Note: Descriptions are shown in the official language in which they were submitted.
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"AN IMPROVED HYDROCRACKING PROCESS "
BACKGROUND OF THE INVENTION
The field of art to which this invention pertains is the hydroprocessing of
at least one hydrocarbonaceous feedstock. Petroleum refiners often produce
desirable products such as turbine fuel, diesel fuel and other products known
as
middle distillates as well as lower boiling hydrocarbonaceous liquids such as
naphtha and gasoline by hydrocracking a hydrocarbon feedstock derived from
crude oil or heavy fractions thereof, for example. Feedstocks most often
subjected to hydrocracking are gas oils and heavy gas oils recovered from
crude
oil by distillation. A typical heavy gas oil comprises a substantial portion
of
hydrocarbon components boiling above 371 °C, usually at least 50
percent by
weight boiling above 371 °C. A typical vacuum gas oil normally has a
boiling
point range between 315°C and 565°C.
Hydrocracking is generally accomplished by contacting in a hydrocracking
reaction vessel or zone the gas oil or other feedstock to be treated with a
suitable hydrocracking catalyst under conditions of elevated temperature and
pressure in the presence of hydrogen so as to yield a product containing a
distribution of hydrocarbon products desired by the refiner. The operating
conditions and the hydrocracking catalysts within a hydrocracking reactor
influence the yield of the hydrocracked products.
There is always a demand for new hydrocracking methods which provide
lower costs and higher liquid product yields and higher quality products. The
present invention greatly improves the economic benefits of a low conversion
per pass process and demonstrates the unexpected advantages.
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INFORMATION DISCLOSURE
US-A-5,720,872 B1 discloses a process for hydroprocessing liquid
feedstocks in two or more hydroprocessing stages which are in separate
reaction vessels and wherein each reaction stage contains a bed of
hydroprocessing catalyst. The liquid product from the first reaction stage is
sent
to a low pressure stripping stage and stripped of hydrogen sulfide, ammonia
and
other dissolved gases. The stripped product stream is then sent to the next
downstream reaction stage, the product from which is also stripped of
dissolved
gases and sent to the next downstream reaction stage until the last reaction
stage, the liquid product of which is stripped of dissolved gases and
collected or
passed on for further processing. The flow of treat gas is in a direction
opposite
the direction in which the reaction stages are staged for the flow of liquid.
Each
stripping stage is a separate stage, but all stages are contained in the same
stripper vessel.
US-A-3,328,290 B1 discloses a two-stage process for the hydrocracking
of hydrocarbons in which the feed is pretreated in the first stage.
US-A-5,114,562 B1 discloses a process wherein a middle distillate
petroleum stream is hydrotreated to produce a low sulfur and low aromatic
product employing two reaction zones in series. The effluent from the first
reaction zone (desulfurization) is cooled and introduced into a hydrogen
stripping zone wherein hydrogen sulfide is removed overhead along with a small
amount of hydrocarbons which were in the vapor at conditions present at the
top
of the stripping zone. The bottom stream from the stripping zone is reheated
and introduced into the second reaction zone (aromatic saturation) containing
sulfur-sensitive noble metal hydrogenation catalyst.
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US-A-5,980,729 B1 discloses a hydrocracking process wherein a
hydrocarbonaceous feedstock and a hot hydrocracking zone effluent containing
hydrogen is passed to a denitrification and desulfurization reaction zone to
produce hydrogen sulfide and ammonia to thereby clean up the fresh feedstock.
The resulting hot, uncooled effluent from the denitrification and
desulfurization
zone is hydrogen stripped in a stripping zone maintained at essentially the
same
pressure as the preceding reaction zone with a hydrogen-rich gaseous stream to
produce a vapor stream comprising hydrogen, hydrocarbonaceous compounds
boiling at a temperature below the boiling range of the fresh feedstock,
hydrogen
sulfide and ammonia, and a liquid hydrocarbonaceous stream.
US-A-5,403,469 B1 discloses a parallel hydrotreating and hydrocracking
process. Effluent from the two processes are combined in the same separation
vessel and separated into a vapor comprising hydrogen and a hydrocarbon-
containing liquid. The hydrogen is shown to be supplied as part of the feed
streams to both the hydrocracking and the hydrotreater.
BRIEF SUMMARY OF THE INVENTION
The present invention is a catalytic hydrocracking process which provides
higher yields and quality of liquid products yields, specifically higher
yields of
turbine fuel and diesel oil. The process of the present invention provides the
yield advantages associated with a low conversion per pass operation without
compromising unit economics such that lower capital costs may be realized the
use of this invention. In addition , an overall reduction in fuel gas and
hydrogen
consumption, and light ends production may also be obtained.
One embodiment of the present invention relates to a process for
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hydrocracking a hydrocarbonaceous feedstock. The process passes a
hydrocarbonaceous feedstock and hydrogen to a denitrification and
desulfurization reaction zone at reaction zone conditions including a
temperature
from 204°C to 482°C, a pressure from 3.5 MPa to 17.3 MPa, a
liquid hourly
space velocity of the hydrocarbonaceous feedstock from 0.1 hr'' to 15 hr 1,
with
a catalyst, and recovering a denitrification and desulfurization reaction zone
effluent therefrom. The denitrification and desulfurization reaction zone
effluent
passes directly to a hot, high pressure stripper utilizing a hot, hydrogen-
rich
stripping gas to produce a first liquid stream comprising hydrocarbonaceous
compounds boiling in the range of the hydrocarbonaceous feedstock and a first
vapor stream comprising hydrogen, hydrogen sulfide and ammonia. At least a
portion of the first liquid stream comprising hydrocarbonaceous compounds
boiling in the range of the hydrocarbonaceous feedstock passes to a
hydrocracking zone containing a hydrocracking catalyst and operating at a
temperature from 204°C to 482°C, a pressure from 3.5 MPa to 17.3
MPa, a
liquid hourly space velocity from 0.1 hr' 1 to 15 hr 1. A hydrocracking zone
effluent
passes directly to the hot, high pressure stripper. At least a portion of the
first
vapor stream recovered in step (b) and at least a portion of the hydrocracking
zone effluent pass to a post-treat hydrogenation reaction zone to saturate
aromatic compounds. Condensing at least a portion of the resulting effluent
from
the post-treat hydrogenation reaction zone produces a second liquid stream
comprising hydrocarbonaceous compounds boiling at a temperature below the
boiling range of the hydrocarbonaceous feedstock and a second vapor stream
comprising hydrogen and hydrogen sulfide. First, second and third portions of
the second vapor stream are recycled respectively to the hydrocracking zone,
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the denitrification and desulfurization reaction zone, and the hot, high
pressure
stripper. At least a portion of the hydrogen sulfide may be removed from the
second vapor stream before it is recycled to the hydrocracking zone. The
hydrocarbonaceous compounds boiling at a temperature below the boiling range
of the hydrocarbonaceous feedstock are recovered.
In the present invention the hydrocarbonaceous feedstock entering
the first denitrification and desulfurization reaction zone may serve as a
first
hydrocarbonaceous feedstock. A second hydrocarbonaceous feedstock having
an average boiling temperature lower than the first hydrocarbonaceous
feedstock may pass into an upper end of the hot, high pressure stripper to
serve
as reflux or into an intermediate location in the denitrification and
desulfurization
reaction zone to serve as quench. At least a portion of the second feedstock
may be vaporized in the hot, high pressure stripper and passed into the post-
treat hydrogenation reaction zone to saturate aromatic compounds and thereby
improve the quality of the hydrocarbonaceous effluent from the post-treat
zone.
Alternately or in addition, at least a portion of the second hydrocarbonaceous
feedstock serves as quench and passes through at least a portion of the
catalyst
in the denitrification and desulfurization reaction zone for subsequent
introduction into the hot, high pressure stripper.
BRIEF DESCRIPTION OF THE DRAWING
The drawing is a simplified process flow diagram of an embodiment of the
present invention.
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DETAILED DESCRIPTION OF THE INVENTION
It has been discovered that higher liquid product yields and a lower cost
of production can be achieved and enjoyed in the above-described
hydrocracking process.
The process of the present invention is particularly useful for
hydrocracking hydrocarbon oils containing hydrocarbons and/or other organic
materials to produce a product containing hydrocarbons and/or other organic
materials of lower average boiling point and lower average molecular weight.
The product may also have improved product characteristics such as improved
cetane and smoke point, and reduced contaminants such as sulfur and nitrogen.
The hydrocarbon feedstocks that may be subjected to hydroprocessing by the
method of the invention include all mineral oils and synthetic oils (e.g.,
shale oil,
tar sand products, etc.) and fractions thereof. Illustrative hydrocarbon
feedstocks include those containing components boiling above 288°C,
such as
atmospheric gas oils, vacuum gas oils, deasphalted, vacuum, and atmospheric
residua, hydrotreated or mildly hydrocracked residual oils, coker distillates,
straight run distillates, solvent-deasphalted oils, pyrolysis-derived oils,
high
boiling synthetic oils, cycle oils and cat cracker distilllates. A preferred
hydrocracking feedstock is a gas oil or other hydrocarbon fraction having at
least
50% by weight, and most usually at least 75% by weight, of its components
boiling at temperatures above the end point of the desired product, which end
point, in the case of heavy gasoline, is generally in the range from
193°C to
215°C. One of the most preferred gas oil feedstocks will contain
hydrocarbon
components which boil above 288°C with best results being achieved with
feeds
containing at least 25 percent by volume of the components boiling between
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315°C and 538°C. Also included are petroleum distillates wherein
at least 90
percent of the components boil in the range from 149°C to 426°C.
The
petroleum distillates may be treated to produce both light gasoline fractions
(boiling range, for example, from 10°C to 86°C and heavy
gasoline fractions
(boiling range, for example, from 86°C to 204°C. The present
invention is
particularly suited for maximizing the yield of liquid products including
middle
distillate products.
At least one selected feedstock is introduced into a denitrification and
desulfurization reaction zone at hydrotreating reaction conditions. Preferred
denitrification and desulfurization reaction conditions or hydrotreating
reaction
conditions include a temperature from 204°C to 482°C, a pressure
from 3.5 MPa
to 17.3 MPa, a liquid hourly space velocity of the fresh hydrocarbonaceous
feedstock from 0.1 hr' to 10 hr' with a hydrotreating catalyst or a
combination
of hydrotreating catalysts.
The term "hydrotreating" or "denitrification and desulfurization" as used
herein refers to processes wherein a hydrogen-containing treat gas is used in
the presence of suitable catalysts which are primarily active for the removal
of
heteroatoms, such as sulfur and nitrogen and for some hydrogenation of
aromatics. Suitable hydrotreating 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 hydrotreating catalysts include zeolitic catalysts, as
well
as noble metal catalysts where the noble metal is selected from palladium and
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platinum. It is within the scope of the present invention that more than one
type
of hydrotreating 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.
The resulting effluent from the denitrification and desulfurization
reaction zone is transferred without intentional heat-exchange (uncooled) and
is
introduced into a hot, high pressure stripping zone maintained at essentially
the
same pressure as the denitrification and desulfurization reaction zone where
it is
countercurrently stripped with a hydrogen-rich gaseous stream to produce a
first
gaseous hydrocarbonaceous stream containing hydrogen, hydrogen sulfide,
ammonia and hydrocarbonaceous compounds, and a first
liquidhydrocarbonaceous stream containing hydrocarbonaceous compounds
boiling at a temperature greater than 343°C. The stripping zone is
preferably
maintained at a temperature in the range from 232°C to 468°C.
The effluent
from the denitrification and desulfurization reaction zone is not
substantially
cooled prior to stripping and would only be lower in temperature due to
unavoidable heat loss during transport from the reaction zone to the stripping
zone. It is preferred that any cooling of the denitrification and
desulfurization
reaction zone effluent prior to stripping is less than 55°C. By
maintaining the
pressure of the stripping zone at essentially the same pressure as the
denitrification and desulfurization reaction zone is meant that any difference
in
pressure is due to the pressure drop required to flow the effluent stream from
the reaction zone to the stripping zone. It is preferred that the pressure
drop is
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less than 800 kl'a. The hydrogen-rich gaseous stream is preferably supplied to
the stripping zone in an amount greater than 1 weight percent of the
hydrocarbonaceous feedstock that enters the denitrification and
desulfurization
zone. The hydrogen-rich gaseous stream used as the stripping medium in the
stripping zone may be first introduced into a reflux heat exchange zone
located
in an upper end of the stripping zone to produce reflux therefor and then
introducing the resulting heated hydrogen-rich gaseous stream into a lower end
of the stripping zone to perform the stripping function.
At least a portion of the first liquid hydrocarbonaceous stream containing
hydrocarbonaceous compounds boiling at a temperature in the range of the
feedstock entering the desulfurization and denitrification zone and preferably
greater than 343°C recovered from the high pressure stripping zone is
introduced directly into a hydrocracking zone along with added hydrogen.
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
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sodium, magnesium, calcium, rare earth metals, etc. They are further
characterized by crystal pores of relatively uniform diameter between 4 and 14
Angstroms (10-'° meters). 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, 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 (10-'° meters), 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.
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 B1.
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
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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.
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. 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., 371 °-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
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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.
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 B 1.
The hydrocracking of the hydrocarbonaceous feedstock in contact with a
hydrocracking catalyst is conducted in the presence of hydrogen and preferably
at hydrocracking reactor conditions which include a temperature from
232°C to
468°C, a pressure from 3448 kPa gauge to 20685 kPa gauge, a liquid
hourly
space velocity (LHSV) from 0.1 to 30 hr'', and a hydrogen circulation rate
from
337 normal m3/m3 to 4200 normal m3/m3. In accordance with the present
invention, the term "substantial conversion to lower boiling products" is
meant to
connote the conversion of at least 5 volume percent of the fresh feedstock. In
a
preferred embodiment, the per pass conversion in the hydrocracking zone is in
the range from 15% to 75%. More preferably the per pass conversion is in the
range from 20% to 60%.
It is preferred that any cooling of the hydrocracking zone effluent prior to
stripping is less than 55°-C. The hydrocrackingpressure is maintained
at
essentially the same pressure as the stripper.
The resulting first gaseous hydrocarbonaceous stream containing
hydrocarbonaceous compounds boiling at a temperature less than 343°C,
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hydrogen, hydrogen sulfide and ammonia from the stripping zone is preferably
introduced in an all vapor phase into a post-treat hydrogenation reaction zone
to
hydrogenate at least a portion of the aromatic compounds in order to improve
the quality of the middle distillate, particularly the jet fuel. The post-
treat
hydrogenation reaction zone may be conducted in a downflow, upflow or radial
flow mode of operation and may utilize any known hydrogenation catalyst. The
effluent from the post-treat hydrogenation reaction zone is preferably cooled
to a
temperature in the range from 4.4°C to 60°C and at least
partially condensed to
produce a second liquid hydrocarbonaceous stream which is divided to produce
at least a portion of the hydrogen-rich gaseous stream introduced into the
hot,
high pressure stripper, the hydrocracking zone and the desulfurization and
denitrogenation reaction zone. Fresh make-up hydrogen may be introduced into
the process at any suitable and convenient location. Before the hydrogen-rich
gaseous stream is divided and introduced into the hydrocracking reaction zone,
it is preferred that at least a significant portion, at least 90 weight
percent, for
example, of the hydrogen sulfide is removed and recovered by means of known,
conventional methods. In a preferred embodiment, the hydrogen-rich gaseous
stream introduced into the hydrocracking reaction zone contains less than 50
wppm hydrogen sulfide.
DETAILED DESCRIPTION OF THE DRAWING
With reference now to the drawing, a feed stream comprising vacuum
gas oil is introduced into the process via line 1 and admixed with a
hereinafter-
described liquid recycle stream transported via line 36. The resulting
admixture is
transported via line 2 and is admixed with a hydrogen-rich gaseous stream
provided via line 27 and the resulting admixture is carried via line 3 and
introduced
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into denitrification and desulfurization zone 4. The admixture passes through
denitrification and desulfurization catalyst zone 5 and is optionally admixed
with a
liquid stream containing light cycle oil introduced via line 6 and the
resulting
admixture is passed through denitrification and desulfurization catalyst zone
7.
The resulting effluent from the denitrification and desulfurization zone 4 is
carried
via line 8 and is admixed with a hereinafter-described effluent from
hydrocracking
zone 37 carried via line 31 and the resulting admixture is carried via line 9
and
introduced into stripping. zone 10. A liquid hydrocarbonaceous stream is
removed
from the bottom of stripping zone 10 via line 29 and is admixed with a
hydrogen-
rich gaseous stream provided via line 38 and the resulting admixture is
carried via
line 30 and introduced into hydrocracking zone 37. A resulting hydrocracking
effluent is removed from hydrocracking zone 37 via line 31 as hereinabove
described. An optional liquid stream containing straight run diesel is carried
via
line 12 and introduced into stripping zone 10 to serve as reflux. A vaporous
stream is stripped and carried upwards in stripping zone 10 and is contacted
with
hydrogenation zone 11 and a resulting effluent is removed from stripping zone
10
via line 13. The resulting vapor stream contained in line 13 is introduced
into heat-
exchanger 14 and a partially condensed effluent stream is removed from heat-
exchanger 14, carried via line 16, contacted with an aqueous stream carried
via
line 15 and the resulting admixture is subsequently carried via line 17 and
introduced into high pressure separator 18. A gaseous stream containing
hydrogen and hydrogen sulfide is removed from high pressure separator 18 via
line 21 and introduced into acid gas recovery zone 22. A lean solvent is
introduced via line 23 into acid gas recovery zone 22 and contacts the
hydrogen-
rich gaseous stream in order to dissolve an acid gas. A rich solvent
containing
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acid gas is removed from acid gas recovery zone 22 via line 24 and recovered.
A
hydrogen-rich gaseous stream containing a reduced concentration of acid gas is
removed from acid gas recovery zone 22 via line 25 and is admixed with fresh
makeup hydrogen which is introduced via line 26. The resulting admixture is
transported via line 27 and a portion thereof is carried via line 28 to serve
as
stripping gas in stripping zone 10. Another portion of the hydrogen-rich
gaseous
stream carried via line 27 is transported via line 38 and is introduced into
hydrocracking zone 37 as hereinabove described. The third and remaining
portion of the hydrogen-rich gaseous stream carried via line 27 is introduced
into
denitrification and desulfurization reaction zone 4 as hereinabove described.
A
liquid stream is removed from high pressure separator 18 via line 20 and is
introduced into fractionation zone 32. A spent aqueous stream is removed from
high pressure separator 18 via line 19 and recovered. Light gaseous
hydrocarbons and naphtha boiling range compounds are removed from
fractionation zone 32 via line 33 and recovered. A liquid stream containing
kerosene boiling range compounds is removed from fractionation zone 32 via
line
34 and recovered. A liquid hydrocarbon stream containing diesel boiling range
compounds is removed from fractionation zone 32 via line 35 and recovered. A
heavy liquid hydrocarbon stream containing compounds boiling in the range
greater than diesel boiling range compounds is removed from fractionation zone
32 via line 36 and admixed with the fresh hydrocarbonaceous feed as described
hereinabove.
Example 1
A feedstock in an amount of 100 mass units having the characteristics
presented in Table 1 is introduced along with a liquid recycle stream into a
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denitrification and desulfurization reaction zone at operating conditions
presented in Table 2. The resulting effluent from the denitrification and
desulfurization reaction zone is combined with the effluent from a
hydrocracking
zone and introduced into the hot, high pressure stripper operated at a
pressure
of 12.2 MPa and a temperature of 371 °C. A liquid hydrocarbonaceous
stream
containing hydrocarbons boiling in the range of the fresh feedstock is removed
from the bottom of the hot, high pressure stripperand is introduced into the
hydrocracking zone at operating conditions presented in Table 2.
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Table 1
Hydrocracker Feedstock Analysis
Vacuum Gas Oil
Specific Gravity 0.91
Distillation, Volume Percent
IBP °C 222
356
396
30 429
50 448
70 475
90 502
95 517
Sulfur, weight percent 2.22
Nitrogen, weight percent 0.074
(wt. PPM) (740)
Conradson Carbon, weight percent 0.15
Table 2
Summary of Operating Conditions
Denitrification and Desulfurizationon
Reacti Zone
Pressure, Mpa 12.5
p Temperature, C 393
Hydrocracking Reaction Zone
Pressure, Mpa 12.5
Temperature, C 385
Conversion Per Pass, % 35
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The total conversion to hydrocarbons having a boiling point less than
343°C is 99.5% and a summary of the overall mass balance is presented
in
Table 3. These results demonstrate the advantages provided by the process of
the present invention when receiving a single feedstream.
Table 3
Overall Mass Balance
Mass Units
Feeds
Vacuum Gas Oil 100.0
Hydrogen 2.8
102.8
Products
Hydrogen Sulfide 2.4
Ammonia 0.1
C1-C~. 4.5
Naphtha 23.9
Distillate 71.4
Unconverted Oil 0.5
102.8
Example 2
100 mass units of a feedstock having the characteristics presented in
Table 1 is again introduced along with a liquid recycle stream into a
denitrification and desulfurization reaction zone at operating conditions
presented in Table 3. An FCC light cycle oil in an amount of 30 mass units and
having the characteristics presented in Table 4 is introduced into an
intermediate point in the denitrification and desulfurization reaction zone to
serve
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as quench and to contact at least a portion of the catalyst therein. The
resulting
effluent from the denitrification and desulfurization reaction zone is
combined
with the effluent from a hydrocracking zone and introduced into the hot, high
pressure stripper operated at a pressure of 12.2 MPa and a temperature of
371 °C. The hot, high pressure stripper is refluxed by the introduction
of 20
mass units of a straight run diesel having the characteristics presented in
Table
4.
Table 4
Co-Feed Analyses
Straight Run Diesel Light Cycle Oil
Specific Gravity0.89 0.94
Boiling Range, 204-338 204-338
C
Sulfur, weight 15,000 10,000
PPM
Cetane Index 38 28
A liquid hydrocarbonaceous stream containing hydrocarbons boiling in
the range of the vacuum gas oil feedstock is removed from the bottom of the
hot, high pressure stripper and is introduced into the hydrocracking zone at
operating conditions presented in Table 3. The total conversion to
hydrocarbons
having a boiling point less than 343°C is 99.5% and a summary of the
overall
mass balance is presented in Table 5. An analysis of the distillate product
indicates that the sulfur concentration is less than 10 wppm. 'These results
demonstrate the advantages provided by the process of the present invention.
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Table 5
Overall Mass Balance
Mass
i m;+~
Feeds
Vacuum Gas Oil 100.0
Straight Run Diesel 20.0
Light Cycle Oil 30.0
Hydrogen 3.2
153.2
Products
Hydrogen Sulfide 3.0
Ammonia 0.2
C1-Ca. 5.0
Naphtha 24.0
Distillate 120.5
Unconverted Oil 0.5
153.2
