U.S. patent application number 12/826019 was filed with the patent office on 2011-01-06 for membrane desulfurization of liquid hydrocarbons using an extractive liquid membrane contactor system and method.
Invention is credited to Ahmed Bahamdan, Esam Z. Hamad, Feras Hamad, Tammana Veera Venkata Ramakrishna, Garba O. Yahaya.
Application Number | 20110000823 12/826019 |
Document ID | / |
Family ID | 43411399 |
Filed Date | 2011-01-06 |
United States Patent
Application |
20110000823 |
Kind Code |
A1 |
Hamad; Feras ; et
al. |
January 6, 2011 |
MEMBRANE DESULFURIZATION OF LIQUID HYDROCARBONS USING AN EXTRACTIVE
LIQUID MEMBRANE CONTACTOR SYSTEM AND METHOD
Abstract
The process of the present invention is directed to the
desulfurization of a sulfur-containing hydrocarbon stream with a
membrane contactor, where sulfur compounds are concentrated in a
sulfur-rich stream on a permeate side of the membrane using an
extractive liquid, and a sulfur-lean stream is recovered as a
retentate. The sulfur-rich stream, which has a small volume
relative to the original hydrocarbon stream, is conveyed to a
recovery zone to recover extractive liquid, and the remaining
hydrocarbon stream having an increased concentration of sulfur
compounds is passed to a downstream desulfurization apparatus or
system, such as a hydrotreating system, to recover the hydrocarbons
associated with the organosulfur compounds.
Inventors: |
Hamad; Feras; (Dhahran,
SA) ; Bahamdan; Ahmed; (Dhahran, SA) ; Yahaya;
Garba O.; (Dhahran, SA) ; Ramakrishna; Tammana Veera
Venkata; (Dhahran, SA) ; Hamad; Esam Z.;
(Dhahran, SA) |
Correspondence
Address: |
ABELMAN, FRAYNE & SCHWAB
666 THIRD AVENUE, 10TH FLOOR
NEW YORK
NY
10017
US
|
Family ID: |
43411399 |
Appl. No.: |
12/826019 |
Filed: |
June 29, 2010 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61222411 |
Jul 1, 2009 |
|
|
|
Current U.S.
Class: |
208/236 ;
196/14.52; 208/237; 208/240; 208/250 |
Current CPC
Class: |
C10G 21/12 20130101;
C10G 31/11 20130101 |
Class at
Publication: |
208/236 ;
208/250; 208/240; 208/237; 196/14.52 |
International
Class: |
C10G 21/20 20060101
C10G021/20; C10G 21/22 20060101 C10G021/22; C10G 21/12 20060101
C10G021/12; C10G 21/16 20060101 C10G021/16; C10G 21/00 20060101
C10G021/00 |
Claims
1. A method of reducing the sulfur content of a sulfur-containing
hydrocarbon feedstream comprising: passing the feedstream in
contact with a membrane on a retentate side of a membrane
separation unit; passing an extractive liquid in contact with the
membrane on a permeate side of the membrane separation unit under
conditions in which the extractive liquid contacts the feedstream;
concentrating sulfur compounds in the extractive liquid in a
permeate stream of the membrane separation unit; recovering as a
retentate stream a first hydrocarbon product stream of reduced
sulfur content; recovering and subjecting the permeate stream to a
fractionation process step for recovery of at least a portion of
the extractive liquid; and recovering a resulting sulfur-rich
hydrocarbon stream from the fractionation process step.
2. The method of claim 1, wherein the sulfur-rich hydrocarbon
stream is subjected to a hydrodesulfurization process step, and
recovering a second hydrocarbon product stream of reduced sulfur
content.
3. The method of claim 1, further comprising mixing the first and
second hydrocarbon product streams to provide a final product
stream of reduced sulfur content.
4. The method of claim 1, wherein the feedstream contains a
plurality of different sulfur-containing compounds and at least
certain of the sulfur-containing compounds are soluble in the
extractive liquid.
5. The method of claim 4, wherein the extractive liquid is selected
from the group consisting of fumaronitrile; maleonitrile; glyoxal;
2-nitrofuran; acetonitrile; acrylonitrile; nitramine; isoxazole;
furfural; 5-methylfurfural; benzoylacetonitrile; vinyl formate;
methyl formate; oxazole; sulfuric acid; diketene; benzonitrile;
acrolein; dimethyl-oxalate; furan; benzaldehyde; acetic anhydride;
methacrylonitrile; dimethyl sulfide; lactic acid; acetic acid;
dimethyl formamide; dimethyl sulfoxide; aqueous potassium
hydroxide; furfuryl alcohol; vinylacetylene; nicotinonitrile;
pyridazine; methylmaleic anhydride; acetaldehyde; cis-crotonitrie;
3-nitrobenzotrifluoride; methyl phenyl ketone; vinyl acetate;
p-tolualdehyde; m-tolualdehyde; o-tolualdehyde;
propylene-carbonate; methanol; methanol and aqueous sodium
hydroxide; dimethylsulfoxide and methanol; 1-ethyl,
3-methylimidazolium ethyl sulfate; 1-ethyl, 3-methylimidazolium
methyl sulfate; 1-ethyl, 3-methylimidazolium hexafluorophosphate;
1-butyl, 3-methylimidazolium tetrafluoroborate; 1-ethyl,
3-methylimidazolium bis(trifluoromethanesulfonyl)imidate;
1-n-propyl-3-methylimidazolium
bis(trifluoromethanesulfonyl)imidate;
1-n-butyl-3-methylimidazolium; 1-n-butyl-3-methylimidazolium
trifluorotris(pentafluoroethyl)phosphate;
1-n-hexyl-3-methylimidazolium bis(trifluoromethanesulfonyl)imidate;
and 1-n-decyl-3-methylimidazolium
bis(trifluoromethanesulfonyl)imidate.
6. The method of claim 1, wherein target sulfur compounds comprise
aliphatic sulfur molecules, and the extractive liquid is selected
from the group consisting of acetonitrile; dimethyl sulfoxide;
acrylonitrile; benzonitrile; dimethyl formamide; aqueous sodium
hydroxide; aqueous potassium hydroxide; furfuryl alcohol;
vinylacetylene; sulfuric acid; dimethylsulfoxide and methanol;
furfural; and 5-methylfurfural.
7. The method of claim 1, wherein target sulfur compounds comprise
aromatic sulfur compounds including thiophenes, benzothiophenes and
dibenzothiophenes, and the extractive liquid is selected from the
group consisting of acetonitrile; furfural; benzonitrile; dimethyl
sulfide; dimethyl formamide; methanol; lactic acid;
propylene-carbonate; 5-methylfurfural; methyl formate; 1-ethyl,
3-methylimidazolium ethyl sulfate; 1-ethyl, 3-methylimidazolium
methyl sulfate; 1-ethyl, 3-methylimidazolium hexafluorophosphate;
1-butyl, 3-methylimidazolium tetrafluoroborate; 1-ethyl,
3-methylimidazolium bis(trifluoromethanesulfonyl)imidate;
1-n-propyl-3-methylimidazolium
bis(trifluoromethanesulfonyl)imidate; 1-n-butyl-3-methylimidazolium
trifluorotris(pentafluoroethyl)phosphate; and
1-n-butyl-3-methylimidazolium.
8. The method of claim 1, wherein target sulfur compounds comprise
alkyl derivatives of aromatic sulfur molecules including
4,6-dimethyl-dibenzothiophenes, and the extractive liquid is
selected from the group consisting of acetonitrile; acrylonitrile;
furfural; 5-methylfurfural; benzoylacetonitrile; vinyl formate;
diketene; benzonitrile; acrolein; dimethyl-oxalate; benzaldehyde;
acetic anhydride; methacrylonitrile; acetic acid; dimethyl
formamide; dimethyl sulfoxide; aqueous potassium hydroxide;
furfuryl alcohol; 1-ethyl, 3-methylimidazolium ethyl sulfate;
1-ethyl, 3-methylimidazolium methyl sulfate; 1-ethyl,
3-methylimidazolium hexafluorophosphate; 1-butyl,
3-methylimidazolium tetrafluoroborate; and 1-ethyl,
3-methylimidazolium bis(trifluoromethanesulfonyl)imidate.
9. The method of claim 1, wherein the membrane is a porous
membrane.
10. The method of claim 9, wherein the porous membrane constitutes
a controlled interface for contact between the hydrocarbon
feedstream and the extractive liquid.
11. The method of claim 9, wherein the porous membrane constitutes
a non-dispersive contact interface between the extractive liquid
and the hydrocarbon feedstream.
12. The method of claim 9, wherein the porous membrane comprises a
material which is insoluble in the hydrocarbon and the extractive
liquid.
13. The method of claim 9, wherein the porous membrane comprises a
material which undergoes minimal swelling in the hydrocarbon and
the extractive liquid.
14. A liquid hydrocarbon desulfurization system comprising: a
source of extractive liquid; a membrane housing including a porous
membrane having a retentate side and a permeate side, a retentate
portion configured and dimensioned for maximizing contact between a
liquid hydrocarbon feedstream and the retentate side of the
membrane, and a permeate portion configured and dimensioned for
maximizing contact between the extractive liquid and the retentate
side of the membrane.
Description
RELATED APPLICATIONS
[0001] This applications claims priority to U.S. Provisional Patent
Application Ser. No. 61/222,411, which is incorporated by reference
in its entirety herein.
FIELD OF THE INVENTION
[0002] The invention relates to processes for desulfurization of a
hydrocarbon feed using membrane separation, and more particularly
to a process and system for desulfurization of a hydrocarbon feed
using an extractive liquid membrane separation contactor.
BACKGROUND OF THE INVENTION
[0003] 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, 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."
[0004] 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.
[0005] 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.
[0006] 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.
[0007] The most common hydrocarbon desulfurization process is
hydrotreating, in particular, hydrodesulfurization. In typical
hydrodesulfurization 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.degree. C. and pressures of about
30 to 200 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.
[0008] 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.
[0009] 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.
[0010] 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.
[0011] 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 cut naphtha feed under pervaporation conditions. The
processes propose to minimize olefin and naphthene hydrogenation
during hydrotreating, particularly problematic in hydrotreating FCC
naphtha since the high olefin content is again prone to
hydrogenation.
[0012] 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.
[0013] 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.
[0014] 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.
[0015] 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.
[0016] Various problems exist with the above-described existing
membrane desulfurization processes. In some processes, dense layer
of polymeric membrane are relied upon to enhance the selectivity of
the membrane to sulfur compounds. However, this required extensive
energy consumption to pass the materials through the membrane, and
also limits the feed stream.
[0017] In addition, some existing membrane desulfurization
processes require material to be transformed into a gaseous phase
in order to increase the permeate transport rate. The material is
transformed by heating and/or vacuum, also increasing the energy
requirements. Other membrane desulfurization processes require the
use of a transport agent to enhance the transport rate of sulfur
compounds in dense layer of polymeric membrane. Transport agents
generally cause plasticizing of the selective membrane and has a
deleterious impact on its selectively to sulfur compounds.
[0018] Another approach to reducing the sulfur content in
hydrocarbons uses dispersed phase contactors. However, dispersed
phase contactors require high solvent holdup, which is often
associated with other problems such as emulsion formation, foaming,
unloading and flooding. Further, conventional extraction techniques
such as liquid-liquid extraction, in which the two liquids are
intermixed, suffers from many drawbacks, including slow phase
separation and production of stable emulsions, resulting in the
need to produce high surface area for mass transfer.
[0019] Therefore, it is an object of the present invention to
provide a membrane separation process and apparatus to desulfurize
liquid hydrocarbon streams without the above-described problems
associated with conventional membrane desulfurization
processes.
[0020] It is a further object of the present invention to provide a
liquid extraction process and system to desulfurize liquid
hydrocarbon streams without the above-described problems associated
with dispersed phase contactors.
[0021] It would therefore be desirable to provide a system and
method that reduces the sulfur content of hydrocarbon streams using
an extractive liquid membrane contactor.
SUMMARY OF THE INVENTION
[0022] The present invention utilizes an extractive liquid membrane
contactor to desulfurize a hydrocarbon stream. A sulfur-containing
liquid hydrocarbon is passed in contact with the retentate side of
a porous membrane, while an extractive liquid is passed along the
permeate side of the porous membrane. The membrane provides a
controlled interface to allow the extractive liquid to draw
sulfur-containing compounds from the hydrocarbon liquid.
[0023] In particular, the proposed membrane contactor relies on
extractive liquids to solubilize and transfer the sulfur compounds
though pores of the membrane, so that the transfer rate of the
sulfur compounds is not hindered. The membrane contactor brings the
extractive liquid and the liquid feedstream into controlled contact
without intermixing. The requirements for creating a vacuum or to
convert the permeate in a gaseous phase in order to enhance the
transport of the sulfur compounds are obviated, and the operating
costs associated with the use of vacuum and energy of vaporization
are eliminated.
[0024] In one aspect, a process of the present invention is
directed to desulfurization of a sulfur-containing hydrocarbon
stream with a membrane separation apparatus in which 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 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 of hydrocarbons.
BRIEF DESCRIPTION OF THE DRAWINGS
[0025] Further advantages and features of the present invention
will become apparent from the detailed description of a preferred
embodiment of the invention that follows and reference to the
accompanying drawings, in which:
[0026] FIG. 1 is a schematic diagram of a combined membrane
separation desulfurization process and an alternate desulfurization
process according to embodiments of the invention; and
[0027] FIG. 2 is a schematic diagram of a combined membrane
separation desulfurization process and an alternate desulfurization
process according to embodiments of the invention using extractive
liquid as a sweep stream and including an extractive liquid
regeneration/recovery zone.
DETAILED DESCRIPTION OF THE INVENTION
[0028] As used herein, the term "unrefined hydrocarbon" is to be
understood to mean crude oil and 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 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.
[0029] With reference to FIG. 1, a schematic overview of a
desulfurization system 10 is described. A hydrocarbon feedstream
12, such as a hydrocarbon feedstream 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 unit 14 by transfer to an extractive liquid
stream on the permeate side of the membrane. The sulfur-containing
hydrocarbons thus are concentrated into a sulfur-rich hydrocarbon
stream 16. The portion of the feedstream remaining on the feed side
of the membrane, the retentate, is conveyed as a sulfur-lean
hydrocarbon stream 18. The sulfur-lean hydrocarbon stream 18 has a
substantially reduced concentration of sulfur-containing compounds
as compared to the feedstream 12. The sulfur-rich stream 16,
typically a small volume as compared to the volume of the original
feedstream 12, is transferred to a second stage desulfurization
system 20, such as a hydrotreating unit, after a post treatment
step to remove at least a portion of the extractive liquid, to
recover useful hydrocarbons associated with the organosulfur
compounds. Effluent from the second stage desulfurization system
20, a second stage sulfur-lean stream 22, and the membrane
desulfurized hydrocarbon stream 18, can be combined to provide a
low sulfur hydrocarbon stream 24 with minimal or no loss in
hydrocarbon product volume. In an alternative embodiment of the
process, the second stage sulfur-lean stream 22 that may be rich in
aromatics is transferred to one or more subsequent processing
steps.
[0030] The combined membrane separation system 10 described herein
advantageously is conducted as a liquid separation process. The
hydrocarbon feedstream 12, the sulfur-rich hydrocarbon stream 16
and the sulfur-lean hydrocarbon stream 18 are all maintained in the
liquid phase. The feedstream 12, which can be a crude oil
feedstream, a diesel feedstream, a naphtha feedstream, a gas oil
feedstream, or a 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, and thus remain in the sulfur-lean
hydrocarbon stream 18. Accordingly, the prior art pervaporation
operations described above 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.
[0031] 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 hydrocarbon feedstream
desulfurization.
[0032] 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 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.
[0033] The membrane is generally formed of a porous material, which
provides sites for controlled interface between liquid hydrocarbon
feed and extractive liquid. The transport of sulfur compounds
mainly occurs between the liquids in the membrane pores. In certain
embodiments, the porous membrane provides a non-dispersive contact
interface between the extractive liquid and the hydrocarbon
feedstream. The non-dispersive contact via the porous membrane
contactor improves performance as compared to conventional
dispersed-phase contactors, such as liquid-liquid extraction. In
addition, solvent holdup is low, which is advantageous especially
in embodiments in which expensive extractive liquid solvents are
used. The membrane contactor of the present invention also avoids
problems often encountered in conventional contactors, such as
formation of emulsions, foaming, unloading and flooding.
[0034] Preferably, the porous membrane is formed of a material
which has good wetability properties and is insoluble in the
hydrocarbon and the extractive liquid. Further, the material for
the membrane is selected so as to minimize swelling in the presence
of the hydrocarbon and the extractive liquids.
[0035] Membrane materials include those conventionally used for
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.RTM., nylon and polyether
terephthalate (PET). Other non-polymer materials can also be
used.
[0036] The membrane contactor provides a contact interface between
the hydrocarbon feed and the extractive liquid. The selectivity of
the membrane system to sulfur compounds is generally impacted by
the choice of extractive liquid. In addition, because of the porous
nature of the membrane, much higher flux and permeability are
obtainable when compared to nonporous (solid) membranes, such as
those used in pervaporation membrane processes.
[0037] In certain embodiments, the extractive liquid comprises a
compound or mixture selected from the group consisting of
fumaronitrile; maleonitrile; glyoxal; 2-nitrofuran; acetonitrile;
acrylonitrile; nitramine; isoxazole; furfural; 5-methylfurfural;
benzoylacetonitrile; vinyl formate; methyl formate; oxazole;
sulfuric acid; diketene; benzonitrile; acrolein; dimethyl-oxalate;
furan; benzaldehyde; acetic anhydride; methacrylonitrile; dimethyl
sulfide; lactic acid; acetic acid; dimethyl formamide; dimethyl
sulfoxide; aqueous potassium hydroxide; furfuryl alcohol;
vinylacetylene; nicotinonitrile; pyridazine; methylmaleic
anhydride; acetaldehyde; cis-crotonitrie; 3-nitrobenzotrifluoride;
methyl phenyl ketone; vinyl acetate; p-tolualdehyde;
m-tolualdehyde; o-tolualdehyde; propylene-carbonate; methanol;
methanol and aqueous sodium hydroxide; dimethylsulfoxide and
methanol; 1-ethyl, 3.sup.--methylimidazolium ethyl sulfate;
1-ethyl, 3-methylimidazolium methyl sulfate; 1-ethyl,
3-methylimidazolium hexafluorophosphate; 1-butyl,
3-methylimidazolium tetrafluoroborate; 1-ethyl, 3-methylimidazolium
bis(trifluoromethanesulfonyl)imidate;
1-n-propyl-3-methylimidazolium
bis(trifluoromethanesulfonyl)imidate;
1-n-butyl-3-methylimidazolium; 1-n-butyl-3-methylimidazolium
trifluorotris(pentafluoroethyl)phosphate;
1-n-hexyl-3-methylimidazolium bis(trifluoromethanesulfonyl)imidate;
and 1-n-decyl-3-methylimidazolium
bis(trifluoromethanesulfonyl)imidate.
[0038] The following Table 1 summarizes the performance of certain
extractive solvents for sulfur removal from diesel having a 1.4%
w/w sulfur content, based on equilibrium partitioning of sulfur
compounds between the hydrocarbon phase and extractive liquid
phase:
TABLE-US-00001 TABLE 1 Solvent Weight % Sulfur removal Furfural
28.6 Acetonitrile 26.2 Methanol 16.1 5-Methyl furfural 47.3
Propylene carbonate 16.0 Dimethyl sulfoxide 10.5 Acetone/water
(50/50) 3.7 Furfuryl alcohol 18.8 Acetic acid 22.6 Lactic acid 2.0
Dimethylformamide 40.8
[0039] The following Table 2 summarizes the performance of certain
extractive solvents for sulfur removal from Arab Light crude oil
having a 1.9% w/w sulfur content, based on equilibrium partitioning
of sulfur compounds between the hydrocarbon phase and extractive
liquid phase:
TABLE-US-00002 TABLE 2 Solvent Weight % Sulfur removal Furfural
13.6 Acetonitrile 3.9 Methanol 1.5
[0040] In certain embodiments in which the target sulfur compounds
comprise aliphatic sulfur molecules, the extractive liquid is
selected from the group consisting of acetonitrile; dimethyl
sulfoxide; acrylonitrile; benzonitrile; dimethyl formamide; aqueous
sodium hydroxide; aqueous potassium hydroxide; furfuryl alcohol;
vinylacetylene; sulfuric acid; dimethylsulfoxide and methanol;
furfural; and 5-methylfurfural.
[0041] In additional embodiments in which the target sulfur
compounds comprise aromatic sulfur compounds including thiophenes,
benzothiophenes and dibenzothiophenes, and the extractive liquid is
selected from the group consisting of acetonitrile; furfural;
benzonitrile; dimethyl sulfide; dimethyl formamide; methanol;
lactic acid; propylene-carbonate; 5-methylfurfural; methyl formate;
1-ethyl, 3-methylimidazolium ethyl sulfate; 1-ethyl,
3-methylimidazolium methyl sulfate; 1-ethyl, 3-methylimidazolium
hexafluorophosphate; 1-butyl, 3-methylimidazolium
tetrafluoroborate; 1-ethyl, 3-methylimidazolium
bis(trifluoromethanesulfonyl)imidate;
1-n-propyl-3-methylimidazolium
bis(trifluoromethanesulfonyl)imidate; 1-n-butyl-3-methylimidazolium
trifluorotris(pentafluoroethyl)phosphate; and
1-n-butyl-3-methylimidazolium.
[0042] In further embodiments in which the target sulfur compounds
comprise alkyl derivatives of aromatic sulfur molecules including
4,6-dimethyl-dibenzothiophenes, the extractive liquid is selected
from the group consisting of acetonitrile; acrylonitrile; furfural;
5-methylfurfural; benzoylacetonitrile; vinyl formate; diketene;
benzonitrile; acrolein; dimethyl-oxalate; benzaldehyde; acetic
anhydride; methacrylonitrile; acetic acid; dimethyl formamide;
dimethyl sulfoxide; aqueous potassium hydroxide; furfuryl alcohol;
1-ethyl, 3-methylimidazolium ethyl sulfate; 1-ethyl,
3-methylimidazolium methyl sulfate; 1-ethyl, 3-methylimidazolium
hexafluorophosphate; 1-butyl, 3-methylimidazolium
tetrafluoroborate; and 1-ethyl, 3-methylimidazolium
bis(trifluoromethane sulfonyl)imidate.
[0043] In contrast to pervaporation techniques commonly known in
the art, the membrane separation system for separating sulfur
compounds from hydrocarbon feeds of the present invention operates
at temperatures and pressures that maintain the feedstream in
liquid phase.
[0044] 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.
[0045] In a preferred embodiment, the membrane unit is configured
and dimensioned to allow maximum contact between the liquid
hydrocarbon feedstream and the porous membrane on the retentate
side, and to allow maximum contact between the extractive liquid
and the porous membrane on the permeate side. The configuration and
dimensions are provided to allow substantially all of the liquid
hydrocarbon feedstream to come into contact with the porous
membrane, and hence with the extractive liquid maintained in the
pores of the membrane.
[0046] 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 system effluent with minimal or no loss of the original
hydrocarbon volume. This low sulfur hydrocarbon effluent can serve
as a feedstream for subsequent fractionating in a downstream
process. Alternatively, the low sulfur hydrocarbon effluent may be
sold as sweet crude oil, thereby taking advantage of the favorable
price differential between sweet and sour crude oils.
[0047] Referring to FIG. 2, a configuration of a system 100 of the
present invention is schematically depicted. Crude oil or other
hydrocarbons are conveyed from a feed tank 108 in a stream 112 to a
retentate side 136 of the membrane contactor 114. Extractive liquid
is introduced via a sweep stream 140 to the permeate side of the
membrane contactor from an extractive liquid vessel 142. At the
membrane 114 interface, controlled contact is provided between the
feedstream and the extractive liquid so as to minimize intermixing
of the liquids. The membrane contactor 114 provides the required
surface area to meet the requisite degree of sulfur removal.
[0048] The extractive liquids are selected to draw the
sulfur-containing compounds out of the hydrocarbon feedstream, such
as aliphatic sulfur molecules (including but not limited to
sulfides, disulfides and mercaptans) and/or aromatic molecules
(including but not limited to thiophenes, benzothiophenes,
dibenzothiophenes and alkyl derivatives of aromatic sulfur
molecules such as 4,6-dimethyl-dibenzothiophenes). The sulfur-lean
stream 118 can be used as is, or combined with the sulfur-rich
stream 116 after it has been subjected to further
desulfurization.
[0049] The sulfur-rich stream 116, including a high concentration
of sulfur compounds and extractive liquids, are passed to a
suitable regeneration zone, such as a flash tank 144, within which
solvents (extractive liquid) is recovered/regenerated via a recycle
line 145, and sulfur rich oil is discharged. The sulfur-rich
hydrocarbon stream is passed to a conventional desulfurization
process 120 such as a hydrodesulfurization unit. The
hydrodesulfurized hydrocarbons 122 and the retentate hydrocarbons
118 can be used as separate product streams or combined as a single
product stream.
Example
[0050] Membrane contactors using polyvinylidene fluoride (PVDF)
flat sheet ultrafiltration membranes were constructed and tested in
accordance with the present invention. The membranes were about 125
.mu.m in thickness, had pores of 0.1 .mu.m or 0.2 .mu.m, and a
porosity of 70%, 75% or 80%. Furfural was used as the extractive
solvent. The flow rate of both the extractive solvent and the
hydrocarbon streams was set at 10 milliliters per minute. Table 3
provides the results indicating effective mass transfer
coefficients (in centimeters per hour).
TABLE-US-00003 TABLE 3 Mass Transfer Hydrocarbon stream Membrane
Contactor Coefficient Arab light crude 0.1 .mu.m pore, 70% porosity
0.25 (1.9% w/w sulfur) Diesel (1.5% w/w sulfur) 0.1 .mu.m pore, 70%
porosity 0.19 Diesel (1.5% w/w sulfur) 0.1 .mu.m pore, 75% porosity
0.28 Diesel (1.5% w/w sulfur) 0.2 .mu.m pore, 80% porosity 0.37
[0051] 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.
* * * * *