U.S. patent application number 12/271851 was filed with the patent office on 2010-05-20 for integrated slurry hydrocracking and coking process.
Invention is credited to Robert S. HAIZMANN, Paul R. ZIMMERMAN.
Application Number | 20100122932 12/271851 |
Document ID | / |
Family ID | 42170613 |
Filed Date | 2010-05-20 |
United States Patent
Application |
20100122932 |
Kind Code |
A1 |
HAIZMANN; Robert S. ; et
al. |
May 20, 2010 |
Integrated Slurry Hydrocracking and Coking Process
Abstract
Integrated slurry hydrocracking (SHC) and coking methods for
making slurry hydrocracking (SHC) distillates are disclosed.
Representative methods involve passing a slurry comprising a
recycle SHC gas oil, a coker gas oil, a vacuum column resid, and a
solid particulate through an SHC reaction zone in the presence of
hydrogen to obtain the SHC distillate. Recovery of an SHC pitch
from fractionation of the SHC reaction zone effluent provides an
additional possibility for integration with the coker, and
particularly via the upgrading of the SHC pitch in the coker to
provide coke and lighter hydrocarbons such as SHC vacuum gas oil
(VGO).
Inventors: |
HAIZMANN; Robert S.;
(Rolling Meadows, IL) ; ZIMMERMAN; Paul R.;
(Palatine, IL) |
Correspondence
Address: |
HONEYWELL/UOP;PATENT SERVICES
101 COLUMBIA DRIVE, P O BOX 2245 MAIL STOP AB/2B
MORRISTOWN
NJ
07962
US
|
Family ID: |
42170613 |
Appl. No.: |
12/271851 |
Filed: |
November 15, 2008 |
Current U.S.
Class: |
208/55 ; 208/106;
208/122; 208/124; 208/95 |
Current CPC
Class: |
C10G 47/26 20130101;
C10G 2400/06 20130101; C10G 2400/04 20130101 |
Class at
Publication: |
208/55 ; 208/124;
208/122; 208/106; 208/95 |
International
Class: |
C10G 11/02 20060101
C10G011/02 |
Claims
1. An integrated process for preparing a slurry hydrocracking (SHC)
distillate, the process comprising: (a) passing a heavy hydrocarbon
feedstock comprising a coker gas oil through an SHC reaction zone
in the presence of hydrogen to provide an SHC effluent; and (b)
recovering said SHC distillate from said SHC effluent.
2. The process of claim 1, wherein said coker gas oil is obtained
from a delayed coker or a fluidized coker.
3. The process of claim 1, wherein the heavy hydrocarbon feedstock
is present as a slurry, in combination with a solid particulate, in
said SHC reaction zone.
4. The process of claim 3, wherein said solid particulate comprises
a compound of a metal of Group IVB, Group VB, Group VIB, Group
VIIB, or Group VIII.
5. The process of claim 1, wherein said heavy hydrocarbon feedstock
further comprises a vacuum column residue.
6. The process of claim 1, further comprising recovering an SHC gas
oil from said SHC effluent, and recycling said SHC gas oil to said
SHC zone, whereby said heavy hydrocarbon feedstock comprises said
SHC gas oil and said coker gas oil.
7. The process of claim 6, wherein, said SHC distillate is
separated, as a lower boiling component, from said SHC gas oil by
flash separation or fractionation of said SHC effluent.
8. The process of claim 6, wherein said SHC gas oil has a
distillation end point temperature from about 427.degree. C.
(800.degree. F.) to about 538.degree. C. (1000.degree. F.).
9. The process of claim 1, wherein said SHC reaction zone is
maintained at a temperature from about 343.degree. C. (650.degree.
F.) to about 538.degree. C. (1000.degree. F.), a pressure from
about 3.5 MPa (500 psig) to about 21 MPa (3000 psig), and a space
velocity from about 0.1 to about 30 volumes of heavy hydrocarbon
feedstock per hour per volume of said SHC zone.
10. The process of claim 1, further comprising hydrotreating a
distillate feedstock comprising said SHC distillate in a
hydrotreating zone to obtain a hydrotreated distillate.
11. The process of claim 10, wherein said distillate feedstock
further comprises, in addition to said SHC distillate, a
straight-run distillate.
12. The process of claim 10, wherein said hydrotreated distillate
has an API gravity of at least about 20.degree..
13. The process of claim 10 wherein said hydrotreating is carried
out in the presence of a hydrotreating catalyst under hydrotreating
conditions including a temperature from about 260.degree. C.
(500.degree. F.) to about 426.degree. C. (800.degree. F.), a
pressure from about 7.0 MPa (1000 psig) to about 21 MPa (3000
psig), and a liquid hourly space velocity (LHSV) from about 0.1
hr.sup.-1 to about 10 hr.sup.-1.
14. The process of claim 13, wherein the hydrotreating catalyst
comprises a metal selected from the group consisting of nickel,
cobalt, tungsten, molybdenum, and mixtures thereof, on a refractory
inorganic oxide support.
15. The process of claim 1, further comprising recovering an SHC
pitch, as a higher boiling component, by flash separation or
fractionation of said SHC effluent.
16. The process of claim 15, wherein said SHC pitch comprises
hydrocarbons boiling at a temperature of greater than about
538.degree. C. (1000.degree. F.).
17. The process of claim 15, further comprising passing said SHC
pitch to a coker that produces said coker gas oil.
18. A method for making a distillate hydrocarbon component by
integrating slurry hydrocracking (SHC), coking, and hydrotreating,
the method comprising: (a) passing a slurry comprising an SHC gas
oil, a coker gas oil obtained from a delayed coker or a fluidized
coker, and a solid particulate through an SHC reaction zone in the
presence of hydrogen to provide an SHC effluent, (b) recovering
said SHC gas oil, an SHC distillate, and SHC pitch from said SHC
effluent, (c) recycling said SHC gas oil to said SHC reaction zone,
(d) hydrotreating said SHC distillate to obtain said synthetic
crude oil as a hydrotreated distillate, and (e) passing said SHC
pitch to said delayed coker or said fluidized coker to obtain a
coke product.
19. The method of claim 18, wherein the SHC distillate comprises
less than about 20% by weight of hydrocarbons boiling at a
temperature of greater than 343.degree. C. (650.degree. F.).
20. The method of claim 18, wherein said method comprises further
integrating a crude oil atmospheric distillation column and a crude
oil vacuum distillation column, whereby a straight-run distillate
from said crude oil atmospheric distillation column is hydrotreated
together with said SHC distillate and a vacuum gas oil from said
vacuum distillation column is passed through said SHC reaction zone
together with said SHC gas oil and said coker gas oil.
Description
FIELD OF THE INVENTION
[0001] The present invention relates to methods for preparing
distillate hydrocarbons using slurry hydrocracking (SHC) to upgrade
gas oils obtained from refinery operations and particularly delayed
coking. The integration of SHC with coking and optionally other
processes such as crude oil fractionation and/or hydrotreating may
be used to obtain a high quality (e.g., high API gravity and/or low
sulfur) distillate.
DESCRIPTION OF RELATED ART
[0002] Gas oils and particularly vacuum gas oil (VGO) are produced
in a number of refinery operations that process heavy hydrocarbon
feedstocks. Such operations include coking, crude oil
fractionation, and visbreaking. Coking processes (e.g., delayed
coking or fluidized coking) involve thermal (i.e., non-catalytic)
cracking of atmospheric and vacuum column residues to generate
lighter hydrocarbons and solid coke. See, for example, Meyers, R.
A., Handbook of Petroleum Refining Processes, 3.sup.rd Ed., Ch. 12,
McGraw-Hill (2004). Delayed coking in particular has become a
predominant process for upgrading "bottom of the barrel" refinery
process streams. However, the gas oils produced from coking
operations, such as delayed coker VGO, are regarded as low quality
products requiring further upgrading with fluid catalytic cracking
(FCC), hydrocracking, and/or hydrotreating. Coker gas oils are
unfortunately not easily processed according to such conventional
methods, due to the significant levels of contaminants (e.g.,
metals and sulfur compounds) that deactivate supported metal
catalysts, as well as coke precursors in these streams. The
conversion of coker gas oils to more salable distillate and naphtha
blending components for transportation fuels is therefore
associated with a number of drawbacks.
[0003] Another process known to generate gas oils is slurry
hydrocracking, which refers to the conversion of heavy hydrocarbon
feedstocks in the presence of hydrogen and solid catalyst particles
(e.g., as a metal nanoaggregate) in a slurry phase or optionally in
a homogenous catalyst system using an oil-soluble metallic catalyst
such as a metal sulfide compound.
[0004] Representative slurry hydrocracking processes are described,
for example, in U.S. Pat. No. 5,755,955 and U.S. Pat. No.
5,474,977. In addition to the VGO normally present in the reactor
effluent, slurry hydrocracking produces a low-value, refractory
pitch stream that normally cannot be economically upgraded or even
blended into other products such as fuel oil or synthetic crude
oil, due to its high viscosity and solids content.
[0005] A particular source of synthetic crude oil of increasing
interest, and for which blending components are sought to improve
its flow characteristics, is bitumen. This low-quality
hydrocarbonaceous material is recovered from oil sand deposits,
such as those found in the vast Athabasca region of Alberta,
Canada, as well as in Venezuela and the United States. Bitumen is
recognized as a valuable source of "semi-solid" petroleum, which
can be refined into many valuable end products including
transportation fuels such as gasoline or even petrochemicals.
[0006] There is an ongoing need in the art for process in which
heavy hydrocarbons (e.g., atmospheric column and vacuum column
resids as well as gas oils) are converted or upgraded with improved
efficiency. There is also a need for such processes in which the
net production of low-value end products, including gas oils and
pitch, is minimized. There is further a need for overall crude oil
refining processes that include the upgrading of crude oil residues
and particularly those obtained in significant proportions from
heavy crude oil feedstocks.
SUMMARY OF THE INVENTION
[0007] Aspects of the invention relate to the finding that slurry
hydrocracking (SHC) can be effectively integrated with other
refining processes such as coking, hydrotreating, and/or crude oil
fractionation to produce a high value distillate stream while
recycling unwanted gas oils, preferably to extinction. SHC is
generally known in the art for its ability to convert vacuum column
residues to lighter products. However, it has now been surprisingly
discovered that the use of coker gas oil (e.g., delayed coker VGO)
as a heavy hydrocarbon feedstock component or incremental feed to
SHC can suppress coke formation, in addition to being converted to
more valuable naphtha and distillate products, in the SHC reactor
and provide other important benefits associated with the resulting
SHC/coking integrated process.
[0008] In a representative integrated process, low-quality coker
gas oil is utilized in combination with recycled SHC gas oil,
recovered from downstream fractionation/separation of the SHC
effluent, in the overall heavy hydrocarbon feedstock to SHC. While
portions of this feedstock also generally include conventional
components such as vacuum column resid, the presence of coker gas
oil improves the SHC reactor effluent quality, particularly with
respect to a reduced coke yield as well as an increased naphtha and
distillate yield, as discussed above. Moreover, coker gas oil is
(1) often readily available in large quantities, particularly in
the case of refineries processing heavy crude oils, and (2)
difficult to further upgrade using FCC, hydrocracking, or
hydrotreating due to the high levels of contaminants that poison
(deactivate) catalysts used in these processes. However, it has now
been determined that coker gas oil is an attractive incremental
feedstock (e.g., in combination with a vacuum column residue) which
is efficiently cracked using SHC to yield lighter and more valuable
net distillate and optionally naphtha products. Moreover, the
integration of SHC with coking (e.g., delayed coking or fluidized
coking) offers the further advantage, according to some
embodiments, of passing the pitch byproduct of SHC to the coker
inlet, together with atmospheric column or vacuum column resids
that are conventionally processed in coking operations. The
processing of SHC pitch in the coker thus allows for
conversion/upgrading of this byproduct to higher value hydrocarbons
and solid coke. Whether or not the SHC pitch is processed in the
coker, the reduced yield of gas oil end products, such as
hydrocarbons boiling the VGO range, in the integrated SHC/coking
process, diminishes the need for the separate hydrotreating and/or
hydrocracking of such products.
[0009] According to one representative embodiment, an integrated
SHC/coking process is combined with hydrotreating of the SHC
distillate. As a result of the low (or non-existent) net yield of
gas oil products such as VGO, due to recycling of these
heavy-boiling fractions back to the SHC reaction zone, the
hydrotreated distillate has a sufficiently high API gravity (e.g.,
at least about 20.degree.), making it attractive for blending into
a synthetic crude oil that is transported via a pipeline. Thus, the
hydrotreated distillate, or even the SHC distillate without
hydrotreating, may be obtained as a high quality transportation
fuel blending component with only a minor amount or essentially no
hydrocarbons boiling at a temperature representative of gas oils
(e.g., greater than about 343.degree. C. (650.degree. F.)).
[0010] The SHC process may also be integrated with an existing
refinery hydrotreating process, conventionally used for sulfur- and
nitrogen-containing compound removal from distillates, by
hydrotreating a recovered SHC distillate product in conjunction
with a straight-run distillate obtained from crude oil
fractionation and/or other refinery distillate streams. This
integration may advantageously reduce overall capital costs of the
complex. As discussed above, the integration of SHC with existing
coking, optionally hydrotreating, and optionally other conventional
refinery operations has the potential to provide significant
benefits in terms of improved processing efficiency and product
yields, reduction or elimination of low-value refractory
byproducts, and/or the associated capital cost reduction. According
to a specific embodiment of the invention, a crude oil vacuum
column bottoms residue stream provides a part of the heavy
hydrocarbon feedstock to an SHC reactor, and is combined at the
inlet of the SHC reactor with coker gas oil (e.g., coker VGO).
Other portions of the residue from the vacuum column or other
fractions from this column, may also be processed in the coker
itself. In another embodiment, a coker gas oil or a portion of this
refinery gas oil component provides, optionally together with a
straight-run gas oil (e.g., straight-run VGO), a portion of the
heavy hydrocarbon feedstock processed using SHC, and SHC pitch that
is separated from the SHC effluent by fractionation may be in turn
passed to the coker (e.g., delayed coker or fluidized coker) for
upgrading.
[0011] These and other aspects and embodiments relating to the
present invention are apparent from the following Detailed
Description.
BRIEF DESCRIPTION OF THE DRAWING
[0012] FIG. 1 depicts a representative process in which slurry
hydrocracking is integrated into a typical refinery flowscheme
having an existing coker to produce net products of a hydrotreated
distillate and coke from crude oil, with little or no overall
production of refractory gas oils such as VGO.
[0013] FIG. 2 depicts a second representative integrated
process.
DETAILED DESCRIPTION
[0014] Embodiments of the invention relate to the use of slurry
hydrocracking (SHC) in combination with coking to upgrade a heavy
hydrocarbon feedstock. A representative heavy hydrocarbon feedstock
to the SHC is a mixture of SHC gas oil, recovered from the SHC
effluent and recycled to an SHC reactor (or reaction zone), and a
refinery coker gas oil. According to one embodiment, for example,
the heavy hydrocarbon feedstock comprises both a vacuum column
residue and a coker gas oil (e.g., obtained from a delayed coker or
a fluidized coker). Integration of a refinery coker operation with
SHC provides important benefits as discussed above. The heavy
hydrocarbon feedstock, in addition to recycled SHC gas oil and
coker gas oil, may contain further components that can benefit from
the SHC operation to decrease the overall molecular weight of the
heavy hydrocarbon feedstock, and/or remove organic sulfur and
nitrogen compounds and metals. According to various embodiments,
SHC is improved (e.g., by the suppression of coke formation) when a
significant portion of the heavy hydrocarbon feedstock boils in a
representative gas oil range (e.g., from about 343.degree. C.
(650.degree. F.) to about 566.degree. C. (1050.degree. F.)) and
only at most about 80% by weight, and often at most about 60% by
weight, of the heavy hydrocarbon feedstock are compounds boiling
above 566.degree. C. (1050.degree. F.).
[0015] In addition to SHC gas oil and coker gas oil, representative
further components of the heavy hydrocarbon feedstock include
residual oils such as a crude oil atmospheric distillation column
residuum boiling above about 343.degree. C. (650.degree. F.), a
crude oil vacuum distillation column residuum boiling above
566.degree. C. (1050.degree. F.), tars, bitumen, coal oils, and
shale oils. Other asphaltene-containing materials such as whole or
topped petroleum crude oils including heavy crude oils may also be
used as components processed by SHC. In addition to asphaltenes,
these further possible components of the heavy hydrocarbon
feedstock, as well as others, generally also contain significant
metallic contaminants (e.g., nickel, iron and vanadium), a high
content of organic sulfur and nitrogen compounds, and a high
Conradson carbon residue. The metals content of such components,
for example, may be 100 ppm to 1,000 ppm by weight, the total
sulfur content may range from 1% to 7% by weight, and the API
gravity may range from about -5.degree. to about 35.degree.. The
Conradson carbon residue of such components is generally at least
about 5%, and is often from about 10% to about 30% by weight.
Overall, many of the heavy hydrocarbon feedstock components of the
SHC process, including the coker gas oil, have properties that
render them detrimental to other types of catalytic conversion
processes such as hydrocracking and fluid catalytic cracking.
[0016] Integrated methods of processes for preparing SHC
distillates generally involve passing a heavy hydrocarbon feedstock
comprising a coker gas oil through an SHC reaction zone in the
presence of hydrogen to provide an SHC effluent. The heavy
hydrocarbon feedstock may be, but is not necessarily, present in a
heterogeneous slurry catalyst system in the SHC reactor, in which
the catalyst is in the form of a solid particulate. For purposes of
the present disclosure, however, homogeneous catalyst systems, in
which the catalytically active metal is present in the liquid phase
and is dissolved in the heavy hydrocarbon feedstock (e.g., as an
oil-soluble metal compound such as a metal sulfide), also fall
within the definition of an SHC process, since homogeneous
processes are equally applicable for upgrading the same types of
heavy hydrocarbon feedstocks with the same advantageous results
associated with the embodiments discussed herein.
[0017] The SHC reaction is carried out in the presence of a
combined recycle gas containing hydrogen and under conditions
sufficient to crack at least a portion of the heavy hydrocarbon
feedstock to a lighter-boiling SHC distillate fraction that is
recovered from the effluent of the SHC reactor. The combined
recycle gas is a mixture of a hydrogen-rich gas stream, recovered
from the SHC effluent (e.g., as an overhead gas stream from a high
pressure separator) and fresh make-up hydrogen that is used to
replace hydrogen consumed in the SHC reactor or reaction zone and
lost in any purge or vent gas streams or through dissolution.
Operation without hydrogen recycle (i.e., with "once-through"
hydrogen) represents an alternative mode of operation, in which a
number of possible hydrogen sources of varying purity may be
used.
[0018] The recovery of SHC distillate typically involves the use of
flash separation and/or distillation of the SHC effluent, or a
lower boiling fraction or cut thereof (e.g., a fraction having a
lower distillation endpoint), to separate the SHC distillate as a
lower boiling component from the co-produced (or unconverted) SHC
gas oil in the SHC effluent. SHC distillate may therefore be
recovered using a single stage of flash separation of the SHC
effluent in an SHC high pressure separator or, alternatively, using
a plurality of separation stages in an SHC fractionator, for
example an atmospheric fractionator or SHC atmospheric distillation
column. A particular representative embodiment involves passing the
SHC effluent to an atmospheric or pressurized fractionator and
recovering the SHC distillate as either an overhead product or a
side cut (e.g., with some of the light end, C.sub.4.sup.-
hydrocarbon products removed). Further product recovery is then
carried out by passing a bottoms product or residue from this first
(e.g., atmospheric) SHC fractionator to a second (e.g., vacuum) SHC
fractionator and recovering the SHC gas oil (e.g., heavy VGO). At
least a portion of the SHC gas oil is then recycled to the SHC
reactor or reaction zone, as discussed above. An SHC vacuum
fractionator may be used to separate not only the SHC gas oil, for
example as a side cut, but also the SHC pitch, for example as a
vacuum column bottoms product or residue, as well as an SHC light
VGO that may optionally be subjected to hydrotreating as described
in greater detail below.
[0019] If a slurry is formed with the heavy hydrocarbon feedstock,
normally passed upwardly through the SHC reaction zone, the slurry
generally has a solid particulate content in the range from about
0.01% to about 10% by weight. The solid particulate is generally a
compound of a catalytically active metal, or a metal in elemental
form, either alone or supported on a refractory material such as an
inorganic metal oxide (e.g., alumina, silica, titania, zirconia,
and mixtures thereof). Other suitable refractory materials are
include carbon, coal, and clays. Zeolites and non-zeolitic
molecular sieves are also useful as solid supports. One advantage
of using a support is its ability to act as a "coke getter" or
adsorbent of asphaltene precursors that might otherwise lead to
fouling of process equipment.
[0020] Catalytically active metals for use in hydroprocessing
include those from Group IVB, Group VB, Group VIB, Group VIIB, or
Group VIII of the Periodic Table, which are incorporated in the
heavy hydrocarbon feedstock in amounts effective for catalyzing
desired hydrotreating and/or hydrocracking reactions to provide,
for example, lower boiling hydrocarbons that may be fractionated
from the hydroprocessing slurry effluent as naphtha and/or
distillate products in the substantial absence of the solid
particulate. Representative metals include iron, nickel,
molybdenum, vanadium, tungsten, cobalt, ruthenium, and mixtures
thereof. The catalytically active metal may be present as a solid
particulate in elemental form or as an organic compound or an
inorganic compound such as a sulfide (e.g., iron sulfide) or other
ionic compound. Metal or metal compound nanoaggregates may also be
used to form the solid particulates.
[0021] Often, it is desired to form such metal compounds, as solid
particulates, in situ from a catalyst precursor such as a metal
sulfate (e.g., iron sulfate monohydrate) that decomposes or reacts
in the hydroprocessing reaction zone environment, or in a
pretreatment step, to form a desired, well-dispersed and
catalytically active solid particulate (e.g., as iron sulfide).
Precursors also include oil-soluble organometallic compounds
containing the catalytically active metal of interest that
thermally decompose to form the solid particulate (e.g., iron
sulfide) having catalytic activity. Such compounds are generally
highly dispersible in the heavy hydrocarbon feedstock and normally
convert under pretreatment or hydroprocessing reaction zone
conditions to the solid particulate that is contained in the slurry
effluent. An exemplary in situ solid particulate preparation,
involving pretreating the heavy hydrocarbon feedstock and
precursors of the ultimately desired metal compound, is described,
for example, in U.S. Pat. No. 5,474,977.
[0022] Other suitable precursors include metal oxides that may be
converted to catalytically active (or more catalytically active)
compounds such as metal sulfides. In a particular embodiment, a
metal oxide containing mineral may be used as a precursor of a
solid particulate comprising the catalytically active metal (e.g.,
iron sulfide) on an inorganic refractory metal oxide support (e.g.,
alumina). Bauxite represents a particular precursor in which
conversion of iron oxide crystals contained in this mineral
provides an iron sulfide catalyst as a solid particulate, whereby
the iron sulfide after conversion being supported on the alumina
that is predominantly present in the bauxite precursor.
[0023] Conditions in the SHC reactor or reaction zone generally
include a temperature from about 343.degree. C. (650.degree. F.) to
about 538.degree. C. (1000.degree. F.), a pressure from about 3.5
MPa (500 psig) to about 21 MPa (3000 psig), and a space velocity
from about 0.1 to about 30 volumes of heavy hydrocarbon feedstock
per hour per volume of said SHC zone. The catalyst and conditions
used in the SHC reaction zone are suitable for upgrading the heavy
hydrocarbon feedstock to provide a lower boiling component, namely
an SHC distillate fraction, in the SHC effluent exiting the SHC
reaction zone. The SHC distillate is generally recovered from the
total SHC effluent (optionally after the removal of a hydrogen-rich
gas stream for recycle to the SHC reactor, as discussed above) as a
fraction having a distillation end point which is normally above
that of naphtha. The SHC distillate, for example, may be recovered
as a fraction having a distillation end point temperature typically
in the range from about 204.degree. C. (400.degree. F.) to about
399.degree. C. (750.degree. F.), and often from about 260.degree.
C. (500.degree. F.) to about 343.degree. C. (650.degree. F.), with
heavier boiling compounds being recycled with the SHC gas oil or
recovered in an SHC pitch stream that is optionally passed to a
coker.
[0024] According to a particular embodiment, the SHC distillate and
a higher-boiling SHC fraction may be recovered as an overhead and a
bottoms stream, respectively, exiting a hot high pressure separator
to which the SHC effluent is fed (optionally after the removal of
the hydrogen-rich gas stream). Fractionation of the higher-boiling
SHC fraction (e.g., in a vacuum distillation column) can then
provide the SHC gas oil (e.g., a heavy VGO) and SHC pitch. As an
alternative to single-stage separation in a high pressure
separator, the SHC distillate may be recovered as a lower boiling
component from the SHC effluent by fractionation (i.e., using
multiple vapor-liquid equilibrium separation stages), for example
as a side cut of an SHC atmospheric fractionator or distillation
column. The residue or bottoms from this first SHC fractionator
column can then be fed to a second SHC fractionator such as a
vacuum distillation column to provide the SHC gas oil, SHC pitch,
and optionally other fractions, such as an SHC light VGO. In
integrated SHC/coking process that are combined with hydrotreating
of the SHC distillate, all or a portion of this SHC light VGO may
be used together (mixed or combined) with the SHC distillate as a
feed to a hydrotreating zone, as discussed below.
[0025] According to representative embodiments of the invention,
the yield of SHC distillate (having a distillation end point in
these ranges), is generally at least 30% by weight (e.g., from
about 30% to about 65% by weight), normally at least about 35% by
weight (e.g., from about 35% to about 55% by weight), and often at
least about 40% by weight (e.g., from about 40% to about 50% by
weight), of the combined SHC effluent weight (e.g., the combined
weight of the SHC distillate and SHC gas oil). Depending on the
desired end products, the SHC distillate may itself be fractionated
to yield, for example, naphtha and diesel fuel having varying
distillation end point temperatures. For example, a relatively
light naphtha may be separated from the SHC distillate, having a
distillation end point temperature from about 175.degree. C.
(347.degree. F.) to about 193.degree. C. (380.degree. F.).
According to other embodiments, a relatively heavy naphtha may be
separated, having a distillation end point temperature from about
193.degree. C. (380.degree. F.) to about 204.degree. C.
(400.degree. F.). The naphtha may be fractionated into one or more
naphtha fractions, for example light naphtha, gasoline, and heavy
naphtha, with representative distillation end points being in the
ranges from about 138.degree. C. (280.degree. F.) to about
160.degree. C. (320.degree. F.), from about 168.degree. C.
(335.degree. F.) to about 191.degree. C. (375.degree. F.), and from
about 193.degree. C. (380.degree. F.) to about 216.degree. C.
(420.degree. F.), respectively.
[0026] Also, depending on the particular separation/fractionation
conditions used to recover the SHC distillate, this stream will
normally contain quantities of organic nitrogen compounds and
organic sulfur compounds. For example, the amount of total sulfur,
substantially present in the form of organic sulfur compounds such
as alkylbenzothiophenes, in this stream is generally from about
0.1% to about 4%, normally from about 0.2% to about 2.5%, and often
from about 0.5% to about 2%. The amount of total nitrogen in the
SHC distillate, substantially present in the form of organic
nitrogen compounds such as non-basic aromatic compounds including
cabazoles, will normally be from about 100 ppm to about 2%, and
often from about 100 ppm to about 750 ppm. The SHC distillate will
also generally contain a significant fraction of polyaromatics such
as 2-ring aromatic compounds (e.g., fused aromatic rings such as
naphthalene and naphthalene derivatives) as well as multi-ring
aromatic compounds. According to some representative embodiments,
the combined amount of 2-ring aromatic compounds and multi-ring
aromatic compounds is at least about 50% by weight of the SHC
distillate, whereas the amount of mono-ring aromatic compounds
(e.g., benzene and benzene derivatives such as alkylaromatic
compounds) typically represents only at most about 20% by
weight.
[0027] The heavy hydrocarbon feedstock to the SHC reactor or
reaction zone, as discussed above, comprises, in addition to the
SHC gas oil (e.g., a heavy SHC VGO), a coker gas oil (e.g., a heavy
coker gas oil) produced from delayed or fluidized coking, and often
a vacuum column resid. In addition to the SHC and coker gas oils,
other representative gas oil components that may be included in the
heavy hydrocarbon feedstock include straight-run gas oils such as
vacuum gas oil, recovered by fractional distillation of crude
petroleum. Other gas oils produced in refineries include
deasphalted gas oil and visbreaker gas oil. Gas oils, as well as
the combined heavy hydrocarbon feedstock to the SHC reaction zone
that comprises these gas oils, can therefore be a mixture of
hydrocarbons boiling in range from about 343.degree. C.
(650.degree. F.) to an end point of about 593.degree. C.
(1100.degree. F.), with other representative distillation end
points being about 566.degree. C. (1050.degree. F.), about
538.degree. C. (1000.degree. F.), and about 482.degree. C.
(900.degree. F.). A representative SHC gas oil has a distillation
end point temperature from about 427.degree. C. (800.degree. F.) to
about 538.degree. C. (1000.degree. F.). In the case of a
straight-run vacuum gas oil, the distillation end point is governed
by the crude oil vacuum fractionation column and particularly the
fractionation temperature cutoff between the vacuum gas oil and
vacuum column bottoms split. Thus, refinery gas oil components
suitable in heavy hydrocarbon feedstocks to the SHC reactor, such
as straight-run fractions, often result from crude oil
fractionation or distillation operations, while other gas oil
components are obtained following one or more hydrocarbon
conversion reactions.
[0028] The SHC may be beneficially combined with hydrotreating,
such that the recovered SHC distillate or a fraction thereof,
(e.g., a naphtha fraction or a diesel fuel fraction) is
catalytically hydrotreated in a hydrotreating zone to reduce the
content of total sulfur and/or total nitrogen. According to
specific embodiments, for example, a hydrotreated naphtha fraction
may be obtained having a sulfur content of less than about 30 ppm
by weight, often less than about 10 ppm by weight, and even less
than about 5 ppm by weight. A hydrotreated diesel fuel may be
obtained having a sulfur content of less than about 50 ppm by
weight, often less than about 20 ppm by weight, and even less than
about 10 ppm by weight. Hydrotreating of SHC distillates to provide
a hydrotreated distillate, or hydrotreating of fractions of the SHC
distillates, may therefore provide low-sulfur products and even
ultra low sulfur naphtha and diesel fractions in compliance with
applicable tolerances. According to a preferred embodiment, the SHC
distillate has a sufficient API gravity for incorporation into a
crude oil or synthetic crude oil obtained, for example, from tar
sands. Representative API gravity values are greater than about
20.degree. (e.g., from about 25.degree. to about 40.degree.) and
greater than about 35.degree. (e.g., from about 40.degree. to about
55.degree.).
[0029] In other embodiments, integration of the SHC process with
hydrotreating can involve, for example, passing an additional
refinery distillate stream, such as a straight-run distillate, to
the hydrotreating zone or reactor. Whether or not one or more
additional streams are hydrotreated in combination with the SHC
distillate, the hydrotreating is normally carried out in the
presence of a fixed bed of hydrotreating catalyst and a combined
recycle gas stream containing hydrogen. Typical hydrotreating
conditions include a temperature from about 260.degree. C.
(500.degree. F.) to about 426.degree. C. (800.degree. F.), a
pressure from about 7.0 MPa (1000 psig) to about 21 MPa (3000
psig), and a liquid hourly space velocity (LHSV) from about 0.1
hr.sup.-1 to about 10 hr.sup.-1. As is understood in the art, the
Liquid Hourly Space Velocity (LHSV, expressed in units of
hr.sup.-1) is the volumetric liquid flow rate over the catalyst bed
divided by the bed volume and represents the equivalent number of
catalyst bed volumes of liquid processed per hour. The LHSV is
closely related to the inverse of the reactor residence time.
Suitable hydrotreating catalysts comprise a metal selected from the
group consisting of nickel, cobalt, tungsten, molybdenum, and
mixtures thereof, on a refractory inorganic oxide support.
[0030] As discussed above, the SHC process is advantageously
integrated with refinery coking operations such as a delayed coker
or a fluidized coker, wherein a coker gas oil such as heavy coker
gas oil or coker VGO from delayed coking or fluidized coking is
passed to the SHC reaction zone for upgrading, thereby beneficially
suppressing coke formation in the SHC reactor. Another possibility
for additional SHC/coking integration involves further utilization
of an SHC pitch recovered from downstream separation and/or
fractionation of the SHC effluent or a higher boiling fraction or
cut of this effluent (e.g., a fraction having a higher initial
boiling point). A typical SHC pitch stream may be recovered, for
example, from the bottoms of an SHC vacuum column. According to a
particular embodiment, in which a higher-boiling SHC effluent
fraction is recovered as a bottoms stream exiting a hot high
pressure separator or an SHC atmospheric fractionator, vacuum
fractionation of this bottoms stream may be performed to yield the
SHC gas oil that is recycled to the SHC reactor and the heavier SHC
pitch stream. The SHC pitch may be passed to the coker (e.g.,
delayed coker or fluidized coker) for further integration of SHC
and coking, such that the coker is used to convert not only a
vacuum column bottoms residuum, but also the SHC pitch, thereby
obtaining additional higher-value products from this SHC product. A
typical SHC pitch will comprise or consist essentially of
hydrocarbons boiling at temperatures greater than about 482.degree.
C. (900.degree. F.), usually greater than about 538.degree. C.
(1000.degree. F.), and often greater than about 593.degree. C.
(1100.degree. F.).
[0031] The present invention therefore relates to overall refinery
flowschemes or processes for upgrading crude oil in the manner
discussed above, and especially such overall processes wherein
coker gas oil is part of the heavy hydrocarbon feedstock to an SHC
process. Due to the internal recycle of SHC gas oil and SHC pitch
in such overall flowschemes or processes, substantially all of the
net products are either distillates or coke, with little or no
production of low-value SHC gas oil and SHC pitch. According to
representative embodiments of the invention, the yields of
distillate products (e.g., a hydrotreated distillate as discussed
above) and coke account for at least 80% of the overall process
yields (e.g., from about 80% to about 99%), and often account for
at least 85% of these yields (e.g., from about 85% to about
95%).
[0032] Further aspects of the invention relate to utilizing the SHC
processes discussed above for making a synthetic crude oil or
synthetic crude oil blending component. The processes involve
passing a gas oil derived from a delayed coker or fluidized coker
to an SHC process, with optional integration of the process with a
hydrotreater as discussed above. Depending on the fractionation
conditions used for downstream processing of the SHC effluent, an
SHC distillate may be obtained having hydrocarbons essentially all
boiling in the distillate range or lower. In representative
embodiments, less than about 20% by weight, and often less than
about 10% by weight, of the SHC distillate are hydrocarbons boiling
at a temperature of greater than 343.degree. C. (650.degree. F.).
Such SHC processes may additionally be integrated with crude oil
fractionation columns, such that a straight-run distillate from a
crude oil atmospheric distillation column is hydrotreated together
the SHC distillate. Also, a VGO and/or vacuum residuum (or resid)
from the vacuum distillation column may be passed to the SHC
reactor or reaction zone (i.e., such that the VGO is part of the
heavy hydrocarbon feedstock, together with the recycled SHC gas oil
and coker gas oil).
[0033] A representative process flowscheme illustrating a
particular embodiment for carrying out the methods described above
is depicted in FIG. 1. FIG. 1 is to be understood to present an
illustration of the invention and/or principles involved. As is
readily apparent to one of skill in the art having knowledge of the
present disclosure, methods according to various other embodiments
of the invention will have configurations, components, and
operating parameters determined, in part, by the specific
feedstocks, products, and product quality specifications.
[0034] According to the embodiment illustrated in FIG. 1, a slurry
hydrocracking (SHC) reactor or reaction zone 20 is integrated into
a refinery flowscheme. The heavy hydrocarbon feedstock 1 to this
reaction zone 20 is a combination of a coker vacuum gas oil (VGO)
stream 2 from a delayed coking process 30 and an SHC VGO (e.g., SHC
heavy VGO) recycle stream 3. An additional component of heavy
hydrocarbon feedstock 1 to SHC process 20 is a vacuum column
residue stream (or resid) 4 from crude vacuum column or tower 40,
typically containing hydrocarbons boiling above (i.e., having a
cutpoint temperature) of about 566.degree. C. (1050.degree. F.). As
shown in FIG. 1, atmospheric column 80 generates atmospheric
residue or reduced crude stream 13, with a typical cutpoint
temperature of about 343.degree. C. (650.degree. F.) that is
fractionated in vacuum column 40.
[0035] Optionally, the heavy hydrocarbon feedstock 1 further
includes a VGO fraction 5a from vacuum column 40, which, for
example, contains hydrocarbons boiling in the range from about
343.degree. C. (650.degree. F.) to about 566.degree. C.
(1050.degree. F.). A portion of this VGO fraction 5a or a different
VGO fraction 5b from vacuum column 40 may optionally be fed
directly to distillate hydrotreating process 50. Another stream
optionally used as an incremental feedstock to hydrotreating
process 50 is straight-run distillate 11 obtained as a distillate
fraction of crude oil stream 12, fractionated in crude atmospheric
column or tower 80. A further stream which may be hydrotreated is a
portion of the SHC VGO recycle stream 3 from SHC fractionator 70 or
a different SHC VGO fraction 3a, such as light VGO that is a
lower-boiling fraction compared to SHC VGO recycle stream 3. Thus,
SHC distillate 7, optionally with any combination or all of streams
11, 5b, and/or 3a, is used to obtain hydrotreated distillate 14 as
a product of the overall process having reduced nitrogen compound
and sulfur compound impurities and/or an API gravity as discussed
above that may be utilized as a blending component for synthetic
crude oil.
[0036] The SHC process, including SHC reaction zone 20, is
therefore utilized in an integrated manner to upgrade VGO stream 2
from delayed coking process 30, which, as discussed above,
beneficially suppresses coke formation in the SHC reactor or
reaction zone. The total SHC effluent stream 6 is then subjected to
downstream separation/fractionation operations to recover upgraded
products, remove pitch, and recycle intermediates. According to the
embodiment illustrated in FIG. 1, total SHC effluent is separated
using hot high pressure separator (HHPS) 60 to recover SHC
distillate 7, generally boiling in a range above that of naphtha. A
higher-boiling fraction 8 recovered from SHC effluent and in
particular from the bottoms of HHPS 60 is then fractionated in SHC
fractionator 70, typically operating as a vacuum column. SHC
fractionator separates SHC VGO recycle stream 3 from SHC pitch
stream 9, which, as discussed above, is advantageously used as a
feedstock to delayed coker 30. Delayed coker 30 generates coke 10
and coker VGO stream 2 as a recycle stream (internal to the overall
process) that is a refinery gas oil component of heavy hydrocarbon
feedstock 1 to SHC process 20.
[0037] FIG. 2 depicts an alternative flowscheme that is a variation
of the embodiment depicted in FIG. 1, with the reference numbers of
FIG. 1 being used to represent similar process streams and
equipment shown in FIG. 2. According to this embodiment, a first
(e.g., atmospheric) SHC fractionator 60-A is used in place of HHPS
(reference number 60 in FIG. 1) to recover SHC distillate 7-A,
which is a side cut removed from first SHC fractionator 60-A, for
example having light ends (e.g., C.sub.4.sup.- hydrocarbon
products) in the total SHC effluent stream 6 removed. A higher
boiling fraction 8-A is removed as a bottoms product from first SHC
fractionator 60-A and then fractionated in a second (e.g., vacuum)
SHC fractionator 70, corresponding to fractionator 70 in FIG. 1.
The bottoms product may be fractionated in second vacuum
fractionator 70 to yield SHC VGO recycle stream 3, SHC pitch stream
9, and SHC VGO fraction 3a, which may be a lighter boiling
fraction, such as light VGO, compared to SHC VGO recycle stream
3.
[0038] As shown in FIG. 2, SHC pitch stream 9 is used as a
feedstock to a delayed coker and particularly coker fractionator
30-A. The coker fractionator bottoms product 16 is passed to one of
two coker drums 30-B using T-valve or switch valve 30-C. Coke 10 is
then removed and recovered coker liquid 15 is sent back to coker
fractionator 30-A, which is used to fractionate coker VGO 2, for
example as a heavy coker gas oil, and optionally one or more
lighter coker hydrocarbon products 17 such as a coker distillate
and/or coker naphtha that may be hydrotreated in hydrotreating
process 50 in combination with SHC distillate 7-A and optionally
other streams as mentioned above.
[0039] The overall processes illustrated in both FIG. 1 and FIG. 2,
in which an SHC process is integrated with a delayed coker,
therefore produces essentially the net products of coke 10 and
hydrotreated distillate 14. As is apparent from this description,
overall aspects of the invention are directed to the integration of
slurry hydrocracking (SHC) and coking to optimize refinery
operations. In view of the present disclosure, it will be seen that
several advantages may be achieved and other advantageous results
may be obtained. Those having skill in the art will recognize the
applicability of the methods disclosed herein to any of a number of
integrated SHC processes. Those having skill in the art, with the
knowledge gained from the present disclosure, will recognize that
various changes could be made in the above processes without
departing from the scope of the present disclosure.
* * * * *