Claims

1. A process for reducing the sulfur content of an unrefined liquid hydrocarbon feedstream containing sulfur compounds, the process comprising:

providing a membrane separation unit containing a membrane having a porous substrate with a sulfur-selective material retained upon the surface of the substrate and/or within the pores of the substrate;

introducing the unrefined liquid hydrocarbon feedstream into the membrane separation unit;

concentrating the sulfur compounds in a first unrefined hydrocarbon stream as a liquid permeate of the membrane unit;

recovering as a liquid retentate of the membrane separation unit a second unrefined hydrocarbon separation product stream of reduced sulfur content;

recovering and subjecting the first unrefined hydrocarbon stream to a hydrodesulfurization process step and recovering a third stream that is substantially free of sulfur compounds; and

mixing the second unrefined hydrocarbon stream and the third product stream to provide a final product stream of low sulfur content.

2. The process of claim 1 in which the membrane separation unit is operated with a sweep stream on the permeate side of the membrane at a temperature between about 15° C. and about 60° C.

3. The process of claim 1 in which the membrane separation unit is operated with an imposed pressure differential across the membrane of between about 1 psi and about 15 psi.

4. A process for reducing the sulfur content of a hydrocarbon feed stream comprising:

a. providing a membrane separation unit containing a membrane having a porous substrate with a sulfur-selective material upon the surface of the substrate and/or within the pores of the substrate, the membrane having a first side and a second side;

b. conveying an unrefined liquid hydrocarbon feedstream past the first side of the membrane;

c. recovering a liquid permeate unrefined hydrocarbon stream from the second side of the membrane, the permeate unrefined hydrocarbon stream having a higher sulfur concentration than the unrefined hydrocarbon stream; and

d. recovering a liquid retentate unrefined hydrocarbon stream from the first side of the membrane, the retentate unrefined hydrocarbon stream having a lower sulfur concentration than the unrefined hydrocarbon stream.

5. A process for reducing the sulfur content of a hydrocarbon feed that includes a first desulfurization stage and a second desulfurization stage, the process comprising:

b. conveying an unrefined liquid hydrocarbon stream past the first side of the membrane;

c. recovering a liquid retentate unrefined hydrocarbon stream from the first side of the membrane, the retentate unrefined hydrocarbon stream having a lower sulfur content than the unrefined hydrocarbon stream; and

d. recovering a liquid permeate unrefined hydrocarbon stream having a higher sulfur content than the unrefined hydrocarbon stream from the second side of the membrane and treating it the second desulfurization stage.

6. The process of claim 5, wherein the second desulfurization stage includes a hydrodesulfurization step.

7. The process of claim 5, wherein the second desulfurization stage includes an oxidative desulfurization step.

8. The process of claim 1, wherein the unrefined liquid hydrocarbon feedstream is crude oil.

9. The process of claim 1, wherein the sulfur-selective material is selective to thiophenes.

10. The process of claim 5, wherein the sulfur-selective material is selective to dibenzothiophenes.

11. The process of claim 1, wherein the sulfur selective material comprises an ionic liquid.

12. The process of claim 11, wherein the ionic liquid comprises a methyl-pyridinium based ionic liquid.

13. The process of claim 12, wherein the methyl-pyridinium based ionic liquid comprises N-butyl-3-methyl-pyridinium methyl sulfate.

14. The process of claim 11, wherein the ionic liquid comprises an imidazolium-based ionic liquid.

15. The process of claim 4, wherein the unrefined liquid hydrocarbon feedstream is crude oil.

16. The process of claim 4, wherein the sulfur-selective material is selective to thiophenes.

17. The process of claim 5, wherein the unrefined liquid hydrocarbon feedstream is crude oil.

18. The process of claim 5, wherein the sulfur-selective material is selective to thiophenes.

19. The process of claim 4, wherein the sulfur selective material comprises an ionic liquid.

20. The process of claim 19, wherein the ionic liquid comprises a methyl-pyridinium based ionic liquid.

21. The process of claim 20, wherein the methyl-pyridinium based ionic liquid comprises N-butyl-3-methyl-pyridinium methyl sulfate.

22. The process of claim 19, wherein the ionic liquid comprises an imidazolium-based ionic liquid.

23. The process of claim 5, wherein the sulfur selective material comprises an ionic liquid.

24. The process of claim 23, wherein the ionic liquid comprises a methyl-pyridinium based ionic liquid.

25. The process of claim 24, wherein the methyl-pyridinium based ionic liquid comprises N-butyl-3-methyl-pyridinium methyl sulfate.

26. The process of claim 23, wherein the ionic liquid comprises an imidazolium-based ionic liquid.