U.S. patent application number 13/906720 was filed with the patent office on 2014-12-04 for hydrocarbon conversion processes using ionic liquids.
The applicant listed for this patent is UOP LLC. Invention is credited to Alakananda Bhattacharyya, Rajeswar R. Gattupalli, Robert B. James, Beckay J. Mezza, Massimo Sangalli, Peter Van Opdorp.
Application Number | 20140353208 13/906720 |
Document ID | / |
Family ID | 51983913 |
Filed Date | 2014-12-04 |
United States Patent
Application |
20140353208 |
Kind Code |
A1 |
Gattupalli; Rajeswar R. ; et
al. |
December 4, 2014 |
HYDROCARBON CONVERSION PROCESSES USING IONIC LIQUIDS
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.
Inventors: |
Gattupalli; Rajeswar R.;
(Arlington Heights, IL) ; Mezza; Beckay J.;
(Arlington Heights, IL) ; Bhattacharyya; Alakananda;
(Glen Ellyn, IL) ; James; Robert B.; (Northbrook,
IL) ; Sangalli; Massimo; (Des Plaines, IL) ;
Van Opdorp; Peter; (Naperville, IL) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
UOP LLC |
Des Plaines |
IL |
US |
|
|
Family ID: |
51983913 |
Appl. No.: |
13/906720 |
Filed: |
May 31, 2013 |
Current U.S.
Class: |
208/88 |
Current CPC
Class: |
C10G 55/06 20130101;
C10G 21/27 20130101; C10G 2300/305 20130101; C10G 21/28 20130101;
C10G 2300/307 20130101; C10G 2300/202 20130101; C10G 2300/308
20130101 |
Class at
Publication: |
208/88 |
International
Class: |
C10G 55/06 20060101
C10G055/06 |
Claims
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; 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.
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.
Description
BACKGROUND OF THE INVENTION
[0001] 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.
[0002] 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.
[0003] 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.
[0004] There remains a need in the art for improved conversion
processes for hydrocarbon feeds having contaminants.
SUMMARY OF THE INVENTION
[0005] 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.
[0006] 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
[0007] FIG. 1 is a simplified flow scheme illustrating various
embodiments of the conversion processes.
[0008] 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
[0009] 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.
[0010] In general, VGO comprises petroleum hydrocarbon components
boiling in the range of from about 100.degree. C. to about
720.degree. C. In an embodiment, the VGO boils from about
250.degree. C. to about 650.degree. C. and has a density in the
range of from about 0.80 g/cm.sup.3 to about 1.2 g/cm.sup.3. In
another embodiment, the VGO boils from about 95.degree. C. to about
580.degree. C.; and in a further embodiment, the VGO boils from
about 300.degree. C. to about 720.degree. C.
[0011] The term "coker gas oil" means the hydrocarbon material
boiling in the range between about 260.degree. C. and about
600.degree. 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.
[0012] The term "heavy coker gas oil" means the hydrocarbon
material boiling in the range between about 300.degree. C. and
about 620.degree. 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.
[0013] The term "light cycle oil" means the hydrocarbon material
boiling in the range between about 205.degree. C. and about
400.degree. 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.
[0014] The term "vacuum residue" means the hydrocarbon material
boiling of at least about 510.degree. 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.
[0015] The term "light olefins" means the hydrocarbon material
boiling in the range less than 38.degree. 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 C.sub.2, C.sub.3, and C.sub.4 olefins.
[0016] The term "diesel" means the hydrocarbon material boiling in
the range between about 150.degree. C. and about 370.degree. 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.
[0017] The term "naphtha" means the hydrocarbon material boiling in
the range between about 10.degree. C. and about 200.degree. 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.
[0018] The term "gasoline" means the hydrocarbon material boiling
in the range between about 10.degree. C. (80.degree. F.) and about
185.degree. 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.
[0019] The term "distillate" means the hydrocarbon material boiling
in the range between about 150.degree. C. and about 420.degree. 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.
[0020] The term "jet fuel" means the hydrocarbon material boiling
in the range between about 120.degree. C. and about 300.degree. 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.
[0021] The term "cetane number" means a diesel fuel rating
comparable to the octane-number rating for gasoline. Typically, it
is the percentage of cetane (C.sub.16H.sub.34) 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.
[0022] 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.degree. to about 35.degree.. The
Conradson carbon residue of such components is generally less than
30 wt %.
[0023] 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.
[0024] 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.sup.+.sub.feed-EP.sup.+.sub.product)/EP.sup.+.sub.feed).-
times.100%
[0025] Where EP.sup.+ indicates the fraction of material in the
feed or product boiling above the desired endpoint.
[0026] Yield is defined as the rate of formation of desired product
relative to the feed rate.
Yield=(Production Rate of Desired Product)/(Feed
Rate).times.100%
[0027] Selectivity is expressed as the yield of desired product
relative to conversion.
Selectivity=Yield/Conversion.times.100%
[0028] 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 %.
[0029] 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
%.
[0030] 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 %.
[0031] 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.
[0032] 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.
[0033] 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.
[0034] 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.
[0035] 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 %.
[0036] 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 %.
[0037] 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.
[0038] 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.degree. 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.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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.
[0045] 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;
[0046] 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.
[0047] 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.
[0048] 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.
[0049] 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.
[0050] 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.
[0051] Zeolite-based catalysts are commonly used in FCC reactors,
as are composite catalysts which contain zeolites, silica-aluminas,
alumina, and other binders.
[0052] Typical FCC conditions include a temperature of about
400.degree. C. to about 800.degree. 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.
[0053] Hydrocracking refers to a process in which hydrocarbons
crack in the presence of hydrogen to lower molecular weight
hydrocarbons.
[0054] 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.
[0055] Hydrocracking conditions may include a temperature of about
290.degree. C. (550.degree. F.) to about 468.degree. C.
(875.degree. F.), or about 343.degree. C. (650.degree. 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.sup.-1, and a hydrogen rate of about 421
to about 2,527 Nm.sup.3/m.sup.3 oil (2,500-15,000 scf/bbl).
[0056] 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.
[0057] 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-%.
[0058] Hydrotreating reaction conditions include a temperature of
about 290.degree. C. (550.degree. F.) to about 455.degree. C.
(850.degree. F.), or 316.degree. C. (600.degree. F.) to about
427.degree. C. (800.degree. F.) or 343.degree. C. (650.degree. F.)
to about 399.degree. C. (750.degree. 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.sup.-1 to
about 4 hr.sup.-1, or about 1.5 to about 3.5 hr.sup.-1, and a
hydrogen rate of about 168 to about 1,011 Nm.sup.3/m.sup.3 oil
(1,000-6,000 scf/bbl).
[0059] 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.
[0060] 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.
[0061] 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).
[0062] 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.
[0063] 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).
[0064] 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.
[0065] 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.
[0066] 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.
[0067] 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.
[0068] 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.degree. C. to less than the decomposition temperature of the
ionic liquid, usually less than about 300.degree. 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.
[0069] 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.
[0070] 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.
[0071] 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.
[0072] 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.
[0073] 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.
[0074] 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.degree. 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.degree. C. lower than the
first temperature. In a non limiting example, the first temperature
is about 80.degree. C. Such temperature differences may facilitate
separation of the hydrocarbon feed and ionic liquid phases.
[0075] 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.
[0076] 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.
[0077] 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.
[0078] 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.
[0079] 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.
[0080] 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.
[0081] 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
[0082] 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.degree. 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.degree. C. (380.degree. 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-US-00001 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.degree. C. (380F)
Conversion, vol % 75.2 80.22 C5 + Gasoline, vol % 55.25 59.08
Example 2
[0083] 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.degree. 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.degree. C.
(380.degree. 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-US-00002 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
[0084] 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.degree. 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.degree. C.
(380.degree. 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.degree. C. (380.degree. 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-US-00003 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 %
[0085] 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.
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