Note: Descriptions are shown in the official language in which they were submitted.
CA 02657780 2009-01-14
WO 2008/010799 PCT/US2006/027987
A HYDROCARBON DESULFURIZATION PROCESS
BACKGROUND OF THE INVENTION
[0001] The field of art to which this invention pertains is desulfurization of
hydrocarbon
feedstocks to low levels of sulfur. Hydrodesulfurization processes have been
used by
petroleum refiners to produce more valuable hydrocarbonaceous streams such as
naphtha,
gasoline, kerosene and diesel, for example, having lower concentrations of
sulfur and
nitrogen. Feedstocks most often subjected to hydrotreating or desulfurization
are normally
liquid hydrocarbonaceous streams such as naphtha, kerosene, diesel, gas oil,
vacuum gas oil
(VGO) and reduced crude, for example. Traditionally, hydrodesulfurization
severity is
selected to produce an improvement sufficient to produce a marketable product
or a suitable
feedstock for downstream processing. Over the years, it has been recognized
that due to
environmental concerns and newly enacted rules and regulations, saleable
products must meet
lower and lower limits on contaminants such as sulfur and nitrogen. Recently
new
regulations were proposed in the United States and Europe which basically
require the
complete removal of sulfur from liquid hydrocarbons which are used as
transportation fuels
such as gasoline and diesel.
[0002] Desulfurization is generally accomplished by contacting the
hydrocarbonaceous
feedstock in a desulfurization reaction vessel or zone with a suitable
desulfurization catalyst
under conditions of elevated temperature and pressure in the presence of
hydrogen to yield a
product containing the desired maximum limits of sulfur. The operating
conditions and the
desulfurization catalysts within the desulfurization reactor influence the
quality of the
desulfurized products.
[0003] Although a wide variety of process flow schemes, operating conditions
and
catalysts have been used in commercial desulfurization activities, there is
always a demand
for new desulfurization methods which provide lower costs and the required
product quality.
With the mandated low sulfur transportation fuels, the process of the present
invention greatly
improves the economic benefits of producing low sulfur fuels.
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INFORMATION DISCLOSURE
[00041 US 5,114,562 B 1 discloses a process wherein middle distillate
petroleum streams
are hydrotreated to produce a low sulfur and low aromatic product in two
reaction zones in
series. The effluent of the first reaction zone is purged of hydrogen sulfide
by hydrogen
stripping and then reheated by indirect heat exchange. The second reaction
zone employs a
sulfur-sensitive noble metal hydrogenation catalyst.
BRIEF SUMMARY OF THE INVENTION
[00051 The present invention is an improved process for the production of low
sulfur
hydrocarbonaceous products. A first hydrocarbonaceous feedstock comprising
hydrocarbon
components boiling above 343 C and hydrogen is reacted in a first
desulfurization zone to
produce a first desulfurization zone effluent which is introduced into a vapor-
liquid separator
operated at an elevated temperature to provide a vaporous stream comprising
lower boiling
hydrocarbonaceous compounds and hydrogen and a liquid hydrocarbonaceous stream
comprising hydrocarbon components having a reduced concentration of sulfur.
The vaporous
stream comprising lower boiling hydrocarbonaceous compounds, hydrogen, and a
second
hydrocarbonaceous feedstock comprising hydrocarbon components boiling below
371 C are
reacted in a hydrocracking zone to produce a hydrocracking zone effluent which
is introduced
together with a hydrocarbonaceous recycle stream preferably boiling in the
range from 149 C
to 371 C to a hydrogenation zone to produce a hydrogenation zone effluent
which is
fractionated to produce an ultra low sulfur hydrocarbonaceous stream
preferably boiling in the
range from 149 C to 371 C. The liquid hydrocarbonaceous stream provided by
the vapor-
liquid separator is fractionated to produce a hydrocarbonaceous recycle stream
preferably
boiling in the range from 149 C to 371 C and a liquid hydrocarbonaceous
stream comprising
hydrocarbon components boiling above 371 C and having a reduced concentration
of sulfur.
[0005.11 According to one aspect of the present invention there is provided a
process
for desulfurizing two hydrocarbonaceous feedstocks which process comprises the
following
steps: (a) reacting a first hydrocarbonaceous feedstock (1) comprising
hydrocarbon
components boiling above 343 F and hydrogen (28) with a desulfurization
catalyst in a
desulfurization zone (3) operated at desulfurization conditions to produce a
desulfurization
zone effluent (4); (b) introducing the desulfurization zone effluent into a
vapor-liquid
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separator (5) operated at a temperature greater than 288 C to provide a
vaporous stream (17)
comprising hydrogen, hydrogen sulfide and lower boiling hydrocarbonaceous
compounds
boiling up to 371 C and a first liquid hydrocarbonaceous stream (6)
comprising hydrocarbon
components boiling above 371 C and having a reduced concentration of sulfur;
(c) passing
the vaporous stream (17) comprising hydrogen, hydrogen sulfide and lower
boiling
hydrocarbonaceous compounds boiling up to 371 C and a second
hydrocarbonaceous
feedstock (18) comprising hydrocarbon components boiling below 371 C to a
hydrocracking
zone (21) to produce a hydrocracking zone effluent; (d) passing the
hydrocracking zone
effluent and a hydrocarbonaceous recycle stream (16) boiling in the range from
149 C to
371 C to a hydrogenation zone (22) to produce a hydrogenation zone effluent
(23); (e)
fractionating the hydrogenation zone effluent (23) to produce an ultra low
sulfur
hydrocarbonaceous steam (38) boiling in the range from 149 C to 371 C; and (f)
fractionating the first liquid hydrocarbonaceous steam (6) recovered in step
(b) to produce a
hydrocarbonaceous recycle stream (16) boiling in the range from 149 C to 371 C
and a
second liquid hydrocarbonaceous stream (17) comprising hydrocarbon components
boiling
above 371 C and having a reduced concentration of sulfur.
[0006] Other embodiments of the present invention encompass further details
such as
types and descriptions of feedstocks, desulfurization catalysts, hydrocracking
catalysts and
preferred operating conditions including temperatures and pressures, all of
which are
hereinafter disclosed in the following discussion of each of these facets of
the invention.
[0007] The drawing is a simplified process flow diagram of a preferred
embodiment of
the present invention.
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DETAILED DESCRIPTION OF THE INVENTION
[0008] It has been discovered that a more efficient and economical production
of ultra
low sulfur hydrocarbon products including ultra low sulfur diesel stock can be
achieved and
enjoyed in the above-described integrated hydrodesulfurization and
hydrocracking process.
[0009] In accordance with the present invention, the first feedstock which is
introduced
into the first desulfurization zone preferably contains components boiling
above 343 C and
more preferably boiling above 371 C and includes, for example, atmospheric
gas oils,
vacuum gas oils, cracked gas oils, coker distillates, straight run
distillates, solvent deasphalted
oils, pyrolysis-derived oils, high boiling synthetic oils and cat cracker
distillates. A preferred
feedstock is a gas oil or other fraction having at least 50% by weight and
most usually at
least 75% by weight of its components boiling at a temperature between 315 C
and 538 C.
[0010] The first feedstock is reacted with hydrogen in a first desulfurization
zone
containing desulfurization catalyst operated at desulfurization conditions.
Preferred
desulfurization conditions include a temperature from 204 C to 482 C and a
liquid hourly
space velocity of the hydrocarbonaceous feed from 0.1 hr-1 to 10 hr".
[0011] Suitable desulfurization catalysts for use in the present invention 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 desulfurization catalysts
include zeolitic
catalysts, as well as noble metal catalysts where the noble metal is selected
from palladium
and platinum. It is within the scope of the present invention that more than
one type of
desulfurization catalyst be used in the same reaction vessel. The Group VIII
metal is typically
present in an amount ranging from 2 to 20 weight percent, preferably from 4 to
12 weight
percent. The Group VI metal will typically be present in an amount ranging
from 1 to 25
weight percent, preferably from 2 to 25 weight percent. Typical
desulfurization temperatures
range from 204 C to 482 C with pressures from 2.1 MPa to 17.3 MPa, preferably
from 2.1 MPa to 13.9 MPa.
[0012] The resulting effluent from the first desulfurization zone is
introduced into a
vapor-liquid separator preferably operated at a temperature greater than 288 C
to provide a
vaporous stream comprising hydrogen, hydrogen sulfide and lower boiling
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hydrocarbonaceous compounds boiling up to 371 C and a first liquid
hydrocarbonaceous
stream comprising hydrocarbon components boiling above 371 C and having a
reduced
concentration of sulfur. This first liquid hydrocarbonaceous stream also
contains a portion of
hydrocarbons boiling in the range from 149 C to 371 C is preferably introduced
into a hot
flash zone, then a cold flash zone and subsequently fractionated to provide a
hydrocarbonaceous recycle stream containing hydrocarbons boiling in the range
from 149 C
to 371 C and a second liquid hydrocarbonaceous stream comprising hydrocarbon
components
boiling above 371 C and having a reduced concentration of sulfur. This second
liquid
hydrocarbonaceous stream is preferably utilized as a suitable feedstock for a
fluid catalytic
cracking process. The vaporous stream comprising hydrogen, hydrogen sulfide
and lower
boiling hydrocarbonaceous compounds boiling up to 371 C and a second
hydrocarbonaceous
feedstock comprising hydrocarbon components boiling below 371 C is passed to
a
hydrocracking zone containing hydrocracking catalyst to produce a
hydrocracking zone
effluent. The second hydrocarbonaceous feedstock may be any suitable feedstock
boiling
below 371 C and preferably boils in the range from 177 C to 371 C. Such
suitable
feedstocks, for example, include straight run middle distillate, kerosene and
diesel boiling
range hydrocarbons, coker distillate and light cycle oil.
[00131 The hydrocracking zone may contain one or more beds of the same or
different
catalyst. In one embodiment, when the preferred products are middle
distillates the preferred
hydrocracking catalysts utilize amorphous bases or low-level zeolite bases
combined with one
or more Group VIII or Group VIB metal hydrogenating components. In another
embodiment,
when the preferred products are in the gasoline boiling range, the
hydrocracking zone
contains a catalyst which comprises, in general, any crystalline zeolite
cracking base upon
which is deposited a minor proportion of a Group VIII metal hydrogenating
component.
Additional hydrogenating components may be selected from Group VIB for
incorporation
with the zeolite base. The zeolite cracking bases are sometimes referred to in
the art as
molecular sieves and are usually composed of silica, alumina and one or more
exchangeable
cations such as sodium, magnesium, calcium, rare earth metals, etc. They are
further
characterized by crystal pores of relatively uniform diameter between 4 and 14
Angstroms. It
is preferred to employ zeolites having a relatively high silica/alumina mole
ratio between 3
and 12. Suitable zeolites found in nature include, for example, mordenite,
stilbite, heulandite,
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ferrierite, dachiardite, chabazite, erionite and faujasite. Suitable synthetic
zeolites include, for
example, the B, X, Y and L crystal types, e.g., synthetic faujasite and
mordenite. The
preferred zeolites are those having crystal pore diameters between 8-12
Angstroms, wherein
the silica/alumina mole ratio is 4 to 6. A prime example of a zeolite falling
in the preferred
group is synthetic Y molecular sieve.
[0014] The natural occurring zeolites are normally found in a sodium form, an
alkaline
earth metal form, or mixed forms. The synthetic zeolites are nearly always
prepared first in
the sodium form. In any case, for use as a cracking base it is preferred that
most or all of the
original zeolitic monovalent metals be ion-exchanged with a polyvalent metal
and/or with an
ammonium salt followed by heating to decompose the ammonium ions associated
with the
zeolite, leaving in their place hydrogen ions and/or exchange sites which have
actually been
decationized by further removal of water. Hydrogen or "decationized" Y
zeolites of this
nature are more particularly described in US-A-3,130,006.
[0015] Mixed polyvalent metal-hydrogen zeolites may be prepared by ion-
exchanging
first with an ammonium salt, then partially back exchanging with a polyvalent
metal salt and
then calcining. In some cases, as in the case of synthetic mordenite, the
hydrogen forms can
,be prepared by direct acid treatment of the alkali metal zeolites. The
preferred cracking bases
are those which are at least 10 percent, and preferably at least 20 percent,
metal-cation-
deficient, based on the initial ion-exchange capacity. A specifically
desirable and stable class
of zeolites are those wherein at least 20 percent of the ion exchange capacity
is satisfied by
hydrogen ions.
[0016] 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
0.05 percent
and 30 percent by weight may be used. In the case of the noble metals, it is
normally
preferred to use 0.05 to 2 weight percent. The preferred method for
incorporating the
hydrogenating metal is to contact the zeolite base material with an aqueous
solution of a
suitable compound of the desired metal wherein the metal is present in a
cationic form.
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Following addition of the selected hydrogenating metal or metals, the
resulting catalyst
powder is then filtered, dried, pelleted with added lubricants, binders or the
like if desired,
and calcined in air at temperatures of, e.g., 37l -648 C in order to activate
the catalyst and
decompose ammonium ions. Alternatively, the zeolite component may first be
pelleted,
followed by the addition of the hydrogenating component and activation by
calcining. The
foregoing catalysts may be employed in undiluted form, or the powdered zeolite
catalyst may
be mixed and copelleted with other relatively less active catalysts, diluents
or binders such as
alumina, silica gel, silica-alumina cogels, activated clays and the like in
proportions ranging
between 5 and 90 weight percent. These diluents may be employed as such or
they may
contain a minor proportion of an added hydrogenating metal such as a Group VIB
and/or
Group VIII metal.
[0017] Additional metal promoted hydrocracking catalysts may also be utilized
in the
process of the present invention which comprises, for example,
aluminophosphate molecular
sieves, crystalline chromosilicates and other crystalline silicates.
Crystalline chromosilicates
are more fully described in US-A-4,363,718.
[0018] The hydrocracking is conducted in the presence of hydrogen and
preferably at
hydrocracking conditions which include a temperature from (232 C) to 468 C, a
pressure
from 3548 kPa to 20785 kPa, a liquid hourly space velocity (LHSV) from 0.1 to
30 hr-I, and a
hydrogen circulation rate from 337 normal m3/m3) to 4200 normal m3/m3.
(0019] The hydrocracking zone effluent and a hydrocarbonaceous recycle stream
preferably boiling in the range from 232 C to 371 C is preferably passed
directly into a
hydrogenation zone containing hydrogenation catalyst to produce a
hydrogenation zone
effluent. The hydrogenation catalyst may be selected from any known
hydrogenation or
desulfurization catalyst. This catalyst may be the same or different from the
desulfurization
catalyst used in the desulfurization zone and may be selected from known
desulfurization
catalysts such as those described hereinabove for example. Preferred
hydrogenation
conditions may be selected from those ranges taught for the desulfurization
zone and may be
more, less or equal to the severity of reaction conditions selected for the
desulfurization zone.
[00201 The resulting hydrogenation zone effluent is partially condensed and
introduced
into a cold vapor-liquid separator operated at a temperature from 21 C to 60
C to produce a
hydrogen-rich gaseous stream containing hydrogen sulfide and a liquid
hydrocarbonaceous
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stream. The resulting hydrogen-rich gaseous stream is preferably passed
through an acid gas
scrubbing zone to reduce the concentration of hydrogen sulfide to produce a
purified
hydrogen-rich gaseous steam, a portion of which may then be recycled as
desired or required.
The liquid hydrocarbonaceous steam from the cold vapor-liquid separator is
preferably
introduced into a cold flash drum to remove dissolved hydrogen and normally
gaseous
hydrocarbons and subsequently sent to a fractionation zone to produce a low
sulfur diesel
product stream. It is preferred that the diesel product stream contains less
than 50 wppm
sulfur, more preferably 10 wppm sulfur. The make-up hydrogen may be introduced
into the
process at any convenient location.
[00211 With reference now to the drawing, a feed stream comprising a heavy
vacuum gas
oil enters the process through line 1 and is admixed with a hydrogen-rich
gaseous stream
provided via line 28 and the resulting admixture is introduced via line 2 into
desulfurization
zone 3. Hydrogen quench is provided to desulfurization zone 3 via lines 30 and
31. A
resulting effluent from desulfurization zone 3 is transported via line 4 and
introduced into hot
vapor-liquid separator 5. A gaseous stream comprising hydrogen, hydrogen
sulfide and lower
boiling range hydrocarbons is removed from hot vapor-liquid separator 5 via
line 17 and is
admixed with a light cycle oil carried via line 18 and boiling in the middle
distillate range,
and the resulting admixture is transported via line 19 and introduced into
reactor 20 wherein
the stream contacts hydrocracking zone 21. The resulting effluent from
hydrocracking
zone 21 is passed directly to hydrogenation zone 22 which is contained in
reaction zone 20.
A resulting effluent from hydrogenation zone 22 is carried via line 23 and
introduced into
heat-exchanger 24. A resulting cooled and partially condensed stream is
removed from heat-
exchanger 24 via line 25 and introduced into cold vapor-liquid separator 26. A
hydrogen-rich
gaseous stream is removed from cold vapor-liquid separator 26 via line 27 and
is introduced
into desulfurization zone 3 via lines 28, 29, 30 and 31 as hereinabove
described. A liquid
hydrocarbonaceous stream is removed from cold vapor-liquid separator 26 via
line 32 and
introduced into cold flash drum 33. A gaseous stream comprising hydrogen and
normally
gaseous hydrocarbons is removed from cold flash drum 33 via line 34. A liquid
stream
comprising diesel boiling range hydrocarbons is removed from cold flash drum
33 via line 35
and introduced into fractionation zone 36. An ultra low sulfur diesel stream
is recovered
from fractionation zone 36 and is removed therefrom via line 38. A
hydrocarbonaceous
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stream comprising compounds boiling below the diesel range is removed from
fractionation
zone 36 via line 37 and recovered. A liquid stream is removed from hot vapor-
liquid
separator 5 via line 6 and introduced into hot flash drum 7. A vapor stream
comprising
hydrogen and lower boiling hydrocarbons is removed from hot flash drum 7 via
line 8 and
recovered. A liquid hydrocarbonaceous stream containing hydrocarbons boiling
at a
temperature greater than 371 C and diesel boiling range hydrocarbons is
removed from hot
flash drum 7 via line 9 and is introduced along with a hereinabove described
vapor stream
provided via line 34 and the resulting admixture is introduced via line 10
into stripping
zone 11. A stream comprising hydrogen, normally gaseous hydrocarbons and
gasoline
boiling range hydrocarbons is removed from stripping zone 11 via line 12 and
recovered. A
liquid hydrocarbonaceous stream comprising hydrocarbons boiling at a
temperature greater
than 371 C and diesel boiling range hydrocarbons is removed from stripping
zone 11 via
line 13 and introduced into fractionation zone 14. A stream comprising lower
boiling
hydrocarbons is removed from fractionation zone 14 via line 15 and recovered.
A liquid
hydrocarbonaceous stream comprising hydrocarbons boiling at a temperature
greater
than 371 C is removed from fractionation zone 14 via line 17 and recovered. A
liquid stream
comprising diesel boiling range hydrocarbons is removed from fractionation
zone 14 via
line 16 and is introduced into reaction zone 20 as hereinabove described.
[0022] The foregoing description and drawing clearly illustrate the advantages
encompassed by the process of the present invention and the benefits to be
afforded with the
use thereof.
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