Note: Descriptions are shown in the official language in which they were submitted.
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RESIDUE HYDROCRACKING PROCESSING
FIFLD OF THE DISCLOSURE
[0001] Embodiments disclosed herein relate generally to hydroconversion
processes,
including processes for hydrocracking residue and other heavy hydrocarbon
fractions.
More specifically, embodiments disclosed herein relate to solvent deasphalting
of a
residuum hydrocarbon feedstock, processing the resulting deasphalted oil in a
residue
desulfurization unit and a residue hydrocracking unit, and processing the
pitch from the
solvent deasphalting unit in a separate residue hydrocracking unit.
BACKGROUND
[0002] As the worldwide demand for gasoline and other distillate refinery
products such
as kerosene, jet and diesel has steadily increased, there has been a
significant trend
toward conversion of higher boiling compounds to lower boiling ones. To meet
the
increasing demand for distillate fuels, refiners have investigated various
reactions, such
as hydrocracking, residual desulfurization (RDS), and solvent deasphalting
(SDA), to
convert Residuum, Vacuum Gas Oil (VG0) and other heavy petroleum feedstocks to
jet
and diesel fuels.
[0003] Catalysts have been developed that exhibited excellent distillate
selectivity,
reasonable conversion activity and stability for heavier feedstocks. The
conversion
rates attainable by the various processes are limited, however. For example,
RDS units
alone can produce a I wt% sulfur fuel from high sulfur residues, but
conversions are
generally limited to about 35% to 40%. Others have proposed to use SDA units
to
solvent deasphalt the residuum feed and process the deasphalted oil only in a
Residuum
Hydrocracking Unit (RHU). Also, others have processed the unconverted vacuum
residuum from a RHU in an SDA unit and recycled the deasphalted oil (DA())
back to
the front end of the RHU. Still others have proposed to process the SDA pitch
directly
in a RHU. Nonetheless, economic processes to achieve high hydrocarbon
conversions
and sulfur removal are desired.
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SUMIVIARY
[0004] In one aspect, embodiments disclosed herein relate to a process for
upgrading
residuum hydrocarbons. The process may include the following steps: solvent
deasphalting a residuum hydrocarbon fraction to produce a deasphalted oil
fraction and
an asphalt fraction; contacting the asphalt fraction and hydrogen with a first
hydroconversion catalyst in a first ebullated bed hydroconversion reactor
system;
recovering an effluent from the first ebullated bed hydroconversion reactor
system;
fractionating the effluent from the first ebullated bed hydroconversion
reactor system to
recover one or more hydrocarbon fractions.
[0005] In another aspect, embodiments disclosed herein relate to a process
for upgrading
residuum hydrocarbons which may include the following steps: solvent
deasphalting a
residuum hydrocarbon fraction to produce a deasphalted oil fraction and an
asphalt
fraction; contacting the asphalt fraction and hydrogen with a first
hydroconversion
catalyst in a first ebullated bed hydroconversion reactor system; recovering
an effluent
from the first ebullated bed hydroconversion reactor system; fractionating the
effluent
from the first ebullated bed hydroconversion reactor system to recover one or
more
hydrocarbon fractions; contacting the deasphalted oil fraction and hydrogen
with a
second hydroconversion catalyst in a residue hydrodesulfurization unit;
recovering an
effluent from the residue hydrodesulfurization unit; contacting the residue
hydrodesulfurization unit effluent with a third hydroconversion catalyst in a
hydrocracking reactor system; recovering an effluent from the hydrocracking
reactor
system; and fractionating the effluent from the hydrocracking reactor system
to recover
one or more hydrocarbon fractions.
[0006] In another aspect, embodiments disclosed herein relate to a process
for upgrading
residuum hydrocarbons which may include the following steps: solvent
deasphalting a
residuum hydrocarbon fraction to produce a deasphalted oil fraction and an
asphalt
fraction; contacting the asphalt fraction and hydrogen with a first
hydroconversion
catalyst in a first ebullated bed hydroconversion reactor system; recovering
an effluent
from the first ebullated bed hydroconversion reactor system; fractionating the
effluent
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from the first ebullated bed hydroconversion reactor system to recover one or
more
hydrocarbon fractions; contacting the deasphalted oil fraction and hydrogen
with a
second hydroconversion catalyst in a residue hydrodesulfurization unit;
recovering an
effluent from the residue hydrodesulfurization unit; fractionating the
effluent from the
hydrocracking reactor system to recover one or more hydrocarbon fractions
including a
vacuum residua hydrocarbon fraction; contacting the vacuum residua hydrocarbon
fraction with a third hydroconversion catalyst in a hydrocracking reactor
system; and
recovering an effluent from the hydrocracking reactor system; fractionating
the effluent
from the hydrocracking reactor system to recover one or more hydrocarbon
fractions.
[0007] Other aspects and advantages will be apparent from the following
description and
the appended claims.
BRIEF DESCRIPTION OF DRAWINGS
[0008] Figure 1 is a simplified process flow diagram of a process for
upgrading residuum
hydrocarbon feedstocks according to embodiments disclosed herein.
[0009] Figure 2 is a simplified process flow diagram of a process for
upgrading residuum
hydrocarbon feedstocks according to embodiments disclosed herein.
[0010] Figure 3 is a simplified process flow diagram of a process for an
integrated
hydroprocessing reactor system to be used with a process for upgrading
residuum
hydrocarbon feedstocks according to embodiments disclosed herein.
[0011] Figure 4 is a simplified alternate process flow diagram of a process
for an
integrated hydroprocessing reactor system to be used with a process for
upgrading
residuum hydrocarbon feedstocks according to embodiments disclosed herein.
DETAILED DESCRIPTION
[0012] In one aspect, embodiments herein relate generally to
hydroconversion processes,
including processes for hydrocracking residue and other heavy hydrocarbon
fractions.
More specifically, embodiments disclosed herein relate to solvent deasphalting
of a
residuum hydrocarbon feedstock, processing the resulting deasphalted oil in a
residue
desulfurization unit and a residue hydrocracking unit, and processing the
pitch from the
solvent deasphalting in a separate residue hydrocracking unit.
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[0013]
Hydroconversion processes disclosed herein may be used for reacting
residuum hydrocarbon feedstocks at conditions of elevated temperatures and
pressures
in the presence of hydrogen and one or more hydroconversion catalyst to
convert the
feedstock to lower molecular weight products with reduced contaminant (such as
sulfur
and/or nitrogen) levels. Hydroconversion processes may include, for example,
hydrogenation, hydrodesulfurization,
hydrodenitrogenation, hydro cracking,
hydrodemetallization, hydroDeCCR or hydrodeaphaltenization, etc.
[0014] As used herein, residuum hydrocarbon fractions, or like terms
referring to
residuum hydrocarbons, are defined as a hydrocarbon fraction having boiling
points or a
boiling range above about 340 C but could also include whole heavy crude
processing.
Residuum hydrocarbon feedstocks that may be used with processes disclosed
herein
may include various refinery and other hydrocarbon streams such as petroleum
atmospheric or vacuum residua, deasphalted oils, deasphalter pitch,
hydrocracked
atmospheric tower or vacuum tower bottom, straight run vacuum gas oils,
hydrocracked
vacuum gas oils, fluid catalytically cracked (FCC) slurry oils, vacuum gas
oils from an
ebullated bed hydrocracking process, shale-derived oils, coal-derived oils,
tar sands
bitumen, tall oils, bio-derived crude oils, black oils, as well as other
similar
hydrocarbon streams, or a combination of these, each of which may be straight
run,
process derived, hydrocracked, partially desulfurized, and/or partially
demetallized
streams. In some embodiments, residuum hydrocarbon fractions may include
hydrocarbons having a normal boiling point of at least 480 C, at least 524 C,
or at least
565 C.
[0015] Referring now to Figure 1, a residuum hydrocarbon fraction
(residuum) 10 is
fed to a Solvent Deasphalting Unit (SDA) 12. In SDA 12, the residuum
hydrocarbon is
contacted with a solvent to selectively dissolve asphaltenes and similar
hydrocarbons to
produce a deasphalted oil (DAO) fraction 14 and a pitch fraction 15.
[0016] Solvent deasphalting may be performed in SDA 12, for example, by
contacting the residuum hydrocarbon feed with a light hydrocarbon solvent at
temperatures in the range from about 38 C to about 204 C and pressures in the
range
from about 7 barg to about 70 barg. Solvents useful in SDA 12 may include C3,
C4,
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C5, C6 and/or C7 hydrocarbons, such as propane, butane, isobutene, pentane,
isopentane, hexane, heptane, or mixtures thereof, for example. The use of the
light
hydrocarbon solvents may provide a high lift (high DA yield). In some
embodiments,
the DAD fraction 14 recovered from the SDA unit 12 may contain 500 wppm to
5000
wppm asphaltenes (i.e., heptane insoluble), 50 to 150 wppm metals (such as Ni,
V, and
others), and 5 wt% to 15 wt% Conradson Carbon Residue.
[0017] Pitch fraction 15 may then by mixed with a diluent 17, such as
SRVGO
(straight run vacuum gas oil) to produce a diluted pitch (residuum) fraction
19. Diluted
pitch fraction 19 and hydrogen 21 may then be fed to an ebullated bed reactor
system
42, which may include one or more ebullated bed reactors, where the
hydrocarbons and
hydrogen are contacted with a hydro conversion catalyst to react at least a
portion of the
pitch with hydrogen to form lighter hydrocarbons, demetallize the pitch
hydrocarbons,
remove Conradson Carbon Residue, or otherwise convert the residuum to useful
products.
[0018] Reactors in ebullated bed reactor 42 may be operated at
temperatures in the
range from about 380 C to about 450 C, hydrogen partial pressures in the range
from
about 70 bara to about 170 bara, and liquid hourly space velocities (LHSV) in
the range
from about 0.2 III to about 2.0 h-1. Within the ebullated bed reactors, the
catalyst may
be back mixed and maintained in random motion by the recirculation of the
liquid
product. This may be accomplished by first separating the recirculated oil
from the
gaseous products. The oil may then be recirculated by means of an external
pump, or,
as illustrated, by a pump having an impeller mounted in the bottom head of the
reactor.
[0019] Target conversions in ebullated bed reactor system 42 may be in
the range
from about 40 wt% to about 75 wt%, depending upon the feedstock being
processed. In
any event, target conversions should be maintained below the level where
sediment
fotmation becomes excessive and thereby prevent continuity of operations. In
addition
to converting the residuum hydrocarbons to lighter hydrocarbons, sulfur
removal may
be in the range from about 40 wt% to about 80 wt%, metals removal may be in
the
range from about 60 wt% to 85 wt% and Conradson Carbon Residue (CCR) removal
may be in the range from about 30 wt% to about 65 wt%.
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[0020] Following conversion in ebullated bed reactor system 42, the
partially
converted hydrocarbons may be recovered via flow line 44 as a mixed vapor /
liquid
effluent and fed to a fractionation system 46 to recover one or more
hydrocarbon
fractions. As illustrated, fractionation system 46 may be used to recover an
offgas 48
containing light hydrocarbon gases and hydrogen sulfide (H2S), a light naphtha
fraction
50, a heavy naphtha fraction 52, a kerosene fraction 54, a diesel fraction 56,
a light
vacuum gas oil fraction 58, a heavy gas oil fraction 60, and a vacuum residuum
fraction
62. In some embodiments, vacuum residuum fraction 62 may be recycled for
further
processing, such as to SDA unit 12, ebullated bed reactor system 42, or other
reaction
units 16, 20 discussed below. In other embodiments, vacuum residuum fraction
62 may
be blended with a cutter fraction 66 to produce a fuel oil.
[0021] Fractionation system 46 may include, for example, a high pressure
high
temperature (HP/HT) separator to separate the effluent vapor from the effluent
liquids.
The separated vapor may be routed through gas cooling, purification, and
recycle gas
compression, or may be first processed through an Integrated Hydroprocessing
Reactor
System (which may include one or more additional hydroconversion reactors),
alone or
in combination with external distillates and/or distillates generated in the
hydrocracking
process, and thereafter routed for gas cooling, purification, and compression.
[0022] The separated liquid from the HP/HT separator may be flashed and
routed to
an atmospheric distillation system along with other distillate products
recovered from
the gas cooling and purification section. The atmospheric tower bottoms, such
as
hydrocarbons having an initial boiling point of at least about 340 C, such as
an initial
boiling point in the range from about 340 C to about 427 C, may then be
further
processed through a vacuum distillation system to recover vacuum distillates.
[0023] The vacuum tower bottoms product, such as hydrocarbons having an
initial
boiling point of at least about 480 C, such as an initial boiling point in the
range from
about 480 C to about 565 C, may then be routed to tankage after cooling, such
as by
direct heat exchange or direct injection of a portion of the residuum
hydrocarbon feed
into the vacuum tower bottoms product.
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[0024] In some
embodiments, the fuel oil fraction 62 recovered following processing
in ebullated bed reactor system 42 and fractionation system 46 may have a
sulfur
content of 2.25 wt% or less; 2.0 wt% or less in other embodiments; and 1.75
wt% or
less in yet other embodiments.
[0025] The deasphalted oil fraction 14 recovered from SDA unit 12 may
be optionally
heated, combined with a hydrogen rich gas 23, and fed to a residue
desulfurization
(RDS) unit 16. RDS unit 16 may include one or more residue desulfurization
reactors.
[0026] In some embodiments, RDS unit 16 may include one or more upflow
reactors
(UFR) (not illustrated) upstream of the RDS reactors. The DAD feed may be
mixed
with the hydrogen rich gas 23 upstream of the reactors or with the feed
entering the
bottom of the UFRs (s), and in some embodiments with the effluent recovered
from the
UFRs. The UFR may help to increase the catalyst life in the downstream RDS
catalyst
beds, as well as remove some sulfur, Conradson Carbon Residue, and asphaltenes
in the
feed.
[0027] Operating conditions in the RDS unit 16, including the UFRs
and/or RDS
reactors, may include temperatures in the range from about 360 C to about 400
C and
hydrogen partial pressures ranging from about 70 barg to about 170 barg. The
RDS
may achieve a desulfurization rate of at least 70 wt% in some embodiments, at
least 80
wt% in other embodiments, and up to or above 92 wt% in yet other embodiments.
[0028] Effluent 18, recovered from the RDS unit 16, may then be further
processed in a
hydrocracking reactor system 20, which may include one or more hydrocracking
reactors, arranged in series or parallel.
[0029] In reactor system 20, the RDS effluent may be hydrocracked under
hydrogen
partial pressures in the range from about 70 bara to about 170 bara,
temperatures in the
range from about 380 C to about 450 C, and LHSV in the range from about 0.2 h-
1 to
about 2.0 h-1 in the presence of a catalyst. In some embodiments, operating
conditions
in hydrocracking reactor system 20 may be similar to those described above for
ebullated bed reactor system 42. In other embodiments, such as where
hydrocracking
reactor system 20 includes one or more ebullated bed reactors, the ebullated
bed
reactors may be operated at higher severity conditions than those in reactor
system 42,
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higher severity referring to a higher temperature, a higher pressure, a lower
space
velocity or combinations thereof
[0030] Depending on the vacuum residuum feedstock properties, the
extent to which
metals and Conradson Carbon Residue are removed in the RDS unit 16, and the
SDA
solvent used, the DA recovered may be treated in a fixed bed reaction system
or an
ebullated bed reactor system 20, as illustrated, which may be similar to that
described
above for ebullated bed reactor system 42 with respect to gas / liquid
separations and
catalyst recirculation, among other similarities. A fixed bed reactor system
may be used,
for example, where the metals and Conradson Carbon Residue content of the DA0
is
less than 80 wppm and 10 wt%, respectively, such as less than 50 wppm ad 7
wt%,
respectively. An ebullated bed reactor system may be used, for example, when
the
metals and Conradson Carbon Residue contents are higher than those listed
above for
the fixed bed reactor system. In either hydrocracking reactor system, the
number of
reactors used may depend on the charge rate, the overall target residue
conversion level,
and the level of conversion attained in RDS unit 16, among other variables. In
some
embodiments, one or two hydrocracking reactors may be used in hydrocracking
reactor
system 20.
[0031] Following conversion in hydrocracking reactor system 20, the
partially
converted hydrocarbons may be recovered via flow line 22 as a mixed vapor /
liquid
effluent and fed to a fractionation system 24 to recover one or more
hydrocarbon
fractions. As illustrated, fractionation system 24 may be used to recover an
offgas 26, a
light naphtha fraction 28, a heavy naphtha fraction 30, a kerosene fraction
32, a diesel
fraction 34, a light vacuum gas oil fraction 36, a heavy vacuum gas oil
fraction 38, and
a vacuum resid fraction 40. In some embodiments, vacuum resid fraction 40 may
be
recycled for further processing. In other embodiments, vacuum resid fraction
40 may
be blended with a cutter fraction 64 to produce a fuel oil.
[0032] Fractionation system 24 may include, for example, a high
pressure high
temperature (HP/HT) separator to separate the effluent vapor from the effluent
liquids.
The separated vapor may be routed through gas cooling, purification, and
recycle gas
compression, or may be first processed through an Integrated Hydroprocessing
Reactor
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System (IHRS) which may include one or more additional hydroconversion
reactors,
alone or in combination with external distillates and/or distillates generated
in the
hydrocracking process and thereafter routed for gas cooling, purification, and
compression.
[0033] The separated liquid from the I1P/IIT separator may be flashed
and routed to
an atmospheric distillation system along with other distillate products
recovered from
the gas cooling and purification section. The atmospheric tower bottoms, such
as
hydrocarbons having an initial boiling point of at least about 340 C, such as
an initial
boiling point in the range from about 340 C to about 427 C, may then be
further
processed through a vacuum distillation system to recover vacuum distillates.
[0034] The vacuum tower bottoms product, such as hydrocarbons having an
initial
boiling point of at least about 480 C, such as an initial boiling point in the
range from
about 480 C to about 565 C, may then be routed to tankage after cooling, such
as by
direct heat exchange or direct injection of a portion of the residuum
hydrocarbon feed
into the vacuum tower bottoms product.
[0035] Overall conversion of the DA0 fraction through the RDS unit 16
and the
hydrocracking reaction system 20 may be in the range from about 75 wt% to
about 95
wt%, such as in the range from about 85 wt% to about 90 wt%.
[0036] In some embodiments, the fuel oil fraction 40 recovered following
processing
in RDS unit 16, hydrocracking reactor system 20 and fractionation system 24
may have
a sulfur content of 1.25 wt% or less; 1.0 wt% or less in other embodiments;
and 0.75
wt% or less in yet other embodiments.
[0037] Catalysts useful in the RDS reactors, the URFs , and the
ebullated bed reactors
may include any catalyst useful for the hydrotreating or hydrocracking of a
hydrocarbon
feedstock. A hydrotreating catalyst, for example, may include any catalyst
composition
that may be used to catalyze the hydrogenation of hydrocarbon feedstocks to
increase
its hydrogen content and/or remove heteroatom contaminants. A hydrocracking
catalyst, for example, may include any catalyst composition that may be used
to
catalyze the addition of hydrogen to large or complex hydrocarbon molecules as
well as
the cracking of the molecules to obtain smaller, lower molecular weight
molecules.
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[0038]
Hydroconversion catalyst compositions for use in the hydroconversion process
according to embodiments disclosed herein are well known to those skilled in
the art
and several are commercially available from W.R. Grace & Co., Criterion
Catalysts &
Technologies, and Albemarle, among others. Suitable hydroconversion catalysts
may
include one or more elements selected from Groups 4-12 of the Periodic Table
of the
Elements. In some embodiments, hydroconversion catalysts according to
embodiments
disclosed herein may comprise, consist of, or consist essentially of one or
more of
nickel, cobalt, tungsten, molybdenum and combinations thereof, either
unsupported or
supported on a porous substrate such as silica, alumina, titania, or
combinations thereof.
As supplied from a manufacturer or as resulting from a regeneration process,
the
hydroconversion catalysts may be in the form of metal oxides, for example. In
some
embodiments, the hydroconversion catalysts may be pre-sulfided and/or pre-
conditioned prior to introduction to the hydrocracking reactor(s).
[0039] Distillate hydrotreating catalysts that may be useful include
catalyst selected from
those elements known to provide catalytic hydrogenation activity. At least one
metal
component selected from Group 8-10 elements and/or from Group 6 elements is
generally chosen. Group 6 elements may include chromium, molybdenum and
tungsten.
Group 8-10 elements may include iron, cobalt, nickel, ruthenium, rhodium,
palladium,
osmium, iridium and platinum. The amount(s) of hydrogenation component(s) in
the
catalyst suitably range from about 0.5% to about 10% by weight of Group 8-10
metal
component(s) and from about 5% to about 25% by weight of Group 6 metal
component(s), calculated as metal oxide(s) per 100 parts by weight of total
catalyst,
where the percentages by weight are based on the weight of the catalyst before
sulfiding. The hydrogenation components in the catalyst may be in the oxidic
and/or the
sulphidic form. If a combination of at least a Group 6 and a Group 8 metal
component is
present as (mixed) oxides, it will be subjected to a sulfiding treatment prior
to proper
use in hydrocracking. In some embodiments, the catalyst comprises one or more
components of nickel and/or cobalt and one or more components of molybdenum
and/or
tungsten or one or more components of platinum and/or palladium. Catalysts
containing
nickel and molybdenum, nickel and tungsten, platinum and/or palladium are
useful.
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100401 Residue hydrotreating catalysts that may be useful include catalysts
generally
composed of a hydrogenation compotant, sclectott front Group ti elements (such
as
molybdenum and/or tungsten) and Croup 11-10 elements' (such as cobalt and/or
nickel),
or a mixture thereof, which may be supported on an alumina support.
Phosphorous
((Stoup 15) oxide is optionally present as an active ingredient. A typical
catalyst may
contain from 3 to 35 wt % hydrogenation components, with an alumina. biader.
The
catalyst pellets may range in sire from 1/32 inch to liS inch, and may be of a
spherical,
extruded. trilobata or quacirilotiale shape. in some embodiments, tlat. Iced
pausing
though the catalyst zone contacts tint A catalyst presclectod for metals
removal, though
some sulfur, nitrogen and aromatics removal may a:so occur. Subsequent
catalyst layers
may he used for sulfur end nitrogen retrieval, though they would also he
expected to
catalyze the removal of :11CIII14 and/or cracking reactions. Catalyst
layer(ii) for
&metallization, when ptesent, stay comprise eatalyst(s) having an average pore
size
ranging limn 125 to 225 Angstroms and a 1101:C volume ranging from 0.5-1.1
Catalyst layer(s) ror denitrogertationkicsulliirizatioa may comprise
catalyst(s) having Sr
average pore size ranging from 100 to 191) Angstroms with a pore volume of 0.5-
1.1
creg. U.S. Pat. No. 4,990,243 describes a hydrotreating catalyst having a pore
mice of
at ;cast about 60 Angstroms, and preferably from about 75 Angstroms to about
125
Angstroms. A &metallization catalyst useful 11.m the present process is
described. for
example, in US. Pat. Nn. 4,976,848. Likewise, catalysts useful for
desulfurization
of heavy streams are described, ter example, in U.S. Pat. NOS, 5,215,955 and
5.177,047. Catalysts useful for desulfurization of middle distillate, vacuum
gas
oil streams and naphtha streams are described, for example, in U.S. Pat. No.
4.990,243.
100411 Useful residue hydrotreating catalysts include catalysts having a
porous refractory
base made up of alumina, silica, phosphorous, or various combinations of
these. One or
more types of catalysts may he used as residisc hydratroating catalyst, and
where Iwo or
more catalysts are used, the catalysts may Isst present ill thu reactor zone
as layers. The
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catalysts in the lower layer(s) may have good demetallization activity. The
catalysts
may also have hydrogenation and desulfurization activity, and it may be
advantageous
to use large pore size catalysts to maximize the removal of metals. Catalysts
having
these characteristics are not optimal for the removal of Conradson Carbon
Residue and
sulfur. The average pore size for catalyst in the lower layer or layers will
usually be at
least 60 Angstroms and in many cases will be considerably larger. The catalyst
may
contain a metal or combination of metals such as nickel, molybdenum, or
cobalt.
Catalysts useful in the lower layer or layers are described in U.S. Pat. Nos.
5,071,805
5,215,955, and 5,472,928. For example, those catalysts as described in U.S.
Patent No.
5,472,928 and having at least 20% of the pores in the range of 130 to 170
Angstroms,
based on the nitrogen method, may be useful in the lower catalysts layer(s).
The
catalysts present in the upper layer or layers of the catalyst zone should
have greater
hydrogenation activity as compared to catalysts in the lower layer or layers.
Consequently catalysts useful in the upper layer or layers may be
characterized by
smaller pore sizes and greater Conradson Carbon Residue removal,
denitrogenation and
desulfurization activity. Typically, the catalysts will contain metals such
as, for
example, nickel, tungsten, and molybdenum to enhance the hydrogenation
activity. For
example, those catalysts as described in U.S. Patent No. 5,472,928 and having
at least
30% of the pores in the range of 95 to 135 Angstroms, based on the nitrogen
method,
may be useful in the upper catalysts layers. The catalysts may be shaped
catalysts or
spherical catalysts. In addition, dense, less friable catalysts may be used in
the upflow
fixed catalyst zones to minimize breakage of the catalyst particles and the
entrainment
of particulates in the product recovered from the reactor.
[0042] One skilled in the art will recognize that the various catalyst
layers may not be
made up of only a single catalyst type, but may be composed of an
inteinfixture of
different catalyst types to achieve the optimal level of metals or Conradson
Carbon
Residue removal and desulfurization for that layer. Although some
hydrogenation will
occur in the lower portion of the zone, the removal of Conradson Carbon
Residue,
nitrogen, and sulfur may take place primarily in the upper layer or layers.
Obviously
additional metals removal also will take place. The specific catalyst or
catalyst mixture
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selected for each layer, the number of layers in the zone, the proportional
volume in the
bed of each layer, and the specific hydrotreating conditions selected will
depend on the
feedstock being processed by the unit, the desired product to be recovered, as
well as
commercial considerations such as cost of the catalyst. All of these
parameters are
within the skill of a person engaged in the petroleum refining industry and
should not
need further elaboration here.
[0043] Referring now to Figure 2, where like numerals represent like
parts, a
simplified flow diagram of a process for upgrading residuum hydrocarbon
feedstocks
according to embodiments disclosed herein is illustrated. As described above
with
respect to Figure 1, the residuum hydrocarbon feedstock 10 is processed
through SDA
unit 12, and the resulting pitch fraction is processed in ebullated bed
reactor system 42
and fractionation system 46. Deasphalted oil fraction 14 may be combined with
a
hydrogen rich gas 23 and fed to RDS unit 16, which may include one or more
residue
desulfurization reactors.
[0044] Effluent 18 recovered from RDS unit 16 may then be processed in a
fractionation system 24 to produce one or more hydrocarbon fractions 26, 28,
and 38,
among others, as well as a vacuum residua fraction 40. The vacuum residua
fraction 40
and optionally one or more of additional heavier hydrocarbon fractions
recovered in
fractionation system 24 may then be fed to a hydrocracking reactor system 20
to
produce additional distillate range hydrocarbons. Following conversion in
reaction
system 20, effluent 22 may be fractionated to recover various distillate
hydrocarbon
fractions. In some embodiments, effluent 22 may be fractionated along with
effluent 18
in fractionation system 24 (as illustrated) or a combined fractionation system
processing
effluents 18 and 44.
[0045] By advantageously combining SDA and RDS with ebullated bed
hydrocracking reactors, for example, the conversion of the DA0 fraction can be
increased to very high levels, such as 85 wt% to 90 wt%, while still producing
a 1 wt%
sulfur stable fuel oil, even when processing high sulfur containing residues,
such as
those having up to or greater than 6.5 wt% sulfur. The processing of SDA pitch
in a
separate reaction / separation train may allow the production of a 2 wt%
sulfur stable
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fuel oil while converting 40 wt% to 65 wt% of the pitch to atmospheric and
vacuum
distillate boiling range materials. The resulting combined overall conversion
from both
processing trains may be in the range from about 55 wt% or 60 wt% to as high
as about
95 wt% or more, such as in the range from about 65 wt% to about 85 wt%.
Further,
such conversions may be advantageously achieved without sediment formation
that
could otherwise cause plugging and intettnittent operation.
[0046] Example
[0047] In the following example, a 40 k BPSD of Arabian Heavy vacuum
residue is
first processed in an SDA unit at a 73 vol% lift. The resulting properties of
the DAO
and SDA pitch are summarized in Table 1. The DAO, containing 4.27 wt% sulfur,
10
wt% CCR and 47 wppm Ni + V, is then processed in an RDS unit so as to reduce
the
sulfur content of the feed by 85 to 87 wt%. Concurrently the residue fraction
in the feed
is converted 35 to 45%. In this example the RDS effluent is then hydrocracked
in single
ebullated bed reactor, which is close coupled to the RDS reactors, increasing
the overall
conversion to 85 vol% and overall BIDS to 91.8 wt%. It is estimated that the
resulting
unconverted oil (UCO) has a sulfur content and API gravity of approximately
1.0 wt%
and 11.9 , respectively. It is envisaged the UCO from this reaction system
will meet the
low sulfur fuel oil specifications without any additional cutterstock
addition. The
overall space velocity required to achieve this level of conversion and
desulfurization is
estimated to be about 0.2 hr-1.
Table 1
DAO & SDA Pitch Properties
Properties VR Feed DAO SDA Pitch
Feed rate, kBPSD 40.0 29.2 10.8
API Gravity 4.81 10.58 -8.68
Specific Gravity 1.0381 0.9959 1.1521
Sulfur, wt% 5.2 4.27 7.37
Nitrogen, wt% 0.40 0.25 0.75
Oxygen, wt% 0.12 0.09 0.19
CCR, wt% 25 10 60
Ni+ V, wppm 270 47 790
565 C-,vol% 10 13.7
565 C+, vol% 90 86.3 100
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[0048] Fifty-five (55) vol% of the SDA pitch is then also converted a
separate
ebullated bed reactor system, containing a single reactor, operating in
parallel with the
RDS and hydrocracking reactors, producing a medium sulfur vacuum residue which
contains 2.6 wt% sulfur. After cutterstock addition, the resulting fuel oil
will contain
less than 2 wt% sulfur and more than likely less than 1.5 wt% sulfur,
depending on the
fuel oil blending components. The reactor space velocity for the pitch
conversion unit is
estimated to be about 0.25 1-1-1, resulting in an overall space velocity for
the RDS plus
DA0 hydrocracking reactor and the pitch conversion reactor of 0.22 III.
[0049] The resulting overall conversion for this configuration is 75
vol%, producing
approximately 12,096 BPSD of diesel, 12,332 BPSD of hydrocracker or FCC feed,
4,056 BPSD of LS fuel oil and 4,760 BPSD of medium sulfur vacuum residue. The
overall yields and product properties for this processing configuration are
provided in
Table 2.
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Table 2
Residue Hydrocracking Process
Overall Yields and Properties
Feed Wt% Vol % Sp. API S, N, CCR, V, Ni,
Gr. wt% wt% wt% wppm wppm
360-565 9.3 10.0 0.9659 15.00 3.75 0.20 0.50 1 0.5
565 C+ 90.7 90.0 1.046 3.770 5.35 0.42 27.51 226
72
Total 100.0 100.0 1.038 4.815 5.2 0.40 25 205 65
Overall Product Yields & Properties _____________________________
Products Wt% Vol % Sp. API S, N, CCR, V. Ni,
Gr. wt% wt% wt% wppm wppm
112S 4.75
NH3 0.22
1120 0.09
Cl 1.17
C2 1.04
C3 1.51
C4 1.44 2.57 0.584
C5-145C 11.08 15.73 0.7313 61.99 0.04 0.02
145-370C 30.24 36.46 0.8608 32.89 _ 0.23 0.07
370-565C 28.00 30.83 0.9428 18.59 0.85 0.24 0.5 1 <1
LS Resid 9.64 10.14 0.9868 11.90 1.02 0.27 15.5 18
13.2
(565 C+)
MS Resid 12.91 11.90 1.1262 -5.86 2.60 0.73 53.4 164
111
(565 C+)
Total 102.09 107.63
C5+ 91.87 105.06 0.9077 24.39 0.8119 0.2292
C4+ 93.31 107.63 0.8999 25.73 0.7993 0.2256
Chemical 1425.98
H2S Cons
Overall Removals, wt%
HDS 85.9
EIDN 45.4
CCR 65.9
Vanadium 88.7 ___________________________________________________
Nickel 75.6
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[0050] Figures 3 and 4 illustrate two embodiments for the IHRS and are
described
below, however other embodiments will be obvious to those skilled in the art
as being
possible. Figure 3 describes an embodiment where the IHRS is installed
downstream of
the ebullated bed reactor system 42. Figure 4 illustrates an embodiment where
the
IHRS is installed downstream of the hydrocracking reactor system 20.
[0051] As shown in Figure 3, the effluent stream 44 from ebullated bed
hydroprocessing reactor 42 may be cooled in a heat exchanger (not shown) and
fed to a
HP/HT V/L separator 81 where a vapor stream including the light products and
distillates boiling below about 1000 F normal boiling point and a liquid
stream
including unconverted residuum may be separated and processed separately in
downstream equipment. A vapor stream 67 may be fed to a fixed-bed
hydroprocessing
reactor 86 to carry out hydrotreating, hydrocracking or a combination thereof.
An
effluent stream 68 from the IHRS fixed-bed reactor system 86 is fed to a
fractionation
system 147 which recovers an offgas stream 48, light hydrotreated or
hydrocracked
naphtha stream 50, heavy hydrotreated or hydrocracked naphtha stream 52,
hydrotreated or hydrocracked kerosene stream 54, hydrotreated or hydrocracked
diesel
stream 56, as described above. The liquid stream 63 may be cooled in a heat
exchanger
(not shown) and depressurized in a pressure letdown system (not shown) before
being
fed to a vacuum fractionation system 72 which recovers a light hydrotreated or
hydrocracked VG0 stream 58, a heavy hydrotreated or hydrocracked VGO stream 60
and an unconverted vacuum residuum stream 62. In some embodiments, the vacuum
tower bottoms product stream, such as hydrocarbons having an initial boiling
point of at
least about 480 C, such as an initial boiling point in the range from about
480 C to
about 565 C, may be routed to tankage after cooling, such as by direct heat
exchange or
direct injection of a portion of the residuum hydrocarbon feed into the vacuum
tower
bottoms product.
[0052] As shown in Figure 4, in an alternate IHRS flow scheme, the
effluent stream
22 from the ebullated bed reactor system 20 may be cooled in a heat exchanger
(not
shown) and fed to a HP/HT V/L separator 181 where a vapor stream including the
light
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products and distillates boiling below about 1000 F normal boiling point and a
liquid
stream including unconverted residuum may be separated and processed
separately in
downstream equipment. A vapor stream 167 is fed to a fixed-bed hydroproccssing
reactor 186 to carry out hydrotreating, hydrocracking or a combination thereof
An
effluent stream 168 from the IHRS fixed-bed reactor system 186 may be fed to
an
atmospheric fractionation system 146 which recovers an offgas stream 26, light
hydrotrcated or hydrocracked naphtha stream 28, heavy hydrotreated or
hydrocracked
naphtha stream 30, hydrotreated or hydrocracked kerosene stream 32,
hydrotreated or
hydrocracked diesel stream 34. A liquid stream 163 is cooled in a heat
exchanger (not
shown) and depressurized in a pressure letdown system (not shown) and may he
fed to a
vacuum fractionation system 172 which recovers a light hydrotreated or
hydrocracked
VG0 stream 36, a heavy hydrotreated or hydrocracked VG0 stream 38 and an
unconverted vacuum residuum stream 40. In some embodiments, the vacuum tower
bottoms product stream, such as hydrocarbons having an initial boiling point
of at least
about 480 C, such as an initial boiling point in the range from about 480 C to
about
565 C, may then be routed to tankage after cooling, such as by direct heat
exchange or
direct injection of a portion of the residuum hydrocarbon feed into the vacuum
tower
bottoms product.
100531 While described
above with respect to two separate fractionation systems 24,
46, embodiments disclosed herein also contemplate fractionating the effluents
22, 44 in
a common fractionation system. For example, the effluents may be fed into a
common
gas cooling, purification, and compression loop before further processing in
an
atmospheric tower and a vacuum tower as described above. The use of a combined
separation scheme may provide for a reduced capital investment, when desired,
but may
result in the production of a single fuel oil fraction having a sulfur level
intermediate
those achieved by separate processing. The combined separation scheme may also
be
used along with the 1HRS being installed downstream of both the ebullated bed
reactor
system 42 and the hydrocracking reactor system 20 and being fed by the
combined
effluents 22, 44.
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[0054] As
described above, embodiments disclosed herein effectively integrate SDA
and RDS with residue hydrocracking, extending the residue conversion limits
above
those which can be attained by residue hydrocracking alone. Further, the
higher
conversions may be attained using less catalytic reactor volume as compared to
other
schemes proposed to achieve similar conversions. As a result, embodiments
disclosed
herein may provide comparable or higher conversions but requiring a lower
capital
investment. Further, embodiments disclosed herein may be used to produce a
fuel oil
having less than 1 wt% sulfur from a high sulfur containing residue feed while
maximizing overall conversion.
[0055] Advantageously, the initial SDA may allow the hydrocracking of
the pitch to be
operated at relatively high temperatures and space velocities, without the
tendency to
form excessive sediments, by limiting conversion. The hydrocracking of the DAO
may
also be performed at relatively high temperatures and space velocities, as the
DA0 may
have a very low asphaltene content. As a result, the overall processing
schemes
disclosed herein may be performed using low reactor volumes while still
achieving high
conversions. Likewise, other resulting advantages may include: reduced
catalyst
consumption rates due to rejecting metals in the asphalt from the SDA unit;
reduced
capital investment; and elimination or significant reduction in the need for
injection of
slurry oil upstream of the ebullated bed reactors, among other advantages.
[0056] While the disclosure includes a limited number of embodiments,
those skilled in
the art, having benefit of this disclosure, will appreciate that other
embodiments may be
devised which do not depart from the scope of the present disclosure.
Accordingly, the
scope should be limited only by the attached claims.
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