U.S. patent application number 11/585338 was filed with the patent office on 2008-04-24 for process and installation for conversion of heavy petroleum fractions in a fixed bed with integrated production of middle distillates with a very low sulfur content.
Invention is credited to Andrea Gragnani, Frederick Morel.
Application Number | 20080093262 11/585338 |
Document ID | / |
Family ID | 39316914 |
Filed Date | 2008-04-24 |
United States Patent
Application |
20080093262 |
Kind Code |
A1 |
Gragnani; Andrea ; et
al. |
April 24, 2008 |
Process and installation for conversion of heavy petroleum
fractions in a fixed bed with integrated production of middle
distillates with a very low sulfur content
Abstract
This invention relates to a process and an installation for
treatment of a heavy petroleum feedstock, of which at least 80% by
weight has a boiling point of greater than 340.degree. C., whereby
the process comprises the following stages: (a) Hydroconversion in
a fixed-bed reactor operating with an upward flow of liquid and
gas, whereby the net conversion in products boiling below
360.degree. C. is from 10 to 99% by weight; (b) Separation of the
effluent obtained from stage (a) into a gas containing hydrogen and
H.sub.2S, a fraction comprising the gas oil, and optionally a
fraction that is heavier than the gas oil and a naphtha fraction;
c) Hydrotreatment by contact with at least one catalyst of at least
the fraction comprising the gas oil obtained in stage (b); d)
Separation of the effluent obtained at the end of stage (c) into a
gas containing hydrogen and at least one gas oil fraction having a
sulfur content of less than 50 ppm, preferably less than 20 ppm,
and more preferably still less than 10 ppm, the hydroconversion
stage (a) being conducted at a pressure P1 and the hydrotreatment
stage (c) being conducted at a pressure P2, the difference
.DELTA.P=P1-P2 being at least 2 MPa, the hydrogen supply for the
hydroconversion (a) and hydrotreatment (c) stages being ensured by
a single compression system with n stages.
Inventors: |
Gragnani; Andrea; (Paris,
FR) ; Morel; Frederick; (Francheville, FR) |
Correspondence
Address: |
MILLEN, WHITE, ZELANO & BRANIGAN, P.C.
2200 CLARENDON BLVD., SUITE 1400
ARLINGTON
VA
22201
US
|
Family ID: |
39316914 |
Appl. No.: |
11/585338 |
Filed: |
October 24, 2006 |
Current U.S.
Class: |
208/107 ;
585/527 |
Current CPC
Class: |
C10G 65/12 20130101;
C10G 2400/06 20130101 |
Class at
Publication: |
208/107 ;
585/527 |
International
Class: |
C10G 47/00 20060101
C10G047/00 |
Claims
1. Process for treatment of a heavy petroleum feedstock of which at
least 80% by weight has a boiling point of greater than 340.degree.
C., which comprises the following stages: (a) Hydrocracking in a
fixed bed with at least one catalyst at a temperature of
300-500.degree. C., a pressure of at least 4 MPa and less than or
equal to 17 MPa, an hourly space velocity of 0.1 to 10 h.sup.-1 and
in the presence of 50 to 5000 Nm.sup.3 of hydrogen per m.sup.3 of
feedstock, the net conversion into products boiling below
360.degree. C. being from 10 to 99% by weight, (b) Separation of
the effluent that is obtained from stage (a) into a gas containing
hydrogen and H.sub.2S, a fraction comprising the gas oil, and
optionally a fraction that is heavier than the gas oil and a
naphtha fraction; c) Hydrotreatment by contact with at least one
catalyst of at least the fraction comprising the gas oil obtained
in stage (b), at a temperature of 200 to 500.degree. C., at a
liquid hourly space velocity relative to the catalyst volume of 0.1
to 10 h.sup.-1 in the presence of 100 to 5000 Nm.sup.3 of hydrogen
per m.sup.3 of feedstock; d) Separation of the effluent that is
obtained at the end of stage (c) into a gas containing hydrogen and
at least one gas oil fraction that has a sulfur content of less
than 50 ppm, the hydroconversion stage (a) being conducted at a
pressure P1 and the hydrotreatment stage (c) being conducted at a
pressure P2, the difference .DELTA.P=P1-P2 being at least 2 MPa,
the hydrogen supply for the hydroconversion (a) and hydrotreatment
(c) stages being ensured by a single compression system with n
stages, n being greater than or equal to 2.
2. Process according to claim 1, in which n is between 2 and 6.
3. Process according to claim 2, in which n is between 2 and 5.
4. Process according to claim 3, in which n is between 2 and 4.
5. Process according to claim 4, characterized by the fact that n
is equal to 3.
6. Process according to claim 1, in which .DELTA.P is from 4 to 8
MPa.
7. Process according to claim 6, in which .DELTA.P is from 5 to 7
MPa.
8. Process according to claim 1, in which in stage (d), a gas oil
whose sulfur content is less than 20 ppm is separated.
9. Process according to claim 8, in which in stage (d), a gas oil
whose sulfur content is less than 10 ppm is separated.
10. Process according to claim 1, in which the pressure P1
implemented in the fixed-bed catalytic hydroconversion stage (a) is
between 6 and 17 MPa.
11. Process according to claim 10, in which the pressure P1 is
between 8 and 12 MPa.
12. Process according to claim 1, in which the pressure P2
implemented in the hydrotreatment stage (c) is between 4 and 8
MPa.
13. Process according to claim 12, in which the pressure P2 is
between 4.5 and 6 MPa.
14. Process according to claim 1, in which n=3 and the delivery
pressure of the first compression stage is between 4 and 5 MPa, the
delivery pressure of the second compression stage is between 8 and
12 MPa, and the delivery pressure of the third compression stage is
between 12 and 17 MPa.
15. Process according to claim 15, in which n=3 and the delivery
pressure of the first compression stage is between 4.5 and 5 MPa,
the delivery pressure of the second compression stage is between 9
and 11 MPa, and the delivery pressure of the third compression
stage is between 13 and 15 MPa.
16. Process according to claim 1, in which n=3 and in which the
delivery hydrogen from the second compression stage supplies the
hydrotreatment reactor.
17. Process according to claim 1, in which the partial hydrogen
pressure in the P2.sub.H2 hydrotreatment reactor is between 3.4 and
8 MPa.
18. Process according to claim 18, in which P2.sub.H2 is between 4
and 6 MPa.
19. Process according to claim 1, according to which the hydrogen
supplying the last compression stage is the recycled hydrogen
originating from the separation stage (d) or from the separation
stage (b).
20. Process according to claim 1, according to which the delivery
hydrogen from an intermediate compression stage can, moreover,
supply a hydrotreatment unit of gas oil obtained directly from
atmospheric distillation, called "straight-run gas oil," at a
pressure of between 3 and 6.5 MPa.
21. Installation for treatment of a heavy petroleum feedstock
comprising the following reaction zones: a single hydrogen
compression zone that consists of n compression stages arranged in
series, n being greater than or equal to 2, a catalytic
hydroconversion zone (II) that consists of at least one fixed-bed
reactor that is supplied with hydrogen via the last compression
stage, and connected via the pipe (11) to a separation zone (III)
that consists of at least one separator (15) and at least one
distillation column (18), the separator allowing the separation of
a hydrogen-rich gas via the pipe (16) and a liquid phase that is
brought via the pipe (17) to the distillation column (18); the pipe
(21) drawing off the distilled gas oil fraction is connected to a
hydrotreatment zone (IV) that consists of a fixed-bed
hydrotreatment reactor that is supplied with hydrogen by an
intermediate compression stage, and whose pipe of the effluent (25)
is connected to a separation zone (V) allowing evacuation of
hydrogen to the last compression stage.
22. Installation according to claim 22, in which n is preferably
between 2 and 6.
23. Installation according to claim 22, in which n is preferably
between 2 and 5.
24. Installation according to claim 23, in which n is preferably
between 2 and 4.
25. Installation according to claim 24, in which n is equal to
3.
26. Installation according to claim 21, in which the delivery from
an intermediate compression stage feeds a straight-run gas oil
hydrotreatment reactor (40).
Description
FIELD OF THE INVENTION
[0001] The invention relates to an improved process for conversion
of heavy petroleum fractions in a fixed bed with integrated
production of gas oil fractions with very low sulfur content, and
the installation allowing the implementation of said process.
[0002] This invention relates to a process and an installation for
the treatment of heavy hydrocarbon feedstocks containing
sulfur-containing, nitrogen-containing and metallic impurities. It
relates to a process making it possible to convert at least
partially such a hydrocarbon feedstock, for example a
direct-distillation vacuum distillate, a vacuum distillate that is
obtained from a conversion process or oils that are deasphalted
with solvent, into gas oils that meet sulfur specifications, i.e.,
having less than 50 ppm of sulfur, preferably less than 20 ppm, and
even more preferably less than 10 ppm, and one or more heavy
products that advantageously can be used as a feedstock for
catalytic cracking (such as fluidized-bed catalytic cracking), as a
feedstock for hydrocracking (such as high-pressure catalytic
hydrocracking), as a fuel oil with high or low sulfur content, or
as a feedstock for a carbon rejection process (such as the
coker).
TECHNOLOGICAL BACKGROUND OF THE INVENTION
[0003] Until 2000, the authorized sulfur content in diesel fuel was
350 ppm. Much more stringent values have been imposed since 2005
since this maximum content is not to exceed 50 ppm. This maximum
value will next be revised downward and should not exceed 10 ppm in
a few years.
[0004] It is therefore necessary to develop processes meeting these
requirements without prohibitively increasing the cost of
production.
[0005] The gasolines and the gas oils that are obtained from the
conversion process, such as, for example, hydroconversion, are very
refractory in hydrotreatment compared to gas oils that are obtained
directly from the atmospheric distillation of crude oils.
[0006] To obtain very low sulfur contents, it is necessary to
convert the most refractory radicals, especially di- and
trialkylated dibenzothiophenes, or those having a greater degree of
alkylation, for which access of the sulfur atom to the catalyst is
limited by the alkyl groups. For this family of compounds, the
route of hydrogenation of an aromatic cycle before the
desulfurization by breaking the Csp3-S bond is faster than the
direct desulfurization by breaking the Csp2-S bond.
[0007] It is also necessary to obtain a major reduction of the
nitrogen content by conversion especially of the most refractory
radicals, especially benzacridines and benzocarbazoles, whereby the
acridines are not only refractory, but also inhibit hydrogenation
reactions.
[0008] Conversion gas oils therefore require very rigorous
operating conditions to obtain the desired sulfur
specifications.
[0009] A process for conversion of heavy petroleum fractions
including a fixed bed for producing middle distillates with a low
sulfur content has been described in particular in Patent
Application US 2003/0089637. This process, however, makes it
possible to reduce sulfur levels below 50 ppm only under very
rigorous pressure conditions, which considerably increases the cost
of the gas oil that is ultimately obtained.
[0010] There is therefore a genuine need for a process making it
possible to hydrotreat conversion gas oils under less rigorous
operating conditions allowing a reduction in investment costs while
maintaining a reasonable cycle duration of the hydrotreatment
catalyst and allowing sulfur contents of less than 50 ppm,
preferably less than 20 ppm, and even more preferably less than 10
ppm, to be obtained.
[0011] Values in ppm are all expressed by weight.
SUMMARY OF THE INVENTION
[0012] The present inventors have found that it is possible to
minimize investment costs by optimizing operating pressures used
while obtaining gas oils of good quality having such limited sulfur
contents.
DETAILED DESCRIPTION OF THE INVENTION
[0013] Thus, the process of the invention is a process for
treatment of a heavy petroleum feedstock of which at least 80% by
weight has a boiling point of greater than 340.degree. C., which
comprises the following stages: [0014] (a) Hydrocracking in a fixed
bed with at least one catalyst at a temperature of about 300 to
about 500.degree. C. and often from about 350 and 450.degree. C., a
pressure of at least 4 MPa and less than or equal to 17 MPa, an
hourly space velocity of from 0.1 to 10 h.sup.-1 and in the
presence of 50 to 5000 Nm.sup.3 of hydrogen per m.sup.3 of
feedstock, the net conversion into products boiling below
360.degree. C. being from 10 to 99% by weight, [0015] (b)
Separation of the effluent obtained from stage (a) into a gas
containing hydrogen and H.sub.2S, a fraction comprising the gas
oil, and optionally a fraction that is heavier than the gas oil and
a naphtha fraction; [0016] c) Hydrotreatment by contact with at
least one catalyst of at least the fraction comprising the gas oil
obtained in stage (b) at a temperature of from 200 to 500.degree.
C., at a liquid hourly space velocity relative to the catalyst
volume of 0.1 to 10 h.sup.-1 in the presence of 100 to 5000
Nm.sup.3 of hydrogen per m.sup.3 of feedstock; [0017] d) Separation
of the effluent that is obtained at the end of stage (c) into a gas
containing hydrogen and at least one gas oil fraction having a
sulfur content of less than 50 ppm, preferably less than 20 ppm,
and even more preferably less than 10 ppm, the hydroconversion
stage (hydrocracking) (a) being conducted at a pressure P1 and the
hydrotreatment stage (c) being conducted at a pressure P2, the
difference .DELTA.P=P1-P2 being at least 2 MPa, generally from 4 to
8 MPa, and preferably from 5 to 7 MPa, and the hydrogen supply for
the hydroconversion (a) and hydrotreatment (c) stages being ensured
by a single compression system with n stages, n being greater than
or equal to 2, generally between 2 and 5, preferably between 2 and
4, and particularly preferably equal to 3.
[0018] The liquid hourly space velocity (LHSV) corresponds to the
ratio of the feedstock liquid flow rate in m.sup.3/h per volume of
catalyst in m.sup.3.
[0019] According to the process of the invention, the pressure P1
implemented in the catalytic hydroconversion stage (a) in a fixed
bed is between 6 and 17 MPa and preferably between 8 and 12
MPa.
[0020] The pressure P2 implemented in the hydrotreatment stage (c)
is between 4 and 8 MPa and preferably between 4.5 and 6 MPa.
[0021] Thus, in the process according to the invention, pressures
that are completely different for each of the hydroconversion and
hydrotreatment stages can be used, which makes it possible in
particular to significantly limit the investment costs.
[0022] In the process according to the invention, the use of the
pressure that is optimum for each particular stage is made possible
by implementing a single, multistage hydrogen supply system.
[0023] Thus, the hydroconversion stage is supplied with hydrogen
originating from delivery from the last compression stage, and the
hydrotreatment stage is supplied with hydrogen originating from
delivery from an intermediate compression stage, i.e., at a lower
total pressure.
[0024] According to one particular embodiment, the process of the
invention implements a single, 3-stage hydrogen compressor in which
the delivery pressure of the first stage is between 4 and 5 MPa,
preferably between 4.5 and 5 MPa, the delivery pressure of the
second stage is between 8 and 12 MPa, preferably between 9 and 11
MPa, and the delivery pressure of the third stage is between 12 and
17 MPa, preferably between 13 and 15 MPa.
[0025] In one particular embodiment, the hydrogen originating from
the delivery from the second compression stage feeds the
hydrotreatment reactor.
[0026] According to one particular embodiment, the partial hydrogen
pressure in the hydrotreatment reactor P2.sub.H2 is between 3.4 and
8 MPa and preferably between 4 and 6 MPa.
[0027] These elevated partial hydrogen pressure values are made
possible by the fact that all of the make-up hydrogen necessary to
the process is brought into stage (c). In this invention, the
"make-up hydrogen" is mentioned in contrast to the recycled
hydrogen. The hydrogen purity is generally between 84 and 100% and
preferably between 95 and 100%.
[0028] According to another embodiment, the hydrogen supplying the
last compression stage can be recycled hydrogen originating from
the separation stage (d) and/or the separation stage (b).
[0029] This recycled hydrogen can optionally supply an intermediate
stage of the compressor that has stages. In this case, it is
preferred that said hydrogen has been purified before its
recycling.
[0030] According to another embodiment, the delivery hydrogen from
the initial compression stage and/or from an intermediate stage
can, moreover, supply a unit for hydrotreatment of gas oil that is
obtained directly from atmospheric distillation, called
"straight-run gas oil." In a conventional way, the straight-run gas
oil hydrotreatment unit is operated at a pressure of between 3 and
6.5 MPa and preferably between 4.5 and 5.5 MPa.
[0031] The reaction conditions of each of the stages will now be
described in greater detail, especially in conjunction with the
drawings in which:
[0032] FIG. 1 shows the diagram of the installation allowing
implementation of one embodiment of the process according to the
invention;
[0033] FIG. 2 shows the diagram of the installation allowing
implementation of another embodiment of the process according to
the invention.
[0034] The process according to the invention is very particularly
suitable for treatment of heavy feedstocks, i.e., feedstocks of
which at least 80% by weight has a boiling point of greater than
340.degree. C. Their initial boiling point is generally established
at least 340.degree. C., often at least 370.degree. C. or even at
least 400.degree. C. These are, for example, direct-distillation
vacuum distillates, vacuum distillates that are obtained from
conversion processes such as, for example, those that originate
from coking, from a fixed-bed hydroconversion (such as those
obtained from the HYVAHL.RTM. processes for treatment of heavy
products developed by the applicant) or processes for
hydrotreatment of heavy products in a boiling bed (such as those
obtained from H-OIL.RTM. processes), or else oils that are
deasphalted with solvent (for example with propane, with butane or
with pentane) coming from deasphalting of direct-distillation
vacuum residue or residues that are obtained from the HYVAHL.RTM.
or H-OIL.RTM. processes. The feedstocks can also be formed by
mixing these various fractions. They can also contain fractions
originating from the process that is the object of this invention
and those recycled for its supply. They can also contain gas-oil
fractions and heavy gas oils originating from the catalytic
cracking that has a distillation interval of about 160.degree. C.
to about 500.degree. C. They can also contain aromatic extracts and
paraffins that are obtained within the framework of the production
of lubricating oils. According to this invention, the feedstocks
that are treated are preferably vacuum distillates.
[0035] The sulfur content of the feedstock is highly variable and
is nonlimiting. The content of metals such as nickel and vanadium
is generally between about 1 ppm and 30 ppm, but it is without any
technical limitation.
[0036] The feedstock is treated first of all in a hydroconversion
section (II) in the presence of hydrogen originating from the
hydrogen compression zone (I). Then, the treated feedstock is
separated into the separation zone (III) from where, among other
fractions, a gas oil fraction is recovered that then supplies the
hydrotreatment zone (IV) from where the remaining sulfur is
removed.
[0037] Each of these reaction zones is shown in FIGS. 1 and 2. The
different physical reactions or transformations carried out in each
of these zones will be described below.
[0038] Zone (I) represents the compression of hydrogen in several
stages (three in the figures). In this zone, the make-up hydrogen
is treated, optionally mixed with the flows of purified recycling
hydrogen, to raise its pressure to the level required by stage (a).
Said single compression system generally includes at least two
compression stages that are generally separated by compressed gas
cooling systems, liquid and vapor phase separation units and
optionally inputs of the purified recycling hydrogen flows. The
breakdown into several stages therefore makes available hydrogen at
one or more intermediate pressures between that of the input and
that of the output of the system. This (these) intermediate
pressure level(s) can supply hydrogen to at least one catalytic
hydrotreatment or hydrocracking unit.
[0039] More specifically, the make-up hydrogen that is necessary to
the operation of zones (II) and (IV) achieves a pressure of between
1 and 3.5 MPa, and preferably between 2 and 2.5 MPa by a pipe (4)
in a zone (I) where it is compressed, optionally with other
recycling hydrogen flows, in a multistage compression system. Each
compression stage (1, 2 and 3), three in the figures, is separated
from the next by a liquid-vapor separation and cooling system (33),
(34) and (35) allowing the gas temperature and the amount of liquid
carried to the following compression stage to be reduced. The pipes
allowing the evacuation of this liquid are not shown in the
figures.
[0040] Between the first and the last stage, and more often between
the second and the third stage, one pipe (7) routes at least part,
and preferably all, of the compressed hydrogen to the
hydrotreatment zone (IV). The hydrogen leaving the zone (IV)
through the pipe (8) is sent to the following compression stage,
more often the third and last. The pipe (14) routes the hydrogen to
zone (II).
[0041] The feedstock to be treated (such as defined above) enters
the hydroconversion zone (II) in a fixed bed via a pipe (10). The
effluent that is obtained in the pipe (11) is sent into the
separation zone (III).
[0042] This zone (II) comprises at least one fixed-bed reactor that
contains at least one catalyst.
[0043] The operation is usually carried out under an absolute
pressure of 6 to 17 MPa, and most often of 8 to 12 MPa, at a
temperature of about 300.degree. C. to about 500.degree. C., and
often from about 350 to about 450.degree. C. The liquid hourly
space velocity (LHSV) relative to the volume of catalyst and the
partial pressure of hydrogen are important factors that one skilled
in the art knows to select based on the characteristics of the
feedstock to be treated and the desired conversion. Most often, the
LHSV, relative to the catalyst volume, is located in a range that
goes from about 0.1 h.sup.-1 to about 10 h.sup.-1, and preferably
from about 0.2 h.sup.-1 to about 5 h.sup.-1. The amount of hydrogen
mixed with the feedstock is usually from about 50 to about 5000
normal cubic meters (Nm.sup.3) per cubic meter (m.sup.3) of the
liquid feedstock, and most often from about 100 to about 2000
Nm.sup.3/m.sup.3, and preferably from about 200 to 1500
Nm.sup.3/m.sup.3.
[0044] The net conversion into products boiling below 360.degree.
C. of the fraction having a boiling point of greater than
540.degree. C. is between 10 and 99% by weight, most often between
10 and 70% by weight, and advantageously between 15 and 45%.
[0045] In this hydroconversion stage, it is possible to use any
standard catalyst, in particular a granular catalyst comprising, on
an amorphous substrate, at least one metal or metal compound with a
hydro-dehydrogenating function. This catalyst can be a catalyst
comprising metals of group VIII, for example nickel and/or cobalt,
most often in combination with at least one metal of group VIB, for
example molybdenum and/or tungsten. It is possible, for example, to
use a catalyst comprising from 0.5 to 10% by weight of nickel and
preferably from 1 to 5% by weight of nickel (expressed in terms of
nickel oxide NiO), and from 1 to 30% by weight of molybdenum and
preferably from 5 to 20% by weight of molybdenum (expressed in
terms of molybdenum oxide MoO.sub.3) on an amorphous mineral
substrate. This substrate will be selected from, for example, the
group that is formed by alumina, silica, silica-aluminas, magnesia,
clays and mixtures of at least two of these minerals. This
substrate can likewise contain other compounds, and, for example,
oxides that are selected from the group that is formed by boron
oxide, zirconia, titanium oxide, and phosphoric anhydride. Most
often, an alumina substrate is used, and very often an alumina
substrate that is doped with phosphorus and optionally boron is
used. The concentration of phosphoric anhydride P.sub.2O.sub.5 is
usually less than about 20% by weight and most often less than
about 10% by weight. This concentration of P.sub.2O.sub.5 is
usually at least 0.001% by weight. The concentration of boron
trioxide B.sub.2O.sub.3 is usually from about 0 to about 10% by
weight. The alumina that is used is usually a .gamma.- or
.eta.-alumina. The total content of oxides of metals of groups VI
and VIII is often from about 5 to about 40% by weight and in
general from about 7 to 30% by weight, and the ratio by weight
expressed in terms of metal oxide between the metal (or metals) of
group VI to the metal (or metals) of group VII is in general from
about 20 to about 1 and most often from about 10 to about 2.
[0046] Another type of usable catalyst comprises at least one metal
of group VIII and at least one metal from the group VIB and one
silica-alumina.
[0047] Another type of usable catalyst is a catalyst that contains
at least one matrix, at least one Y zeolite and at least one
hydro-dehydrogenating metal. The matrices, metals, and additional
elements described above can also be part of the composition of
this catalyst. Advantageous Y zeolites are described in the Patent
Applications WO-00/71641, EP-911 077 as well as U.S. Pat. Nos.
4,738,940 and 4,738,941.
[0048] The hydrocracked effluent obtained from stage (a) is then
separated in stage (b). It is introduced by a pipe (11) into at
least one separator (15) that separates, on the one hand, a gas
containing hydrogen (gaseous phase) in the pipe (16) and, on the
other hand, a liquid effluent in the pipe (17). It is possible to
use a hot separator followed by a cold separator. A series of hot
and cold separators at medium and low pressure can also be
present.
[0049] The liquid effluent is sent into a separator (18) that is
preferably composed of at least one distillation column, and it is
separated into at least one distillate fraction that includes a gas
oil fraction and that is located in the pipe (21). It is also
separated into at least one fraction that is heavier than the gas
oil that is evacuated via the pipe (23).
[0050] At the level of the separator (18), the acid gas can be
separated in a pipe (19), the naphtha can be separated in an
additional pipe (20), and the fraction that is heavier than the gas
oil can be separated in a vacuum distillation column into a vacuum
residue discharging via the pipe (23) and one or more pipes (22)
that correspond to vacuum gas oil fractions.
[0051] The fraction from the pipe (23) can be used as an industrial
fuel oil with a low sulfur content or can advantageously be sent to
a carbon rejection process, such as, for example, coking.
[0052] Naphtha (20), obtained separately, optionally with the
naphtha (29) separated in zone (IV) added, is advantageously
separated into heavy and light gasolines, the heavy gasoline being
sent into a reforming zone and the light gasoline being sent to a
zone where paraffin isomerization is carried out.
[0053] The vacuum gas oil (22) may optionally be sent, alone or in
a mixture with similar fractions of different origins, into a
catalytic cracking process in which these fractions are
advantageously treated under conditions that make it possible to
produce a gaseous fraction, a gasoline fraction, a gas oil fraction
and a fraction that is heavier than the gas oil fraction that is
often called the slurry fraction by ones skilled in the art. They
can also be sent into a catalytic hydrocracking process in which
they are advantageously treated under conditions making it possible
to produce in particular a gaseous fraction, a gasoline fraction,
or a gas oil fraction.
[0054] In FIGS. 1 and 2, the separation zone (III) formed by the
separators (15) and (18) is shown by dotted lines.
[0055] For distillation, the conditions are, of course, selected
based on the initial feedstock. If the initial feedstock is a
vacuum gas oil, the conditions will be more rigorous than if the
initial feedstock is an atmospheric gas oil. For an atmospheric gas
oil, conditions are generally selected such that the initial
boiling point of the heavy fraction is from about 340.degree. C. to
about 400.degree. C., and for a vacuum gas oil, they are generally
selected such that the initial boiling point of the heavy fraction
is from about 540.degree. C. to about 700.degree. C.
[0056] For naphtha, the final boiling point is between about
120.degree. C. and about 180.degree. C.
[0057] The gas oil is between the naphtha and the heavy
fractions.
[0058] The fraction points given here are indicative, but the
operator will choose the fraction point based on the quality and
the quantity of the desired products, as is generally
practiced.
[0059] At the outlet of stage (b), the gas oil fraction most often
has a sulfur content of between 100 and 10,000 ppm, and the
gasoline fraction most often has a sulfur content of at most 1000
ppm. The gas oil fraction thus does not meet 2005 sulfur
specifications.
[0060] The gas oil fraction is then sent (alone or optionally with
an external naphtha and/or gas oil fraction added to the process)
into a hydrotreatment zone (IV) provided with at least one fixed
bed of a hydrotreatment catalyst in order to reduce the sulfur
content to below 50 ppm, preferably below 20 ppm, and even more
preferably below 10 ppm. It is also necessary to significantly
reduce the nitrogen content of the gas oil to obtain a desulfurized
product with a stable color.
[0061] It is possible to add to said gas oil fraction a fraction
that is produced outside of the process according to the invention,
which normally cannot be directly incorporated into the gas oil
pool. This hydrocarbon fraction can be selected from, for example,
the group that is formed by the LCO (light cycle oil) originating
from fluidized-bed catalytic cracking as well as a gas oil that is
obtained from a high-pressure hydroconversion process of a vacuum
distillation gas oil.
[0062] Usually, an operation proceeds at a total pressure of about
4 to 8 MPa, and preferably from about 4.5 to 6 MPa. The temperature
in this stage is usually from about 200 to about 500.degree. C.,
preferably from about 330 to about 410.degree. C. This temperature
is usually adjusted based on the desired level of
hydrodesulfurization and/or saturation of aromatic compounds and
should be compatible with the desired cycle duration. The liquid
hourly space velocity or LHSV and the partial hydrogen pressure are
selected based on the characteristics of the feedstock to be
treated and the desired conversion. Most often, the LHSV is in a
range of from about 0.1 h.sup.-1 to about 10 h.sup.-1 and
preferably 0.1 h.sup.-1-5 h.sup.-1, and advantageously from about
0.2 h.sup.-1 to about 2 h.sup.-1.
[0063] The total amount of hydrogen mixed with the feedstock
depends largely on the hydrogen consumption from stage b) as well
as the recycled purified hydrogen gas sent to stage a). It is,
however, usually from about 100 to about 5000 normal cubic meters
(Nm.sup.3) per cubic meter (m.sup.3) of the liquid feedstock and
most often from about 150 to 1000 Nm.sup.3/m.sup.3.
[0064] The operation of stage d) in the presence of a large amount
of hydrogen makes it possible to usefully reduce the partial
pressure of ammonia. In the preferred case of this invention, the
partial pressure of ammonia is generally less than 0.5 MPa.
[0065] An operation is likewise usefully carried out with a reduced
partial hydrogen sulfide pressure that is compatible with the
stability of the sulfide catalysts. In the preferred case of this
invention, the partial hydrogen sulfide pressure is generally less
than 0.5 MPa.
[0066] In the hydrodesulfurization zone, the ideal catalyst should
have a strong hydrogenation capacity so as to accomplish thorough
refinement of the products and to obtain a major reduction of
sulfur and nitrogen. According to the preferred embodiment of the
invention, the hydrotreatment zone operates at a relatively low
temperature, which points in the direction of thorough
hydrogenation and therefore an improvement of the content of
aromatic compounds of the product and its cetane number and
limitation of coking. The scope of this invention would not be
exceeded by using a single catalyst or several different catalysts
simultaneously or in succession in the hydrotreatment zone.
Usually, this stage is carried out industrially in one or more
reactors with one or more catalytic beds and with downward liquid
flow.
[0067] In the hydrotreatment zone, at least one fixed bed of the
hydrotreatment catalyst comprising a hydro-dehydrogenating function
and an amorphous substrate is used. A catalyst is preferably used
whose substrate is selected from, for example, the group that is
formed by alumina, silica, silica-aluminas, magnesia, clays and
mixtures of at least two of these minerals. This substrate can also
contain other compounds and, for example, oxides selected from the
group that is formed by boron oxide, zirconia, titanium oxide, and
phosphoric anhydride. Most often, an alumina substrate is used and,
better, .eta.- or .gamma.-alumina. The hydrogenating function is
ensured by at least one metal of group VIII, for example nickel
and/or cobalt, optionally in combination with a metal of group VIB,
for example molybdenum and/or tungsten. Preferably, a catalyst
based on NiMo will be used. For gas oils that are difficult to
hydrotreat and for very high levels of hydrodesulfurization, one
skilled in the art knows that the desulfurization of an NiMo-based
catalyst is superior to that of a CoMo catalyst because the first
has a greater hydrogenating function than the second. For example,
it is possible to use a catalyst that comprises from 0.5 to 10% by
weight of nickel and preferably from 1 to 5% by weight of nickel
(expressed in terms of nickel oxide NiO), and from 1 to 30% by
weight of molybdenum and preferably from 5 to 20% by weight of
molybdenum (expressed in terms of molybdenum oxide (MoO.sub.3)) on
an amorphous mineral substrate. In an advantageous case, the total
content of oxides of metals of groups VI and VIII is often from
about 5 to about 40% by weight and in general from about 7 to 30%
by weight, and the ratio by weight expressed in terms of metal
oxide between the metal (metals) of group VI to the metal (or
metals) of group VIII is in general from about 20 to about 1 and
most often from about 10 to about 2.
[0068] The catalyst can also contain an element such as phosphorus
and/or boron. This element may have been introduced into the matrix
or may have been deposited on the substrate. It is also possible to
deposit silicon on the substrate, alone or with phosphorus and/or
boron. The concentration of said element is usually less than about
20% by weight (calculated in terms of oxide) and most often less
than about 10% by weight, and it is usually at least 0.001% by
weight. The concentration of boron trioxide B.sub.2O.sub.3 is
usually from about 0 to about 10% by weight.
[0069] Preferred catalysts contain silicon deposited on a substrate
(such as alumina), optionally with P and/or B also deposited, and
also containing at least one metal of group VIII (Ni, Co) and at
least one metal of group VIB (W, Mo).
[0070] The hydrotreated effluent that is obtained exits via the
pipe (25) to be sent into the separation zone (V) shown in a
diagram in dotted lines in FIGS. 1 and 2.
[0071] Here, it comprises a separator (26), preferably a cold
separator, where a gaseous phase exiting via the pipe (8) and a
liquid phase exiting via the pipe (27) are separated.
[0072] The liquid phase is sent into a separator (31), preferably a
stripper, to remove the hydrogen sulfide exiting into the pipe
(28), most often mixed with naphtha. A gas oil fraction is drawn
off by the pipe (30), a fraction that meets sulfur specifications,
i.e., having less than 50 ppm of sulfur, and generally less than 20
ppm of sulfur, or even less than 10 ppm. The H.sub.2S--naphtha
mixture is then optionally treated to recover the purified naphtha
fraction. Separation can also be carried out at the level of the
separator (31), and the naphtha can be drawn off via the pipe
(29).
[0073] The process according to the invention also advantageously
comprises a hydrogen recycling loop for the 2 zones (II) and (IV)
that can be independent for the two zones, but is preferably
shared, and that is now described based on FIG. 1.
[0074] The gas containing the hydrogen (gaseous phase of the pipe
(16) that is separated in the zone (III)) is treated to reduce its
sulfur content and optionally to eliminate the hydrocarbon
compounds that have been able to pass during the separation.
[0075] Advantageously and according to FIG. 1, the gaseous phase of
the pipe (16) enters a purification and cooling system (36). It is
sent into a cooling tower after having been washed by injected
water and partially condensed by a recycled hydrocarbon fraction
from the low-temperature section downstream from the cooling tower.
The effluent from the cooling tower is sent into a separation zone
where water, a hydrocarbon fraction and a gaseous phase are
separated.
[0076] A portion of the recycled hydrocarbon fraction is sent into
the separation zone (III), and advantageously into the pipe
(37).
[0077] The gaseous phase that is obtained and from which
hydrocarbon compounds have been removed is sent, if necessary, into
a treatment unit to reduce the sulfur content. Advantageously, this
is a treatment with at least one amine.
[0078] In certain cases, it is enough that only a portion of the
gaseous phase is treated. In other cases, all of it should be
treated.
[0079] The gas that contains the hydrogen that has thus optionally
been purified is then sent to a purification system that makes it
possible to obtain hydrogen with a purity comparable to make-up
hydrogen.
[0080] A membrane purification system offers an economical means of
separating hydrogen from other light gases based on a permeation
technology. An alternative system could be purification by
adsorption with regeneration by pressure variation known under the
term Pressure Swing Adsorption (PSA). A third technology or a
combination of several technologies could also be considered.
[0081] At the outlet of the purification system, one or more pipes
(5) and (6) allow recycling of purified hydrogen to the zone (I),
normally at one or more pressure levels. Direct recycling to the
feed (38) of the zone (II) can also be considered, and in this
case, purification of this flow by membranes or PSA is no longer
necessary.
[0082] One particular embodiment has been described here for
separating the entrained hydrocarbon compounds; any other method
known to one skilled in the art is suitable.
[0083] In the preferred embodiment of FIG. 1, all of the make-up
hydrogen is introduced via the pipe (7) at the level of the zone
(IV).
[0084] According to another embodiment, a pipe bringing solely a
portion of the hydrogen at the level of zone (IV) can be
provided.
[0085] The zone (IV) being able to benefit from a high flow rate of
high-purity hydrogen operates at a partial hydrogen pressure that
is very near the total pressure and for the same reason at very low
partial pressures of hydrogen sulfide and ammonia. This
advantageously makes it possible to reduce the total pressure and
the amounts of catalyst necessary to obtain specifications for the
gas oil that is produced and overall to minimize investment
costs.
[0086] The process of the invention is implemented in an
installation comprising the following reaction zones:
[0087] A single hydrogen compression zone that consists of n
compression stages arranged in series, n being between 2 and 6,
preferably between 2 and 5, preferably between 2 and 4 and being
more preferably equal to 3,
[0088] A catalytic hydroconversion zone (II) that consists of at
least one fixed-bed reactor that is fed with hydrogen via the last
compression stage and is connected via the pipe (11) to a
separation zone (III) that consists of at least one separator (15)
and at least one distillation column (18), the separator allowing
the separation of a hydrogen-rich gas via the pipe (16) and a
liquid phase that is brought via the pipe (17) to the distillation
column (18); the pipe (21) drawing off the distilled gas oil
fraction is connected to
[0089] A hydrotreatment zone (IV) that consists of a fixed-bed
hydrotreatment reactor that is supplied with hydrogen by an
intermediate compression stage, and of which the effluent pipe (25)
is connected to
[0090] A separation zone (V) that makes it possible to evacuate the
hydrogen to the last compression stage.
[0091] Thus, according to one embodiment of the invention, the
installation is such as that shown in a diagram in FIG. 1.
[0092] The detail of the various reaction zones is such as has been
described above in conjunction with the description of the
process.
[0093] According to one particular embodiment, in the installation
according to the invention, an intermediate compression stage, the
first one in FIG. 2, is connected to a straight-run gas oil
hydrotreatment reactor (40).
[0094] The invention also relates to the use in an installation for
conversion of a heavy petroleum feedstock in a fixed bed of a
single multistage hydrogen compressor.
[0095] The invention will be illustrated using the following
example that is not limiting.
[0096] In an installation according to the invention (as
illustrated in FIG. 1) with a single, three-stage compression
system, the conversion of a mixture of vacuum gas oil (VGO) and a
heavy coker gas oil (HCGO) that is obtained from a Middle-Eastern
crude oil is performed.
[0097] The properties of the mixture are as follows:
TABLE-US-00001 VGO + HCGO Density at 15.degree. C. 0.945 Sulfur, %
by Weight 3.4 Nitrogen, ppm by Weight 1554 Conradson Carbon, % by
Weight <1 Nickel + Vanadium, ppm by Weight <2 C.sub.7
Insolubles, % by Weight <0.05 ASTM Distillation, ASTM D1160,
.degree. C. T 5% 368 T 50% 456 T 95% 558
[0098] The VGO+HCGO mixture described in the table above is sent
into a mild hydrocracking unit (MHC) that operates under the
following conditions: [0099] Total pressure: 9.5 MPa [0100] VVH:
0.7 h.sup.-1 [0101] Catalyst: NiMo on alumina such as the HR-548
catalyst that is marketed by the Axens Company [0102] Mean reactor
temperature: 370.degree. C.
[0103] Under these conditions, a conversion of the VGO+HCGO
feedstock of about 25% by weight is obtained. The yield of the
diesel fraction is 25.7% by volume. The sulfur content of this
diesel fraction is 150 ppm. This product therefore does not meet
the international specifications that limit the sulfur of the
diesel fuels to less than 10 ppm.
[0104] This diesel fraction is sent into a fixed-bed hydrotreatment
unit that operates under the following conditions: [0105] Total
pressure: 5.7 MPa [0106] VVH: 0.85 h.sup.-1 [0107] Catalyst: CoMo
on alumina such as the HR-526 marketed by the Axens Company, [0108]
Mean reactor temperature: 345.degree. C.
[0109] The addition of hydrogen from the diesel hydrotreatment unit
is taken from the outlet of the 2.sup.nd stage of the compressor.
The delivery pressure of the 2.sup.nd stage of the make-up
compressor is 6.5 MPa. The high-pressure purging of the
hydrotreatment unit is recycled to the intake of the 3.sup.rd stage
of the compressor. The delivery pressure of the 3.sup.rd stage of
the make-up compressor is 10.2 MPa. The diesel hydrotreatment unit
does not comprise a hydrogen recycling compressor.
[0110] At the outlet of the hydrotreatment reactor, the yields and
the qualities of products are illustrated in the following table.
The diesel that is produced has a sulfur content that is less than
10 ppm by weight, which duly meets future international
specifications.
TABLE-US-00002 Yields, % by Volume Naphtha 1.4 Diesel 25.7
Hydrotreated VGO 75.7 H.sub.2 Consumption, % by Weight 1.3 Diesel
Properties Density at 15.degree. C. 0.870 Sulfur, ppm <10 Cetane
48 Hydrotreated VGO Properties Density at 15.degree. C. 0.890
Sulfur, ppm <300 Hydrogen, % by Weight 13.0
[0111] Without further elaboration, it is believed that one skilled
in the art can, using the preceding description, utilize the
present invention to its fullest extent. The preceding preferred
specific embodiments are, therefore, to be construed as merely
illustrative, and not limitative of the remainder of the disclosure
in any way whatsoever.
[0112] In the foregoing and in the examples, all temperatures are
set forth uncorrected in degrees Celsius and, all parts and
percentages are by weight, unless otherwise indicated.
[0113] The preceding examples can be repeated with similar success
by substituting the generically or specifically described reactants
and/or operating conditions of this invention for those used in the
preceding examples.
[0114] From the foregoing description, one skilled in the art can
easily ascertain the essential characteristics of this invention
and, without departing from the spirit and scope thereof, can make
various changes and modifications of the invention to adapt it to
various usages and conditions.
* * * * *