Note: Descriptions are shown in the official language in which they were submitted.
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
1
FIXED BED HYDROPROCESSING OF DEASPHALTER ROCK
FIELD
[0001] Systems and methods are provided for processing of difficult
refinery
streams, such as rock from a deasphalting unit.
BACKGROUND
[0002] One of the challenges in making effective use of the full range of a
crude oil
is processing of the vacuum resid portion of a crude oil. Processing of resid
feeds in a
fixed bed process can lead to poor catalyst lifetime and/or processing unit
run length if
substantial conversion is performed on the 1050 F+ portion of the feed. The
problems
with coking of catalyst and reactor run length can be mitigated by use of
ebullating bed
or other fluidized bed technologies. However, such fluidized bed processing
methods
can present substantial additional challenges relative to fixed bed
hydroprocessing.
[0003] U.S. Patent No. 7,279,090 describes a method for deasphalting a
vacuum
resid feed and processing the deasphalter rock using an ebullating bed
reactor. The
examples report 65% to 70% conversion of the deasphalter rock processed in the
ebullating bed reactor. The deasphalted oil can be processed either in a fixed
bed reactor
or an ebullating bed reactor.
SUMMARY
[0004] In an aspect, a method for fixed bed processing of deasphalter rock
is
provided, comprising: performing solvent deasphalting on a resid feedstock to
form a
deasphalter rock fraction and a deasphalted oil fraction, the resid feedstock
having a T10
distillation point of at least about 650 F (-343 C), the deasphalter rock
fraction
comprising at least about 10 wt% of the resid feedstock; and exposing a
feedstock
comprising at least a portion of the deasphalter rock fraction to a fixed bed
of
hydroprocessing catalyst under hydroprocessing conditions effective for
conversion of at
least 40 wt% of the at least a portion of the deasphalter rock relative to a
conversion
temperature of 1050 F (566 C) to form a hydroprocessed effluent, the feedstock
comprising at least about 10 wt% of the at least a portion of the deasphalter
rock, or at
least about 20 wt%, or at least about 30 wt%, or at least about 40 wt%, or at
least about
50 wt%.
[0005] In another aspect, a method for fixed bed processing of deasphalter
rock is
provided, comprising: exposing a feedstock comprising deasphalter rock and a
co-feed
comprising a catalytic slurry oil, a lubes extract, a heavy coker gas oil, a
vacuum gas oil
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
2
derived from a heavy oil, or a combination thereof, to a fixed bed of
hydroprocessing
catalyst under hydroprocessing conditions effective for conversion of at least
40 wt% of
the deasphalter rock relative to a conversion temperature of 1050 F (566 C) to
form a
hydroprocessed effluent, the feedstock comprising at least about 20 wt% of the
co-feed,
the feedstock comprising at least about 10 wt% of the deasphalter rock, or at
least about
20 wt%, or at least about 30 wt%, or at least about 40 wt%, or at least about
50 wt%.
BRIEF DESCRIPTION OF THE FIGURES
[0006] FIG. 1 shows an example of a reaction system for fixed bed
processing a
deasphalter rock feed.
[0007] FIG. 2 shows results from processing deasphalter rock with an
aromatic
solvent.
[0008] FIG. 3 shows results from processing deasphalter rock with an
aromatic
solvent.
[0009] FIG. 4 shows an example of a reaction system for integrating fixed
bed
processing a deasphalter rock feed with a fluid catalytic cracking process.
DETAILED DESCRIPTION
[0010] In various aspects, systems and methods are provided for fixed bed
hydroprocessing of deasphalter rock. Instead of attempting to process vacuum
resid in a
fixed bed processing unit, vacuum resid is deasphalted to form a deasphalted
oil and
deasphalter residue or rock. The rock can then be hydroprocessed in a fixed
bed reaction
zone, optionally after combining the rock with a co-feed and/or a
hydroprocessing
solvent, such as an aromatic petroleum fraction.
[0011] Processing deasphalter rock in the presence of an aromatic petroleum
fraction
can be in contrast to processing the deasphalter rock in the presence of the
deasphalted
oil that was separated from the resid to form the rock (i.e., processing the
vacuum resid
without deasphalting). In contrast to the co-feeds and/or solvents according
to the
invention, hydroprocessing of a whole vacuum resid (deasphalted oil plus rock)
can tend
to result in an increase in IN during processing. As a result, at processing
conditions
severe enough to convert more than about 35%-50% of the resid, the SBN of the
partially
processed resid can become comparable to the IN, leading to asphaltene
precipitation
and/or coke formation in a fixed bed environment.
[0012] More generally, it is conventionally understood that conversion of
1050 F+
(566 C+) vacuum resid fractions by hydroprocessing and/or hydrocracking is
limited by
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
3
incompatibility. Under conventional understanding, at somewhere between 30 wt%
and
55 wt% conversion of the 1050 F+ portion, it is conventionally believed that
the reaction
product becomes incompatible with the feed. For example, as the 1050 F+ (566
C+)
feedstock converts to 1050 F- (566 C-) products, hydrogen transfer,
oligomerization,
and dealkylation reactions can occur which create molecules that are
increasingly
difficult to keep in solution. Somewhere between 30 wt% and 55 wt% 1050 F+
(566 C+) conversion, a second liquid hydrocarbon phase separates. This
new
incompatible phase is believed to be mostly polynuclear aromatics rich in N,
S, and
metals. The new incompatible phase can also be high in micro carbon residue
(MCR).
The new incompatible phase can stick to surfaces in the unit where it cokes
and then can
foul the equipment. Based on the above conventional understanding, it would be
expected that hydroprocessing of a feed containing at least about 40 wt%
deasphalter
rock, or at least about 50 wt%, or at least about 60 wt%, would cause
incompatibility as
the 1050 F+ (566 C+) material is converted to compounds boiling below 1050 F
(566 C).
[0013]
Another conventional alternative can be to perform solvent deasphalting on a
vacuum resid to form a deasphalted oil and deasphalter rock. The vacuum resid
can then
be hydroprocessed, while the deasphalter rock is used as a feed for a coker.
Coking of
the rock can tend to lead to relatively low liquid product yields, such as
around 55 wt%
or less. The liquid product yield is correlated with the amount of micro
carbon residue of
the vacuum resid used to form the deasphalter rock. When the micro carbon
residue of
the vacuum resid is about 10 wt% or more, the resulting deasphalter rock can
tend to
have a sufficiently low liquid product yield from coking that this type of
process scheme
is not favored.
[0014] In
sharp contrast to this conventional wisdom, it has been discovered that the
difficulties in fixed bed hydroprocessing of deasphalter rock (and/or other
1050 F+/566 C+) material can be reduced or minimized by processing the
deasphalter
rock in an environment with a reduced or minimized content of feed components
that are
quickly converted into low solubility number fractions. During hydroprocessing
of a
vacuum resid fraction, at least part of the solvency power for asphaltenes of
the vacuum
resid fraction is provided by components that may be aromatic in nature, but
that can
also be rapidly transformed under hydroprocessing conditions to compounds
having a
lower solvency power. This can result in the solubility number of the vacuum
resid
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
4
fraction being reduced during hydroprocessing at a faster rate than the
insolubility
number. This problem can be mitigated by performing an initial solvent
deasphalting
step on a vacuum resid (or alternatively an atmospheric resid) to separate out
deasphalted
oil and deasphalter rock. In some aspects, the solvent deasphalting can
correspond to
propane deasphalting, so that propane deasphalter rock is formed.
Conventionally, it is
understood that the solubility number of deasphalter rock is higher than the
solubility
number of the corresponding deasphalted oil made during a deasphalting
process. As an
example, a vacuum resid with a solubility number of about 100 was separated by
pentane
deasphalting into 75 vol% deasphalted oil with a solubility number of about 80
and 25
vol% deasphalter rock with a solubility number of about 120. It has been
discovered that
after an initial increase in insolubility number to about 70, the solubility
number and
insolubility number of deasphalter rock are reduced at similar rates during
hydroprocessing, which can allow for higher levels of conversion of the
deasphalter rock
while reducing or minimizing coke formation and/or other plugging of a fixed
bed
reactor.
[0015] The fixed bed hydroprocessing of the deasphalter rock can be further
facilitated by combining the deasphalter rock with a co-feed that has a
solubility number
higher than deasphalter rock, such as at least about 110, or at least about
120, and that
exhibits similar reduction rates for solubility number and insolubility number
during
hydroprocessing. An example of such a co-feed is an FCC bottoms fraction. The
amount of such co-feed added to the deasphalter rock can be any convenient
amount up
to about 60 wt%, such as about 1 wt% to 60 wt%, or about 10 wt% to about 50
wt%, or
about 15 wt% to about 40 wt%.
[0016] Optionally, a portion of the deasphalter rock feed can also
correspond to an
aromatic solvent that can improve the viscosity or other flow properties of
the
deasphalter rock. An aromatic solvent can have a final boiling point and/or a
T95
distillation point of about 700 F (-371 C) or less and an aromatics content of
at least
about 50 wt% relative to the weight of the solvent. Such an aromatic solvent
can be
present in an amount of about 50 wt% or less of the feed for lower boiling
solvents,
while higher boiling solvents can be limited to about 25 wt% or less. Examples
of
suitable aromatic solvent can include xylenes and light cycle oils.
[0017] FCC bottoms, sometimes referred to as catalytic slurry oil is an
example of a
suitable co-feed for co-processing with deasaphalter rock. Fluid catalytic
cracking
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
(FCC) processes can commonly be used in refineries to increase the amount of
fuels that
can be generated from a feedstock. Because FCC processes do not typically
involve
addition of hydrogen to the reaction environment, FCC processes can be useful
for
conversion of higher boiling fractions to naphtha and/or distillate boiling
range products
at a lower cost than hydroprocessing. However, such higher boiling fractions
can often
contain multi-ring aromatic compounds that are not readily converted, in the
absence of
additional hydrogen, by the medium pore or large pore molecular sieves
typically used in
FCC processes. As a result, FCC processes can often generate a bottoms
fraction that is
highly aromatic in nature. Additionally, the bottoms fraction can also contain
catalyst
fines generated from the fluidized bed of catalyst during the FCC process.
This type of
FCC bottoms fraction can also be referred to as a catalytic slurry oil or main
column
bottoms. Other suitable co-feeds include, but are not limited to, lube
extracts, heavy
coker gas oils, and vacuum gas oils derived from heavy oils.
[0018] Typical FCC bottoms fractions can have a relatively high
insolubility number
(IN) of about 70 to about 110, which is a measure of the volume percentage of
toluene
that would be needed to maintain solubility of a given petroleum fraction.
According to
conventional practices, combining a feed with an IN of greater than about 50
with a
virgin crude oil fraction is known to lead to rapid coking under
hydroprocessing
conditions. However, it has been discovered that such FCC bottoms can be co-
processed
with deasphalter rock at unexpectedly high levels of conversion in a fixed bed
hydroprocessing environment.
[0019] In this discussion, reference is made to catalytic slurry oil, FCC
bottoms, and
main column bottoms. These terms are used interchangeably herein. It is noted
that
when initially formed, a catalytic slurry oil can include several weight
percent of catalyst
fines. Such catalyst fines can optionally be removed (such as partially
removed to a
desired level) by any convenient method, such as filtration. In this
discussion, unless
otherwise explicitly noted, references to a catalytic slurry oil are defined
to include
catalytic slurry oil either prior to or after such a process for reducing the
content of
catalyst fines within the catalytic slurry oil.
[0020] In some aspects, reference is made to conversion of a feedstock
relative to a
conversion temperature T. Conversion relative to a temperature T is defined
based on
the portion of the feedstock that boils at a temperature greater than the
conversion
temperature T. The amount of conversion during a process (or optionally across
multiple
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
6
processes) is defined as the weight percentage of the feedstock that is
converted from
boiling at a temperature above the conversion temperature T to boiling at a
temperature
below the conversion temperature T. As an illustrative hypothetical example,
consider a
feedstock that includes 40 wt% of components that boil at 700 F (371 C) or
greater. By
definition, the remaining 60 wt% of the feedstock boils at less than 700 F
(371 C). For
such a feedstock, the amount of conversion relative to a conversion
temperature of 700 F
(371 C) would be based only on the 40 wt% that initially boils at 700 F (371
C) or
greater. If such a feedstock is exposed to a process with 30% conversion
relative to a
700 F (371 C) conversion temperature, the resulting product would include 72
wt% of
components boiling below 700 F (371 C) and 28 wt% of components boiling above
700 F (371 C).
Resid Feedstock and Solvent Deasphalting
[0021] In various aspects, a resid fraction (or residual fraction)
corresponds to a
heaviest and/or highest boiling fraction from a temperature based
fractionation process.
An atmospheric resid corresponds to a fractionation bottoms from an
atmospheric
distillation or fractionation. A vacuum resid corresponds to a fractionation
bottoms from
a vacuum distillation or fractionation. Such resid fractions can have an
initial boiling
point (such as an initial ASTM D2892 boiling point) of 650 F (343 C) or
greater.
Preferably, a resid fraction can have an 10% distillation point (such as an
ASTM D2892
10% distillation point) of at least 650 F (343 C), alternatively at least 660
F (349 C) or
at least 750 F (399 C). In some aspects the 10% distillation point can be
still greater
(corresponding to a vacuum resid), such as at least 900 F (482 C), or at least
950 F
(510 C), or at least 975 F (524 C), or at least 1020 F (549 C), or at least
1050 F
(566 C). Such a 10% distillation point can be referred to herein as a "T10
boiling point".
Other fractional weight boiling points, such as T5, T90, or T95 boiling points
can be
determined in a similar manner.
[0022] In addition to resid fractions, reference may be made to one or more
types of
fractions generated during distillation of a petroleum feedstock. Such
fractions may
include naphtha fractions, kerosene fractions, diesel fractions, and (vacuum)
gas oil
fractions. Each of these types of fractions can be defined based on a boiling
range, such
as a boiling range that includes at least 90 wt% of the fraction (T90 boiling
point), and
preferably at least 95 wt% of the fraction (T95 boiling point). For example,
for many
types of naphtha fractions, at least 90 wt% of the fraction, and preferably at
least 95
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
7
wt%, can have a boiling point in the range of 85 F (29 C) to 350 F (177 C).
For some
heavier naphtha fractions, at least 90 wt% of the fraction, and preferably at
least 95 wt%,
can have a boiling point in the range of 85 F (29 C) to 400 F (204 C). For a
kerosene
fraction, at least 90 wt% of the fraction, and preferably at least 95 wt%, can
have a
boiling point in the range of 300 F (149 C) to 600 F (288 C). Alternatively,
for a
kerosene fraction targeted for some uses, such as jet fuel production, at
least 90 wt% of
the fraction, and preferably at least 95 wt%, can have a boiling point in the
range of
300 F (149 C) to 550 F (288 C). For a diesel fraction, at least 90 wt% of the
fraction,
and preferably at least 95 wt%, can have a boiling point in the range of 400 F
(204 C) to
750 F (399 C). Although feedstocks in the light to middle distillate boiling
range can
typically be assessed according to ASTM D2887, if a feedstock or other sample
contains
components not suitable for characterization using D2887, other standard
methods, such
as ASTM D1160 and/or ASTM D2892, may be used instead for such component.
[0023] Typical gas oil fractions can include, for example, fractions with
an initial
boiling point of at least about 650 F (-343 C), or at least about 700 F (-371
C), or at
least about 750 F (-399 C). Alternatively, a gas oil fraction may be
characterized using
a T5 boiling point, such as a fraction with a T5 boiling point of at least
about 650 F
(-343 C), or at least about 700 F (-371 C), or at least about 750 F (-399 C).
In some
aspects, the final boiling point of a gas oil fraction can be about 1150 F (-
621 C) or less,
such as about 1100 F (-593 C) or less, or about 1050 F (-566 C) or less.
Alternatively,
a gas oil fraction may be characterized using a T95 boiling point, such as a
fraction with
a T95 boiling point of about 1150 F (-621 C) or less, or about 1100 F (-593 C)
or less,
or about 1050 F (-566 C) or less. In still other aspects, a gas oil fraction
can correspond
to a lower boiling gas oil fraction, with a T95 boiling point or final boiling
point of about
1000 F (-538 C) or less, such as about 935 F (-500 C) or less. An example of a
suitable type of gas oil fraction is a wide cut vacuum gas oil (VGO), with a
T5 boiling
point of at least about 700 F (-371 C) and a T95 boiling point of about 1100 F
(-593 C) or less, preferably a T95 boiling point of about 1000 F (-538 C) or
less.
[0024] After forming a resid fraction, such as a vacuum resid fraction, a
solvent
deasphalting process can be used to separate deasphalted oil from deasphalter
rock.
Solvent deasphalting is a solvent extraction process. Typical solvents include
alkanes or
other hydrocarbons containing about 3 to about 6 carbons per molecule.
Examples of
suitable solvents include propane, n-butane, isobutane, and n-pentane. In some
aspects,
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
8
propane deasphalting can be used, which can increase the amount of deasphalter
rock
that is generated. Alternatively, other types of solvents may also be
suitable, such as
supercritical fluids. During solvent deasphalting, a feed portion is mixed
with the
solvent. Portions of the feed that are soluble in the solvent are then
extracted, leaving
behind a residue with little or no solubility in the solvent. Typical solvent
deasphalting
conditions include mixing a feedstock fraction with a solvent in a weight
ratio of from
about 1 : 2 to about 1 : 10, such as about 1 : 8 or less. Typical solvent
deasphalting
temperatures range from about 40 C to about 150 C. The pressure during solvent
deasphalting can be from about 50 psig (-345 kPag) to about 500 psig (-3.4
MPag).
[0025] The portion of the deasphalted feedstock that is extracted with the
solvent is
often referred to as deasphalted oil. The yield of deasphalted oil from a
solvent
deasphalting process varies depending on a variety of factors, including the
nature of the
feedstock, the type of solvent, and the solvent extraction conditions. A
lighter molecular
weight solvent such as propane will result in a lower yield of deasphalted oil
as
compared to n-pentane, as fewer components of a bottoms fraction will be
soluble in the
shorter chain alkane. However, the deasphalted oil resulting from propane
deasphalting
is typically of higher quality, resulting in expanded options for use of the
deasphalted oil.
Under typical deasphalting conditions, increasing the temperature will also
usually
reduce the yield while increasing the quality of the resulting deasphalted
oil. In various
embodiments, the yield of deasphalted oil from solvent deasphalting can be
about 85
wt% or less of the feed to the deasphalting process, or about 75 wt% or less.
The
deasphalted oil resulting from the solvent deasphalting procedure can then be
optionally
exposed to a solvent extraction process. After a deasphalting process, the
yield of
deasphalter rock can be at least about 15 wt% of the feed to the deasphalting
process, or
at least about 20 wt%, or at least about 25 wt%, or at least about 30 wt%, or
at least
about 35 wt%, or at least about 40 wt%, and/or about 75 wt% or less, or about
65 wt% or
less, or about 50 wt% or less, or about 40 wt% or less, or about 30 wt% or
less, or about
25 wt% or less. Each of the above lower bounds for the amount of deasphalter
rock
yield is explicitly contemplated in conjunction with each of the above upper
bounds.
[0026] In some aspects, the deasphalted oil can be exposed to further
processing to
form Group I lubricant base stocks. For example, two types of additional
solvent
processing can be performed. The first type of solvent processing is solvent
extraction to
reduce the aromatics content and/or the amount of polar molecules. The solvent
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
9
extraction process selectively dissolves aromatic components to form an
aromatics-rich
extract phase (sometimes referred to as a lubes extract) while leaving the
more paraffinic
components in an aromatics-poor raffinate phase. Naphthenes are distributed
between
the extract and raffinate phases. Typical solvents for solvent extraction
include phenol,
furfural and N-methyl pyrrolidone. By controlling the solvent to oil ratio,
extraction
temperature and method of contacting distillate to be extracted with solvent,
one can
control the degree of separation between the extract and raffinate phases. Any
convenient type of liquid-liquid extractor can be used, such as a counter-
current liquid-
liquid extractor. Depending on the initial concentration of aromatics in the
deasphalted
bottoms, the raffinate phase can have an aromatics content of about 10 wt% to
about 50
wt%.
[0027] In
some aspects, the raffinate from the solvent extraction can be
under-extracted. In such aspects, the extraction is carried out under
conditions such that
the raffinate yield is maximized while still removing most of the lowest
quality
molecules from the feed. Raffinate yield may be maximized by controlling
extraction
conditions, for example, by lowering the solvent to oil treat ratio and/or
decreasing the
extraction temperature. The raffinate from the solvent extraction unit can
then be solvent
dewaxed under solvent dewaxing conditions to remove hard waxes from the
raffinate.
[0028]
Solvent dewaxing typically involves mixing the raffinate feed from the
solvent extraction unit with chilled dewaxing solvent to form an oil-solvent
solution.
Precipitated wax is thereafter separated by, for example, filtration. The
temperature and
solvent are selected so that the oil is dissolved by the chilled solvent while
the wax is
precipitated.
[0029] An
example of a suitable solvent dewaxing process involves the use of a
cooling tower where solvent is prechilled and added incrementally at several
points
along the height of the cooling tower. The oil-solvent mixture is agitated
during the
chilling step to permit substantially instantaneous mixing of the prechilled
solvent with
the oil. The prechilled solvent is added incrementally along the length of the
cooling
tower so as to maintain an average chilling rate at or below 10 F per minute,
usually
between about 1 F to about 5 F per minute. The
final temperature of the
oil-solvent/precipitated wax mixture in the cooling tower will usually be
between 0 and
50 F (-18 to 10 C). The mixture may then be sent to a scraped surface chiller
to separate
precipitated wax from the mixture.
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
[0030] Representative dewaxing solvents are aliphatic ketones having 3-6
carbon
atoms such as methyl ethyl ketone and methyl isobutyl ketone, low molecular
weight
hydrocarbons such as propane and butane, and mixtures thereof. The solvents
may be
mixed with other solvents such as benzene, toluene or xylene.
[0031] In general, the amount of solvent added will be sufficient to
provide a
liquid/solid weight ratio between the range of 5/1 and 20/1 at the dewaxing
temperature
and a solvent/oil volume ratio between 1.5/1 to 5/1. The solvent dewaxed oil
is typically
dewaxed to an intermediate pour point, preferably less than about +10 C, such
as less
than about 5 C or less than about 0 C. The resulting solvent dewaxed oil is
suitable for
use in forming one or more types of Group I base oils. The aromatics content
will
typically be greater than 10 wt% in the solvent dewaxed oil. Additionally, the
sulfur
content of the solvent dewaxed oil will typically be greater than 300 wppm.
Additional Feedstocks and Solvents ¨ Aromatic Feeds, Light Cycle Oil,
Catalytic Slurry
Oil
[0032] In various aspects, the amount of deasphalter rock in a feed for
fixed bed
hydroprocessing can be at least about 10 wt% of the feed, or at least about 20
wt%, or at
least about 30 wt%, or at least about 40 wt%, or at least about 50 wt%, or at
least about
60 wt%. Deasphalter rock can tend to be a high viscosity fraction, and may
even be a
solid or semi-solid fraction at ambient temperature. In order to facilitate
introducing the
deasphalter rock into a reactor for fixed bed hydroprocessing, in some aspects
the
deasphalter rock can be co-processed with an additional aromatic co-feed
and/or
aromatic solvent in order to modify the flow properties of the deasphalter
rock feed. One
option can be to add an additional aromatic feed that has similar behavior
during
hydroprocessing to deasphalter rock. An example of a suitable aromatic co-feed
can be
FCC bottoms, also referred to as catalytic slurry oil. Other examples of
suitable aromatic
co-feeds can include, but are not limited to, heavy coker gas oils, lube
extracts, and
vacuum gas oils derived from heavy oils.
[0033] A catalytic slurry oil can correspond to a high boiling fraction,
such as a
bottoms fraction, from an FCC process. A variety of properties of a catalytic
slurry oil
can be characterized to specify the nature of a catalytic slurry oil feed.
[0034] One aspect that can be characterized is a boiling range of the
catalytic slurry
oil. Typically the cut point for forming a catalytic slurry oil can be at
least about 650 F
(-343 C). As a result, a catalytic slurry oil can have a T5 distillation
(boiling) point or a
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
11
T10 distillation point of at least about 650 F (-343 C), as measured according
to ASTM
D2887. In some aspects the D2887 10% distillation point can be greater, such
as at least
about 675 F (-357 C), or at least about 700 F (-371 C). In other aspects, a
broader
boiling range portion of FCC products can be used as a feed, where the broader
boiling
range portion includes a 650 F+ fraction that corresponds to a catalytic
slurry oil. It is
noted that the catalytic slurry oil (650 F+/343 C+) fraction of the feed does
not
necessarily have to represent a "bottoms" fraction from an FCC process, so
long as the
catalytic slurry oil portion has one or more of the other feed charateristics
described
herein.
[0035] In addition to initial boiling points, T5 distillation point, and/or
T10
distillation points, other distillation points may also be useful in
characterizing a
feedstock. For example, a feedstock can be characterized based on the portion
of the
feedstock that boils above 1050 F (566 C). In some aspects, a feedstock (or
alternatively a 650 F+/343 C+ portion of a feedstock) can have an ASTM D2887
95%
distillation point of 1050 F (566 C) or greater, or a 90% distillation point
of 1050 F
(566 C) or greater.
[0036] Density, or weight per volume, of the catalytic slurry oil can also
be
characterized. In various aspects, the density of the catalytic slurry oil (or
alternatively a
650 F+ portion of a feedstock) can be at least about 1.06 g/cc, or at least
about 1.08 g/cc,
or at least about 1.10 g/cc. The density of the catalytic slurry oil can
provide an
indication of the amount of heavy aromatic cores that are present within the
catalytic
slurry oil. A lower density catalytic slurry oil feed can in some instances
correspond to a
feed that may have a greater expectation of being suitable for hydrotreatment
without
substantial and/or rapid coke formation.
[0037] Contaminants such as nitrogen and sulfur are typically found in
catalytic
slurry oils, often in organically-bound form. Nitrogen content can range from
about 50
wppm to about 5000 wppm elemental nitrogen, or about 100 wppm to about 2000
wppm
elemental nitrogen, or about 250 wppm to about 1000 wppm, based on total
weight of
the catalytic slurry oil. The nitrogen containing compounds can be present as
basic or
non-basic nitrogen species. Examples of nitrogen species include quinolones,
substituted
quinolones, carbazoles and substituted carbazoles.
[0038] The sulfur content of a catalytic slurry oil feed can be at least
about 500
wppm elemental sulfur, based on total weight of the catalytic slurry oil.
Generally, the
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
12
sulfur content of a catalytic slurry oil can range from about 500 wppm to
about 100,000
wppm elemental sulfur, or from about 1000 wppm to about 50,000 wppm, or from
about
1000 wppm to about 30,000 wppm, based on total weight of the heavy component.
Sulfur can usually be present as organically bound sulfur. Examples of such
sulfur
compounds include the class of heterocyclic sulfur compounds such as
thiophenes,
tetrahydrothiophenes, benzothiophenes and their higher homologs and analogs.
Other
organically bound sulfur compounds include aliphatic, naphthenic, and aromatic
mercaptans, sulfides, di- and polysulfides.
[0039] Catalytic slurry oils can also include n-heptane insoluble (NHI) or
asphaltenes. In some aspects, the catalytic slurry oil feed (or alternatively
a 650 F+
portion of a feed) can contain at least about 3 wt% of n-heptane asphaltenes,
or at least
about 5 wt%, and/or up to about 10 wt%. Another option for characterizing the
heavy
components of a catalytic slurry oil can be based on the amount of micro
carbon residue
(MCR) in the feed. In various aspects, the amount of MCR in the catalytic
slurry oil feed
(or alternatively a 650 F+ portion of a feed) can be at least about 5 wt%, or
at least about
8 wt%, or at least about 10 wt%, and/or up to about 16 wt%.
[0040] Based on the content of NHI and/or MCR in a catalytic slurry oil
feed, the
insolubility number (IN) for such a feed can be at least about 60, or at least
about 70, or
at least about 80, or at least about 90. Additionally or alternately, the IN
for such a feed
can be about 140 or less, or about 120 or less, or about 110 or less, or about
100 or less,
or about 90 or less, or about 80 or less. It is noted that each lower bound
noted above for
IN is explicitly contemplated in conjunction with each upper bound noted above
for IN.
Additionally or alternately, each lower bound noted above for IN is explicitly
contemplated in conjunction with each lower and/or upper bound noted above for
NHI
and/or MCR.
[0041] With regard to heavy coker gas oils, suitable heavy coker gas oils
can have an
initial boiling point or T5 distillation point of at least about 600 F (-316
C), and/or a
T10 distillation point of at least about 650 F (-343 C), and a T90
distillation point of
about 1050 F (-566 C) or less, and/or a T95 distillation point or final
boiling point of
about 1150 F (-621 C) or less, or about 1100 F (-593 C) or less. Similar to
main
column bottoms, heavy coker gas oils can have a sufficiently high solubility
number
and/or a sufficiently low rate of solubility number reduction to allow for co-
processing of
heavy coker gas oils with deasphalter rock.
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
13
[0042] Lube extracts refer to aromatic extract fractions that can be formed
during
solvent processing of a feedstock to form (Group I) lubricant base stocks.
Similar to
main column bottoms, lube extracts fractions can have a sufficiently high
solubility
number and/or a sufficiently low rate of solubility number reduction to allow
for
co-processing of lube extracts with deasphalter rock.
[0043] Still another potential co-feed can be a vacuum gas oil derived from
a heavy
oil. Heavy oils can have an initial boiling point (measured by, e.g., ASTM
D2887) of
650 F (343 C) or greater and/or a 10% distillation point of at least 650 F
(343 C), or at
least 660 F (349 C), or at least 750 F (399 C). In some aspects the 10%
distillation
point can be still greater, such as at least 950 F (510 C), or at least 1020 F
(549 C), or at
least 1050 F (566 C). In addition to initial boiling points and/or 10%
distillation points,
other distillation points may also be useful in characterizing a heavy oil.
For example, a
feedstock can be characterized based on the portion of the feedstock that
boils above
1050 F (566 C). In some aspects, a feedstock can have a 70% distillation point
of
1050 F (566 C) or greater, or a 60% distillation point of 1050 F (566 C) or
greater, or a
50% distillation point of 1050 F (566 C) or greater, or a 40% distillation
point of 1050 F
or greater. A vacuum gas oil derived from such a heavy oil can have a typical
boiling
range for a vacuum gas oil, such as a T5 distillation point of at least about
650 F
(-343 C), or at least about 700 F (-371 C), and a T95 distillation point of
about 1100 F
(-593 C) or less, or about 1050 F (-566 C) or less, or about 1000 F (-538 C)
or less.
Similar to main column bottoms, a vacuum gas oil derived from such a heavy oil
feed
can have a sufficiently high solubility number and/or a sufficiently low rate
of solubility
number reduction to allow for co-processing of the vacuum gas oil with
deasphalter rock.
[0044] In some aspects, an aromatic solvent can also be added to the
deasphalter
rock feed. An aromatic solvent can assist with the flow properties of the
deasphalter
rock feed. The aromatic solvent can have a final boiling point or a T95
boiling point of
about 400 C or less, or about 375 C or less, or about 350 C or less. In order
to reduce or
minimize incompatibility issues, the amount of the aromatic solvent can be
about 50
wt% or less of the feed, or about 40 wt% or less, or about 30 wt% or less, or
about 20
wt% or less, or about 10 wt% or less. The amount of aromatic solvent can also
be
dependent on the boiling range of the solvent. For a solvent having a final
boiling point
or a T95 boiling point of at least about 300 C, the amount of the aromatic
solvent can be
about 40 wt% or less, or about 30 wt% or less, or about 20 wt% or less, or
about 10 wt%
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
14
or less. For a solvent having a final boiling point or a T95 boiling point of
at least about
350 C, the amount of the aromatic solvent can be about 30 wt% or less, or
about 25 wt%
or less, or about 20 wt% or less, or about 10 wt% or less. For a solvent
having a final
boiling point or a T95 boiling point of at least about 400 C, the amount of
aromatic
solvent can be about 25 wt% or less, or about 15 wt% or less, or about 10 wt%
or less.
[0045] Additionally or alternately, at least a minimum amount of a co-feed,
an
aromatic solvent, or a combination thereof can be introduced into the fixed
bed
hydroprocessing environment with the deasphalter rock feed. For example, the
at least a
minimum amount of co-feed, aromatic solvent, or a combination thereof can be
combined with the deasphalter rock to facilitate flow of the deasphalter rock
into and/or
through the fixed bed environment. In such aspects, the desphalter rock can be
exposed
to the fixed bed of hydroprocessing catalyst in the presence of at least about
10 wt% of
aromatic co-feed, aromatic solvent, or a combination thereof, or at least
about 15 wt%, or
at least about 20 wt%, or at least about 25 wt%.
[0046] One option for an aromatic solvent can be a solvent corresponding to
one or a
few chemical compounds. Examples of individual compounds that can be included
in an
aromatic solvent include, but are not limited to, xylenes, alkylated benzenes,
and/or other
aromatic compounds with a boiling point between about 120 C to about 400 C, or
about
120 C to about 350 C, or about 120 C to about 300 C, or about 120 C to about
250 C,
or about 150 C to about 400 C, or about 150 C to about 350 C, or about 150 C
to about
300 C, or about 150 C to about 250 C.
[0047] Another option for an aromatic solvent can be to use one or more
refinery
streams. The one or more refinery streams can have a combined aromatic content
of at
least about 50 wt% relative to the weight of the aromatic solvent, or at least
about 60
wt%. Examples of suitable refinery streams for use as an aromatic solvent can
include,
but are not limited to, light cycle oils, coker gas oils, and/or other
refinery streams
having a boiling range between about 120 C to about 500 C, or about 120 C to
about
450 C, or about 120 C to about 400 C, or about 120 C to about 350 C, or about
120 C
to about 300 C, or about 120 C to about 250 C, or about 150 C to about 500 C,
or about
150 C to about 450 C, or about 150 C to about 400 C, or about 150 C to about
350 C,
or about 150 C to about 300 C, or about 150 C to about 250 C, or about 200 C
to about
550 C, or about 200 C to about 500 C, or about 200 C to about 450 C, or about
200 C
to about 400 C, or about 200 C to about 350 C, or about 200 C to about 300 C,
or about
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
250 C to about 550 C, or about 250 C to about 500 C, or about 250 C to about
450 C,
or about 250 C to about 400 C, or about 250 C to about 350 C. It is noted that
the
above boiling ranges can correspond to an initial boiling point or a T5
boiling point to a
final boiling point or a T95 boiling point.
Fixed Bed Hydrotreatment
[0048] Conventionally, feeds having an IN of greater than about 50 have
been
viewed as unsuitable for fixed bed hydroprocessing. This conventional view is
due to
the belief that feeds with an IN of greater than about 50 are likely to cause
substantial
formation of coke within a reactor, leading to rapid plugging of a fixed
reactor bed.
Instead of using a fixed bed reactor, feeds with a high IN value are
conventionally
processed using other types of reactors that can allow for regeneration of
catalyst during
processing, such as a fluidized bed reactor. Alternatively, if a fixed bed
catalyst is used
for conventional processing of a high IN feed, the conditions are
conventionally selected
to achieve a low amount of conversion in the feed relative to a conversion
temperature of
1050 F (566 C), such as less than about 30% to about 50% conversion.
Performing a
limited amount of conversion on a high IN feed is conventionally believed to
be required
to avoid rapid precipitation and/or coke formation within a fixed bed reactor.
[0049] In various aspects, a feed composed of a substantial portion of
deasphalter
rock can be hydrotreated under effective hydrotreating conditions to form a
hydrotreated
effluent. The effective hydrotreating conditions can allow for conversion of
at least
about 55 wt% of the deasphalter rock relative to 1050 F (566 C), or at least
about 60
wt%, or at least about 65 wt%, or at least about 70 wt%. It is noted that when
deasphalter rock is formed by a deasphalting process, a deasphalted oil
fraction is also
formed. This deasphalted oil fraction can be substantially completely
converted in a
separate process, such as a fixed bed hydrotreatment process. Based on the
combined
conversion of the deasphalted oil and the deasphalter rock, at least about 80
wt% of the
1050 F+ (566 C+) portion of a vacuum resid can be achieved, or at least about
85 wt%.
[0050] Hydroprocessing (such as hydrotreating) is carried out in the
presence of
hydrogen. A hydrogen stream can be fed or injected into a vessel or reaction
zone or
hydroprocessing zone in which the hydroprocessing catalyst is located.
Hydrogen,
which is contained in a hydrogen "treat gas," is provided to the reaction
zone. Treat gas,
as referred to herein, can be either pure hydrogen or a hydrogen-containing
gas, which is
a gas stream containing hydrogen in an amount that is sufficient for the
intended
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
16
reaction(s), optionally including one or more other gasses (e.g., nitrogen and
light
hydrocarbons such as methane), and which will not adversely interfere with or
affect
either the reactions or the products. Impurities, such as H2S and NH3 are
undesirable and
would typically be removed from the treat gas before it is conducted to the
reactor. In
aspects where the treat gas stream is different from a stream that
substantially consists of
hydrogen (i.e., at least about 99 vol% hydrogen), the treat gas stream
introduced into a
reaction stage can contain at least about 50 vol%, or at least about 75 vol%
hydrogen, or
at least about 90 vol% hydrogen.
[0051] In some aspects, a combination of catalysts can be used for
hydroprocessing
of a heavy oil feed. For example, a heavy oil feed can be contacted first by a
demetallation catalyst, such as a catalyst including NiMo or CoMo on a support
with a
median pore diameter of 200 A or greater. A demetallation catalyst represents
a lower
activity catalyst that is effective for removing at least a portion of the
metals content of a
feed. This allows a less expensive catalyst to be used to remove a portion of
the metals,
thus extending the lifetime of any subsequent higher activity catalysts. The
demetallized
effluent from the demetallation process can then be contacted with a
conventional
hydrotreating catalyst.
[0052] Contacting conditions in the contacting or hydroprocessing zone can
include,
but are not limited to, temperature, pressure, hydrogen flow, hydrocarbon feed
flow, or
combinations thereof Contacting conditions in some embodiments are controlled
to
yield a product with specific properties.
[0053] Hydroprocessing is carried out in the presence of hydrogen. A
hydrogen
stream is, therefore, fed or injected into a vessel or reaction zone or
hydroprocessing
zone in which the hydroprocessing catalyst is located. Hydrogen, which is
contained in a
hydrogen "treat gas," is provided to the reaction zone. Treat gas, as referred
to herein,
can be either pure hydrogen or a hydrogen-containing gas, which is a gas
stream
containing hydrogen in an amount that is sufficient for the intended
reaction(s),
optionally including one or more other gasses (e.g., nitrogen and light
hydrocarbons such
as methane), and which will not adversely interfere with or affect either the
reactions or
the products. Impurities, such as H2S and NH3 are undesirable and would
typically be
removed from the treat gas before it is conducted to the reactor. The treat
gas stream
introduced into a reaction stage will preferably contain at least about 50
vol.% and more
preferably at least about 75 vol.% hydrogen.
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
17
[0054] Hydrogen can be supplied at a rate of from 300 SCF/B (standard cubic
feet of
hydrogen per barrel of feed) (53 S m3/m3) to 10000 SCF/B (1780 S m3/m3).
Preferably,
the hydrogen is provided in a range of from 1000 SCF/B (178 S m3/m3) to 5000
SCF/B
(891 S m3/m3).
[0055] Hydrogen can be supplied co-currently with the heavy hydrocarbon oil
and/or
solvent or separately via a separate gas conduit to the hydroprocessing zone.
The contact
of the heavy hydrocarbon oil and solvent with the hydroprocessing catalyst and
the
hydrogen produces a total product that includes a hydroprocessed oil product,
and, in
some embodiments, gas.
[0056] The temperature in the contacting zone can be at least about 680 F (-
360 C),
or at least about 700 F (-371 C), or at least about 716 F (-380 C), or at
least about
750 F (-399 C), or at least about 788 F (-420 C). Additionally or alternately,
the
temperature in the contacting zone can be about 810 F (-433 C) or less, or
about 788 F
(-420 C) or less. Above about 810 F thermal reactions of the feedstock can
form
sufficient coke in the reactor and in upstream and downstream heat exchangers
to make
conventional fixed bed processing less desirable.
[0057] Total pressure in the contacting zone can be about 600 psig (-4.2
MPag) to
about 6000 psig (-42 MPag), or about 600 psig (-4.2 MPag) to about 5000 psig (-
34
MPag), or about 600 psig (-4.2 MPag) to about 4000 psig (-28 MPag), or about
600 psig
(-4.2 MPag) to about 3000 psig (-21 MPag), or about 1000 psig (-6.9 MPag) to
about
6000 psig (-42 MPag), or about 1000 psig (-6.9 MPag) to about 5000 psig (-34
MPag),
or about 1000 psig (-6.9 MPag) to about 4000 psig (-28 MPag), or about 1000
psig
(-6.9 MPag) to about 3000 psig (-21 MPag), or about 1500 psig (-10.3 MPag) to
about
6000 psig (-42 MPag), or about 1500 psig (-10.3 MPag) to about 5000 psig (-34
MPag), or about 1500 psig (-10.3 MPag) to about 4000 psig (-28 MPag), or about
1500
psig (-10.3 MPag) to about 3000 psig (-21 MPag). Preferably, a feed including
deasphalter rock can be hydroprocessed under relatively high hydrogen partial
pressure
conditions. In such aspects, the hydrogen partial pressure during
hydroprocessing can be
from about 1000 psig (-6.9 MPag) to about 6000 psig (-42 MPag), such as at
least about
1500 psig (-10 MPag), or at least about 2000 psig (-14 MPag), or about 5000
psig (-34
MPag) or less, or about 4000 psig (-28 MPag) or less, or about 3000 psig (-21
MPag) or
less.
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
18
[0058] The liquid hourly space velocity of the feed (or optionally the
deasphalter
rock portion of the feed) can generally range from 0.01 to 5 h or 0.05 h' to 2
h or
0.1 to 1.5 h'.
[0059] Based on the reaction conditions described above, in various aspects
of the
invention, a portion of the reactions taking place in the hydroprocessing
reaction
environment can correspond to thermal cracking reactions. In addition to the
reactions
expected during hydroprocessing of a feed in the presence of hydrogen and a
hydroprocessing catalyst, thermal cracking reactions can also occur at
temperatures of
360 C and greater. In the hydroprocessing reaction environment, the presence
of
hydrogen and catalyst can reduce the likelihood of coke formation based on
radicals
formed during thermal cracking.
[0060] In an embodiment of the invention, contacting the input feed in the
hydroconversion reactor with the hydroprocessing catalyst in the presence of
hydrogen to
produce a hydroprocessed product is carried out in a single contacting zone.
In another
aspect, contacting is carried out in two or more contacting zones.
[0061] In an aspect, the hydrotreating step may comprise at least one
hydrotreating
reactor, and optionally may comprise two or more hydrotreating reactors
arranged in
series flow. A vapor separation drum can optionally be included after each
hydrotreating
reactor to remove vapor phase products from the reactor effluent(s). The vapor
phase
products can include hydrogen, H2S, NH3, and hydrocarbons containing four (4)
or less
carbon atoms (i.e., "C4-hydrocarbons"). The effective hydrotreating conditions
can be
suitable for removal of at least about 70 wt%, or at least about 80 wt%, or at
least about
90 wt% of the sulfur content in the feedstream from the resulting liquid
products.
Additionally or alternately, at least about 50 wt%, or at least about 75 wt%
of the
nitrogen content in the feedstream can be removed from the resulting liquid
products. In
some aspects, the final liquid product from the hydrotreating unit can contain
less than
about 10000 wppm sulfur, or less than about 5000 wppm sulfur, or less than
about 3000
wppm sulfur, or less than about 1000 wppm sulfur, or less than about 500 wppm
sulfur.
Additionally or alternately, the final liquid product from the hydrotreating
unit can
contain at least about 1 wppm sulfur, or at least about 100 wppm sulfur, or at
least about
500 wppm sulfur, or at least about 1000 wppm sulfur.
[0062] Hydrotreating catalysts suitable for use herein can include those
containing at
least one Group VIA metal and at least one Group VIII metal, including
mixtures
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
19
thereof. Examples of suitable metals include Ni, W, Mo, Co and mixtures
thereof, for
example CoMo, NiMoW, NiMo, or NiW. These metals or mixtures of metals are
typically present as oxides or sulfides on refractory metal oxide supports.
The amount of
metals for supported hydrotreating catalysts, either individually or in
mixtures, can range
from 0.5 to 35 wt %, based on the weight of the catalyst. Additionally or
alternately, for
mixtures of Group VIA and Group VIII metals, the Group VIII metals are present
in
amounts of from 0.5 to 5 wt % based on catalyst, and the Group VIA metals are
present
in amounts of from 5 to 30 wt % based on the catalyst. A mixture of metals may
also be
present as a bulk metal catalyst wherein the amount of metal is 30 wt % or
greater, based
on catalyst weight.
[0063] Suitable metal oxide supports for the hydrotreating catalysts
include oxides
such as silica, alumina, silica-alumina, titania, or zirconia. Examples of
aluminas
suitable for use as a support can include porous aluminas such as gamma or
eta. In some
aspects, when a porous metal oxide support is utilized, the catalyst can have
an average
pore size (as measured by nitrogen adsorption) of about 30 A to about 1000 A,
or about
50 A to about 500 A, or about 60 A to about 300 A. Pore diameter can be
determined,
for example, according to ASTM Method D4284-07 Mercury Porosimetry.
Additionally
or alternately, the catalyst can have a surface area (as measured by the BET
method) of
about 100 to 350 m2/g, or about 150 to 250 m2/g. In some aspects, a supported
hydrotreating catalyst can have the form of shaped extrudates. The extrudate
diameters
can range from 1/32nd to 118th inch, from 1/20th to 1/10th inch, or from
1/20th to 1/16th
inch. The extrudates can be cylindrical or shaped. Non-limiting examples of
extrudate
shapes include trilobes and quadralobes.
[0064] In various aspects, the deasphalted oil formed after deasphalting
can also be
hydroprocessed in any convenient manner, such as by fixed bed hydroprocessing.
One
option can be to separately process the deasphalted oil under conditions
similar to those
described above. In other aspects, suitable conditions for processing a
deasphalted oil
can be similar to conditions for hydrotreatment of a vacuum gas oil boiling
range feed.
For example, hydrotreating conditions can include temperatures of 200 C to 430
C, or
315 C to 420 C; pressures of 250 psig (1.8 MPag) to 5000 psig (34.6 MPag) or
300 psig
(2.1 MPag) to 3000 psig (20.8 MPag); liquid hourly space velocities (LHSV) of
0.1 hr-1
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
to 10 hr-1; and hydrogen treat rates of 200 scf/B (35.6 m3/m3) to 10,000 scf/B
(1780
m3/m3), or 500 (89 m3/m3) to 5,000 scf/B (890 m3/m3).
Product Properties ¨ Hydrotreated Effluent
[0065] Processing a resid feed in the manner described above, so that a
deasphalted
oil portion and a deasphalter rock portion are separately hydroprocessed using
fixed bed
hydrotreatment, can allow for improved yield relative to fixed bed
hydroprocessing of
the resid feed while providing for a commercially viable run length for the
reaction
system. In various aspects, the conversion of the deasphalter rock relative to
a
conversion temperature of 1050 F (566 C) can be at least about 40 wt%, or at
least about
50 wt%, or at least about 55 wt%, or at least about 60 wt%, or at least about
65 wt%, or
at least about 70 wt%, or at least about 75 wt%. Additionally or alternately,
the high
degree of conversion of the deasphalter rock can allow for high levels of
conversion of
the combined deasphalted oil (DAO) and deasphalter rock. For example,
separation of a
resid into 60 wt% DA0 and 40 wt% rock, followed by 95 wt% conversion of the
DA0
and 40 wt% conversion of the rock results in an overall resid 1050 F+ (566 C+)
conversion of 73%. In various aspects, the conversion of the combined
deasphalted oil
and deasphalter rock relative to 1050 F (566 C) can be at least about 60 wt%,
or at least
about 65 wt%, or at least about 70 wt%, or at least about 75 wt%, or at least
about 80
wt%.
[0066] Another method for characterizing the hydrotreatment of the
deasphalter rock
can be based on the asphaltene content of the hydroprocessed product. In some
aspects,
the deasphalter rock can have an asphaltene content (defined as n-heptane
insolubles) of
about 10 wt% to about 50 wt%, or at least about 15 wt%, or at least about 20
wt%,
and/or about 40 wt% or less, or about 30 wt% or less. After hydroprocessing,
the
amount of asphaltenes in the hydrotreated effluent can be about 50 wt% or less
of the
amount of asphaltenes in the feed containing the deasphalter rock, or about 40
wt% or
less, or about 30 wt% or less, or about 20 wt% or less, or about 10 wt% or
less.
[0067] After hydrotreatment (or other hydroprocessing), the hydrotreated
(or
hydroprocessed) effluent from the deasphalter rock and/or the hydrotreated
effluent from
the deasphalted oil can be processed in any further convenient manner. For
example, the
hydrotreated effluent from the deasphalter rock and/or the hydrotreated
effluent from the
deasphalted oil can be hydrocracked, processed in a fluid catalytic cracker,
or treated in
another conventional refinery process for processing of gas oil boiling range
feeds.
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
21
[0068] After hydrotreatment of the deasphalter rock, the liquid (C3+)
portion of the
hydrotreated effluent can have a volume that is at least about 95% of the
volume of the
catalytic slurry oil feed, or at least about 100% of the volume of the feed,
or at least
about 105%, or at least about 110%, such as up to about 150% of the volume. It
is noted
that C3 and C4 hydrocarbons can be used, for example, to form liquefied
propane or
butane gas as a potential liquid product. Therefore, the C3+ portion of the
effluent is
counted as the "liquid" portion of the effluent product, even though a portion
of the
compounds in the liquid portion of the hydrotreated effluent may exit the
hydrotreatment
reactor (or stage) as a gas phase at the exit temperature and pressure
conditions for the
reactor.
[0069] Additionally or alternately, after hydrotreatment of the deasphalter
rock, the
sulfur content of the liquid (C3+) portion of the hydrotreated effluent can be
about 20000
wppm or less, or about 10000 wppm or less, or about 5000 wppm or less, or
about 3000
wppm or less, or about 1000 wppm or less, such as at least about 1 wppm, or at
least
about 100 wppm. Additionally or alternately, the sulfur content of the
hydrotreated
effluent can be reduced by at least about 50% relative to the sulfur content
of the
deasphalter rock, or at least about 60%, or at least about 70%, or at least
about 80%.
[0070] Additionally or alternately, the micro carbon residue of the
hydrotreated
effluent can be reduced by at least about 50% relative to the micro carbon
residue of the
deasphalter rock, or at least about 60%, or at least about 70%, or at least
about 80%.
[0071] Additionally or alternately, the hydrogen content of the liquid
(C3+) portion
of the hydrotreated effluent from processing of the deasphalter rock can be at
least about
9.5 wt%, or at least about 10.0 wt%, or at least about 10.5 wt%, or at least
about 11.0
wt%, or at least about 11.5 wt%.
Additional Embodiments
[0072] Embodiment 1. A method for fixed bed processing of deasphalter rock,
comprising: performing solvent deasphalting on a resid feedstock to form a
deasphalter
rock fraction and a deasphalted oil fraction, the resid feedstock having a T10
distillation
point of at least about 650 F (-343 C), the deasphalter rock fraction
comprising at least
about 10 wt% of the resid feedstock; and exposing a feedstock comprising at
least a
portion of the deasphalter rock fraction to a fixed bed of hydroprocessing
catalyst under
hydroprocessing conditions effective for conversion of at least 40 wt% of the
at least a
portion of the deasphalter rock relative to a conversion temperature of 1050 F
(566 C) to
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
22
form a hydroprocessed effluent, the feedstock comprising at least about 10 wt%
of the at
least a portion of the deasphalter rock, or at least about 20 wt%, or at least
about 30 wt%,
or at least about 40 wt%, or at least about 50 wt%.
[0073] Embodiment 2. A method for fixed bed processing of deasphalter rock,
comprising: exposing a feedstock comprising deasphalter rock and a co-feed
comprising
a catalytic slurry oil, a lubes extract, a heavy coker gas oil, a vacuum gas
oil derived
from a heavy oil, or a combination thereof, to a fixed bed of hydroprocessing
catalyst
under hydroprocessing conditions effective for conversion of at least 40 wt%
of the
deasphalter rock relative to a conversion temperature of 1050 F (566 C) to
form a
hydroprocessed effluent, the feedstock comprising at least about 20 wt% of the
co-feed,
the feedstock comprising at least about 10 wt% of the deasphalter rock, or at
least about
20 wt%, or at least about 30 wt%, or at least about 40 wt%, or at least about
50 wt%.
[0074] Embodiment 3. The method of Embodiment 2, further comprising
performing solvent deasphalting on a resid feedstock to form at least the
deasphalter rock
and a deasphalted oil fraction, the resid feedstock having a T10 distillation
point of at
least about 650 F (-343 C), the deasphalter rock comprising at least about 10
wt% of the
resid feedstock.
[0075] Embodiment 4. The method of any of Embodiments 2 to 3, wherein the
feedstock comprises at least about 20 wt% of the catalytic slurry oil, or at
least about 30
wt%, or at least about 40 wt%, or at least about 50 wt%.
[0076] Embodiment 5. The method any of Embodiments 2 to 4, wherein the
feedstock comprises at least about 30 wt% of the co-feed, or at least about 40
wt%, or at
least about 50 wt%.
[0077] Embodiment 6. The method of any of the above embodiments, wherein
the
feedstock further comprises an aromatic solvent, the aromatic comprising at
least 50 wt%
of aromatic compounds relative to a weight of the aromatic solvent, the
aromatic solvent
having a boiling range from about 100 C to about 500 C, the aromatic solvent
optionally
comprising a light cycle oil.
[0078] Embodiment 7. The method of Embodiment 6, wherein the aromatic
solvent
has a final boiling point or a T95 boiling point of about 300 C or less, or
wherein the
aromatic solvent has a final boiling point or a T95 boiling point of about 350
C or less
and the feedstock comprises about 40 wt% or less of the aromatic solvent, or
wherein the
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
23
aromatic solvent has a final boiling point or a T95 boiling point of about 400
C or less
and the feedstock comprises about 30 wt% or less of the aromatic solvent.
[0079] Embodiment 8. The method of any of the above embodiments, further
comprising solvent processing at least a portion of the deasphalted oil
fraction to form a
Group I lubricant base stock.
[0080] Embodiment 9. The method of any of the above embodiments, further
comprising fractionating at least a portion of the hydroprocessed effluent to
form a
hydroprocessed bottoms fraction and at least one of a naphtha boiling range
fraction and
a diesel boiling range fraction; deasphalting at least a portion of the
hydroprocessed
bottoms fraction to form a hydroprocessed deasphalted oil; and processing at
least a
portion of the hydroprocessed deasphalted oil under fluid catalytic cracking
conditions.
[0081] Embodiment 10. The method of Embodiment 9, wherein processing the at
least a portion of the hydroprocessed deasphalted oil under fluid catalytic
cracking
conditions further comprises processing a vacuum gas oil boiling range feed
under the
fluid catalytic cracking conditions.
[0082] Embodiment 11. The method of Embodiment 9 or 10, wherein processing
the
at least a portion of the hydroprocessed deasphalted oil under fluid catalytic
cracking
conditions a) forms at least a catalytic slurry oil fraction, at least a
portion of the catalytic
slurry oil fraction being used as a co-feed for the hydroprocessing of the
deasphalter
rock; b) forms at least a light cycle oil fraction having a final boiling
point or T95 boiling
point of about 650 F (-343 C) or less, at least a portion of the light cycle
oil fraction
being used as an aromatic solvent for the hydroprocessing of the deasphalter
rock; or c) a
combination thereof.
[0083] Embodiment 12. The method of any of Embodiments 1 or 3 ¨ 11, wherein
performing solvent deasphalting on the resid feedstock comprises performing
propane
deasphalting on the resid feedstock.
[0084] Embodiment 13. The method of any of the above embodiments, wherein
the
deasphalter rock or the at least a portion of the deasphalter rock comprises
at least about
wt% n-heptane insolubles, the hydroprocessed effluent comprising about 50% or
less
of the n-heptane insolubles in the feedstock exposed to the fixed bed
hydroprocessing
catalyst, or about 40% or less, or about 30% or less.
[0085] Embodiment 14. The method of any of the above embodiments, wherein
the
effective hydroprocessing conditions are effective for conversion of at least
about 40
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
24
wt% of the 1050 F+ (566 C+) portion of the deasphalter rock or the at least a
portion of
the deasphalter rock, or at least about 50 wt%, or at least about 60 wt%, or
at least about
65 wt%, or at least about 70 wt%; or wherein the effective hydroprocessing
conditions
for conversion of the deasphalter rock comprise a temperature of about 371 C
to about
433 C, optionally at least about 380 C or at least about 399 C or at least
about 420 C,
and a total pressure of about 600 psig (-4.2 MPag) to about 6000 psig (-42
MPag),
optionally at least about 6.9 MPag or at least about 10.3 MPag, optionally
about 34
Mpag or less or about 28 MPag or less, or about 21 MPag or less, the effective
hydroprocessing conditions optionally further comprising a hydrogen partial
pressure of
at least about 6.9 MPag or at least about 10.3 MPag and/or about 34 MPag or
less or
about 28 MPag or less or about 21 MPag or less; or a combination thereof.
[0086] Embodiment 15. The method of any of the above embodiments, further
comprising hydrotreatment of at least a portion of the deasphalted oil
fraction, a
combined conversion of the at least a portion of the deasphalted oil fraction
and the (at
least a portion of the) deasphalter rock fraction relative to 1050 F (566 C)
being at least
about 60 wt%, or at least about 70 wt%, or at least about 80 wt%, wherein
optionally the
hydrotreating conditions for the hydrotreatment of the at least a portion of
the
deasphalted oil fraction comprise temperatures of 200 C to 430 C, or 315 C to
420 C;
pressures of 250 psig (1.8 MPag) to 5000 psig (34.6 MPag) or 300 psig (2.1
MPag) to
3000 psig (20.8 MPag); liquid hourly space velocities (LHSV) of 0.1 hr-1 to 10
hr-1; and
hydrogen treat rates of 200 scf/B (35.6 m3/m3) to 10,000 scf/B (1781 m3/m3),
or 500 (89
m3/m3) to 5,000 scf/B (890 m3/m3).
[0087] Embodiment 16. The method of any of the above embodiments, wherein
the
hydroprocessed effluent has a micro-carbon residue content that is about 50%
or less of a
micro-carbon residue content in the feedstock exposed to the fixed bed
hydroprocessing
catalyst, or about 40% or less, or about 30% or less; or wherein the
hydroprocessed
effluent has sulfur content of less than about 5000 wppm, or about 3000 wppm,
or about
1000 wppm, and/or at least about 1 wppm, or at least about 100 wppm, or at
least about
500 wppm, or at least about 1000 wppm; or a combination thereof.
[0088] Embodiment 17. A hydroprocessed effluent formed according to the method
of
any of the above embodiments.
EXAMPLES
Example of Reaction System Configuration
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
[0089] FIG. 1 schematically shows an example of a reaction system for
processing
deasphalter rock in a fixed bed hydroprocessing unit. In FIG. 1, an initial
feed 105 that
includes at least a portion of deasphalter rock can be introduced into a fixed
bed
hydrotreatment reactor (or reactors) 110. The initial feed 105 can also
include a co-feed
or an aromatic solvent. The hydrotreatment reactor(s) 110 can generate an
effluent 115
that can be fractionated 120 to form any convenient number of products. As an
example,
the hydrotreated effluent 115 can be fractionated and/or separated 120 to form
an H2S
output 121, a light ends (C4-) fraction 122, a (light) naphtha boiling range
fraction (C5¨
C9) 124, a diesel boiling range fraction (C10 ¨ 600 F) 126, and a bottoms
fraction 128.
The bottoms fraction 128 can be deasphalted 130 to form a deasphalted oil 138
and a
fraction containing asphalt and/or wax 139. Examplex of suitable deasphalting
methods
can include pentane deasphalting and propane deasphalting.
[0090] FIG. 4 shows an example of integrating fixed bed hydroprocessing of
deasphalter rock into a refinery process flow. In the example shown in FIG. 4,
the fixed
bed hydroprocessing of deasphalter rock is integrated with a fluid catalytic
cracking
(FCC) unit that can provide catalytic slurry oil as a co-feed as well as light
cycle oil as an
aromatic solvent.
[0091] In FIG. 4, a vacuum resid feed 445 is separated in a solvent
deasphalting unit
440 to form a deasphalted oil 442 and deasphalter rock 405. The deasphalter
rock 405
can be combined with an FCC bottoms fraction (catalytic slurry oil) 465 as a
co-feed for
hydrotreatment in a fixed bed hydrotreater 410. Optionally, if additional
aromatic
solvent is desired, a portion of light cycle oil (not shown) can also be added
to the
deasphalter rock 405 prior to hydrotreatment 410. The effluent 415 from
hydrotreater
410 can optionally be combined with other feeds suitable for processing in an
FCC
reactor, such as a vacuum gas oil feed 454 or a portion 452 of the deasphalted
oil 442.
The hydrotreated effluent 415 can then be processed in FCC reactor 460 to form
FCC
bottoms fraction 465 and a plurality of lower boiling products 468. Any
remaining
portion of deasphalted oil 442 can, for example, be processed in a Group I
lubes plant
470 to form a plurality of products, such as an aromatic extract product 471,
a Group I
base stock product 473, and a wax product 475.
Example 1 ¨ Fixed Bed Hydroprocessing of Deasphalter Rock with Xylene Solvent
[0092] A deasphalter rock feed was formed by performing solvent
deasphalting a
vacuum resid in a ROSE unit. The resulting deasphalter rock had a density of
1.10
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
26
g/cm3, 6 wt% sulfur, 0.7 wt% nitrogen, 40 wt% micro-carbon residue, 92 wppm
Ni, and
304 wppm V. The rock is about 6 wt% 650 F ¨ 1050 F and about 94 wt% greater
than
1050 F. At room temperature the rock was a brittle solid. In order to form a
liquid feed,
the rock was dissolved in xylenes to produce a feed corresponding to about 60
wt% rock
and 40 wt% xylenes.
[0093] A
fixed bed reactor was loaded with crushed extrudates (40 ¨ 60 mesh) of a
commercially available supported CoMo catalyst. The mixture of feed and
solvent was
processed at 400 C, 1000 psig, 6000 SCF/B, and 0.08 WHSV. The reaction
configuration roughly corresponded to the configuration shown in FIG. 1. The
reaction
system was operated for about 200 days to identify any potential deactivation
of the
catalyst at long processing run times. The composition of the hydrotreated
effluent was
relatively stable from about day 80 to about 200 of the processing run. A
material
balance for the fixed bed hydroprocessing of the deasphalter rock (not
including the
xylene solvent) is also shown in FIG. 1. The material balance shown in FIG. 1
is based
on cut points between C4 and C5, between C9 and C10, and at 600 F (316 C). The
material balance can also be expressed based on a naphtha boiling range of
about C5 to
350 F (177 C), 350 F to 650 F (343 C), and 650 F ¨ 1050 F (566 C). Based on
this
second definition for describing the material balance, the hydrotreated
effluent during the
course of the processing run included about 4.5 wt% H2S, about 4 wt% light
ends (C4-),
about 7 wt% naphtha, about 15 wt% 350 F ¨ 650 F (diesel), about 32 wt% 650 F ¨
1050 F, and about 37 wt% 1050 F+. Based on the initial feed, this corresponds
to
between about 55% and 60% conversion relative to 1050 F.
[0094] FIG. 2
shows a further comparison of the composition of the hydrotreated
effluent relative to the initial deasphalter rock feed. In FIG. 2, the
abbreviation "ARC"
refers to the number of aromatic rings in a compound. The last 4 categories
include two
bars, with the left bar corresponding to the feed while the right bar
corresponds to the
hydrotreated product. As shown in FIG. 2, the initial feed based on the
deasphalter rock
includes only 4+ ring aromatics, sulfides, polar compounds, and solids.
After
hydrotreatment of the feed in FIG. 2, the about 80 wt% solids in the
deasphalter rock
feed have been reduced to about 18 wt% solids in the hydrotreated effluent.
[0095] During
the stable portion of the processing run, the fixed bed hydrotreatment
removed about 75 wt% ¨ 80 wt% of the sulfur and about 80 wt% of the metals (Ni
+ V).
As shown in FIG. 3, the hydrotreatment also resulted in an increase in API
gravity for
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
27
the hydrotreated effluent relative to the desaphalter rock that started at
about 12 and then
settled at about 8 during the stable portion of the processing run. This long
term stability
of the fixed bed hydrotreatment process was unexpected based on the nature of
the feed.
It is noted that the observed loss in activity in FIG. 3 appears to be due to
deposition of
metals on the catalyst, rather than accumulation of coke.
[0096] In a typical fixed bed process for treating a vacuum resid, a WHSV
of about
0.1 hr1 would be used under conditions suitable for conversion of about 40¨
55% of the
feed relative to 1050 F. Thus, about 10,000 barrels of catalyst are needed for
each 1000
barrels/hr of feed. The process run length for conventional resid
hydroprocessing can be
determined based on accumulation of metals, with a conventional run end point
when
about 15 wt% to about 20 wt% of metals are deposited on the catalyst.
[0097] By contrast, by processing the rock portion of a feed separately
from the
remaining deasphalted oil portion of a resid, higher net space velocities can
be achieved
while also achieving both greater conversion and longer run length. A typical
rock yield
from propane deasphalting can be about 40 wt% of a resid feed. The resulting
deasphalted oil can be processed at about 0.5 hr1 WHSV (about 1200 barrels of
catalyst
per 1000 barrels/hour) while the deasphalter rock can be processed at about
0.05 hr-1
(about 8000 barrels of catalyst per 1000 barrels/hour). The amount of combined
conversion for processing of both feeds can be about 80% to about 85%. The
deasphalted oil can have a low metals content and low coke formation on
catalyst,
allowing for extended run length. The deasphalter rock can also have an
extended run
length. Due to the reduced or minimized coke formation, the run length for
processing
the deasphalter rock can instead be based on metals accumulation. The amount
of metal
accumulation while maintaining desired catalyst activity can be about 20 wt%
to about
30 wt%, due to the reduced or minimized amount of coke deposition. Based on
the
reduced catalyst amount and the extended run length between catalyst change,
performing fixed bed processing separately on deasphalter rock and deasphalted
oil can
reduce catalyst consumption by about 20% to about 50% relative to conventional
resid
processing.
Example 2 ¨ Example of Integration with Refinery Processing
[0098] A process train similar to the configuration shown in FIG. 4 was
used to
process a vacuum resid feed. The initial vacuum resid feed had an API Gravity
of about
4.9, a sulfur content of about 5.4 wt%, a micro-carbon residue content of
about 22.3
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
28
wt%, a nitrogen content of about 0.3 wt%, and a metals content (Ni + V) of
about 200
wppm. The solubility number for the vacuum resid was about 100 and the
insolubility
number was about 25.
[0099] The vacuum resid feed was commercially deasphalted by propane
deasphalting to form a deasphalted oil and deasphalter rock. The deasphalted
oil had an
API gravity of about 16, a sulfur content of about 3.05 wt%, a micro-carbon
residue
content of about 2.4 wt%, a nitrogen content of about 0.1 wt%, a solubility
number of 40,
and an insolubility number of 0. The deasphalted oil had little or no content
of Ni and/or
V. The deasphalted oil was suitable for further processing, such as in a Group
I lubes
plant or in a fluid catalytic cracking process. The deasphalter rock had an
API gravity of
about 0.6, a sulfur content of about 6.3 wt%, a micro-carbon residue of about
30.2 wt%,
a nitrogen content of about 0.22 wt%, a metals content (Ni + V) of about 225
wppm, a
solubility number of about 125, and an insolubility number of about 25.
[00100] The deasphalter rock was used to form a feed by combining 60 wt% of
deasphalter rock with 40 wt% of a catalytic slurry oil. The catalytic slurry
oil had an
API gravity of about -5.0, a sulfur content of about 3.9 wt%, a micro-carbon
residue of
about 9.5 wt%, a nitrogen content of about 0.18 wt%, a solubility number of
about 200,
and an insolubility number of about 87. The combined deasphalter rock and
catalytic
slurry oil feed was processed at 2500 psig (17 MPag), 400 C, and 0.2 LHSV over
a
commercially available supported CoMo hydrotreating catalyst. The effluent
from
hydroprocessing of the deasphalter rock and co-feed had a sulfur content of
about 0.1
wt%, a micro-carbon residue of about 1 wt%, an API gravity of about 19, and a
nitrogen
content of about 0.05 wt%. About 20 wt% of the effluent had a boiling point
greater
than 1050 F. This effluent was suitable for use as part of a feed to a fluid
catalytic
cracking unit.
[00101] FIG. 4 shows an example of how the hydrotreatment effluent from
treating a
combination of deasphalter rock and catalytic slurry oil can be integrated
with an overall
refinery scheme. As shown in FIG. 4, the hydrotreated effluent from treating
the
deasphalter rock / catalytic slurry oil feed can be combined with additional
vacuum gas
oil to serve as a feed for a commercial scale FCC reactor. The FCC process can
generate
the catalytic slurry oil used as co-feed for the deasphalter rock. If the
amount of catalytic
slurry oil is not sufficient, light cycle oil from the FCC process can be used
as an
aromatic solvent, in an amount corresponding to up to about 50 wt% of the
feed. The
CA 02993442 2018-01-23
WO 2017/019263 PCT/US2016/041062
29
deasphalted oil can be used for Group I lube production and/or as additional
vacuum gas
oil for FCC processing.
[00102] When numerical lower limits and numerical upper limits are listed
herein,
ranges from any lower limit to any upper limit are contemplated. While the
illustrative
embodiments of the invention have been described with particularity, it will
be
understood that various other modifications will be apparent to and can be
readily made
by those skilled in the art without departing from the spirit and scope of the
invention.
Accordingly, it is not intended that the scope of the claims appended hereto
be limited to
the examples and descriptions set forth herein but rather that the claims be
construed as
encompassing all the features of patentable novelty which reside in the
present invention,
including all features which would be treated as equivalents thereof by those
skilled in
the art to which the invention pertains.
[00103] The present invention has been described above with reference to
numerous
embodiments and specific examples. Many variations will suggest themselves to
those
skilled in this art in light of the above detailed description. All such
obvious variations
are within the full intended scope of the appended claims.
