U.S. patent application number 16/015469 was filed with the patent office on 2019-01-10 for hydroprocessing of high density cracked fractions.
The applicant listed for this patent is ExxonMobil Research and Engineering Company. Invention is credited to Stephen H. Brown, Brian A. Cunningham, Samia Ilias, Jesse R. McManus, Randolph J. Smiley.
Application Number | 20190010410 16/015469 |
Document ID | / |
Family ID | 62904644 |
Filed Date | 2019-01-10 |
![](/patent/app/20190010410/US20190010410A1-20190110-D00000.png)
![](/patent/app/20190010410/US20190010410A1-20190110-D00001.png)
![](/patent/app/20190010410/US20190010410A1-20190110-D00002.png)
![](/patent/app/20190010410/US20190010410A1-20190110-D00003.png)
![](/patent/app/20190010410/US20190010410A1-20190110-D00004.png)
![](/patent/app/20190010410/US20190010410A1-20190110-D00005.png)
United States Patent
Application |
20190010410 |
Kind Code |
A1 |
Brown; Stephen H. ; et
al. |
January 10, 2019 |
HYDROPROCESSING OF HIGH DENSITY CRACKED FRACTIONS
Abstract
Systems and methods are provided for upgrading a high density
cracked feedstock, such as a catalytic slurry oil, by
hydroprocessing. The upgrading can further include performing a
separation on the effluent from hydroprocessing of the cracked
feedstock, such as a distillation (i.e., separation based on
boiling point) or a solvent-based separation. The separation on the
hydroprocessed effluent can allow for separation of an
aromatics-enriched fraction and an aromatics-depleted fraction from
the hydroprocessed effluent. The aromatics-enriched fraction and
aromatics-depleted fraction can then be separately used and/or
separately undergo further processing.
Inventors: |
Brown; Stephen H.; (Lebanon,
NJ) ; Cunningham; Brian A.; (Tokyo, JP) ;
Smiley; Randolph J.; (Hellertown, PA) ; Ilias;
Samia; (Bridgewater, NJ) ; McManus; Jesse R.;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
ExxonMobil Research and Engineering Company |
Annandale |
NJ |
US |
|
|
Family ID: |
62904644 |
Appl. No.: |
16/015469 |
Filed: |
June 22, 2018 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
62530523 |
Jul 10, 2017 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C10G 47/00 20130101;
C10G 2300/4081 20130101; C10G 67/04 20130101; C10G 2400/30
20130101; C10G 45/00 20130101; C10G 2300/202 20130101; C10G 2400/02
20130101; C10G 2400/06 20130101; C10G 65/10 20130101; C10G 49/002
20130101; C10G 11/18 20130101; C10G 2300/308 20130101; C10G 65/12
20130101; C10G 2300/301 20130101; C10G 21/00 20130101; C10G 2400/04
20130101 |
International
Class: |
C10G 65/10 20060101
C10G065/10 |
Claims
1. A method for processing a heavy cracked feedstock, comprising:
exposing a feedstock comprising a density at 15.degree. C. of 1.06
g/cm.sup.3 or more and at least 50 wt % of one or more 343.degree.
C.+ cracked fractions to a hydroprocessing catalyst under fixed bed
hydroprocessing conditions to form a hydroprocessed effluent, the
one or more 343.degree. C.+ cracked fractions having an aromatics
content of 40 wt % or more relative to a weight of the one or more
343.degree. C.+ cracked fractions, a 343.degree. C.+ portion of the
hydroprocessed effluent having a density at 15.degree. C. of 1.04
g/cm.sup.3 or less; separating the hydroprocessed effluent in one
or more separation stages to form an aromatics-enriched fraction
and an aromatics-depleted fraction; and exposing at least a portion
of the aromatics-enriched fraction to a second hydroprocessing
catalyst under second fixed bed hydroprocessing conditions to form
a second hydroprocessed effluent.
2. The method of claim 1, wherein exposing the feedstock to the
hydroprocessing catalyst further comprises exposing the at least a
portion of the aromatics-enriched fraction to the hydroprocessing
catalyst, wherein the hydroprocessing conditions comprise the
second hydroprocessing conditions, and wherein the hydroprocessed
effluent comprises the second hydroprocessed effluent.
3. The method of claim 1, wherein the separating the hydroprocessed
effluent in one or more separation stages comprises performing a
separation based on boiling point to form an aromatics-enriched
fraction and an aromatics-depleted fraction.
4. The method of claim 3, wherein the aromatics-enriched fraction
has a T10 distillation point of 371.degree. C. or more, and the
aromatics-depleted fraction has a T90 distillation point of
371.degree. C. or less.
5. The method of claim 3, wherein the aromatics-enriched fraction
has a T10 distillation point of 454.degree. C. or more, and the
aromatics-depleted fraction has a T90 distillation point of
454.degree. C. or less.
6. The method of claim 1, wherein the separating the hydroprocessed
effluent in one or more separation stages comprises performing a
solvent-based separation to form an aromatics-enriched fraction and
an aromatics-depleted fraction.
7. The method of claim 6, wherein the separating the hydroprocessed
effluent in one or more separation stages further comprises
performing a separation based on boiling point prior to performing
the solvent-based separation to form the aromatics-enriched
fraction and the aromatics-depleted fraction.
8. The method of claim 6, wherein the solvent-based separation
comprises solvent extraction using an aromatic solvent, the
aromatic solvent optionally comprising N-methylpyrrolidone.
9. The method of claim 1, the method further comprising exposing at
least a portion of the aromatics-depleted fraction to a distillate
hydroprocessing catalyst under distillate fixed bed hydroprocessing
conditions to form a distillate hydroprocessing effluent.
10. The method of claim 1, wherein the one or more 343.degree. C.+
cracked fractions comprise a coker bottoms fraction, a steam
cracker tar fraction, a coal tar, a visbreaker gas oil, or a
combination thereof.
11. The method of claim 1, wherein the one or more 343.degree. C.+
cracked fractions comprise a catalytic slurry oil, or wherein the
one or more 343.degree. C.+ cracked fractions consist essentially
of a catalytic slurry oil.
12. The method of claim 11, further comprising settling the
catalytic slurry oil prior to exposing the feed to the
hydroprocessing catalyst, the settled catalytic slurry oil having a
catalyst fines content of 1 wppm or less.
13. The method of claim 1, wherein the feedstock comprises at least
60 wt % of the one or more cracked feeds.
14. The method of claim 1, wherein the one or more 343.degree. C.+
cracked fractions comprise about 2 wt % or more n-heptane
insolubles and the hydroprocessed effluent comprises about 1 wt %
or less n-heptane insolubles; or wherein the one or more
343.degree. C.+ cracked fractions comprise at least a first amount
of micro carbon residue, and the hydroprocessed effluent comprises
less than about half of the first amount of micro carbon residue;
or a combination thereof.
15. The method of claim 1, wherein the one or more 343.degree. C.+
cracked fractions comprise at least 3 wt % of a 566.degree. C.+
portion, the effective hydroprocessing conditions being effective
for 55 wt % or more conversion of the feedstock relative to
566.degree. C.
16. The method of claim 1, wherein the feedstock comprises 4.0 wt %
or more of micro carbon residue; or wherein the hydroprocessed
effluent comprises 4.0 wt % or less of micro carbon residue; or a
combination thereof.
17. The method of claim 1, wherein the feedstock comprises at least
1.0 wt % of organic sulfur, the hydroprocessed effluent comprising
1000 wppm or less of organic sulfur.
18. The method of claim 1, wherein the fixed bed hydroprocessing
conditions comprise fixed bed hydrotreating conditions, fixed bed
hydrocracking conditions, fixed bed demetallization conditions, or
a combination thereof.
19. The method of claim 1, wherein the hydroprocessing conditions
comprise about 55 wt % or more conversion relative to 566.degree.
C., and wherein an I.sub.N of at least one of the first
hydroprocessed effluent and the second hydroprocessed effluent is
10 or more lower than an I.sub.N of the feedstock.
20. The method of claim 19, wherein a difference between an
S.sub.BN of the hydroprocessed effluent and the I.sub.N of the
hydroprocessed effluent is at least 30, or at least 40.
21. A method for processing a heavy cracked feedstock, comprising:
exposing a feedstock comprising a density at 15.degree. C. of 1.06
g/cm.sup.3 or more and at least 50 wt % of one or more 343.degree.
C.+ cracked fractions to a hydroprocessing catalyst under fixed bed
hydroprocessing conditions to form a hydroprocessed effluent, the
one or more 343.degree. C.+ cracked fractions having an aromatics
content of 40 wt % or more relative to a weight of the one or more
343.degree. C.+ cracked fractions, a 343.degree. C.+ portion of the
hydroprocessed effluent having a density at 15.degree. C. of 1.04
g/cm.sup.3 or less; separating, from the hydroprocessed effluent, a
first fraction comprising a T10 distillation point of at least
260.degree. C. and a T90 distillation point of 454.degree. C. or
less and a second fraction comprising a T10 distillation point of
at least 427.degree. C.; and exposing at least a portion of the
first fraction to a distillate hydroprocessing catalyst under
distillate fixed bed hydroprocessing conditions to form a
distillate hydroprocessing effluent.
22. The method of claim 21, wherein a 177.degree. C.-371.degree. C.
portion of the distillate hydroprocessing effluent has a sulfur
content of 50 wppm or less (or 15 wppm or less).
23. A system for processing a cracked feedstock, comprising: a
first hydroprocessing reactor comprising a first hydroprocessing
inlet, a first hydroprocessing outlet, and a fixed bed comprising a
first hydroprocessing catalyst, the first hydroprocessing inlet
comprising a feedstock comprising a density at 15.degree. C. of
1.06 g/cm.sup.3 or more and at least 50 wt % of one or more
343.degree. C.+ cracked fractions, the one or more 343.degree. C.+
cracked fractions having an aromatics content of 40 wt % or more
relative to a weight of the one or more cracked fractions, the
first hydroprocessing outlet comprising a hydroprocessed effluent;
a separation stage comprising a separation inlet, a first
separation outlet, and a second separation outlet, the first
separation inlet being in fluid communication with the first
hydroprocessing outlet, a first separation outlet comprising a
hydroprocessed effluent fraction having a T10 distillation point of
at least 260.degree. C. and a T90 distillation point of 454.degree.
C. or less, a second separation outlet comprising a hydroprocessed
effluent fraction having a T10 distillation point of at least
427.degree. C.; and a second hydroprocessing reactor comprising a
second hydroprocessing inlet, a second hydroprocessing outlet, and
a fixed bed comprising a second hydroprocessing catalyst, the
second hydroprocessing inlet being in fluid communication with the
first separation outlet.
24. The system of claim 23, wherein the first hydroprocessing inlet
is in fluid communication with the second separation outlet.
25. The system of claim 23, further comprising a fluid catalytic
cracking reactor in indirect fluid communication with the second
hydroprocessing outlet.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional
Application Ser. No. 62/530,523 filed Jul. 10, 2017, which is
herein incorporated by reference in its entirety.
FIELD
[0002] Systems and methods are provided for hydroprocessing of main
column bottoms from FCC processing to form hydroprocessed product
fractions.
BACKGROUND
[0003] Fluid catalytic cracking (FCC) processes are commonly used
in refineries as a method for converting feedstocks, without
requiring additional hydrogen, to produce lower boiling fractions
suitable for use as fuels. While FCC processes can be effective for
converting a majority of a typical input feed, under conventional
operating conditions at least a portion of the resulting products
can correspond to a fraction that exits the process as a "bottoms"
fraction. This bottoms fraction can typically be a high boiling
range fraction, such as a .about.650.degree. F.+(.about.343.degree.
C.+) fraction. Because this bottoms fraction may also contain FCC
catalyst fines, this fraction can sometimes be referred to as a
catalytic slurry oil.
SUMMARY
[0004] In various aspects, a method for processing a heavy cracked
feedstock is provided. The method can include exposing a feedstock
comprising a density at 15.degree. C. of 1.06 g/cm.sup.3 or more
and at least 50 wt % of one or more 343.degree. C.+ cracked
fractions to a hydroprocessing catalyst under fixed bed
hydroprocessing conditions to form a hydroprocessed effluent. The
one or more 343.degree. C.+ cracked fractions can having an
aromatics content of 40 wt % or more relative to a weight of the
one or more 343.degree. C.+ cracked fractions. A 343.degree. C.+
portion of the hydroprocessed effluent can have a density at
15.degree. C. of 1.04 g/cm.sup.3 or less. The hydroprocessed
effluent can then be separated in one or more separation stages to
form an aromatics-enriched fraction and an aromatics-depleted
fraction. At least a portion of the aromatics-enriched fraction can
then be exposed to a second hydroprocessing catalyst under second
fixed bed hydroprocessing conditions to form a second
hydroprocessed effluent. As an alternative, the separation can be
used to separate, from the hydroprocessed effluent, a first
fraction comprising a T10 distillation point of at least
260.degree. C. and a T90 distillation point of 454.degree. C. or
less and a second fraction comprising a T10 distillation point of
at least 427.degree. C. Optionally, in a single stage
configuration, the at least a portion of the aromatics-enriched
fraction (or the second fraction) can be recycled and combined with
the feedstock, so that the second hydroprocessing catalyst
corresponds to the first hydroprocessing catalyst. In such an
option, the second hydroprocessed effluent can represent a portion
of the first hydroprocessing effluent.
[0005] The separating of the hydroprocessed effluent to form the
aromatics-enriched fraction and the aromatics-depleted fraction can
correspond to a separation based on boiling point, a solvent-based
separation, or a combination thereof. For a boiling point
separation, some convenient cut points can correspond to forming an
aromatics-enriched fraction with a T10 distillation point of
371.degree. C. or more, or 454.degree. C. or more, with a
corresponding aromatics-depleted fraction having a T90 distillation
point of 371.degree. C. or less, or 454.degree. C. or less.
[0006] In some aspects, the method can further include exposing at
least a portion of the aromatics-depleted fraction (or at least a
portion of the first fraction) to a distillate hydroprocessing
catalyst under distillate fixed bed hydroprocessing conditions to
form a distillate hydroprocessing effluent. In such aspects, a
177.degree. C.-371.degree. C. portion of the distillate
hydroprocessing effluent can optionally having a sulfur content of
50 wppm or less.
[0007] The one or more 343.degree. C.+ cracked fractions in the
feedstock can correspond to any convenient type of heavy cracked
fraction. Suitable examples of 343.degree. C.+ cracked fractions
include a catalytic slurry oil, a coker bottoms fraction, a steam
cracker tar fraction, a coal tar, a visbreaker gas oil, or a
combination thereof. Optionally, the one or more 343.degree. C.+
cracked fractions can consist essentially of a catalytic slurry
oil, so that a catalytic slurry oil corresponds to all of the
343.degree. C.+ cracked fraction. In aspects where a catalytic
slurry oil is part of the one or more cracked fractions, the method
can further include settling the catalytic slurry oil prior to
exposing the feed to the hydroprocessing catalyst. A settled
catalytic slurry oil can typically have a minimal catalyst fines
content, such as 1 wppm or less.
[0008] In various aspects, the one or more 343.degree. C.+ cracked
fractions can include about 2 wt % or more n-heptane insolubles. In
such aspects, the hydroprocessed effluent can include about 1 wt %
or less n-heptane insolubles. Additionally or alternately, the one
or more 343.degree. C.+ cracked fractions can include at least a
first amount of micro carbon residue, and the hydroprocessed
effluent can include less than about half of the first amount of
micro carbon residue. Additionally or alternately, the one or more
343.degree. C.+ cracked fractions can include at least 3 wt % of a
566.degree. C.+ portion. In such aspects, the effective
hydroprocessing conditions can be effective for 55 wt % or more
conversion of the feedstock relative to 566.degree. C.
[0009] In various aspects, an insolubility number (I.sub.N) of at
least one of the first hydroprocessed effluent and the second
hydroprocessed effluent can be 10 or more lower than an I.sub.N of
the feedstock. Additionally or alternately, a difference between a
solubility number (S.sub.BN) of the hydroprocessed effluent and the
I.sub.N of the hydroprocessed effluent can be at least 30.
[0010] In various aspects, the feedstock can include 4.0 wt % or
more of micro carbon residue. Additionally or alternately, the
hydroprocessed effluent can include 4.0 wt % or less of micro
carbon residue. Additionally or alternately, the feedstock can
include at least 1.0 wt % of organic sulfur, with the
hydroprocessed effluent including 1000 wppm or less of organic
sulfur.
[0011] In various additional aspects, a system for processing a
cracked feedstock is provided. The system can include a first
hydroprocessing reactor comprising a first hydroprocessing inlet, a
first hydroprocessing outlet, and a fixed bed comprising a first
hydroprocessing catalyst. During operation of the system, the first
hydroprocessing inlet can contain a feedstock comprising a density
at 15.degree. C. of 1.06 g/cm.sup.3 or more and at least 50 wt % of
one or more 343.degree. C.+ cracked fractions. The one or more
343.degree. C.+ cracked fractions can correspond to any of the
types of 343.degree. C.+ cracked fractions described above in
association with the method aspects. During operation of the
system, the first hydroprocessing outlet can contain a
hydroprocessed effluent. The system can further include a
separation stage comprising a separation inlet, a first separation
outlet, and a second separation outlet. The first separation inlet
can be in fluid communication with the first hydroprocessing
outlet. During operation of the system, the first separation outlet
can contain a hydroprocessed effluent fraction having a T90
distillation point of 454.degree. C. or less. During operation of
the system, the second separation outlet can contain a
hydroprocessed effluent fraction having a T10 distillation point of
at least 427.degree. C. The system can further include a second
hydroprocessing reactor comprising a second hydroprocessing inlet,
a second hydroprocessing outlet, and a fixed bed comprising a
second hydroprocessing catalyst. The second hydroprocessing inlet
can be in fluid communication with the first separation outlet. The
first hydroprocessing inlet can optionally be in fluid
communication with the second separation outlet to allow for
recycle of a heavier portion of the hydroprocessed effluent for
further hydroprocessing. The system can optionally further include
a fluid catalytic cracking reactor in indirect fluid communication
with the second hydroprocessing outlet.
BRIEF DESCRIPTION OF THE FIGURES
[0012] FIG. 1 shows an example of a two stage reaction system for
processing of heavy cracked feedstocks.
[0013] FIG. 2 shows an example of another reaction system for
processing of heavy cracked feedstocks.
[0014] FIG. 3 shows an example of a two stage reaction system for
processing of heavy cracked feedstocks.
[0015] FIG. 4 shows an example of another reaction system for
processing of heavy cracked feedstocks.
[0016] FIG. 5 shows results related to solubility number and
insolubility number from hydrotreatment of a feedstock containing
one or more cracked fractions corresponding to catalytic slurry
oils.
DETAILED DESCRIPTION
[0017] In various aspects, systems and methods are provided for
upgrading a high density cracked feedstock, such as a catalytic
slurry oil, by hydroprocessing. The upgrading can further include
performing a separation on the effluent from hydroprocessing of the
cracked feedstock, such as a distillation (i.e., separation based
on boiling point) or a solvent-based separation. The separation on
the hydroprocessed effluent can allow for separation of an
aromatics-enriched fraction and an aromatics-depleted fraction from
the hydroprocessed effluent. The aromatics-enriched fraction and
aromatics-depleted fraction can then be separately used and/or
separately undergo further processing. In aspects where
hydroprocessing is followed by distillation, the hydroprocessing
can allow for distillation of a hydroprocessed effluent for feeds
where distillation would not normally be practical under
conventional distillation conditions. In aspects where
hydroprocessing is followed by a solvent-based separation, the
recycle of the aromatics-enriched fraction as part of the feed for
hydroprocessing can enhance run lengths, due in part to the
recycled portion of the feed providing an increase in the S.sub.BN
of the total feed to hydroprocessing.
[0018] It has been unexpectedly discovered that heavy cracked
fractions, such as catalytic slurry oils, can be hydroprocessed
with reduced or minimized amounts of coking by limiting the amount
of conventional, non-cracked fractions included in the feedstock.
While this discovery can allow for hydroprocessing of heavy cracked
fractions under conventional, fixed bed processing conditions,
further improvements are still desirable. For example, although
heavy cracked fractions can be hydroprocessed with reduced or
minimized coking and/or reactor plugging, achieving a desired
target sulfur content in the hydroprocessed effluent can require
low space velocities. It has been discovered that this is due in
part to limitations in performing aromatics saturation at high
temperatures, where the equilibrium processes for aromatic
formation/saturation can tend to favor higher levels of aromatics.
As another example, it can be desirable to increase the amount of
conventional and/or non-cracked feeds that can be included in the
feedstock while maintaining coking and/or reactor plugging at a
reduced or minimized level. It has been discovered that increasing
the quantity of aromatics in a feedstock can reduce the amount of
coking. Without being bound by any particular theory, it is
believed that increasing the aromatics content can provide an
increased solubility number (S.sub.BN) for a feedstock. It is
further believed that increased coking and/or reactor plugging
often occurs when the I.sub.N of the feedstock/products in a
reactor environment approaches near to (or possibly exceeds) the
S.sub.BN value of the feedstock/products. Increasing the S.sub.BN
of a feedstock can reduce the likelihood that the S.sub.BN will
approach near to the insolubility number (I.sub.N) of the
feedstock/products in the hydroprocessing environment.
[0019] Some additional difficulties in processing heavy cracked
feeds can be related to difficulties in performing distillation on
the feeds. Conventionally, one of the strategies for processing a
challenging feedstock can be to use distillation to separate a more
favorable portion of a feed from a typically higher boiling less
favorable portion. Under such a conventional strategy, an
atmospheric distillation can be used to separate a feed into lower
boiling portions and a higher boiling portion at a distillation cut
point between about 600.degree. F. (.about.316.degree. C.) and
about 700.degree. F. (.about.371.degree. C.). The higher boiling
portion can then correspond to a roughly 316.degree. C.+ portion,
or a roughly 343.degree. C.+ portion, or a roughly 371.degree. C.+
portion. Conventionally, a further distillation can be performed on
this higher boiling portion under reduced pressure or vacuum
distillation conditions. This can produce one or more vacuum
distillate fractions and a bottoms fraction. Unfortunately, heavy
cracked feeds such as catalytic slurry oils can often have a
density of about 1.04 g/cm.sup.3 or more, or about 1.06 g/cm.sup.3
or more, or about 1.08 g/cm.sup.3 or more, such as up to 1.14
g/cm.sup.3 or possibly still higher. At such higher density values,
performing a vacuum distillation under conventional vacuum
distillation conditions becomes increasingly difficult and/or
inefficient. In particular, such high density fractions can tend to
have poor separation characteristics under conventional vacuum
distillation conditions. As a result, either substantial amounts of
undesirable components can remain in the "desired" distillate
fraction(s), and/or substantial amounts of the desired components
can remain in the bottoms fraction.
[0020] In some aspects, one or more of the difficulties in
processing a heavy cracked feed can be reduced or mitigated by
first performing hydroprocessing on a heavy cracked feed, and then
using distillation to separate the resulting hydroprocessed
effluent. After hydroprocessing, the 343.degree. C.+ portion of the
hydroprocessed effluent can have a reduced density, such as 1.02
g/cm.sup.3 or less, or 1.0 g/cm.sup.3 or less, or 0.99 g/cm.sup.3
or less. This can allow the 343.degree. C.+ portion of the
hydroprocessed effluent to be readily separated under conventional
vacuum distillation conditions. By performing an initial
hydroprocessing step, the 343.degree. C.+ portion of the
hydroprocessed effluent can be separated to form various lower
boiling fractions and a bottoms fraction.
[0021] After an initial hydroprocessing, a separation can be
performed at any convenient cut point to assist with modifying the
conditions for equilibrium conversion/formation of aromatics. For
example, one convenient type of separation can be to perform a
separation at a distillation cut point of about 454.degree. C.
Practically, this may lead to formation of a first fraction with a
T90 or T95 distillation point of roughly 454.degree. C. and a
second fraction with a T5 or T10 distillation point of roughly
454.degree. C. At a distillation cut point of about 454.degree. C.,
a substantial majority of the 4-ring naphthenes in the
hydroprocessed effluent can be separated into the lower boiling
fraction, along with a portion of the 5-ring naphthenes. By
contrast, a majority of the 4-ring aromatics can be separated into
the higher boiling fraction. Different processing strategies can
then be used for the lower and higher boiling fractions. For
example, if additional hydroprocessing is desired for the lower
boiling fraction, lower processing temperatures can be used, as
fewer of the larger multi-ring aromatic compounds remain in the
lower boiling fraction. For the higher boiling fraction, the same
(or higher severity) processing conditions can be used, since the
equilibrium will now drive additional conversion of the aromatics
in the higher boiling fraction toward formation of the now depleted
naphthenes.
[0022] The processing and/or other use of the various lower boiling
fractions can also be different from the further processing of the
bottoms fraction. This can allow, for example, recycle of the
bottoms fraction for use as part of the initial feedstock, which
can further enhance the aromatics content of the feedstock.
Additionally or alternately, the hydroprocessed bottoms can be used
as part of a feed for fluid catalytic cracking.
[0023] In some additional or alternative aspects, one or more of
the difficulties in processing a heavy cracked feed can be reduced
or mitigated by first performing hydroprocessing on a heavy cracked
feed, and then performing a solvent-based separation on the
hydroprocessed effluent. During hydroprocessing, the amount of feed
conversion relative to 566.degree. C. will typically be
substantially less than 100%. For example, the conversion relative
to 566.degree. C. can be 30 wt % to 80 wt %. This means that 20 wt
% to 70 wt % of the 566.degree. C.+ portion of the feed is
unconverted. Such an unconverted portion of the feed can include
substantial amounts of polynuclear aromatics. For a cracked feed
such as a catalytic slurry oil, unconverted polynuclear aromatics
can also be present in lower boiling portions of the hydroprocessed
effluent. A solvent separation process can allow polynuclear
aromatics to be selectively removed from the hydroprocessed
effluent for recycle while allowing higher boiling, non-aromatic
compounds to be selectively passed on to subsequent processing
stages and/or uses. The recycled polynuclear aromatics can then be
hydroprocessed again. This can provide various advantages,
including increasing the aromatic content (and therefore S.sub.BN)
of the feedstock, and decreasing the severity of hydroprocessing
that is needed to remove lower value polynuclear aromatics while
still (eventually) allowing substantially complete conversion of
the polynuclear aromatics to higher value compounds.
[0024] Separation, recycle, and substantially complete conversion
of polynuclear aromatics is generally understood by those skilled
in the art to be impractical using conventional methods.
Conventionally, polynuclear aromatic (PNA) recycle is understood to
result in the accumulation of incompatible PNAs that accelerate
catalyst deactivation/coking, plug reactor beds, and foul equipment
with carbonaceous deposits. It has been discovered, however, that
using feeds with high S.sub.BN values can reduce or minimize the
conventional difficulties that occur when attempting to recycle
PNAs. It has further been unexpectedly discovered that mixtures of
PNAs and naphthenes distill more readily than pure PNAs.
[0025] As defined herein, the term "hydrocarbonaceous" includes
compositions or fractions that contain hydrocarbons and
hydrocarbon-like compounds that may contain heteroatoms typically
found in petroleum or renewable oil fraction and/or that may be
typically introduced during conventional processing of a petroleum
fraction. Heteroatoms typically found in petroleum or renewable oil
fractions include, but are not limited to, sulfur, nitrogen,
phosphorous, and oxygen. Other types of atoms different from carbon
and hydrogen that may be present in a hydrocarbonaceous fraction or
composition can include alkali metals as well as trace transition
metals (such as Ni, V, or Fe).
[0026] In some aspects, reference may be made to conversion of a
feedstock relative to a conversion temperature. Conversion relative
to a temperature can be defined based on the portion of the
feedstock that boils at greater than the conversion temperature.
The amount of conversion during a process (or optionally across
multiple processes) can correspond to the weight percentage of the
feedstock converted from boiling above the conversion temperature
to boiling below the conversion temperature. As an illustrative
hypothetical example, consider a feedstock that includes 40 wt % of
components that boil at 700.degree. F. (.about.371.degree. C.) or
greater. By definition, the remaining 60 wt % of the feedstock
boils at less than 700.degree. F. (.about.371.degree. C.). For such
a feedstock, the amount of conversion relative to a conversion
temperature of .about.371.degree. C. would be based only on the 40
wt % that initially boils at .about.371.degree. C. or greater. If
such a feedstock could be exposed to a process with 30% conversion
relative to a .about.371.degree. C. conversion temperature, the
resulting product would include 72 wt % of .about.371.degree. C.-
components and 28 wt % of .about.371.degree. C.+ components.
[0027] In various aspects, reference may be made to one or more
types of fractions generated during distillation of a feedstock or
effluent. Such fractions may include naphtha fractions, kerosene
fractions, diesel fractions, and other heavier (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 .about.90 wt
% of the fraction, or at least .about.95 wt % of the fraction. For
example, for many types of naphtha fractions, at least .about.90 wt
% of the fraction, or at least .about.95 wt %, can have a boiling
point in the range of .about.85.degree. F. (.about.29.degree. C.)
to .about.350.degree. F. (.about.177.degree. C.). For some heavier
naphtha fractions, at least .about.90 wt % of the fraction, and
preferably at least .about.95 wt %, can have a boiling point in the
range of .about.85.degree. F. (.about.29.degree. C.) to
.about.400.degree. F. (.about.204.degree. C.). For a kerosene
fraction, at least .about.90 wt % of the fraction, or at least
.about.95 wt %, can have a boiling point in the range of
.about.300.degree. F. (.about.149.degree. C.) to .about.600.degree.
F. (.about.288.degree. C.). For a kerosene fraction targeted for
some uses, such as jet fuel production, at least .about.90 wt % of
the fraction, or at least .about.95 wt %, can have a boiling point
in the range of .about.300.degree. F. (.about.149.degree. C.) to
.about.550.degree. F. (.about.288.degree. C.). For a diesel
fraction, at least .about.90 wt % of the fraction, and preferably
at least .about.95 wt %, can have a boiling point in the range of
.about.350.degree. F. (.about.177.degree. C.) to .about.700.degree.
F. (.about.371.degree. C.). For a (vacuum) gas oil fraction, at
least .about.90 wt % of the fraction, and preferably at least
.about.95 wt %, can have a boiling point in the range of
.about.650.degree. F. (.about.343.degree. C.) to
.about.1100.degree. F. (.about.593.degree. C.). Optionally, for
some gas oil fractions, a narrower boiling range may be desirable.
For such gas oil fractions, at least .about.90 wt % of the
fraction, or at least .about.95 wt %, can have a boiling point in
the range of .about.650.degree. F. (.about.343.degree. C.) to
.about.1000.degree. F. (.about.538.degree. C.), or
.about.650.degree. F. (.about.343.degree. C.) to .about.900.degree.
F. (.about.482.degree. C.). A residual fuel product can have a
boiling range that may vary and/or overlap with one or more of the
above boiling ranges. A residual marine fuel product can satisfy
the requirements specified in ISO 8217, Table 2.
[0028] A method of characterizing the solubility properties of a
petroleum fraction can correspond to the toluene equivalence (TE)
of a fraction, based on the toluene equivalence test as described
for example in U.S. Pat. No. 5,871,634 (incorporated herein by
reference with regard to the definition for toluene equivalence,
solubility number (S.sub.BN), and insolubility number (I.sub.N)).
The calculated carbon aromaticity index (CCAI) can be determined
according to ISO 8217. BMCI can refer to the Bureau of Mines
Correlation Index, as commonly used by those of skill in the
art.
[0029] In this discussion, the effluent from a processing stage may
be characterized in part by characterizing a fraction of the
products. For example, the effluent from a processing stage may be
characterized in part based on a portion of the effluent that can
be converted into a liquid product. This can correspond to a
C.sub.3+ portion of an effluent, and may also be referred to as a
total liquid product. As another example, the effluent from a
processing stage may be characterized in part based on another
portion of the effluent, such as a C.sub.5+ portion or a C.sub.6+
portion. In this discussion, a portion corresponding to a
"C.sub.x+" portion can be, as understood by those of skill in the
art, a portion with an initial boiling point that roughly
corresponds to the boiling point for an aliphatic hydrocarbon
containing "x" carbons.
[0030] In this discussion, a low sulfur fuel oil can correspond to
a fuel oil containing about 0.5 wt % or less of sulfur. An ultra
low sulfur fuel oil, which can also be referred to as an Emission
Control Area fuel, can correspond to a fuel oil containing about
0.1 wt % or less of sulfur. A low sulfur diesel can correspond to a
diesel fuel containing about 500 wppm or less of sulfur. An ultra
low sulfur diesel can correspond to a diesel fuel containing about
15 wppm or less of sulfur, or about 10 wppm or less.
[0031] In this discussion, reference may be made to catalytic
slurry oil, FCC bottoms, and main column bottoms. These terms can
be used interchangeably herein. It is noted that when initially
formed, a catalytic slurry oil can include several weight percent
of catalyst fines. Any such catalyst fines can be removed prior to
incorporating a fraction derived from a catalytic slurry oil into a
product pool, such as a naphtha fuel pool or a diesel fuel pool. 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.
Feedstocks for Hydroprocessing--Cracked Fractions
[0032] A catalytic slurry oil is an example of a suitable cracked
fraction for incorporation into a feedstock. It is conventionally
understood that conversion of .about.1050.degree.
F.+(.about.566.degree. C.+) vacuum resid fractions by
hydroprocessing and/or hydrocracking can be limited by
incompatibility. Under conventional understanding, at somewhere
between .about.30 wt % and .about.55 wt % conversion of the
.about.1050.degree. F.+(.about.566.degree. C.+) portion, the
reaction product during hydroprocessing can become incompatible
with the feed. For example, as the .about.566.degree. C.+ feedstock
converts to .about.1050.degree. F.- (.about.566.degree. C.-)
products, hydrogen transfer, oligomerization, and dealkylation
reactions can occur which create molecules that are increasingly
difficult to keep in solution. Somewhere between .about.30 wt % and
.about.55 wt %.about.566.degree. C.+ conversion, a second liquid
hydrocarbon phase separates. This new incompatible phase, under
conventional understanding, can correspond to mostly polynuclear
aromatics rich in N, S, and metals. The new incompatible phase can
potentially 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 this conventional
understanding, catalytic slurry oil can conventionally be expected
to exhibit properties similar to a vacuum resid fraction during
hydroprocessing. A catalytic slurry oil can have an I.sub.N of
about 70 to about 130, .about.1-6 wt % n-heptane insolubles, a
density of 1.04 g/cm.sup.3 or more, or 1.06 g/cm.sup.3 or more, and
a boiling range profile that includes about 3 wt % to about 12 wt %
or less of .about.566.degree. C.+ material. Based on the above
conventional understanding, it can be expected that hydroprocessing
of a catalytic slurry oil would cause incompatibility as the
asphaltenes and/or .about.566.degree. C.+ material converts.
[0033] In contrast to conventional understanding, it has been
discovered that hydroprocessing can be performed while reducing or
minimizing the above difficulties by using a feed composed of a
substantial portion of a catalytic slurry oil, with a minor amount
(or less) of a conventional vacuum resid feed. A catalytic slurry
oil can be processed as part of a feed where the catalytic slurry
oil corresponds to at least about 25 wt % of the feed to a process
for forming fuels, such as at least about 50 wt %, at least about
75 wt %, at least about 90 wt %, or at least about 95 wt %.
Optionally, the feed can correspond to at least about 99 wt % of a
catalytic slurry oil, therefore corresponding to a feed that
consists essentially of catalytic slurry oil. In particular, a feed
can comprise about 25 wt % to about 100 wt % catalytic slurry oil,
or about 25 wt % to about 99 wt %, or about 50 wt % to about 90 wt
%. In contrast to many types of potential feeds for production of
fuels, the asphaltenes in a catalytic slurry oil can apparently be
converted on a time scale comparable to the time scale for
conversion of other aromatic compounds in the catalytic slurry oil.
In other words, without being bound by any particular theory, the
asphaltene-type compounds in a catalytic slurry oil that are
susceptible to precipitation/insolubility can be converted at a
proportional rate to the conversion of compounds that help to
maintain solubility of asphaltene-type compounds. This can have the
effect that during hydroprocessing, the rate of decrease of the
S.sub.BN for the catalytic slurry oil can be similar to the rate of
decrease of I.sub.N, so that precipitation of asphaltenes during
processing can be reduced, minimized, or eliminated. As a result,
it has been unexpectedly discovered that catalytic slurry oil can
be processed at effective hydroprocessing conditions for
substantial conversion of the feed without causing excessive coking
of the catalyst. This can allow hydroprocessing to be used to at
least partially break down the ring structures of the aromatic
cores in the catalytic slurry oil. In a sense, hydroprocessing of a
catalytic slurry oil as described herein can serve as a type of
"hydrodeasphalting", where the asphaltene type compounds are
removed by hydroprocessing rather than by solvent extraction. In
various aspects, the 566.degree. C.+ conversion during
hydroprocessing for a feed including catalytic slurry oil can be at
least 55 wt %, or at least 65 wt %, or at least 75 wt %, such as up
to about 95 wt % or still higher.
[0034] Typically the cut point for forming a catalytic slurry oil
can be at least about 650.degree. F. (.about.343.degree. C.). As a
result, a catalytic slurry oil can have a T5 distillation (boiling)
point or a T10 distillation point of at least about 288.degree. C.,
or at least about 316.degree. C., or at least about 650.degree. F.
(.about.343.degree. C.), as measured according to ASTM D2887. In
some aspects the D2887 10% distillation point (T10) can be greater,
such as at least about 675.degree. F. (.about.357.degree. C.), or
at least about 700.degree. F. (.about.371.degree. C.). In some
aspects, a broader boiling range portion of FCC products can be
used as a feed (e.g., a 350.degree. F.+/.about.177.degree. C.+
boiling range fraction of FCC liquid product), where the broader
boiling range portion includes a 650.degree. F.+(.about.343.degree.
C.+) fraction that corresponds to a catalytic slurry oil. The
catalytic slurry oil (650.degree. F.+/.about.343.degree. 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 comprises one or more of the other feed
characteristics described herein.
[0035] In addition to and/or as an alternative to initial boiling
points, T5 distillation point, and/or T10 distillation points,
other distillation points may be useful in characterizing a
feedstock. For example, a feedstock can be characterized based on
the portion of the feedstock that boils above 1050.degree. F.
(.about.566.degree. C.). In some aspects, a feedstock (or
alternatively a 650.degree. F.+/.about.343.degree. C.+ portion of a
feedstock) can have an ASTM D2887 T95 distillation point of
1050.degree. F. (.about.566.degree. C.) or greater, or a T90
distillation point of 1050.degree. F. (.about.566.degree. C.) or
greater. If a feedstock or other sample contains components that
are not suitable for characterization using D2887, ASTM D1160 may
be used instead for such components.
[0036] In various aspects, density, or weight per volume, of the
catalytic slurry oil can be characterized. The density of the
catalytic slurry oil (or alternatively a 650.degree.
F.+/.about.343.degree. C.+ 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, such as up to about 1.20 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.
[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 can 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 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 include n-heptane insolubles (NHI)
or asphaltenes. In some aspects, the catalytic slurry oil feed (or
alternatively a .about.650.degree. F.+/.about.343.degree. C.+
portion of a feed) can contain at least about 1.0 wt % of n-heptane
insolubles or asphaltenes, or at least about 2.0 wt %, or at least
about 3.0 wt %, or at least about 5.0 wt %, such as up to about 10
wt % or more. In particular, the catalytic slurry oil feed (or
alternatively a .about.343.degree. C.+ portion of a feed) can
contain about 1.0 wt % to about 10 wt % of n-heptane insolubles or
asphaltenes, or about 2.0 wt % to about 10 wt %, or about 3.0 wt %
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
.about.343.degree. C.+ portion of a feed) can be at least about 5
wt %, or at least about 8 wt %, or at least about 10 wt %, or at
least about 12 wt %, such as up to about 20 wt % or more.
[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, such as at least about 70, at least about 80, or at
least about 90. Additionally or alternately, the IN for such a feed
can be about 140 or less, such as about 130 or less, about 120 or
less, about 110 or less, about 100 or less, about 90 or less, or
about 80 or less. Each lower bound noted above for IN can be
explicitly contemplated in conjunction with each upper bound noted
above for IN. In particular, the IN for a catalytic slurry oil feed
can be about 60 to about 140, or about 60 to about 120, or about 80
to about 140.
[0041] An additional favorable feature of hydroprocessing a
catalytic slurry oil can be the increase in product volume that can
be achieved. Due to the high percentage of aromatic cores in a
catalytic slurry oil, hydroprocessing of catalytic slurry oil can
result in substantial consumption of hydrogen. The additional
hydrogen added to a catalytic slurry oil can result in an increase
in volume for the hydroprocessed catalytic slurry oil or volume
swell. For example, the amount of C.sub.3+ liquid products
generated from hydrotreatment and FCC processing of catalytic
slurry oil can be greater than .about.100% of the volume of the
initial catalytic slurry oil. (A similar proportional increase in
volume can be achieved for feeds that include only a portion of
deasphalted catalytic slurry oil.) Hydroprocessing within the
normal range of commercial hydrotreater operations can enable
.about.2000-4000 SCF/bbl (.about.340 Nm.sup.3/m.sup.3 to .about.680
m.sup.3/m.sup.3) of hydrogen to be added to a feed corresponding to
a deasphalted catalytic slurry oil. This can result in substantial
conversion of a deasphalted catalytic slurry oil feed to
.about.700.degree. F.- (.about.371.degree. C.-) products, such as
at least about 40 wt % conversion to .about.371.degree. C.-
products, or at least about 50 wt %, or at least about 60 wt %, and
up to about 90 wt % or more. In some aspects, the
.about.371.degree. C.- product can meet the requirements for a low
sulfur diesel fuel blendstock in the U.S. Additionally or
alternately, the .about.371.degree. C.- product(s) can be upgraded
by further hydroprocessing to a low sulfur diesel fuel or
blendstock. The remaining .about.700.degree. F.+(.about.371.degree.
C.+) product can meet the normal specifications for a
<.about.0.5 wt % S bunker fuel or a <.about.0.1 wt % S bunker
fuel, and/or may be blended with a distillate range blendstock to
produce a finished blend that can meet the specifications for a
<.about.0.1 wt % S bunker fuel. Additionally or alternately, a
.about.343.degree. C.+ product can be formed that can be suitable
for use as a <.about.0.1 wt % S bunker fuel without additional
blending. The additional hydrogen for the hydrotreatment of the
catalytic slurry oil can be provided from any convenient
source.
[0042] Additionally or alternately, the remaining
.about.371.degree. C.+ product (and/or portions of the
.about.371.degree. C.+ product) can be used as feedstock to an FCC
unit and cracked to generate additional LPG, gasoline, and diesel
fuel, so that the yield of .about.371.degree. C.- products relative
to the total liquid product yield can be at least about 60 wt %, or
at least about 70 wt %, or at least about 80 wt %. Relative to the
feed, the yield of C.sub.3+ liquid products can be at least about
100 vol %, such as at least about 105 vol %, at least about 110 vol
%, at least about 115 vol %, or at least about 120 vol %. In
particular, the yield of C.sub.3+ liquid products can be about 100
vol % to about 150 vol %, or about 110 vol % to about 150 vol %, or
about 120 vol % to about 150 vol %.
[0043] More generally, the systems and methods described herein can
be used for processing feedstocks containing one or more types of
cracked feeds that have a high density prior to hydroprocessing,
such as a density of 1.04 g/cm.sup.3 or more, or 1.06 g/cm.sup.3 or
more, or 1.08 g/cm.sup.3 or more, such as up to 1.20 g/cm.sup.3 or
possibly still higher. Additionally or alternately, the feedstock
including one or more cracked feeds can have an aromatics content
of about 40 wt % to about 80 wt %, or about 40 wt % to about 70 wt
%, or about 50 wt % to about 80 wt %. Additionally or alternately,
the feedstock including one or more cracked feeds can have a
S.sub.BN of 100 to 250 and an I.sub.N of 70 to 180, with the
S.sub.BN of the feedstock being greater than the I.sub.N, the
S.sub.BN optionally being greater by at least 30, or at least 40,
or at least 50. In addition to catalytic slurry oils, other types
of cracked stocks include, but are not limited to, heavy coker gas
oils (such coker bottoms), steam cracker tars, coal tars, and
visbreaker gas oils.
[0044] For example, steam cracker tar (SCT) as used herein is also
referred to in the art as "pyrolysis fuel oil". The terms can be
used interchangeably herein. The tar will typically be obtained
from the first fractionator downstream from a steam cracker
(pyrolysis furnace) as the bottoms product of the fractionator,
nominally having a boiling point of at least about 550.degree.
F.+(.about.288.degree. C.+). Boiling points and/or fractional
weight distillation points can be determined by, for example, ASTM
D2892. Alternatively, SCT can have a T5 boiling point (temperature
at which 5 wt % will boil off) of at least about 550.degree. F.
(.about.288.degree. C.). The final boiling point of SCT can be
dependent on the nature of the initial pyrolysis feed and/or the
pyrolysis conditions, and typically can be about 1450.degree. F.
(.about.788.degree. C.) or less.
[0045] SCT can have a relatively low hydrogen content compared to
heavy oil fractions that are typically processed in a refinery
setting. In some aspects, SCT can have a hydrogen content of about
8.0 wt % or less, about 7.5 wt % or less, or about 7.0 wt % or
less, or about 6.5 wt % or less. In particular, SCT can have a
hydrogen content of about 5.5 wt % to about 8.0 wt %, or about 6.0
wt % to about 7.5 wt %. Additionally or alternately, SCT can have a
micro carbon residue (or alternatively Conradson Carbon Residue) of
at least about 10 wt %, or at least about 15 wt %, or at least
about 20 wt %, such as up to about 40 wt % or more.
[0046] SCT can also be highly aromatic in nature. The paraffin
content of SCT can be about 2.0 wt % or less, or about 1.0 wt % or
less, such as having substantially no paraffin content. The
naphthene content of SCT can also be about 2.0 wt % or less or
about 1.0 wt % or less, such as having substantially no naphthene
content. In some aspects, the combined paraffin and naphthene
content of SCT can be about 1.0 wt % or less. With regard to
aromatics, at least about 30 wt % of SCT can correspond to 3-ring
aromatics, or at least 40 wt %. In particular, the 3-ring aromatics
content can be about 30 wt % to about 60 wt %, or about 40 wt % to
about 55 wt %, or about 40 wt % to about 50 wt %. Additionally or
alternately, at least about 30 wt % of SCT can correspond to 4-ring
aromatics, or at least 40 wt %. In particular, the 4-ring aromatics
content can be about 30 wt % to about 60 wt %, or about 40 wt % to
about 55 wt %, or about 40 wt % to about 50 wt %. Additionally or
alternately, the 1-ring aromatic content can be about 15 wt % or
less, or about 10 wt % or less, or about 5 wt % or less, such as
down to about 0.1 wt %.
[0047] Due to the low hydrogen content and/or highly aromatic
nature of SCT, the solubility number (S.sub.BN) and insolubility
number (I.sub.N) of SCT can be relatively high. SCT can have a
S.sub.BN of at least about 100, and in particular about 120 to
about 230, or about 150 to about 230, or about 180 to about 220.
Additionally or alternately, SCT can have an I.sub.N of about 70 to
about 180, or about 100 to about 160, or about 80 to about 140.
Further additionally or alternately, the difference between
S.sub.BN and I.sub.N for the SCT can be at least about 30, or at
least about 40, or at least about 50, such as up to about 150.
[0048] SCT can also have a higher density than many types of crude
or refinery fractions. In various aspects, SCT can have a density
at 15.degree. C. of about 1.08 g/cm.sup.3 to about 1.20 g/cm.sup.3,
or 1.10 g/cm.sup.3 to 1.18 g/cm.sup.3. By contrast, many types of
vacuum resid fractions can have a density of about 1.05 g/cm.sup.3
or less. Additionally or alternately, density (or weight per
volume) of the heavy hydrocarbon can be determined according to
ASTM D287-92 (2006) Standard Test Method for API Gravity of Crude
Petroleum and Petroleum Products (Hydrometer Method), which
characterizes density in terms of API gravity. In general, the
higher the API gravity, the less dense the oil. API gravity can be
5.degree. or less, or 0.degree. or less, such as down to about
-10.degree. or lower.
[0049] Contaminants such as nitrogen and sulfur are typically found
in SCT, often in organically-bound form. Nitrogen content can range
from about 50 wppm to about 10,000 wppm elemental nitrogen or more,
based on total weight of the SCT. Sulfur content can range from
about 0.1 wt % to about 10 wt %, based on total weight of the
SCT.
[0050] Coker bottoms represent another type of cracked feed
suitable for hydroprocessing, optionally in combination with a
catalytic slurry oil and/or steam cracker tar and/or other cracked
fractions. Coking is a thermal cracking process that is suitable
for conversion of heavy feeds into fuels boiling range products.
The feedstock to a coker typically also includes 5 wt % to 25 wt %
recycled product from the coker, which can be referred to as coker
bottoms. This recycle fraction allows metals, asphaltenes,
micro-carbon residue, and/or other solids to be returned to the
coker, as opposed to being incorporated into a coker gas oil
product. This can maintain a desired product quality for the coker
gas oil product, but results in a net increase in the amount of
light ends and coke that are generated by a coking process. The
coker bottoms can correspond to a fraction with a T10 distillation
point of at least 550.degree. F. (288.degree. C.), or at least
300.degree. C., or at least 316.degree. C., and a T90 distillation
point of 566.degree. C. or less, or 550.degree. C. or less, or
538.degree. C. or less. The coker recycle fraction can have an
aromatic carbon content of about 20 wt % to about 50 wt %, or about
30 wt % to about 45 wt %, and a micro carbon residue content of
about 4.0 wt % to about 15 wt %, or about 6.0 wt % to about 15 wt
%, or about 4.0 wt % to about 10 wt %, or about 6.0 wt % to about
12 wt %.
[0051] In some aspects, the weight percent of catalytic slurry oil
in the feed can be greater than or equal to the amount of coker
bottoms. The amount of coker bottoms in the feed can generally be
from about 5 wt % to about 50 wt %, or about 10 wt % to about 50 wt
%, or about 20 wt % to about 35 wt %. The amount of catalytic
slurry oil in the feed can be about 20 wt % to about 95 wt %, or
about 20 wt % to about 70 wt %, or about 40 wt % to about 95 wt %,
or about 50 wt % to about 95 wt %. In aspects where the feed is
deasphalted prior to hydroprocessing, the feed can optionally
further include 5 wt % to 40 wt % of a vacuum resid fraction. The
vacuum resid fraction can have a T10 distillation point of about
510.degree. C. or greater, or about 538.degree. C. or greater, or
about 566.degree. C. or greater.
Feedstock Particle Removal
[0052] In some aspects, a feedstock including one or more cracked
feeds can include various types of particles, such as catalyst
fines present in a catalytic slurry oil and/or coke fines present
in a steam cracker tar. Such particles can optionally be removed
(such as partially removed to a desired level) by any convenient
method, such as filtration. In some aspects, an improved method of
removing particles from a blended feed can correspond to removing a
portion of particles from the blended feed by settling, followed by
using electrostatic filtration to remove additional particles.
Additionally or alternately, particles can be removed from a
blended feed using a filter with a relatively uniform porosity.
Such a filter can optionally be used in conjunction with settling,
so that larger particles can be removed from the feed prior to
filtration by the filter.
[0053] Settling can provide a convenient method for removing larger
particles from a feed. During a settling process, a feed can be
held in a settling tank or other vessel for a period of time. This
time period can be referred to as a settling time. The feed can be
at a settling temperature during the settling time. While any
convenient settling temperature can potentially be used (such as a
temperature from about 20.degree. C. to about 200.degree. C.), a
temperature of about 100.degree. C. or greater (such as at least
105.degree. C., or at least 110.degree. C.) can be beneficial for
allowing the viscosity of the blended feed to be low enough to
facilitate settling. Additionally or alternately, the settling
temperature can be about 200.degree. C. or less, or about
150.degree. C. or less, or about 140.degree. C. or less. In
particular, the settling temperature can be about 100.degree. C. to
about 200.degree. C., or about 105.degree. C. to about 150.degree.
C., or about 110.degree. C. to about 140.degree. C. The upper end
of the settling temperature can be less important, and temperatures
of still greater than 200.degree. C. may also be suitable.
[0054] After the settling time, the particles can be concentrated
in a lower portion of the settling tank. The blended feed including
a portion of catalytic slurry oil and a portion of steam cracker
tar can be removed from the upper portion of the settling tank
while leaving the particle enriched bottoms in the tank. The
settling process can be suitable for reducing the concentration of
particles having a particle size of about 25 .mu.m or greater from
the blended feed.
[0055] After removing the larger particles from the blended feed,
the blended feed can be passed into an electrostatic separator. An
example of a suitable electrostatic separator can be a
Gulftronic.TM. electrostatic separator available from General
Atomic. An electrostatic separator can be suitable for removal of
particles of a variety of sizes, including both larger particles as
well as particles down to a size of about 5 .mu.m or less or even
smaller. However, it can be beneficial to remove larger particles
using a settling process to reduce or minimize the accumulation of
large particles in an electrostatic separator. This can reduce the
amount of time required for flush and regeneration of an
electrostatic separator.
[0056] In an electrostatic separator, dielectric beads within the
separator can be charged to polarize the dielectric beads. A fluid
containing particles for removal can then be passed into the
electrostatic separator. The particles can be attracted to the
dielectric beads, allowing for particle removal. After a period of
time, the electrostatic separator can be flushed to allow any
accumulated particles in the separator to be removed.
[0057] In various aspects, an electrostatic separator can be used
in combination with a settling tank for particle removal.
Performing electrostatic separation on an blended feed effluent
from a settling tank can allow for reduction of the number of
particles in a blended feed to about 500 wppm or less, or about 100
wppm or less, or about 50 wppm or less, such as down to about 20
wppm or possibly lower. In particular, the concentration of
particles in the blended feed after electrostatic separation can be
about 0 wppm to about 500 wppm, or about 0 wppm to about 100 wppm,
or about 0 wppm to about 50 wppm, or about 1 wppm to about 20 wppm.
In some aspects, a single electrostatic separation stage can be
used to reduce the concentration of particles in the blended feed
to a desired level. In some aspects, two or more electrostatic
separation stages in series can be used to achieve a target
particle concentration.
[0058] Another option for removal of particles from a feed,
optionally after settling, can be to use a filter with a relatively
uniform porosity. Examples of such filters correspond to the
HyPulse.RTM. LSI filters available from Mott Corporation of
Farmington, Conn. Such filters can be formed using a sintered metal
fabrication technology that can allow for accurate control of
porosity. Having uniform porosity can assist with having
particulates form a cake on the inside of the filter while reducing
or minimizing the amount of particulates that penetrate into the
screen and/or reducing or minimizing the amount of cake-bridging
between filter elements.
Additional Feedstocks
[0059] In some aspects, at least a portion of a feedstock for
processing as described herein can correspond to a vacuum resid
fraction or another type 950.degree. F.+(510.degree. C.+) or
1000.degree. F.+(538.degree. C.+) fraction. Another example of a
method for forming a 950.degree. F.+(510.degree. C.+) or
1000.degree. F.+(538.degree. C.+) fraction is to perform a high
temperature flash separation. The 950.degree. F.+(510.degree. C.+)
or 1000.degree. F.+(538.degree. C.+) fraction formed from the high
temperature flash can be processed in a manner similar to a vacuum
resid.
[0060] A vacuum resid fraction or a 950.degree. F.+(510.degree.
C.+) fraction formed by another process (such as a flash
fractionation bottoms or a bitumen fraction) can be deasphalted at
low severity to form a deasphalted oil. Optionally, the feedstock
can also include a portion of a conventional feed for lubricant
base stock production, such as a vacuum gas oil.
[0061] A vacuum resid (or other 510.degree. C.+) fraction can
correspond to a fraction with a T5 distillation point (ASTM D2892,
or ASTM D7169 if the fraction will not completely elute from a
chromatographic system) of at least about 900.degree. F.
(482.degree. C.), or at least 950.degree. F. (510.degree. C.), or
at least 1000.degree. F. (538.degree. C.). Alternatively, a vacuum
resid fraction can be characterized based on a T10 distillation
point (ASTM D2892/D7169) of at least about 900.degree. F.
(482.degree. C.), or at least 950.degree. F. (510.degree. C.), or
at least 1000.degree. F. (538.degree. C.).
[0062] Resid (or other 510.degree. C.+) fractions can be high in
metals. For example, a resid fraction can be high in total nickel,
vanadium and iron contents. In an aspect, a resid fraction can
contain at least 0.00005 grams of Ni/V/Fe (50 wppm) or at least
0.0002 grams of Ni/V/Fe (200 wppm) per gram of resid, on a total
elemental basis of nickel, vanadium and iron. In other aspects, the
heavy oil can contain at least 500 wppm of nickel, vanadium, and
iron, such as up to 1000 wppm or more.
[0063] Contaminants such as nitrogen and sulfur are typically found
in resid (or other 510.degree. C.+) fractions, often in
organically-bound form. Nitrogen content can range from about 50
wppm to about 10,000 wppm elemental nitrogen or more, based on
total weight of the resid fraction. Sulfur content can range from
500 wppm to 100,000 wppm elemental sulfur or more, based on total
weight of the resid fraction, or from 1000 wppm to 50,000 wppm, or
from 1000 wppm to 30,000 wppm.
[0064] Still another method for characterizing a resid (or other
510.degree. C.+) fraction is based on the Conradson carbon residue
(CCR) of the feedstock. The Conradson carbon residue of a resid
fraction can be at least about 5 wt %, such as at least about 10 wt
% or at least about 20 wt %. Additionally or alternately, the
Conradson carbon residue of a resid fraction can be about 50 wt %
or less, such as about 40 wt % or less or about 30 wt % or
less.
Hydroprocessing of Feedstock Including One or More Cracked
Fractions
[0065] A feedstock including one or more cracked fractions can be
hydroprocessed to form a hydroprocessed effluent. This can include
hydrotreatment and/or hydrocracking to remove heteroatoms (such as
sulfur and/or nitrogen) to desired levels, reduce Conradson Carbon
content, and/or provide viscosity index (VI) uplift. Additionally
or alternately, the hydroprocessing can be performed to achieve a
desired level of conversion of higher boiling compounds in the feed
to fuels boiling range compounds. Depending on the aspect, a
feedstock can be hydroprocessed by demetallization, aromatics
saturation, hydrotreating, hydrocracking, or a combination
thereof.
[0066] In various aspects, the aromatics content of the feedstock
can be at least 50 wt %, or at least 55 wt %, or at least 60 wt %,
or at least 65 wt %, or at least 70 wt %, or at least 75 wt %, such
as up to 90 wt % or more. Additionally or alternately, the
saturates content of the feedstock can be 50 wt % or less, or 45 wt
% or less, or 40 wt % or less, or 35 wt % or less, or 30 wt % or
less, or 25 wt % or less, such as down to 10 wt % or less. In this
discussion and the claims below, the aromatics content and/or the
saturates content of a fraction can be determined based on ASTM
D7419.
[0067] Depending on the aspect, the hydroprocessing can be
performed in a configuration including at least one hydroprocessing
stage with recycle of an aromatics-enriched stream as part of the
feedstock, or in a configuration with multiple hydroprocessing
stages. The reaction conditions during demetallization and/or
hydrotreatment and/or hydrocracking of the feedstock can be
selected to generate a desired level of conversion of a feed. Any
convenient type of reactor, such as fixed bed (for example trickle
bed) reactors can be used. Conversion of the feed can be defined in
terms of conversion of molecules that boil above a temperature
threshold to molecules below that threshold. The conversion
temperature can be any convenient temperature, such as
.about.700.degree. F. (371.degree. C.) or 1050.degree. F.
(566.degree. C.). The amount of conversion can correspond to the
total conversion of molecules within the combined hydrotreatment
and hydrocracking stages. Suitable amounts of conversion of
molecules boiling above 1050.degree. F. (566.degree. C.) to
molecules boiling below 566.degree. C. include 30 wt % to 100 wt %
conversion relative to 566.degree. C., or 30 wt % to 90 wt %, or 30
wt % to 70 wt %, or 40 wt % to 90 wt %, or 40 wt % to 80 wt %, or
40 wt % to 70 wt %, or 50 wt % to 100 wt %, or 50 wt % to 90 wt %,
or 50 wt % to 70 wt %. In particular, the amount of conversion
relative to 566.degree. C. can be 30 wt % to 100 wt %, or 50 wt %
to 100 wt %, or 40 wt % to 90 wt %. Additionally or alternately,
suitable amounts of conversion of molecules boiling above
.about.700.degree. F. (371.degree. C.) to molecules boiling below
371.degree. C. include 10 wt % to 70 wt % conversion relative to
371.degree. C., or 10 wt % to 60 wt %, or 10 wt % to 50 wt %, or 20
wt % to 70 wt %, or 20 wt % to 60 wt %, or 20 wt % to 50 wt %, or
30 wt % to 70 wt %, or 30 wt % to 60 wt %, or 30 wt % to 50 wt %.
In particular, the amount of conversion relative to 371.degree. C.
can be 10 wt % to 70 wt %, or 20 wt % to 50 wt %, or 30 wt % to 60
wt %.
[0068] The hydroprocessed effluent can also be characterized based
on the product quality. After hydroprocessing (hydrotreating and/or
hydrocracking), the liquid (C.sub.3+) portion of the hydroprocessed
deasphalted oil/hydroprocessed effluent can have a sulfur content
of about 1000 wppm or less, or about 500 wppm or less, or about 100
wppm or less (such as down to .about.0 wppm). Additionally or
alternately, the hydroprocessed deasphalted oil/hydroprocessed
effluent can have a nitrogen content of 200 wppm or less, or 100
wppm or less, or 50 wppm or less (such as down to .about.0 wppm).
Additionally or alternately, the liquid (C.sub.3+) portion of the
hydroprocessed deasphalted oil/hydroprocessed effluent can have a
MCR content and/or Conradson Carbon residue content of 2.5 wt % or
less, or 1.5 wt % or less, or 1.0 wt % or less, or 0.7 wt % or
less, or 0.1 wt % or less, or 0.02 wt % or less (such as down to
.about.0 wt %). MCR content and/or Conradson Carbon residue content
can be determined according to ASTM D4530. Further additionally or
alternately, the effective hydroprocessing conditions can be
selected to allow for reduction of the n-heptane asphaltene content
of the liquid (C.sub.3+) portion of the hydroprocessed deasphalted
oil/hydroprocessed effluent to less than about 1.0 wt %, or less
than about 0.5 wt %, or less than about 0.1 wt %, and optionally
down to substantially no remaining n-heptane asphaltenes. The
hydrogen content of the liquid (C.sub.3+) portion of the
hydroprocessed deasphalted oil/hydroprocessed effluent can be at
least about 10.5 wt %, or at least about 11.0 wt %, or at least
about 11.5 wt %, such as up to about 13.5 wt % or more.
[0069] In aspects where the feedstock includes catalytic slurry
oil, coker bottoms, and/or steam cracker tar, the I.sub.N of the
hydroprocessed effluent can be at least 5 lower than the I.sub.N of
the feedstock prior to hydroprocessing, or at least 10 lower.
[0070] After hydroprocessing, the liquid (C.sub.3+) portion of the
hydroprocessed effluent can have a volume of at least about 95% of
the volume of the corresponding feed to hydroprocessing, 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. In
particular, the yield of C.sub.3+ liquid products can be about 95
vol % to about 150 vol %, or about 110 vol % to about 150 vol %.
Optionally, the C.sub.3 and C.sub.4 hydrocarbons can be used, for
example, to form liquefied propane or butane gas as a potential
liquid product. Therefore, the C.sub.3+ portion of the effluent can
be 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.
[0071] In some aspects, the portion of the hydroprocessed effluent
having a boiling range/distillation point of less than about
700.degree. F. (.about.371.degree. C.) can be used as a low sulfur
fuel oil or blendstock for low sulfur fuel oil. In other aspects,
such a portion of the hydroprocessed effluent can be used
(optionally with other distillate streams) to form ultra low sulfur
naphtha and/or distillate (such as diesel) fuel products, such as
ultra low sulfur fuels or blendstocks for ultra low sulfur fuels.
The portion having a boiling range/distillation point of at least
about 700.degree. F. (.about.371.degree. C.) can be used as an
ultra low sulfur fuel oil having a sulfur content of about 0.1 wt %
or less or optionally blended with other distillate or fuel oil
streams to form an ultra low sulfur fuel oil or a low sulfur fuel
oil. In some aspects, at least a portion of the liquid hydrotreated
effluent having a distillation point of at least about
.about.371.degree. C. can be used as a feed for FCC processing. In
still other aspects, the portion having a boiling
range/distillation point of at least about 371.degree. C. can be
used as a feedstock for lubricant base oil production.
[0072] Optionally, a feed can initially be exposed to a
demetallization catalyst prior to exposing the feed to a
hydrotreating catalyst. Deasphalted oils can have metals
concentrations (Ni+V+Fe) on the order of 10-100 wppm. A combined
catalytic slurry oil/coker bottoms feed can include still higher
levels of metals. Exposing a conventional hydrotreating catalyst to
a feed having a metals content of 10 wppm or more can lead to
catalyst deactivation at a faster rate than may desirable in a
commercial setting. Exposing a metal containing feed to a
demetallization catalyst prior to the hydrotreating catalyst can
allow at least a portion of the metals to be removed by the
demetallization catalyst, which can reduce or minimize the
deactivation of the hydrotreating catalyst and/or other subsequent
catalysts in the process flow. Commercially available
demetallization catalysts can be suitable, such as large pore
amorphous oxide catalysts that may optionally include Group VI
and/or Group VIII non-noble metals to provide some hydrogenation
activity.
[0073] In various aspects, the feedstock can be exposed to a
hydrotreating catalyst under effective hydrotreating conditions.
The catalysts used can include conventional hydroprocessing
catalysts, such as those comprising at least one Group VIII
non-noble metal (Columns 8-10 of IUPAC periodic table), preferably
Fe, Co, and/or Ni, such as Co and/or Ni; and at least one Group VI
metal (Column 6 of IUPAC periodic table), preferably Mo and/or W.
Such hydroprocessing catalysts optionally include transition metal
sulfides that are impregnated or dispersed on a refractory support
or carrier such as alumina and/or silica. The support or carrier
itself typically has no significant/measurable catalytic activity.
Substantially carrier- or support-free catalysts, commonly referred
to as bulk catalysts, generally have higher volumetric activities
than their supported counterparts.
[0074] The catalysts can either be in bulk form or in supported
form. In addition to alumina and/or silica, other suitable
support/carrier materials can include, but are not limited to,
zeolites, titania, silica-titania, and titania-alumina. Suitable
aluminas are porous aluminas such as gamma or eta having average
pore sizes from 50 to 200 .ANG., or 75 to 150 .ANG. (as determined
by ASTM D4284); a surface area (as measured by the BET method) from
100 to 300 m.sup.2/g, or 150 to 250 m.sup.2/g; and a pore volume of
from 0.25 to 1.0 cm.sup.3/g, or 0.35 to 0.8 cm.sup.3/g. More
generally, any convenient size, shape, and/or pore size
distribution for a catalyst suitable for hydrotreatment of a
distillate (including lubricant base stock) boiling range feed in a
conventional manner may be used. Preferably, the support or carrier
material is an amorphous support, such as a refractory oxide.
Preferably, the support or carrier material can be free or
substantially free of the presence of molecular sieve, where
substantially free of molecular sieve is defined as having a
content of molecular sieve of less than about 0.01 wt %.
[0075] The at least one Group VIII non-noble metal, in oxide form,
can typically be present in an amount ranging from about 2 wt % to
about 40 wt %, preferably from about 4 wt % to about 15 wt %. The
at least one Group VI metal, in oxide form, can typically be
present in an amount ranging from about 2 wt % to about 70 wt %,
preferably for supported catalysts from about 6 wt % to about 40 wt
% or from about 10 wt % to about 30 wt %. These weight percents are
based on the total weight of the catalyst. Suitable metal catalysts
include cobalt/molybdenum (1-10% Co as oxide, 10-40% Mo as oxide),
nickel/molybdenum (1-10% Ni as oxide, 10-40% Co as oxide), or
nickel/tungsten (1-10% Ni as oxide, 10-40% W as oxide) on alumina,
silica, silica-alumina, or titania.
[0076] The 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). 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. Optionally, the hydrogen treat gas can be substantially
free (less than 1 vol %) of impurities such as H.sub.2S and
NH.sub.3 and/or such impurities can be substantially removed from a
treat gas prior to use.
[0077] Hydrogen can be supplied at a rate of from about 100 SCF/B
(standard cubic feet of hydrogen per barrel of feed) (17
Nm.sup.3/m.sup.3) to about 10000 SCF/B (1700 Nm.sup.3/m.sup.3).
Preferably, the hydrogen is provided in a range of from about 2000
SCF/B (340 Nm.sup.3/m.sup.3) to about 10000 SCF/B (1700
Nm.sup.3/m.sup.3). Hydrogen can be supplied co-currently with the
input feed to the hydrotreatment reactor and/or reaction zone or
separately via a separate gas conduit to the hydrotreatment
zone.
[0078] The effective hydrotreating conditions can optionally be
suitable for incorporation of a substantial amount of additional
hydrogen into the hydrotreated effluent. During hydrotreatment, the
consumption of hydrogen by the feed in order to form the
hydrotreated effluent can correspond to at least about 1500 SCF/bbl
(.about.260 Nm.sup.3/m.sup.3) of hydrogen, or at least about 1700
SCF/bbl (.about.290 Nm.sup.3/m.sup.3), or at least about 2000
SCF/bbl (.about.330 Nm.sup.3/m.sup.3), or at least about 2200
SCF/bbl (.about.370 Nm.sup.3/m.sup.3), such as up to about 5000
SCF/bbl (.about.850 Nm.sup.3/m.sup.3) or more. In particular, the
consumption of hydrogen can be about 1500 SCF/bbl (.about.260
Nm.sup.3/m.sup.3) to about 5000 SCF/bbl (.about.850
Nm.sup.3/m.sup.3), or about 2000 SCF/bbl (.about.340
Nm.sup.3/m.sup.3) to about 5000 SCF/bbl (.about.850
Nm.sup.3/m.sup.3), or about 2200 SCF/bbl (.about.370
Nm.sup.3/m.sup.3) to about 5000 SCF/bbl (.about.850
Nm.sup.3/m.sup.3).
[0079] Hydrotreating conditions can include temperatures of
200.degree. C. to 450.degree. C., or 315.degree. C. to 425.degree.
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), or about 2.9 MPag to
about 13.9 MPag (.about.400 to 2000 psig); liquid hourly space
velocities (LHSV) of 0.1 hr.sup.-1 to 10 hr.sup.-1, or 0.1
hr.sup.-1 to 5.0 hr.sup.-1; and a hydrogen treat gas rate of from
about 430 to about 2600 Nm.sup.3/m.sup.3 (.about.2500 to 15000
SCF/bbl), or about 850 to about 1700 Nm.sup.3/m.sup.3 (.about.5000
to 10000 SCF/bbl).
[0080] In aspects where multiple hydroprocessing stages are used, a
second (or subsequent) hydrotreatment stage can be operated with
hydrotreating conditions that include a temperature that is
20.degree. C.-100.degree. C. lower than a temperature associated
with a first hydroprocessing stage; a pressure that is 1.5 MPag-10
MPag lower than a pressure associated with a first hydroprocessing
stage (or 1.5 MPag-5 MPag); and/or a space velocity that is 0.2
hr.sup.-1-2.0 hr.sup.-1 greater than a space velocity associated
with a first hydroprocessing stage. Optionally, a hydrotreating
catalyst in a second stage can be the same as a hydroprocessing
catalyst in a first stage.
[0081] In various aspects, the feedstock can be exposed to a
hydrocracking catalyst under effective hydrocracking conditions.
Hydrocracking catalysts typically contain sulfided base metals on
acidic supports, such as amorphous silica alumina, cracking
zeolites such as USY, or acidified alumina. Often these acidic
supports are mixed or bound with other metal oxides such as
alumina, titania or silica. Examples of suitable acidic supports
include acidic molecular sieves, such as zeolites or
silicoaluminophophates. One example of suitable zeolite is USY,
such as a USY zeolite with cell size of 24.30 Angstroms or less.
Additionally or alternately, the catalyst can be a low acidity
molecular sieve, such as a USY zeolite with a Si to Al ratio of at
least about 20, and preferably at least about 40 or 50. ZSM-48,
such as ZSM-48 with a SiO.sub.2 to Al.sub.2O.sub.3 ratio of about
110 or less, such as about 90 or less, is another example of a
potentially suitable hydrocracking catalyst. Still another option
is to use a combination of USY and ZSM-48. Still other options
include using one or more of zeolite Beta, ZSM-5, ZSM-35, or
ZSM-23, either alone or in combination with a USY catalyst.
Non-limiting examples of metals for hydrocracking catalysts include
metals or combinations of metals that include at least one Group
VIII metal, such as nickel, nickel-cobalt-molybdenum,
cobalt-molybdenum, nickel-tungsten, nickel-molybdenum, and/or
nickel-molybdenum-tungsten. Additionally or alternately,
hydrocracking catalysts with noble metals can also be used.
Non-limiting examples of noble metal catalysts include those based
on platinum and/or palladium. Support materials which may be used
for both the noble and non-noble metal catalysts can comprise a
refractory oxide material such as alumina, silica, alumina-silica,
kieselguhr, diatomaceous earth, magnesia, zirconia, or combinations
thereof, with alumina, silica, alumina-silica being the most common
(and preferred, in one embodiment).
[0082] When only one hydrogenation metal is present on a
hydrocracking catalyst, the amount of that hydrogenation metal can
be at least about 0.1 wt % based on the total weight of the
catalyst, for example at least about 0.5 wt % or at least about 0.6
wt %. Additionally or alternately when only one hydrogenation metal
is present, the amount of that hydrogenation metal can be about 5.0
wt % or less based on the total weight of the catalyst, for example
about 3.5 wt % or less, about 2.5 wt % or less, about 1.5 wt % or
less, about 1.0 wt % or less, about 0.9 wt % or less, about 0.75 wt
% or less, or about 0.6 wt % or less. Further additionally or
alternately when more than one hydrogenation metal is present, the
collective amount of hydrogenation metals can be at least about 0.1
wt % based on the total weight of the catalyst, for example at
least about 0.25 wt %, at least about 0.5 wt %, at least about 0.6
wt %, at least about 0.75 wt %, or at least about 1 wt %. Still
further additionally or alternately when more than one
hydrogenation metal is present, the collective amount of
hydrogenation metals can be about 35 wt % or less based on the
total weight of the catalyst, for example about 30 wt % or less,
about 25 wt % or less, about 20 wt % or less, about 15 wt % or
less, about 10 wt % or less, or about 5 wt % or less. In
embodiments wherein the supported metal comprises a noble metal,
the amount of noble metal(s) is typically less than about 2 wt %,
for example less than about 1 wt %, about 0.9 wt % or less, about
0.75 wt % or less, or about 0.6 wt % or less. It is noted that
hydrocracking under sour conditions is typically performed using a
base metal (or metals) as the hydrogenation metal.
[0083] In various aspects, the conditions selected for
hydrocracking can depend on the desired level of conversion, the
level of contaminants in the input feed to the hydrocracking stage,
and potentially other factors. For example, hydrocracking
conditions in a single stage, or in the first stage and/or the
second stage of a multi-stage system, can be selected to achieve a
desired level of conversion in the reaction system. Hydrocracking
conditions can be referred to as sour conditions or sweet
conditions, depending on the level of sulfur and/or nitrogen
present within a feed. For example, a feed with 100 wppm or less of
sulfur and 50 wppm or less of nitrogen, preferably less than 25
wppm sulfur and/or less than 10 wppm of nitrogen, represent a feed
for hydrocracking under sweet conditions.
[0084] A hydrocracking process under sour conditions can be carried
out at temperatures of about 550.degree. F. (288.degree. C.) to
about 840.degree. F. (449.degree. C.), hydrogen partial pressures
of from about 1500 psig to about 5000 psig (10.3 MPag to 34.6
MPag), liquid hourly space velocities of from 0.05 h.sup.-1 to 10
h.sup.-1, and hydrogen treat gas rates of from 35.6 m.sup.3/m.sup.3
to 1781 m.sup.3/m.sup.3 (200 SCF/B to 10,000 SCF/B). In other
embodiments, the conditions can include temperatures in the range
of about 600.degree. F. (343.degree. C.) to about 815.degree. F.
(435.degree. C.), hydrogen partial pressures of from about 1500
psig to about 3000 psig (10.3 MPag-20.9 MPag), and hydrogen treat
gas rates of from about 213 m.sup.3/m.sup.3 to about 1068
m.sup.3/m.sup.3 (1200 SCF/B to 6000 SCF/B). The LHSV can be from
about 0.25 h.sup.-1 to about 50 h.sup.-1, or from about 0.5
h.sup.-1 to about 20 h.sup.-1, preferably from about 1.0 h.sup.-1
to about 4.0 h.sup.-1.
[0085] In some aspects, a portion of the hydrocracking catalyst can
be contained in a second reactor stage. In such aspects, a first
reaction stage of the hydroprocessing reaction system can include
one or more hydrotreating and/or hydrocracking catalysts. The
conditions in the first reaction stage can be suitable for reducing
the sulfur and/or nitrogen content of the feedstock. A separator
can then be used in between the first and second stages of the
reaction system to remove gas phase sulfur and nitrogen
contaminants. One option for the separator is to simply perform a
gas-liquid separation to remove contaminant. Another option is to
use a separator such as a flash separator that can perform a
separation at a higher temperature. Such a high temperature
separator can be used, for example, to separate the feed into a
portion boiling below a temperature cut point, such as about
350.degree. F. (177.degree. C.) or about 400.degree. F.
(204.degree. C.), and a portion boiling above the temperature cut
point. In this type of separation, the naphtha boiling range
portion of the effluent from the first reaction stage can also be
removed, thus reducing the volume of effluent that is processed in
the second or other subsequent stages. Of course, any low boiling
contaminants in the effluent from the first stage would also be
separated into the portion boiling below the temperature cut point.
If sufficient contaminant removal is performed in the first stage,
the second stage can be operated as a "sweet" or low contaminant
stage.
[0086] Still another option can be to use a separator between the
first and second stages of the hydroprocessing reaction system that
can also perform at least a partial fractionation of the effluent
from the first stage. In this type of aspect, the effluent from the
first hydroprocessing stage can be separated into at least a
portion boiling below the distillate (such as diesel) fuel range, a
portion boiling in the distillate fuel range, and a portion boiling
above the distillate fuel range. The distillate fuel range can be
defined based on a conventional diesel boiling range, such as
having a lower end cut point temperature of at least about
350.degree. F. (177.degree. C.) or at least about 400.degree. F.
(204.degree. C.) to having an upper end cut point temperature of
about 700.degree. F. (371.degree. C.) or less or 650.degree. F.
(343.degree. C.) or less. Optionally, the distillate fuel range can
be extended to include additional kerosene, such as by selecting a
lower end cut point temperature of at least about 300.degree. F.
(149.degree. C.).
[0087] In aspects where the inter-stage separator is also used to
produce a distillate fuel fraction, the portion boiling below the
distillate fuel fraction includes, naphtha boiling range molecules,
light ends, and contaminants such as H.sub.2S. These different
products can be separated from each other in any convenient manner.
Similarly, one or more distillate fuel fractions can be formed, if
desired, from the distillate boiling range fraction. The portion
boiling above the distillate fuel range represents the potential
lubricant base stocks. In such aspects, the portion boiling above
the distillate fuel range is subjected to further hydroprocessing
in a second hydroprocessing stage.
[0088] A hydrocracking process under sweet conditions can be
performed under conditions similar to those used for a sour
hydrocracking process, or the conditions can be different. In an
embodiment, the conditions in a sweet hydrocracking stage can have
less severe conditions than a hydrocracking process in a sour
stage. Suitable hydrocracking conditions for a non-sour stage can
include, but are not limited to, conditions similar to a first or
sour stage. Suitable hydrocracking conditions can include
temperatures of about 500.degree. F. (260.degree. C.) to about
840.degree. F. (449.degree. C.), hydrogen partial pressures of from
about 1500 psig to about 5000 psig (10.3 MPag to 34.6 MPag), liquid
hourly space velocities of from 0.05 h.sup.-1 to 10 h.sup.-1, and
hydrogen treat gas rates of from 35.6 m.sup.3/m.sup.3 to 1781
m.sup.3/m.sup.3 (200 SCF/B to 10,000 SCF/B). In other embodiments,
the conditions can include temperatures in the range of about
600.degree. F. (343.degree. C.) to about 815.degree. F.
(435.degree. C.), hydrogen partial pressures of from about 1500
psig to about 3000 psig (10.3 MPag-20.9 MPag), and hydrogen treat
gas rates of from about 213 m.sup.3/m.sup.3 to about 1068
m.sup.3/m.sup.3 (1200 SCF/B to 6000 SCF/B). The LHSV can be from
about 0.25 h.sup.-1 to about 50 h.sup.-1, or from about 0.5
h.sup.-1 to about 20 h.sup.-1, preferably from about 1.0 h.sup.-1
to about 4.0 h.sup.-1.
[0089] In still another aspect, the same conditions can be used for
hydrotreating and hydrocracking beds or stages, such as using
hydrotreating conditions for both or using hydrocracking conditions
for both. In yet another embodiment, the pressure for the
hydrotreating and hydrocracking beds or stages can be the same.
[0090] In yet another aspect, a hydroprocessing reaction system may
include more than one hydrocracking stage. If multiple
hydrocracking stages are present, at least one hydrocracking stage
can have effective hydrocracking conditions as described above,
including a hydrogen partial pressure of at least about 1500 psig
(10.3 MPag). In such an aspect, other hydrocracking processes can
be performed under conditions that may include lower hydrogen
partial pressures. Suitable hydrocracking conditions for an
additional hydrocracking stage can include, but are not limited to,
temperatures of about 500.degree. F. (260.degree. C.) to about
840.degree. F. (449.degree. C.), hydrogen partial pressures of from
about 250 psig to about 5000 psig (1.8 MPag to 34.6 MPag), liquid
hourly space velocities of from 0.05 h.sup.-1 to 10 h.sup.-1, and
hydrogen treat gas rates of from 35.6 m.sup.3/m.sup.3 to 1781
m.sup.3/m.sup.3 (200 SCF/B to 10,000 SCF/B). In other embodiments,
the conditions for an additional hydrocracking stage can include
temperatures in the range of about 600.degree. F. (343.degree. C.)
to about 815.degree. F. (435.degree. C.), hydrogen partial
pressures of from about 500 psig to about 3000 psig (3.5 MPag-20.9
MPag), and hydrogen treat gas rates of from about 213
m.sup.3/m.sup.3 to about 1068 m.sup.3/m.sup.3 (1200 SCF/B to 6000
SCF/B). The LHSV can be from about 0.25 h.sup.-1 to about 50
h.sup.-1, or from about 0.5 h.sup.-1 to about 20 h.sup.-1, and
preferably from about 1.0 h.sup.-1 to about 4.0 h.sup.-1.
[0091] In aspects where multiple hydroprocessing stages are used, a
second (or subsequent) hydrocracking stage can be operated with
hydrocracking conditions that include a temperature that is
20.degree. C.-100.degree. C. lower than a temperature associated
with a first hydroprocessing stage; a pressure that is 1.5 MPag-10
MPag lower than a pressure associated with a first hydroprocessing
stage (or 1.5 MPag-5 MPag); and/or a space velocity that is 0.2
hr.sup.-1-2.0 hr.sup.-1 greater than a space velocity associated
with a first hydroprocessing stage. Optionally, a hydrocracking
catalyst in a second stage can be the same as a hydroprocessing
catalyst in a first stage.
Temperature-Based and Solvent-Based Separations
[0092] In various aspects, the hydroprocessed effluent from the
first hydroprocessing stage (or only stage for a single stage
reaction system) can be passed into a separation stage. A
separation stage can include separations based on boiling
point/distillation point, solvent-based separations, or a
combination thereof. Both boiling point-based and solvent-based
separations can be used to form an aromatics-enriched fraction and
an aromatics-depleted fraction from a hydroprocessed effluent. For
boiling point-based separations, forming an aromatics-enriched
fraction and an aromatics-depleted fraction can be based in part on
selecting a separation cut point that allows naphthenes of a
certain ring type (such as 4-ring naphthenes) to be separated into
an aromatics-depleted fraction while aromatics of that ring type
(such as 4-ring aromatics) are separated into the
aromatics-enriched fraction. Suitable distillation cut points for
this type of separation can be cut points at about 371.degree. C.
(for 3-rings) or about 454.degree. C. (for 4-rings). This can
result in, for example, formation of an aromatics-depleted fraction
with a T90 distillation point or T95 distillation point of
371.degree. C. or less (or 454.degree. C. or less) and a
corresponding aromatics-enriched fraction with a T10 or T5
distillation point of 371.degree. C. or more (or 454.degree. C. or
more). Such fractional weight distillation points can be
determined, for example, according ASTM D2887.
[0093] Two types of solvent processing can be performed on the
combined higher boiling portion from vacuum distillation and the
deasphalted bottoms. The first type of solvent processing is a
solvent extraction to reduce the aromatics content and/or the
amount of polar molecules. The solvent extraction process
selectively dissolves aromatic components to form an aromatics-rich
extract phase 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 5 wt % to about 25 wt %. For typical feeds, the
aromatics contents will be at least about 10 wt %.
[0094] In some aspects, the deasphalted bottoms and the higher
boiling fraction from vacuum distillation can be solvent processed
together. Alternatively, the deasphalted bottoms and the higher
boiling fraction can be solvent processed separately, to facilitate
formation of different types of lubricant base oils. For example,
the higher boiling fraction from vacuum distillation can be solvent
extracted and then solvent dewaxed to form a Group I base oil while
the deasphalted bottoms are solvent processed to form a
brightstock. Of course, multiple higher boiling fractions could
also be solvent processed separately if more than one distinct
Group I base oil and/or brightstock is desired.
[0095] The raffinate from the solvent extraction is preferably
under-extracted. In such preferred 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.
[0096] Solvent deasphalting is another type of solvent extraction
process. Instead of using an aromatic solvent to form a
high-aromatic content extract that is compatible with the solvent,
solvent deasphalting involves using an aliphatic solvent to form a
reduced aromatic content deasphalted oil that is compatible with
the deasphalting solvent. In some aspects, suitable solvents for
high yield deasphalting methods as described herein include alkanes
or other hydrocarbons (such as alkenes) containing 4 to 7 carbons
per molecule, or 5 to 7 carbons per molecule. Examples of suitable
solvents include n-butane, isobutane, n-pentane, C.sub.4+ alkanes,
C.sub.5+ alkanes, C.sub.4+ hydrocarbons, and C.sub.5+ hydrocarbons.
In some aspects, suitable solvents for low yield deasphalting can
include C.sub.3 hydrocarbons, such as propane, or alternatively
C.sub.3 and/or C.sub.4 hydrocarbons. Examples of suitable solvents
for low yield deasphalting include propane, n-butane, isobutane,
n-pentane, C.sub.3+ alkanes, C.sub.4+ alkanes, C.sub.3+
hydrocarbons, and C.sub.4+ hydrocarbons.
[0097] In this discussion, a solvent comprising C.sub.n
(hydrocarbons) is defined as a solvent composed of at least 80 wt %
of alkanes (hydrocarbons) having n carbon atoms, or at least 85 wt
%, or at least 90 wt %, or at least 95 wt %, or at least 98 wt %.
Similarly, a solvent comprising C.sub.n+ (hydrocarbons) is defined
as a solvent composed of at least 80 wt % of alkanes (hydrocarbons)
having n or more carbon atoms, or at least 85 wt %, or at least 90
wt %, or at least 95 wt %, or at least 98 wt %.
[0098] In this discussion, a solvent comprising C.sub.n alkanes
(hydrocarbons) is defined to include the situation where the
solvent corresponds to a single alkane (hydrocarbon) containing n
carbon atoms (for example, n=3, 4, 5, 6, 7) as well as the
situations where the solvent is composed of a mixture of alkanes
(hydrocarbons) containing n carbon atoms. Similarly, a solvent
comprising C.sub.n+ alkanes (hydrocarbons) is defined to include
the situation where the solvent corresponds to a single alkane
(hydrocarbon) containing n or more carbon atoms (for example, n=3,
4, 5, 6, 7) as well as the situations where the solvent corresponds
to a mixture of alkanes (hydrocarbons) containing n or more carbon
atoms. Thus, a solvent comprising C.sub.4+ alkanes can correspond
to a solvent including n-butane; a solvent include n-butane and
isobutane; a solvent corresponding to a mixture of one or more
butane isomers and one or more pentane isomers; or any other
convenient combination of alkanes containing 4 or more carbon
atoms. Similarly, a solvent comprising C.sub.5+ alkanes
(hydrocarbons) is defined to include a solvent corresponding to a
single alkane (hydrocarbon) or a solvent corresponding to a mixture
of alkanes (hydrocarbons) that contain 5 or more carbon atoms.
Alternatively, other types of solvents may also be suitable, such
as supercritical fluids. In various aspects, the solvent for
solvent deasphalting can consist essentially of hydrocarbons, so
that at least 98 wt % or at least 99 wt % of the solvent
corresponds to compounds containing only carbon and hydrogen. In
aspects where the deasphalting solvent corresponds to a C.sub.4+
deasphalting solvent, the C.sub.4+ deasphalting solvent can include
less than 15 wt % propane and/or other C.sub.3 hydrocarbons, or
less than 10 wt %, or less than 5 wt %, or the C.sub.4+
deasphalting solvent can be substantially free of propane and/or
other C.sub.3 hydrocarbons (less than 1 wt %). In aspects where the
deasphalting solvent corresponds to a C.sub.5+ deasphalting
solvent, the C.sub.5+ deasphalting solvent can include less than 15
wt % propane, butane and/or other C.sub.3-C.sub.4 hydrocarbons, or
less than 10 wt %, or less than 5 wt %, or the C.sub.5+
deasphalting solvent can be substantially free of propane, butane,
and/or other C.sub.3-C.sub.4 hydrocarbons (less than 1 wt %).
[0099] Deasphalting of heavy hydrocarbons, such as vacuum resids,
is known in the art and practiced commercially. A deasphalting
process typically corresponds to contacting a heavy hydrocarbon
with an alkane solvent (propane, butane, pentane, hexane, heptane
etc and their isomers), either in pure form or as mixtures, to
produce two types of product streams. One type of product stream
can be a deasphalted oil extracted by the alkane, which is further
separated to produce deasphalted oil stream. A second type of
product stream can be a residual portion of the feed not soluble in
the solvent, often referred to as rock or asphaltene fraction. The
deasphalted oil fraction can be further processed into make fuels
or lubricants. The rock fraction can be further used as blend
component to produce asphalt, fuel oil, and/or other products. The
rock fraction can also be used as feed to gasification processes
such as partial oxidation, fluid bed combustion or coking
processes. The rock can be delivered to these processes as a liquid
(with or without additional components) or solid (either as pellets
or lumps).
[0100] During solvent deasphalting, the input feed to the solvent
deasphalting unit can be mixed with a 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. The portion
of the deasphalted feedstock that is extracted with the solvent is
often referred to as deasphalted oil. 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
40.degree. C. to 200.degree. C., or 40.degree. C. to 150.degree.
C., depending on the nature of the feed and the solvent. The
pressure during solvent deasphalting can be from about 50 psig
(.about.345 kPag) to about 1000 psig (.about.6900 kPag).
Examples of Reaction System Configurations
[0101] FIG. 1 schematically shows an example of a reaction system
for processing a feedstock including one or more cracked fractions.
In FIG. 1, a feedstock 105 that includes one or more cracked
fractions and a hydrogen-containing stream 101 are introduced into
first stage hydroprocessing reactor(s) 110. The first stage
hydroprocessing reactor(s) 110 can correspond to, for example,
fixed bed (such as trickle bed) reactor(s) that include
demetallization catalyst, hydrotreating catalyst, and/or
hydrocracking catalyst. This results in generation of a
hydroprocessed effluent 115. The hydroprocessed effluent 115 can be
separated in a separation stage. In FIG. 1, the separation stage
corresponds to a separation stage based on performing a boiling
point separation. The separation stage in FIG. 1 includes both an
atmospheric distillation tower 120 and a vacuum distillation tower
130. Optionally, other separators (such as a flash separator for
removing light ends prior to atmospheric distillation tower 120)
could also be included as part of a separation stage.
[0102] Atmospheric distillation tower 120 can separate
hydroprocessed effluent 115 into various fractions, such as light
ends 122, naphtha boiling range fraction(s) 124, distillate fuel
boiling range fraction(s) 126, and a bottoms fraction 128. The
bottoms fraction 128 can be passed into a vacuum distillation tower
130 for further separation. For example, the vacuum distillation
tower 130 can separate bottoms fraction 128 into any remaining
light components 132, an intermediate boiling range fraction 135,
and a bottoms fraction 138. The boiling range for intermediate
boiling range fraction 135 can be dependent on the desired
composition. For example, an intermediate boiling range fraction
135 with a T90 distillation point of .about.482.degree. C. or more
can be suitable for removing the heaviest, most aromatic components
prior to second stage hydroprocessing unit 140. As another example,
an intermediate boiling range fraction 135 with a T90 distillation
point of .about.371.degree. C. or less can be suitable for
producing an intermediate boiling range fraction that contains a
majority of the three-ring naphthenes from bottoms fraction 128
while the vacuum bottoms 138 contains a majority of the three-ring
aromatics from bottoms fraction 128. Based on this split of
three-ring naphthenes and three-ring aromatics into different
fractions, the intermediate boiling range fraction 135 can
correspond to an aromatics-depleted fraction while vacuum bottoms
fraction 138 can correspond to an aromatics-enriched fraction. In
this type of example, instead of using the vacuum bottoms 138 as
part of the feed to fluid catalytic cracking unit 190, the vacuum
bottoms can be recycled (not shown) to first hydroprocessing stage
110. This type of recycle is illustrated in connection with the
single stage processing configuration shown in FIG. 2, as discussed
further below. As still another example, an intermediate boiling
range fraction 135 with a T90 distillation point of
.about.454.degree. C. or less can be suitable for producing an
intermediate boiling range fraction that contains a majority of the
four-ring naphthenes (and optionally five-ring naphthenes) from
bottoms fraction 128 while the vacuum bottoms 138 contains a
majority of the four-ring aromatics from bottoms fraction 128. This
type of vacuum bottoms 138 can also be suitable for recycle to
first hydroprocessing stage 110. Based on this split of four-ring
naphthenes and four-ring aromatics into different fractions, the
intermediate boiling range fraction 135 can correspond to an
aromatics-depleted fraction while vacuum bottoms fraction 138 can
correspond to an aromatics-enriched fraction.
[0103] The intermediate boiling range fraction 135 can then be
passed into a second hydroprocessing stage 140, along with optional
hydrogen-containing stream 141. The resulting second stage
hydroprocessed effluent 145 can be passed through a separation
stage 150, such as a knock-out drum, to remove lower boiling
components. For example, lower boiling component stream 152 can
correspond to a C.sub.6- stream (i.e., a stream including roughly
n-hexane, cyclohexane, and lower boiling components). The remaining
heavier portion 155 of hydrotreated effluent 145 can then be used
for any convenient purpose. For example, the twice-hydroprocessed
effluent 145 (or the remaining heavier portion 155 thereof) can be
suitable for use as a feed to a fluid catalytic cracking unit 190.
Optionally, vacuum bottoms 138 can also be passed into fluid
catalytic cracking unit 190. Additionally or alternately,
twice-hydroprocessed effluent 145 (or the remaining heavier portion
155 thereof) can be suitable for use as a feed to a hydrocracking
unit or as a blend component for a low sulfur fuel oil.
[0104] The flow paths in FIG. 1 can represent fluid communication
between the components. Fluid communication can refer to direct
fluid communication or indirect fluid communication. Indirect fluid
communication refers to fluid communication where one or more
intervening process elements are passed through for fluids (and/or
solids) that are communicated between the indirectly communicating
elements. For example, vacuum distillation tower 130 is in indirect
fluid communication with first stage hydroprocessing reactor(s) 110
via atmospheric distillation tower 120.
[0105] FIG. 2 schematically shows another example of a reaction
system for processing a feedstock including one or more cracked
fractions. The example of a reaction system in FIG. 2 corresponds
to a single stage reaction system that uses recycle to achieve at
least some of the benefits of a multi-stage reaction system. In
FIG. 2, a feedstock 205 that includes one or more cracked fractions
and a hydrogen-containing stream 201 are introduced into
hydroprocessing reactor(s) 210. The hydroprocessing reactor(s) 210
can correspond to, for example, fixed bed (such as trickle bed)
reactor(s) that include demetallization catalyst, hydrotreating
catalyst, and/or hydrocracking catalyst. This results in generation
of a hydroprocessed effluent 215. The hydroprocessed effluent 215
can be separated in a separation stage. In FIG. 2, the separation
stage corresponds to a separation stage based on performing a
boiling point separation. The separation stage in FIG. 2 includes
both an atmospheric distillation tower 220 and a vacuum
distillation tower 230. Optionally, other separators (such as a
flash separator for removing light ends prior to atmospheric
distillation tower 220) could also be included as part of a
separation stage.
[0106] Atmospheric distillation tower 220 can separate
hydroprocessed effluent 215 into various fractions, such as light
ends 222, naphtha boiling range fraction(s) 224, distillate fuel
boiling range fraction(s) 226, and a bottoms fraction 228. The
bottoms fraction 228 can be passed into a vacuum distillation tower
230 for further separation. For example, the vacuum distillation
tower 230 can separate bottoms fraction 228 into any remaining
light components 232 and a plurality of heavier fractions. The
heavier fractions can include an intermediate boiling range
fraction 235 with a T90 distillation point of .about.454.degree. C.
or less that contains a majority of the four-ring naphthenes (and
optionally five-ring naphthenes) from bottoms fraction 228. The
heavier fractions can also include a vacuum bottoms 238 that
contains a majority of the four-ring aromatics from bottoms
fraction 228.
[0107] The intermediate boiling range fraction 235 can optionally
be passed into a separation stage 250, such as a knock-out drum, to
remove lower boiling components. For example, lower boiling
component stream 252 can correspond to a C.sub.6- stream (i.e., a
stream including roughly n-hexane, cyclohexane, and lower boiling
components). The remaining heavier portion 255 of intermediate
boiling range fraction 235 can then be used for any convenient
purpose. For example, the intermediate boiling range fraction 235
(or the remaining heavier portion 255 thereof) can be suitable for
use as a feed to a fluid catalytic cracking unit 290. Additionally
or alternately, the intermediate boiling range fraction 235 (or the
remaining heavier portion 255 thereof) can be suitable for use as a
feed to a hydrocracking unit or as a blend component for a low
sulfur fuel oil.
[0108] FIG. 3 shows still another example of a configuration for
hydroprocessing a feedstock that includes one or more cracked
fractions. In FIG. 3, the configuration includes a separation stage
that involves both boiling point separation and solvent-based
separation. In FIG. 3, a feedstock 305 that includes one or more
cracked fractions and a hydrogen-containing stream 301 are
introduced into first stage hydroprocessing reactor(s) 310. The
first stage hydroprocessing reactor(s) 310 can correspond to, for
example, fixed bed (such as trickle bed) reactor(s) that include
demetallization catalyst, hydrotreating catalyst, and/or
hydrocracking catalyst. This results in generation of a
hydroprocessed effluent 315. The hydroprocessed effluent 315 can be
separated in a separation stage. In FIG. 3, the separation stage
includes an optional flash separator 350 and a solvent extraction
unit 360, or another type of solvent-based separator. Another
option for a solvent-based separator can be a solvent deasphalting
unit. The hydroprocessed effluent 315 can be passed into optional
flash separator 350 to remove a lower boiling portion of the
effluent, such as a C.sub.6- stream 352. The remaining portion 355
of hydroprocessed effluent 315 can then be solvent extracted 360.
Solvent extraction unit 360 can generate an extract fraction 368
that is enriched in aromatics relative to the remaining portion 355
of hydroprocessed effluent 315. After (optional) removal of
solvent, the extract 368 can be recycled as part of feedstock 305,
which can increase the aromatics content of feedstock 305 prior to
entering first stage hydroprocessing reactor(s) 310. Solvent
extraction unit 360 can also generate a raffinate fraction 365 that
is passed into second hydroprocessing stage reactor(s) 340, along
with a (optional) hydrogen-containing stream (not shown). The
second hydroprocessing stage reactor(s) 340 can generate a second
hydroprocessed effluent 345. In some aspects, such as the
configuration shown in FIG. 3, the second hydroprocessed effluent
345 can be fractionated in a separation stage 370 (such as an
atmospheric distillation tower) to form, for example, naphtha
boiling range fraction(s) 374, distillate fuel boiling range
fraction(s) 376, and a bottoms fraction 378. The bottoms fraction
378 can be used as a feed for fluid catalytic cracking, or
alternatively the bottoms fraction 378 can be recycled as part of
the input flow into second stage hydroprocessing reactor(s) 340. As
an alternative, separation stage 370 could correspond to a
knock-out drum or other flash separator for removing lower boiling
components (such as a C.sub.6- stream) from second hydroprocessing
effluent 345, and a remaining portion of second hydroprocessing
effluent 345 could be used as a low sulfur fuel oil and/or passed
into a fluid catalytic cracking unit. This type of configuration is
further illustrated in FIG. 4, in conjunction with illustrating a
single stage hydroprocessing configuration that involves a
solvent-based separation stage.
[0109] In FIG. 4, a feedstock 405 that includes one or more cracked
fractions and a hydrogen-containing stream 401 are introduced into
hydroprocessing reactor(s) 410. The hydroprocessing reactor(s) 410
can correspond to, for example, fixed bed (such as trickle bed)
reactor(s) that include demetallization catalyst, hydrotreating
catalyst, and/or hydrocracking catalyst. This results in generation
of a hydroprocessed effluent 415. The hydroprocessed effluent 415
can be separated in a separation stage. In FIG. 4, the separation
stage corresponds to an atmospheric distillation tower 420 followed
by a solvent extraction unit 460. Atmospheric distillation tower
420 can produce a light ends fraction 422, naphtha boiling range
fraction(s) 424, distillate boiling range fraction(s) 426, and a
bottoms fraction 428. Bottoms fraction 428 can then be passed into
solvent extraction unit 460 (or alternatively a solvent
deasphalting unit) to produce an extract 468 and a raffinate 465.
Extract 468 can be recycled for use as part of feedstock 405.
Raffinate 465 can be passed into fluid catalytic cracking unit 490.
Alternatively, raffinate 465 could be used as a low sulfur fuel oil
and/or as a feed for a hydrocracking unit (not shown).
Example 1--Properties of Catalytic Slurry Oils and Hydroprocessed
Catalytic Slurry Oils
[0110] Catalytic slurry oils were obtained from fluid catalytic
cracking (FCC) processes operating on various feeds. Table 1 shows
results from characterization of the catalytic slurry oils.
Additionally, a blend of catalytic slurry oils from several FCC
process sources was also formed and characterized.
TABLE-US-00001 TABLE 1 Characterization of Catalytic Slurry Oils
CSO X CSO 1 CSO 2 CSO 3 CSO 4 (Blend) API Gravity (15.degree. C.)
-7.5 -9.0 1.2 -5.0 -3.0 S (wt %) 4.31 4.27 1.11 1.82 3.07 N (wppm)
1940 2010 1390 1560 1750 H (wt %) 6.6 6.5 8.4 7.0 7.3 MCR (wt %)
11.5 14.6 4.7 13.4 12.5 n-heptane insolubles 4.0 8.7 0.4 5.0 0.7
(wt %) GCD (ASTM D2887) (wt %) <316.degree. C. 2 4 3 316.degree.
C.-371.degree. C. 11 13 12 371.degree. C.-427.degree. C. 43 40 36
427.degree. C.-482.degree. C. 27 26 28 482.degree. C.-538.degree.
C. 7 10 10 538.degree. C.-566.degree. C. 2 2 2 566.degree. C.+ 8 5
9
[0111] As shown in Table 1, typical catalytic slurry oils (or
blends of such slurry oils) can represent a low value and/or
challenged feed. The catalytic slurry oils have an API Gravity at
15.degree. C. of less than 1.5, and often less than 0. The
catalytic slurry oils can have sulfur contents of greater than 1.0
wt %, nitrogen contents of at least 1000 wppm, and hydrogen
contents of less than 8.5 wt %, or less than 7.5 wt %, or less than
7.0 wt %. The catalytic slurry oils can also be relatively high in
micro carbon residue (MCR), with values of at least 4.5 wt %, or at
least 6.5 wt %, and in some cases greater than 10 wt %. The
catalytic slurry oils can also contain a substantial n-heptane
insolubles (asphaltene) content, for example at least 0.3 wt %, or
at least 1.0 wt %, or at least 4.0 wt %. It is noted that the
boiling range of the catalytic slurry oils has more in common with
a vacuum gas oil than a vacuum resid, as less than 10 wt % of the
catalytic slurry oils corresponds to 566.degree. C.+ compounds, and
less than 15 wt % corresponds to 538.degree. C.+ compounds.
[0112] The blend of catalytic slurry oils (CSO X) from Table 1 was
used as a feedstock for a pilot scale processing plant. The blend
of catalytic slurry oils had a density of 1.12 g/cm.sup.3, a T10
distillation point of 354.degree. C., a T50 of 427.degree. C., and
a T90 of 538.degree. C. The blend contained roughly 12 wt % MCR,
had a sulfur content of .about.3 wt %, a nitrogen content of 2500
wppm, and a hydrogen content of .about.7.4 wt %. A compositional
analysis of the blend determined that the blend included 10 wt %
saturates, 70 wt % aromatics with 4 or more rings, and 20 wt %
aromatics with 1-3 rings.
[0113] The blend was used as a feedstock for hydroprocessing in a
reaction system with a single hydrotreating stage. The feedstock
was exposed to a commercially available medium pore NiMo supported
hydrotreating catalyst. The start of cycle conditions were a total
pressure of .about.2600 psig, .about.0.25 LHSV, .about.370.degree.
C., and .about.10,000 SCF/B of hydrogen treat gas. The conditions
resulted in total product with an organic sulfur content of about
125 wppm. The total product from hydroprocessing was analyzed. The
total product at start of run included 3 wt % H.sub.2S; 1 wt % of
C.sub.4- (i.e., light ends); 5 wt % naphtha boiling range
compounds; 47 wt % of 177.degree. C.-371.degree. C. (diesel boiling
range) compounds, which had a sulfur content of less than 15 wppm;
and 45 wt % of 371.degree. C.+ compounds. The 371.degree. C.+
compounds had a specific gravity of .about.1.0 g/cm.sup.3. The
371.degree. C.+ fraction was suitable for use as a hydrocracker
feed, a FCC feed, and/or sale as a fuel oil. The yield of
566.degree. C.+ compounds was 2.5 wt %. Hydrogen consumption at the
start of hydroprocessing was .about.3400 SCF/B. The feed was
processed in the pilot reactor for 300 days, with adjustments to
the conditions to maintain the organic sulfur content in the total
product at roughly 125 wppm. The end of cycle conditions were
.about.2600 psig, .about.0.25 LHSV, .about.410.degree. C., and
.about.10,000 SCF/B of hydrogen treat gas. The total product at end
of run included 3 wt % H.sub.2S; 3 wt % of C.sub.4- (i.e., light
ends); 8 wt % naphtha boiling range compounds; 45 wt % of
177.degree. C.-371.degree. C. (diesel boiling range) compounds,
which had a sulfur content of less than 15 wppm; and 41 wt % of
371.degree. C.+ compounds with a specific gravity of 1.0
g/cm.sup.3. Hydrogen consumption at the end of hydroprocessing was
.about.3300 SCF/B. By the end of the run, greater than 90 wt % of
the 566.degree. C.+ compounds were being converted. There was no
build up in pressure during the course of the run. This lack of
pressure build up and the general stability of the run,
particularly at the end of run conditions which included a
temperature of 410.degree. C., was surprising.
[0114] Without being bound by any particular theory, it is believed
that the surprising stability of the process is explained in part
by the S.sub.BN and I.sub.N values of the hydrotreated effluent
during the course of the processing run, and the corresponding
difference between those values. FIG. 5 shows measured values for
the S.sub.BN and I.sub.N of the liquid portion (C.sub.5+) of the
hydroprocessed effluent in relation to the amount of 566.degree.
C.+ conversion. The amount of 566.degree. C.+ conversion roughly
corresponds to the length of processing time, as the amount of
conversion roughly correlates with the temperature increases
required to maintain the organic sulfur content of the
hydroprocessed effluent at the desired target level of .about.125
wppm. As shown in FIG. 5, both the S.sub.BN and the I.sub.N of the
hydroprocessed effluent decrease with increasing conversion, but
the difference between S.sub.BN and I.sub.N in the hydroprocessed
effluent remains relatively constant at roughly 40 to 50. This
unexpectedly large difference in S.sub.BN and I.sub.N even at
90.sub.+ wt % conversion relative to 566.degree. C. indicates that
the hydroprocessed effluent should have a low tendency to cause
coke formation in the reactor and/or otherwise deposit solids that
can cause plugging.
Example 2--Solvent Separation for Processing of Cracked
Fractions
[0115] The blend of catalytic slurry oils from Example 1 was
processed in a configuration similar to the first hydroprocessing
stage and separation stage shown in FIG. 3. The first stage
hydroprocessing (hydrotreating) conditions included exposing the
feed to a catalyst similar to the NiMo supported catalyst in
Example 1 at a total pressure of .about.2400 psig, .about.1.0 LHSV,
.about.370.degree. C., and .about.10,000 SCF/B of hydrogen treat
gas in order to generate a hydroprocessed effluent. The total
liquid product of the hydroprocessed effluent had a density of 1.04
g/cm.sup.3 and an organic sulfur content of about 0.5 wt %. A
gas-liquid separator was then used to remove light ends (C.sub.6-)
and H.sub.2S from the effluent. The remaining portion of the
effluent, corresponding to the total liquid product, had an initial
boiling point of about 227.degree. C., which was high enough to
allow for solvent extraction of the total liquid product without
further distillation. The total liquid product was solvent
extracted using N-methylpyrrolidone at a 0.25:1 (v/v) treat rate.
This resulted in a raffinate phase corresponding to 60 wt % of the
total liquid product and an extract phase corresponding to 40 wt %
of the total liquid product. The raffinate product had a density of
0.99 g/cm.sup.3 and a sulfur content of .about.500 wppm. The
raffinate stream was suitable for use as a high value LSFO (low
sulfur fuel oil) blending component for blending off of vacuum
resid streams with greater than 0.5 wt % sulfur content.
Alternatively, the raffinate could be used as a high quality feed
for a distillate hydrocracker, which could correspond to the second
stage hydroprocessing unit shown in FIG. 3. Based on the product
quality into the second stage hydroprocessing unit, it is expected
that the second stage hydroprocessing unit could be operated at a
LHSV of 0.5 hr.sup.-1 or greater while producing a diesel boiling
range product with a sulfur content of 15 wppm or less. If gasoline
production is more desirable, still another option could be to
hydrotreat the raffinate prior to passing the twice hydrotreated
effluent into a fluid catalytic cracking process.
[0116] In another processing run, the blend of catalytic slurry
oils from Example 1 was processed in a configuration similar to
FIG. 4. The hydroprocessing (hydrotreating) conditions included
exposing the feed to a catalyst similar to the NiMo supported
catalyst in Example 1 at a total pressure of .about.2400 psig,
.about.0.25 LHSV, .about.370.degree. C., and .about.10,000 SCF/B of
hydrogen treat gas in order to generate a hydroprocessed effluent.
The total liquid product had a density of 0.98 g/cm.sup.3 and a
sulfur content of .about.150 wppm. The total liquid product was
distilled to form .about.5 wt % of a naphtha boiling range fraction
(C.sub.6-177.degree. C.), .about.50 wt % of a diesel fuel boiling
range fraction (177.degree. C.-371.degree. C.), and .about.45 wt %
of 371.degree. C.+ bottoms. The 371.degree. C.+ product was
extracted with N-methylpyrrolidone at a 0.25:1 (v/v) treat rate,
which split the 371.degree. C.+ product into 70 wt % of raffinate
with a density of 0.94 g/cm.sup.3 and 30 wt % of an extract with a
density of 1.07 g/cm.sup.3. The raffinate can be suitable for
further processing in, for example, a fluid catalytic cracker,
while the extract can be, for example, blended off as low sulfur
fuel oil and/or recycled back as part of the feedstock to the
hydroprocessing stage.
Additional Embodiments
Embodiment 1
[0117] A method for processing a heavy cracked feedstock,
comprising: exposing a feedstock comprising a density at 15.degree.
C. of 1.06 g/cm.sup.3 or more and at least 50 wt % of one or more
343.degree. C.+ cracked fractions (or at least 60 wt %, or at least
70 wt %) to a hydroprocessing catalyst under fixed bed
hydroprocessing conditions to form a hydroprocessed effluent, the
one or more 343.degree. C.+ cracked fractions having an aromatics
content of 40 wt % or more relative to a weight of the one or more
343.degree. C.+ cracked fractions, a 343.degree. C.+ portion of the
hydroprocessed effluent having a density at 15.degree. C. of 1.04
g/cm.sup.3 or less; separating the hydroprocessed effluent in one
or more separation stages to form an aromatics-enriched fraction
and an aromatics-depleted fraction; and exposing at least a portion
of the aromatics-enriched fraction to a second hydroprocessing
catalyst under second fixed bed hydroprocessing conditions to form
a second hydroprocessed effluent.
Embodiment 2
[0118] The method of Embodiment 1, wherein exposing the feedstock
to the hydroprocessing catalyst further comprises exposing the at
least a portion of the aromatics-enriched fraction to the
hydroprocessing catalyst, wherein the hydroprocessing conditions
comprise the second hydroprocessing conditions, and wherein the
hydroprocessed effluent comprises the second hydroprocessed
effluent.
Embodiment 3
[0119] The method of any of the above embodiments, wherein the
separating the hydroprocessed effluent in one or more separation
stages comprises performing a separation based on boiling point to
form an aromatics-enriched fraction and an aromatics-depleted
fraction.
Embodiment 4
[0120] The method of Embodiment 3, wherein the aromatics-enriched
fraction has a T10 distillation point of 371.degree. C. or more,
and the aromatics-depleted fraction has a T90 distillation point of
371.degree. C. or less; or wherein the aromatics-enriched fraction
has a T10 distillation point of 454.degree. C. or more, and the
aromatics-depleted fraction has a T90 distillation point of
454.degree. C. or less.
Embodiment 5
[0121] The method of Embodiment 1 or 2, wherein the separating the
hydroprocessed effluent in one or more separation stages comprises
performing a solvent-based separation to form an aromatics-enriched
fraction and an aromatics-depleted fraction, the solvent-based
separation optionally comprising solvent extraction using an
aromatic solvent, the aromatic solvent optionally comprising
N-methylpyrrolidone.
Embodiment 6
[0122] The method of Embodiment 5, wherein the separating the
hydroprocessed effluent in one or more separation stages further
comprises performing a separation based on boiling point prior to
performing the solvent-based separation to form the
aromatics-enriched fraction and the aromatics-depleted
fraction.
Embodiment 7
[0123] The method of any of the above embodiments, the method
further comprising exposing at least a portion of the
aromatics-depleted fraction to a distillate hydroprocessing
catalyst under distillate fixed bed hydroprocessing conditions to
form a distillate hydroprocessing effluent, a 177.degree.
C.-371.degree. C. portion of the distillate hydroprocessing
effluent optionally having a sulfur content of 50 wppm or less (or
15 wppm or less).
Embodiment 8
[0124] A method for processing a heavy cracked feedstock,
comprising: exposing a feedstock comprising a density at 15.degree.
C. of 1.06 g/cm.sup.3 or more and at least 50 wt % of one or more
343.degree. C.+ cracked fractions (or at least 60 wt %, or at least
70 wt %) to a hydroprocessing catalyst under fixed bed
hydroprocessing conditions to form a hydroprocessed effluent, the
one or more 343.degree. C.+ cracked fractions having an aromatics
content of 40 wt % or more relative to a weight of the one or more
343.degree. C.+ cracked fractions, a 343.degree. C.+ portion of the
hydroprocessed effluent having a density at 15.degree. C. of 1.04
g/cm.sup.3 or less; separating, from the hydroprocessed effluent, a
first fraction comprising a T10 distillation point of at least
260.degree. C. (or at least 300.degree. C., or at least 340.degree.
C.) and a T90 distillation point of 454.degree. C. or less and a
second fraction comprising a T10 distillation point of at least
427.degree. C.; and exposing at least a portion of the first
fraction to a distillate hydroprocessing catalyst under distillate
fixed bed hydroprocessing conditions to form a distillate
hydroprocessing effluent, a 177.degree. C.-371.degree. C. portion
of the distillate hydroprocessing effluent optionally having a
sulfur content of 50 wppm or less (or 15 wppm or less).
Embodiment 9
[0125] The method of any of the above embodiments, wherein the one
or more 343.degree. C.+ cracked fractions comprise a catalytic
slurry oil, a coker bottoms fraction, a steam cracker tar fraction,
a coal tar, a visbreaker gas oil, or a combination thereof; or
wherein the one or more 343.degree. C.+ cracked fractions consist
essentially of a catalytic slurry oil.
Embodiment 10
[0126] The method of Embodiment 9, further comprising settling the
catalytic slurry oil prior to exposing the feed to the
hydroprocessing catalyst, the settled catalytic slurry oil having a
catalyst fines content of 1 wppm or less.
Embodiment 11
[0127] The method of any of the above embodiments, wherein the one
or more 343.degree. C.+ cracked fractions comprise about 2 wt % or
more n-heptane insolubles and the hydroprocessed effluent comprises
about 1 wt % or less n-heptane insolubles; or wherein the one or
more 343.degree. C.+ cracked fractions comprise at least a first
amount of micro carbon residue, and the hydroprocessed effluent
comprises less than about half of the first amount of micro carbon
residue; or wherein the one or more 343.degree. C.+ cracked
fractions comprise at least 3 wt % of a 566.degree. C.+ portion,
the effective hydroprocessing conditions being effective for 55 wt
% or more conversion of the feedstock relative to 566.degree. C.
(or 65 wt % or more, or 75 wt % or more); or a combination
thereof.
Embodiment 12
[0128] The method of any of the above embodiments, wherein an
I.sub.N of at least one of the first hydroprocessed effluent and
the second hydroprocessed effluent is 10 or more lower than an
I.sub.N of the feedstock (or 20 or more lower, or 30 or more
lower); or wherein a difference between an S.sub.BN of the
hydroprocessed effluent and the I.sub.N of the hydroprocessed
effluent is at least 30, or at least 40; or a combination
thereof.
Embodiment 13
[0129] The method of any of the above embodiments, wherein the
feedstock comprises 4.0 wt % or more of micro carbon residue (or
6.0 wt % or more); or wherein the catalytic slurry oil comprises
5.0 wt % or more of micro carbon residue (or 7.0 wt % or more, or
10 wt % or more); or wherein the hydroprocessed effluent comprises
4.0 wt % or less of micro carbon residue (or 3.0 wt % or less, or
2.0 wt % or less); or wherein the feedstock comprises at least 1.0
wt % of organic sulfur, the hydroprocessed effluent comprising 1000
wppm or less of organic sulfur (or about 500 wppm or less, or about
200 wppm or less); or a combination thereof.
Embodiment 14
[0130] A system for processing a cracked feedstock, comprising: a
first hydroprocessing reactor comprising a first hydroprocessing
inlet, a first hydroprocessing outlet, and a fixed bed comprising a
first hydroprocessing catalyst, the first hydroprocessing inlet
comprising a feedstock comprising a density at 15.degree. C. of
1.06 g/cm.sup.3 or more and at least 50 wt % of one or more
343.degree. C.+ cracked fractions, the one or more 343.degree. C.+
cracked fractions having an aromatics content of 40 wt % or more
relative to a weight of the one or more cracked fractions, the
first hydroprocessing outlet comprising a hydroprocessed effluent;
a separation stage comprising a separation inlet, a first
separation outlet, and a second separation outlet, the first
separation inlet being in fluid communication with the first
hydroprocessing outlet, a first separation outlet comprising a
hydroprocessed effluent fraction having a T90 distillation point of
454.degree. C. or less, a second separation outlet comprising a
hydroprocessed effluent fraction having a T10 distillation point of
at least 427.degree. C.; and a second hydroprocessing reactor
comprising a second hydroprocessing inlet, a second hydroprocessing
outlet, and a fixed bed comprising a second hydroprocessing
catalyst, the second hydroprocessing inlet being in fluid
communication with the first separation outlet, the first
hydroprocessing inlet optionally being in fluid communication with
the second separation outlet, the system optionally further
comprising a fluid catalytic cracking reactor in indirect fluid
communication with the second hydroprocessing outlet.
Embodiment 15
[0131] A hydroprocessed effluent, a second hydroprocessed effluent,
or a distillate hydroprocessing effluent made according to any of
Embodiments 1-13.
[0132] 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.
[0133] 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.
* * * * *