U.S. patent application number 16/709027 was filed with the patent office on 2020-06-25 for naphthenic compositions derived from fcc process fractions.
The applicant listed for this patent is ExxonMobil Research and Engineering Company. Invention is credited to Daniel Bien, Stephen H. Brown, Mark A. Deimund, Richard A. Demmin, Larry E. Hoch, Samia Ilias, Shiwen Li, Shifang Luo, Randolph J. Smiley, Lei Zhang.
Application Number | 20200199464 16/709027 |
Document ID | / |
Family ID | 69138012 |
Filed Date | 2020-06-25 |
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United States Patent
Application |
20200199464 |
Kind Code |
A1 |
Luo; Shifang ; et
al. |
June 25, 2020 |
NAPHTHENIC COMPOSITIONS DERIVED FROM FCC PROCESS FRACTIONS
Abstract
Systems and methods are provided for producing naphthenic
compositions corresponding to various types of products, such as
naphthenic base oil, specialty industrial oils, and/or hydrocarbon
fluids. The methods of producing the naphthenic compositions can
include exposing a heavy fraction from a fluid catalytic cracking
(FCC) process, such as a FCC bottoms fraction (i.e., a catalytic
slurry oil), to hydroprocessing conditions corresponding to
hydrotreating and/or aromatic saturation conditions. Naphthenic
compositions formed from processing of FCC fractions are also
provided.
Inventors: |
Luo; Shifang; (Annandale,
NJ) ; Zhang; Lei; (Bridgewater, NJ) ; Ilias;
Samia; (Bridgewater, NJ) ; Demmin; Richard A.;
(Highland Park, NJ) ; Deimund; Mark A.; (Jersey
City, NJ) ; Brown; Stephen H.; (Lebanon, NJ) ;
Smiley; Randolph J.; (Hellertown, PA) ; Hoch; Larry
E.; (Yardley, PA) ; Bien; Daniel; (Auderghem
Brussels, BE) ; Li; Shiwen; (Etterbeek, BE) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
ExxonMobil Research and Engineering Company |
Annandale |
NJ |
US |
|
|
Family ID: |
69138012 |
Appl. No.: |
16/709027 |
Filed: |
December 10, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62781892 |
Dec 19, 2018 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C10G 2300/4006 20130101;
C10G 69/04 20130101; C10G 2300/301 20130101; C10G 65/08 20130101;
C10G 2400/30 20130101; C10G 2300/302 20130101; C10G 67/0481
20130101; C10G 2300/308 20130101 |
International
Class: |
C10G 67/04 20060101
C10G067/04 |
Claims
1. A method for processing a product fraction from a fluid
catalytic cracking (FCC) process, comprising: exposing a feed
comprising a catalytic slurry oil, the feed comprising a
343.degree. C.+ portion, to a hydrotreating catalyst under
effective hydrotreating conditions to form a hydrotreated effluent,
the 343.degree. C.+ portion of the feed comprising a density of
1.06 g/cm3 or more, and exposing at least a portion of the
343.degree. C.+ portion to a hydroprocessing catalyst under
effective hydroprocessing conditions to form a hydroprocessed
effluent, wherein a C5+ portion of the hydroprocessed effluent
comprises 50 mol % or more naphthenic carbons and 500 wppm or less
of sulfur.
2. The method of claim 1, wherein the C5+ portion of the
hydroprocessed effluent comprises 60 mol % or more of naphthenic
carbons, or wherein the C5+ portion of the hydroprocessed effluent
comprises 30 mol % or less of paraffinic carbons, or a combination
thereof.
3. The method of claim 1, wherein the C5+ portion of the
hydroprocessed effluent comprises 50 wt % or more saturates.
4. The method of claim 1, wherein the C5+ portion of the
hydroprocessed effluent comprises 15 wt % or less aromatics, or
wherein the C5+ portion of the hydroprocessed effluent comprises 15
mol % or less of aromatic carbons, or a combination thereof.
5. The method of claim 1, wherein the C5+ portion of the
hydroprocessed effluent comprises a kinematic viscosity at
100.degree. C. of 2.0 cSt to 30 cSt, a viscosity index of 25 or
less, or a combination thereof.
6. The method of claim 1, wherein the C5+ portion of the
hydroprocessed effluent comprises 100 wppm or less of sulfur.
7. The method of claim 1, further comprising fractionating the C5+
portion of the hydroprocessed effluent to form one or more
naphthenic base oil compositions, the one or more naphthenic base
oil compositions comprising: a) at least one naphthenic base oil
composition comprising a kinematic viscosity at 100.degree. C. of
1.5 cSt to 4.0 cSt, a viscosity index of -20 to 25, and a T5
distillation point of 270.degree. C. or more; b) at least one
naphthenic base oil composition comprising a kinematic viscosity at
100.degree. C. of 4.5 cSt to 8.0 cSt, a viscosity index of -50 to
0, and a T5 distillation point of 300.degree. C. or more; c) at
least one naphthenic base oil composition comprising a kinematic
viscosity at 100.degree. C. of 8.0 cSt to 20 cSt, a viscosity index
of -80 to -20, and a T5 distillation point of 330.degree. C. or
more; d) at least one naphthenic base oil composition comprising a
kinematic viscosity at 100.degree. C. of 25 cSt to 75 cSt, a
viscosity index of -120 to -50, and a T5 distillation point of
360.degree. C. or more; e) a combination of two or more of a), b),
c), and d); or f) a combination of three or more of a), b), c), and
d).
8. The method of claim 7, wherein the one or more naphthenic base
oil compositions comprise 60 mol % or more of naphthenic carbons,
or wherein the one or more naphthenic base oil compositions
comprise 30 mol % or less paraffinic carbons, or a combination
thereof.
9. The method of claim 7, wherein the one or more naphthenic base
oil compositions comprise 50 wt % or more saturates, or wherein the
one or more naphthenic base oil compositions comprise 15 mol % or
less of aromatic carbons, or a combination thereof.
10. The method of claim 1, wherein the hydroprocessed effluent is
formed without exposing the catalytic slurry oil to a dewaxing
catalyst under catalytic dewaxing conditions, or wherein the
hydroprocessed effluent is formed without exposing the catalytic
slurry oil to a catalyst comprising a zeotype framework in the
presence of hydrogen under hydroprocessing conditions, or a
combination thereof.
11. The method of claim 1, wherein the effective hydroprocessing
conditions comprise fixed bed hydroprocessing conditions.
12. The method of claim 1, wherein the feed comprises a fraction
from a fluid catalytic cracking process having a T5 distillation
point of 343.degree. C. or more, a T95 distillation point of
566.degree. C. or less, or a combination thereof.
13. The method of claim 12, further comprising treating the
fraction from the fluid catalytic cracking process to form a
treated fraction comprising a particle content of 500 wppm or less
of particles having a size of 25 .mu.m or more, the catalytic
slurry oil comprising at least a portion of the treated
fraction.
14. A naphthenic base oil composition, comprising 500 wppm or less
sulfur, 18 mol % to 30 mol % paraffinic carbons, 50 mol % or more
of naphthenic carbons, a kinematic viscosity at 100.degree. C. of
2.0 cSt to 30 cSt, a viscosity index of 25 or less, and a T5
distillation point of 260.degree. C. or more.
15. The composition of claim 14, wherein the composition comprises
70 mol % or more naphthenic carbons and a viscosity index of -50 to
25.
16. The composition of claim 14, wherein the composition comprises
60 mol % to 70 mol % naphthenic carbons and a viscosity index of
-100 to 10.
17. The composition of claim 14, wherein the composition comprises
50 mol % to 60 mol % naphthenic carbons and a viscosity index of
-150 to -20.
18. The composition of claim 14, wherein the composition comprises
25 mol % to 30 mol % paraffinic carbons, 65 mol % to 75 mol % of
naphthenic carbons, a kinematic viscosity at 100.degree. C. of 8.0
cSt to 15 cSt, and a viscosity index of -40 or less.
19. The composition of claim 14, wherein the composition comprises
50 wt % or more saturates.
20. The composition of claim 14, wherein the composition comprises
15 wt % or less aromatics, or wherein the composition comprises 15
mol % or less of aromatic carbons, or a combination thereof.
21. The composition of claim 14, wherein the composition comprises
5 mol % or less aromatic carbons, or wherein the composition
comprises 1.0 wt % or less aromatics, or a combination thereof.
22. A naphthenic base oil composition, comprising 500 wppm or less
sulfur, 18 mol % to 30 mol % paraffinic carbons and 60 mol % or
more of naphthenic carbons, the naphthenic base oil composition
further comprising: a) a kinematic viscosity at 100.degree. C. of
1.5 cSt to 4.5 cSt, a viscosity index of -20 to 25, and a T5
distillation point of 270.degree. C. or more; b) a kinematic
viscosity at 100.degree. C. of 4.5 cSt to 8.0 cSt, a viscosity
index of -50 to 0, and a T5 distillation point of 300.degree. C. or
more; c) a kinematic viscosity at 100.degree. C. of 8.0 cSt to 20
cSt, a viscosity index of -80 to -20, and a T5 distillation point
of 330.degree. C. or more; or d) a kinematic viscosity at
100.degree. C. of 20 cSt to 75 cSt, a viscosity index of -120 to
-50, and a T5 distillation point of 360.degree. C. or more.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional
Application Ser. No. 62/781,892 filed Dec. 19, 2018, which is
herein incorporated by reference in its entirety.
FIELD
[0002] Naphthenic compositions derived from fluid catalytic
cracking product fractions are provided, along with systems and
methods for forming such naphthenic compositions. Examples of
naphthenic compositions include naphthenic base oils, specialty
industrial oils, and naphthenic and/or aromatic hydrocarbon
fluids.
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.
[0004] U.S. Pat. No. 8,691,076 describes methods for manufacturing
naphthenic base oils from effluences of a fluidized catalytic
cracking unit. The methods describe using an FCC unit to process an
atmospheric resid to form a fuels fraction, a light cycle oil
fraction, and a slurry oil fraction. Portions of the light cycle
oil and/or the slurry oil are then hydrotreated and dewaxed to form
naphthenic base oils. U.S. Pat. No. 8,585,889 describes a variation
where the slurry oil fraction is deasphalted prior to
hydrotreatment and dewaxing. U.S. Pat. No. 8,911,613 describes
still other variations where the light cycle oil and/or slurry oil
fractions are co-processed in the hydrotreating and dewaxing stages
with a deasphalted oil from another source.
[0005] U.S. Patent Application Publication 2017/0002279 describes
methods for processing catalytic slurry oils under fixed bed
hydrotreating conditions. U.S. Patent Application Publication
2017/0002273 describes various types of fuels that can be formed
based on fixed bed hydrotreatment of catalytic slurry oils.
SUMMARY
[0006] In an aspect, a method is provided for processing a product
fraction from a fluid catalytic cracking (FCC) process. The method
can include exposing a feed comprising a catalytic slurry oil, the
feed comprising a 343.degree. C.+ portion, to a hydrotreating
catalyst under effective hydrotreating conditions to form a
hydrotreated effluent, the 343.degree. C.+ portion of the feed
comprising a density of 1.06 g/cm3 or more. The method can further
include exposing at least a portion of the 343.degree. C.+ portion
to a hydroprocessing catalyst under effective hydroprocessing
conditions to form a hydroprocessed effluent, wherein a C5+ portion
of the hydroprocessed effluent comprises 50 mol % or more
naphthenic carbons and 500 wppm or less of sulfur.
[0007] In another aspect, a naphthenic base oil composition is
provided that includes 500 wppm or less sulfur, 18 mol % to 30 mol
% paraffinic carbons, 50 mol % or more of naphthenic carbons, a
kinematic viscosity at 100.degree. C. of 2.0 cSt to 30 cSt, a
viscosity index of 25 or less, and a T5 distillation point of
260.degree. C. or more.
BRIEF DESCRIPTION OF THE FIGURES
[0008] FIG. 1 shows an example of a reaction system for forming
naphthenic compositions from a feed comprising a catalytic slurry
oil.
[0009] FIG. 2 shows an example of a reaction system for forming
naphthenic compositions from a feed comprising a catalytic slurry
oil.
[0010] FIG. 3 shows an example of a reaction system for forming
naphthenic compositions from a feed comprising a catalytic slurry
oil.
[0011] FIG. 4 shows an example of a reaction system for forming
naphthenic compositions from a feed comprising a catalytic slurry
oil.
[0012] FIG. 5 shows an example of a reaction system for forming
naphthenic compositions from a feed comprising a catalytic slurry
oil.
[0013] FIG. 6 shows viscosity index versus percentage of naphthenic
carbon for various naphthenic oils formed from naphthenic crude oil
feeds and formed from hydroprocessing of catalytic slurry oils.
[0014] FIG. 7 shows properties for 3.5 cSt naphthenic base oils
after hydroprocessing under various aromatic saturation
conditions.
[0015] FIG. 8 shows pour point versus kinematic viscosity at
100.degree. C. for various naphthenic oils.
[0016] FIG. 9 shows pour point versus kinematic viscosity at
40.degree. C. for various naphthenic oils.
[0017] FIG. 10 shows percentage of paraffinic carbon versus amount
of saturates for various naphthenic oils formed from naphthenic
crude oil feeds and formed from hydroprocessing of catalytic slurry
oils.
DETAILED DESCRIPTION
[0018] In various aspects, systems and methods are provided for
producing naphthenic compositions corresponding to various types of
products, such as naphthenic base oil, specialty industrial oils,
and/or hydrocarbon fluids. The methods of producing the naphthenic
compositions can include exposing a heavy fraction from a fluid
catalytic cracking (FCC) process, such as a FCC bottoms fraction
(i.e., a catalytic slurry oil), to hydroprocessing conditions
corresponding to hydrotreating and/or aromatic saturation
conditions. The hydroprocessing can be performed without exposing
the FCC heavy fraction to catalytic dewaxing conditions. By using a
FCC heavy fraction as a feedstock rather than a conventional feed,
naphthenic product compositions can be formed that have unexpected
properties, such as compositions with unexpectedly low viscosity
index values relative to the naphthenic carbon content of the
compositions. Additionally, by minimizing or avoiding exposure of
the FCC heavy fraction feedstock to catalytic dewaxing conditions,
naphthenic product compositions can be formed that have unexpected
combinations of pour point, kinematic viscosity, and viscosity
index relative to the amount of naphthenic carbon in the
composition.
[0019] Catalytic slurry oils (or other names used to refer to FCC
bottoms fractions) are high sulfur and high aromatic content
fractions generated during FCC processing. Catalytic slurry oils
typically have an initial boiling point and/or T5 distillation
point of 343.degree. C. or more. The final boiling point and/or T95
distillation point can vary, but is commonly 565.degree. C. or
more. Traditionally, the product disposition for catalytic slurry
oil is to use the catalytic slurry oil as a blend component for
forming regular sulfur fuel oils, or as feedstock for formation of
carbon black. Due in part to upcoming and/or planned changes in
regulations for sulfur content in fuel oils, however, alternative
dispositions for catalytic slurry oils are desirable.
[0020] Based on the highly aromatic nature of catalytic slurry
oils, some possible alternative dispositions correspond to using
catalytic slurry oils as a feedstock for production of aromatic
products or naphthenic products. However, catalytic slurry oils can
also contain up to 6.0 wt % or more of sulfur as well as
substantial amounts of nitrogen. Methods for removing such
heteroatoms while preserving the desired aromatic/naphthenic
character of the catalytic slurry oil are needed in order to
produce commercially viable products.
[0021] It has been unexpectedly discovered that catalytic slurry
oil can be used to make a variety of naphthenic product
compositions that are traditionally made from higher value feeds,
such as naphthenic crude oils. In various aspects, single stage or
(preferably) multi-stage hydroprocessing of catalytic slurry oil
can be used to form naphthenic product compositions. By adjusting
the processing conditions, including optionally performing aromatic
saturation and/or solvent processing, naphthenic hydrocarbon
mixtures can be produced with desirable combinations of
compositional and physical properties, such as hydrocarbon mixtures
with high naphthenic carbon content, low sulfur content, and
targeted values for viscosity and/or viscosity index.
[0022] In various aspects, any convenient number of hydroprocessing
stages can be used for the hydrotreatment and/or aromatic
saturation of the FCC heavy fraction. For example, single stage
hydrotreatment may be suitable for forming an effluent containing
less than 250 wppm sulfur and 50 wt % to 75 wt % aromatics. Various
naphthenic compositions can then be formed from such an effluent,
including naphthenic compositions having a kinematic viscosity at
100.degree. C. of 2.5 cSt to 35 cSt. Such naphthenic compositions
can include 50 wt % to 90 wt % aromatics. Of course, any convenient
number of hydrotreatment stages could be used to make such an
effluent. As another example, multi-stage hydroprocessing may be
suitable for forming an effluent containing less than 250 wppm
sulfur and 60 wt % or more naphthenes (or 70 wt % or more).
Optionally, the first stage for forming such a hydroprocessing
effluent can correspond to a hydrotreatment stage, while the second
stage can correspond to an aromatic saturation stage. Various
naphthenic compositions can then be formed from such a
hydroprocessing effluent, including naphthenic compositions having
a kinematic viscosity at 100.degree. C. of 2.0 cSt to 100 cSt, or
2.5 cSt or 50 cSt. Of course, any convenient number of
hydroprocessing stages could be used to make such a hydroprocessed
effluent.
[0023] In various aspects, the naphthenic compositions can have
unexpected combinations of naphthenic carbon content and viscosity
index. Naphthenic carbon content refers to the number of carbon
atoms participating in naphthenic bonding (i.e., saturated ring
bonding). This is in contrast to paraffinic carbons (alkane type
bonding) and aromatic carbons (carbon atoms that are part of a
pi-bond system). The amount of naphthenic carbon, paraffinic
carbon, and/or aromatic carbon can be determined by ASTM D2140. In
some aspects, a naphthenic composition can include 60 mol % or more
naphthenic carbons, relative to the total amount of carbon, or 65
mol % or more, or 70 mol % or more, such as up to 80 mol % or
possibly still higher. In such aspects, the viscosity index of the
naphthenic composition can be -200 to 50, or -150 to 35. This
combination of naphthenic carbon content and viscosity index is in
contrast to naphthenic compositions formed from a conventional
source, such as a naphthenic crude. Naphthenic compositions formed
from naphthenic crudes typically have less than 60 mol % naphthenic
carbons. Additionally or alternately, the amount of paraffinic
carbon can be 30 mol % or less, or 25 mol % or less, such as down
to 18 mol % or possibly still lower. Optionally, in such aspects,
the amount of saturates in the naphthenic composition can be 50 wt
% or more, or 60 wt % or more, or 70 wt % or more, such as up to
99.8 wt % saturates or possibly still higher. Conventionally,
naphthenic oils made from conventional feeds include 34 mol % or
more of paraffinic carbons. Optionally, the effluent can also
contain 15 mol % or less aromatic carbon, or 10 mol % or less, or
5.0 mol % or less, such as down to 1.0 mol % or possibly still
lower.
[0024] In this discussion, an FCC bottoms fraction can be referred
to as a catalytic slurry oil. Catalytic slurry oil is defined
herein to also refer to FCC fractions that substantially correspond
to an FCC bottoms fraction. An FCC fraction that substantially
corresponds to an FCC bottoms fraction is defined to include FCC
fractions that have a T5 to T95 boiling range that is within the
typical boiling range for an FCC bottoms fraction, even if the
fraction was formed via a distillation process that generated
another higher boiling fraction. It is noted that when initially
formed, a catalytic slurry oil can include several weight percent
of catalyst fines. Such catalyst fines can optionally but
preferably be removed (such as partially removed to a desired
level) by any convenient method, such as filtration. In this
discussion, unless otherwise explicitly noted, references to a
catalytic slurry oil are defined to include catalytic slurry oil
either prior to or after such a process for reducing the content of
catalyst fines within the catalytic slurry oil.
[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] All numerical values within the detailed description and the
claims herein are modified by "about" or "approximately" the
indicated value, and take into account experimental error and
variations that would be expected by a person having ordinary skill
in the art.
Feedstock--Catalytic Slurry Oil
[0028] A catalytic slurry oil can correspond to a high boiling
fraction, such as a bottoms fraction, from an FCC process. A feed
including a catalytic slurry oil can correspond to a feed that
includes 50 wt % or more of a catalytic slurry oil, or 75 wt % or
more, or 90 wt % or more, such as up to 100 wt %. A variety of
properties of a catalytic slurry oil can be characterized to
specify the nature of a catalytic slurry oil feed.
[0029] One aspect that can be characterized corresponds to a
boiling range of the catalytic slurry oil. Typically the cut point
for forming a catalytic slurry oil can be 650.degree. F.
(.about.343.degree. C.) or more. As a result, a catalytic slurry
oil can have a T5 distillation (boiling) point or a T10
distillation point of 650.degree. F. (.about.343.degree. C.) or
more, as measured according to ASTM D2887. In some aspects the
D2887 10% distillation point can be greater, such as 675.degree. F.
(.about.357.degree. C.) or more, or 700.degree. F.
(.about.371.degree. C.) or more. 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.
[0030] 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 more, or a T90
distillation point of 1050.degree. F. (.about.566.degree. C.) or
more. Additionally or alternately, the T95 distillation point
and/or the final boiling point can be 1200.degree. F.
(.about.650.degree. C.) or less, or 1150.degree. F.
(.about.620.degree. C.) or less. 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.
[0031] 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 1.06
g/cm3 or more, or 1.08 g/cm3 or more, or 1.10 g/cm3 or more, such
as up to about 1.20 g/cm3 or possibly still higher (ASTM D4052).
The density of the catalytic slurry oil can provide an indication
of the amount of heavy aromatic cores that are present within the
catalytic slurry oil. A lower density catalytic slurry oil feed can
in some instances correspond to a feed that may have a greater
expectation of being suitable for hydrotreatment without
substantial and/or rapid coke formation.
[0032] Contaminants such as nitrogen and sulfur are typically found
in catalytic slurry oils, often in organically-bound form. Nitrogen
content can range from 50 wppm to 5000 wppm elemental nitrogen, or
100 wppm to 2000 wppm elemental nitrogen, or 250 wppm to 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 quinolines,
substituted quinolines, carbazoles, and substituted carbazoles.
[0033] The sulfur content of a catalytic slurry oil feed can be 500
wppm or more elemental sulfur, based on total weight of the
catalytic slurry oil. Generally, the sulfur content of a catalytic
slurry oil can range from 500 wppm to 100,000 wppm elemental
sulfur, or from 1000 wppm to 50,000 wppm, or from 1000 wppm to
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.
[0034] 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 1.0 wt % or more of n-heptane
insolubles or asphaltenes, or 3.0 wt % or more, or 5.0 wt % or
more, such as up to 10 wt % or possibly still higher. 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 5 wt % or more, or 8 wt % or more, or 10 wt % or
more, such as up to 15 wt % or possibly still higher.
[0035] Catalytic slurry oil fractions are typically formed by
atmospheric fractionation of the effluent from an FCC reactor. For
example, after performing an FCC process on a feed, the resulting
FCC effluent is typically fractionated in one or more separation
stages. The one or more separation stages can correspond to an
atmospheric distillation unit, or the one or more separation stages
can correspond to a plurality of individual separations that have
roughly a similar effect as using an atmospheric distillation unit.
The lower boiling fractions generated by fractionation of an FCC
effluent correspond to the typical desired products from FCC
processing, such as a light ends/olefin-containing fraction, a
naphtha fraction, and one or more cycle oils that can optionally be
further upgraded for use as distillate fuel. The "bottoms" cut from
the fractionation of the FCC effluent corresponds to the catalytic
slurry oil.
[0036] Due to the nature of fluid catalytic cracking processes,
catalyst fines are typically generated during such processes. These
catalyst fines tend to be segregated into the bottoms fraction
during the atmospheric fractionation, resulting in formation of a
catalytic slurry oil. Prior to hydroprocessing of a catalytic
slurry oil in a reaction that includes fixed catalyst beds (such as
trickle beds), it can be beneficial to remove the catalyst fines so
that the catalyst fines do not contribute to plugging or channeling
in the catalyst bed. The feedstock, after any optional treatment in
a particle removal stage, can have a particle content of about 500
wppm or less of particles having a size of 25 .mu.m or more, or
about 100 wppm or less, or about 50 wppm or less, or about 20 wppm
or less, such as down to substantially no content of suspended
solids (.about.0 wppm). Filtration is an example of a suitable
method for removing the catalyst fines, although other methods can
also be used in addition to or in place of filtration. Examples of
other methods include, but are not limited to, gravity settling,
electrostatic filtration, and centrifugation. For example,
particles can be removed by first performing gravity settling, and
then passing the effluent from the gravity settler through a filter
available from Mott Corporation or through an electrostatic filter
available from Gulftronic. After removing particles in the
catalytic slurry oil to a desired level, the feed can be
hydroprocessed.
[0037] In some aspects, an alternative to performing filtration can
be to use fractionation and/or solvent processing to remove
catalyst fines from the feed. In other aspects, filtration can be
performed in combination with fractionation and/or solvent
processing. Thus, solvent processing and/or fractionation can
potentially be performed prior to, during, and/or after the
hydroprocessing of the feed including catalytic slurry oil. In
addition to removing particles, performing fractionation and/or
solvent processing can also remove a portion of the higher boiling
components in the feed. If vacuum fractionation is used without
filtration, the catalyst fines can be segregated into the vacuum
bottoms fraction. If solvent deasphalting is used without
filtration, the catalyst fines can be segregated into the residual
or rock fraction.
[0038] Solvent deasphalting is an example of a solvent extraction
process. In some aspects, suitable solvents for solvent
deasphalting include alkanes or other hydrocarbons (such as
alkenes) containing 4 to 7 carbons per molecule. Examples of
suitable solvents include n-butane, isobutane, n-pentane, C4+
alkanes, C5+ alkanes, C4+ hydrocarbons, and C5+ hydrocarbons. In
other aspects, suitable solvents can include C3 hydrocarbons, such
as propane. In such other aspects, examples of suitable solvents
include propane, n-butane, isobutane, n-pentane, C3+ alkanes, C4+
alkanes, C5+ alkanes, C3+ hydrocarbons, C4+ hydrocarbons, and C5+
hydrocarbons.
[0039] A deasphalting process typically corresponds to contacting a
heavy hydrocarbon feed (such as a feed including catalytic slurry
oil) 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
corresponds to a deasphalted oil extracted by the alkane, which is
further separated to produce deasphalted oil stream. A second type
of product stream is the residual portion of the feed not soluble
in the solvent (i.e., a raffinate). Conventionally, the residual
product from solvent deasphalting can be referred to as a rock or
asphaltene fraction. The deasphalted oil fraction can be
hydroprocessed. The rock fraction can potentially be used as a
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).
[0040] During solvent deasphalting, the feed 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 (345 kPag) to about 500 psig
(3447 kPag).
[0041] It is noted that the above solvent deasphalting conditions
represent a general range, and the conditions will vary depending
on the feed. For example, under typical deasphalting conditions,
increasing the temperature can tend to reduce the yield of DAO
while increasing the quality of the resulting deasphalted oil.
Under typical deasphalting conditions, increasing the molecular
weight of the solvent can tend to increase the yield while reducing
the quality of the resulting deasphalted oil, as additional
compounds within a resid fraction may be soluble in a solvent
composed of higher molecular weight hydrocarbons. Under typical
deasphalting conditions, increasing the amount of solvent can tend
to increase the yield of the resulting deasphalted oil. As
understood by those of skill in the art, the conditions for a
particular feed can be selected based on the resulting yield of
deasphalted oil from solvent deasphalting. Because catalytic slurry
oils often are composed of primarily 1050.degree. F.- components,
the yield of deasphalted oil can be quite high, such as 70 wt % to
95 wt %, or 70 wt % to 98 wt %.
Hydroprocessing of Catalytic Slurry Oil to form Naphthenic Product
Compositions
[0042] In various aspects, a feed including catalytic slurry oil
can be hydroprocessed to form one or more naphthenic product
compositions. An example of a suitable type of hydroprocessing can
be hydrotreatment, such as hydrotreatment under trickle bed
conditions. Hydrotreatment can optionally be used in conjunction
with other hydroprocessing, such as an aromatic saturation process.
However, in various aspects, the hydroprocessing can be performed
without exposing the feed containing catalytic slurry oil to
dewaxing conditions. Optionally, the feed including catalytic
slurry oil can also be solvent processed, fractionated, or a
combination thereof. The optional solvent processing/fractionation
can be performed prior to hydroprocessing, between hydroprocessing
stages, and/or after hydroprocessing.
[0043] In various aspects, a feed including catalytic slurry oil
can be hydrotreated under effective hydrotreating conditions to
form a hydrotreated effluent. In some aspects, the hydrotreating
conditions can be selected to achieve a desired level of sulfur
removal, such as reducing the sulfur content in the liquid portion
of the hydrotreated effluent to 250 wppm or less, or 150 wppm or
less, or 100 wppm or less, or 50 wppm or less. In some aspects, the
hydrotreating conditions can be selected to achieve a desired level
of nitrogen removal, such as reducing the nitrogen content in the
liquid portion of the hydrotreated effluent to 250 wppm or less, or
150 wppm or less, or 100 wppm or less, or 50 wppm or less. The
amount of aromatics remaining in the hydrotreated effluent after
reducing the sulfur to 250 wppm or less can be 50 wt % to 80 wt %,
or 60 wt % to 80 wt %.
[0044] Optionally, the effective hydrotreating conditions can be
selected to allow for reduction of the n-heptane asphaltene content
of the hydrotreated 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.
Additionally or alternately, the effective hydrotreating conditions
can be selected to allow for reduction of the micro carbon residue
content of the hydrotreated effluent to less than about 2.5 wt %,
or 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 micro carbon residue.
[0045] Additionally or alternately, in various aspects, the
processing conditions can be selected to achieve a desired level of
conversion of a feedstock, such as conversion relative to a
conversion temperature of .about.700.degree. F. (.about.371.degree.
C.). For example, the process conditions can be selected to achieve
40% or more conversion of the 1050.degree. F.+(.about.566.degree.
C.+) portion of the feedstock to 1050.degree. F.-
(.about.566.degree. C.)- components, or 50 wt % or more, or 60 wt %
or more, such as up to 80 wt % or possibly still higher.
[0046] Hydroprocessing (such as hydrotreating) can be carried out
in the presence of hydrogen. A hydrogen stream can be fed or
injected into a vessel or reaction zone or hydroprocessing zone
corresponding to the location of a hydroprocessing catalyst.
Hydrogen, contained in a hydrogen "treat gas," can be provided to
the reaction zone. Treat gas, as referred to herein, can be either
pure hydrogen or a hydrogen-containing gas stream containing
hydrogen in an amount that for the intended reaction(s). Treat gas
can optionally include one or more other gasses (e.g., nitrogen and
light hydrocarbons such as methane) that do not adversely interfere
with or affect either the reactions or the products. Impurities,
such as H2S and NH3 are undesirable and can typically be removed
from the treat gas before conducting the treat gas to the reactor.
In aspects where the treat gas stream can differ from a stream that
substantially consists of hydrogen (i.e, at least about 99 vol %
hydrogen), the treat gas stream introduced into a reaction stage
can contain at least about 50 vol %, or at least about 75 vol %
hydrogen, or at least about 90 vol % hydrogen.
[0047] During hydrotreatment, a feedstream can be contacted with a
hydrotreating catalyst under effective hydrotreating conditions
which include temperatures in the range of 450.degree. F. to
800.degree. F. (.about.232.degree. C. to .about.427.degree. C.), or
500.degree. F. to 750.degree. F. (.about.260.degree. C. to
.about.399.degree. C.); pressures in the range of 1.5 MPa-g to 20.8
MPa-g (.about.200 to .about.3000 psig), or 3.4 MPa-g to 17.2 MPa-g
(.about.500 to .about.2500 psig), or 6.9 MPa-g to 17.25 MPa-g
(.about.1000 psig to .about.2500 psig); a liquid hourly space
velocity (LHSV) of from 0.1 to 10 hr-1, or 0.1 to 5 hr-1; and a
hydrogen treat gas rate of from 430 to 2600 Nm3/m3 (.about.2500 to
.about.15000 SCF/bbl), or 850 to 1700 Nm3/m3 (.about.5000 to
.about.10000 SCF/bbl).
[0048] In an aspect, the hydrotreating step may comprise at least
one hydrotreating reactor, and optionally may comprise two or more
hydrotreating reactors arranged in series flow. A vapor separation
drum can optionally be included after each hydrotreating reactor to
remove vapor phase products from the reactor effluent(s). The vapor
phase products can include hydrogen, H2S, NH3, and hydrocarbons
containing four (4) or less carbon atoms (i.e., "C4-
hydrocarbons"). The C5+ hydrocarbons can be subsequently cooled to
form liquid products, and therefore the C5+ portion of the effluent
can be referred to as the liquid portion of the effluent. The
effective hydrotreating conditions can be suitable for removal of
70 wt % or more, or 80 wt % or more, or 90 wt % or more of the
sulfur content in the feedstream from the resulting liquid
products. Additionally or alternately, 50 wt % or more, or 75 wt %
or more of the nitrogen content in the feedstream can be removed
from the resulting liquid products.
[0049] Hydrotreating catalysts suitable for use herein can include
those containing at least one Group VIA metal and at least one
Group VIII metal, including mixtures thereof. Examples of suitable
metals include Ni, W, Mo, Co and mixtures thereof, for example
CoMo, NiMoW, NiMo, or NiW. These metals or mixtures of metals are
typically present as oxides or sulfides on refractory metal oxide
supports. The amount of metals for supported hydrotreating
catalysts, either individually or in mixtures, can range from
.about.0.5 to .about.35 wt %, based on the weight of the catalyst.
Additionally or alternately, for mixtures of Group VIA and Group
VIII metals, the Group VIII metals can be present in amounts of
from .about.0.5 to .about.5 wt % based on catalyst, and the Group
VIA metals can be present in amounts of from 5 to 30 wt % based on
the catalyst. A mixture of metals may also be present as a bulk
metal catalyst wherein the amount of metal can comprise .about.30
wt % or greater, based on catalyst weight.
[0050] Suitable metal oxide supports for the hydrotreating
catalysts include oxides such as silica, alumina, silica-alumina,
titanic, or zirconia. Examples of aluminas suitable for use as a
support can include porous aluminas such as gamma or eta. In some
aspects where the support can correspond to a porous metal oxide
support, the catalyst can have an average pore size (as measured by
nitrogen adsorption) of 30 .ANG. to 1000 .ANG., or 50 .ANG. to 500
.ANG., or 60 .ANG. to 300 .ANG.. Pore diameter can be determined,
for example, according to ASTM Method D4284-07 Mercury Porosimetry.
Additionally or alternately, the catalyst can have a surface area
(as measured by the BET method) of 100 to 350 m2/g, or 150 to 250
m2/g. In some aspects, a supported hydrotreating catalyst can have
the form of shaped extrudates. The extrudate diameters can range
from 1/32nd to 1/8th inch (.about.0.7 to .about.3.0 mm), from
1/20th to 1/10th inch (.about.1.3 to .about.2.5 mm), or from 1/20th
to 1/16th inch (.about.1.3 to .about.1.5 mm). The extrudates can be
cylindrical or shaped. Non-limiting examples of extrudate shapes
include trilobes and quadralobes.
[0051] Optionally, more than one hydrotreating stage can be used,
such as having multiple reactors containing hydrotreating catalyst
with a separation stage in between. In such aspects, a portion of
the hydrodesulfurization and/or hydrodenitrogenation can be
performed in a second hydrotreating stage. Optionally, such a
second hydrotreating stage can be operated under aromatic
saturation conditions.
[0052] Aromatic saturation conditions can be similar to
hydrotreating conditions, but the aromatic saturation conditions
can be selected separately (if desired) from the hydrotreating
conditions. Preferably, a separation stage can be located between
the aromatic saturation stage and any hydrotreating stages that
perform substantial removal of sulfur from the feed. The separation
stage can be used to remove H2S, NH3, and C4- hydrocarbons from the
feed after hydrotreating. In other aspects, a separation may not be
performed, so that the effluent may be contacted with an aromatics
saturation catalyst with or without the removal of H2S, NH3 and C4-
components. During aromatic saturation, a feedstream (such as a
portion of a hydrotreated effluent) can be contacted with an
aromatic saturation catalyst under effective aromatic saturation
conditions which include temperatures in the range of 390.degree.
F. to 800.degree. F. (.about.232.degree. C. to .about.427.degree.
C.), or 390.degree. F. to 750.degree. F. (.about.260.degree. C. to
.about.399.degree. C.); pressures in the range of 1.5 MPa-g to 20.8
MPa-g (.about.200 to .about.3000 psig), or 3.4 MPa-g to 17.2 MPa-g
(.about.500 to .about.2500 psig), or 6.9 MPa-g to 17.25 MPa-g
(.about.1000 psig to .about.2500 psig); a liquid hourly space
velocity (LHSV) of from 0.1 to 10 hr-1, or 0.1 to 5 hr-1; and a
hydrogen treat gas rate of from 430 to 2600 Nm3/m3 (.about.2500 to
.about.15000 SCF/bbl), or 850 to 1700 Nm3/m3 (.about.5000 to
.about.10000 SCF/bbl).
[0053] Hydrofinishing and/or aromatic saturation catalysts can
include catalysts containing Group VI metals, Group VIII metals,
and mixtures thereof. In some aspects, hydrotreating catalysts can
be used as aromatic saturation catalysts. In some aspects, an
aromatic saturation catalyst can include a Group VIII noble metal,
such as Pt, Pd, or a combination thereof. For supported aromatic
saturation catalysts, suitable support materials include amorphous
or crystalline oxide materials such as alumina, silica, and
silica-alumina. The support materials may also be modified, such as
by halogenation, or in particular fluorination. The metal content
of the catalyst can be as high as about 20 weight percent for
non-noble metals. In some aspects, an aromatic saturation catalyst
can include a crystalline material belonging to the M41S class or
family of catalysts. The M41S family of catalysts are mesoporous
materials having high silica content. Examples include MCM-41,
MCM-48 and MCM-50. A preferred member of this class is MCM-41.
[0054] The effective hydrotreating conditions and/or aromatic
saturation conditions can optionally be suitable for incorporation
of a substantial amount of additional hydrogen into the
hydrotreated effluent. During hydrotreatment and/or aromatic
saturation, the consumption of hydrogen by the feed in order to
form the hydrotreated effluent can correspond to 1000 SCF/bbl
(.about.260 Nm3/m3) or more of hydrogen, or 1500 SCF/bbl
(.about.290 Nm3/m3) or more, or 2000 SCF/bbl (.about.330 Nm3/m3) or
more, or 2200 SCF/bbl (.about.370 Nm3/m3) or more, such as up to
5000 SCF/bbl (.about.850 Nm3/m3) or possibly still higher.
[0055] In various aspects, the feed including catalytic slurry oil
can be hydroprocessed without exposing the feed to catalytic
dewaxing conditions. For example, the hydroprocessing conditions
can be selected to avoid exposing the feed to dewaxing catalyst
and/or dewaxing conditions where dewaxing is performed primarily by
isomerization. In some aspects, such dewaxing catalysts that cause
dewaxing primarily by isomerization can correspond to, for example,
catalysts that include zeotype frameworks with a unidimensional
pore structure. Additionally or alternately, such catalysts can
include 10-member ring pore zeolites, such as EU-1, ZSM-35 (or
ferrierite), ZSM-11, ZSM-57, NU-87, SAPO-11, and ZSM-22. Such
dewaxing catalysts can include a metal hydrogenation component. The
metal hydrogenation component can typically be a Group 6 and/or a
Group 8-10 metal, such as a Group 8-10 noble metal. For example,
the metal hydrogenation component can be Pt, Pd, or a mixture
thereof. Alternatively, the metal hydrogenation component can be a
combination of a non-noble Group 8-10 metal with a Group 6 metal.
Suitable combinations can include Ni, Co, or Fe with Mo or W,
preferably Ni with Mo or W.
Product Properties--Hydrotreated Effluent
[0056] The intermediate and/or final products from processing of
catalytic slurry oil can be characterized in various manners. One
type of product that can be characterized can be the hydrotreated
effluent derived from hydrotreatment of a catalytic slurry oil feed
(or a feed substantially composed of catalytic slurry oil).
Additionally or alternately, the hydrotreated effluent derived from
hydrotreatment of a catalytic slurry oil feed (or a feed
substantially composed of a catalytic slurry oil) may be
fractionated into light ends, naphtha, distillate and, residual
range portions prior to characterization.
[0057] After hydrotreatment, the liquid (C5+) portion of the
hydrotreated effluent can have a volume of 95% or more of the
volume of the catalytic slurry oil feed, or 100% or more of the
volume of the feed, or 105% or more, or 110% or more, such as up to
150% of the volume or possibly still higher.
[0058] After hydrotreatment, the boiling range of the liquid (C5+)
portion of the hydrotreated effluent can be characterized in
various manners. In some aspects, the total liquid product can have
a T50 distillation point of 320.degree. C. to 400.degree. C., or
350.degree. C. to 380.degree. C. In some aspects, the total liquid
product can have a T90 distillation point of 450.degree. C. to
525.degree. C. In some aspects, the total liquid product can have a
T10 distillation point of 250.degree. C. or more, which can reflect
the low amount of conversion that occurs during hydroprocessing of
higher boiling compounds to C5+ compounds with a boiling point
below 200.degree. C. In some aspects, the (weight) percentage of
the liquid (C5+) portion that comprises a distillation point
greater than about .about.566.degree. C. can be 10 wt % or less, or
5.0 wt % or less, or 2.0 wt % or less, or 1.0 wt % or less, such as
down to 0.05 wt % or less (i.e., substantially no compounds with a
distillation point greater than about 1050.degree.
F./.about.566.degree. C.). Additionally or alternately, the
(weight) percentage of the liquid portion that comprises a
distillation point less than about -370.degree. C. can be 40 wt %
or more, or 50 wt % or more, or 60 wt % or more, such as up to 90
wt % or possibly still higher.
[0059] In some aspects, the density (at 15.degree. C.) of the
liquid (C5+) portion of the hydrotreated effluent can be 1.05 g/cm3
or less, or 1.00 g/cm3 or less, or 0.95 g/cm3 or less, such as down
to 0.88 g/cc or lower. The sulfur content of the liquid (C5+)
portion of the hydrotreated effluent can be 1000 wppm or less, or
500 wppm or less, or 100 wppm or less, such as down to
substantially no remaining sulfur (-1 wppm or possibly lower). The
micro carbon residue of the liquid (C5+) portion of the
hydrotreated effluent can be 4.0 wt % or less, or 2.0 wt % or less,
or 1.0 wt % or less, such as substantially complete removal of
micro carbon residue.
[0060] The aromatics content of the liquid (C5+) portion of the
hydrotreated effluent can vary depending on the severity of the
hydroprocessing. Generally, the aromatics content can range from
substantially no aromatics (.about.0 wt %, or alternatively 1.0 wt
% or less) to 30 wt %. In some aspects, the liquid portion of the
hydrotreated effluent can have an aromatics content of 0 wt % to 30
wt %, or 0 wt % to 20 wt %, or 0 wt % to 10 wt %. In such aspects
with lower aromatics content, the naphthene content of the liquid
portion of the hydrotreated effluent can be 70 wt % to 98 wt %, or
70 wt % to 90 wt %, or 80 wt % to 98 wt %.
[0061] For compositions with a T5 distillation point of 343.degree.
C. or more and an aromatics content of 30 wt % or less, or 30 wt %
or less, or 20 wt % or less, the amount of naphthenic carbon in the
composition can also be characterized. For example, a naphthenic
composition can include 60 mol % or more naphthenic carbons,
relative to the total amount of carbon, or 65 mol % or more, or 70
mol % or more. In such aspects, the viscosity index of the
naphthenic composition can be -200 to 50, or -150 to 35.
[0062] One or more products can also be further fractionated to
form narrow boiling range hydrocarbon fluids. For example, at least
a portion of the diesel product (177.degree. C. to 343.degree. C.)
can be fractionated to form hydrocarbon fluids. The hydrocarbon
fluids can be formed to have a desired boiling range, a desired
average carbon number, and/or another target property.
[0063] As examples of fractions that can be formed, in some aspects
a naphthenic base oil composition can be formed that includes a
kinematic viscosity at 100.degree. C. of 1.5 cSt to 4.0 cSt, a
viscosity index of -20 to 25, and a T5 distillation point of
270.degree. C. or more. As another example, a naphthenic base oil
composition can be formed that includes a kinematic viscosity at
100.degree. C. of 4.5 cSt to 8.0 cSt, a viscosity index of -50 to
0, and a T5 distillation point of 300.degree. C. or more. As
another example, a naphthenic base oil composition can be formed
that includes a kinematic viscosity at 100.degree. C. of 8.0 cSt to
20 cSt, a viscosity index of -80 to -20, and a T5 distillation
point of 330.degree. C. or more. As still another example, a
naphthenic base oil composition can be formed that includes a
kinematic viscosity at 100.degree. C. of 25 cSt to 75 cSt, a
viscosity index of -120 to -50, and a T5 distillation point of
360.degree. C. or more.
[0064] In various aspects, reference may be made to one or more
types of fractions generated during distillation of a petroleum
feedstock. Such fractions may include naphtha fractions, kerosene
fractions, diesel fractions, and vacuum gas oil fractions. Each of
these types of fractions can be defined based on a boiling range,
such as a boiling range that includes at least -90 wt % of the
fraction, or at least -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 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.400.degree. F. (.about.204.degree. C.) to .about.750.degree.
F. (.about.399.degree. C.).
Examples of Reaction System Configurations
[0065] FIG. 1 shows an example of a reaction system suitable for
processing of a catalytic slurry oil to form one or more naphthenic
product compositions. The reaction system example in FIG. 1
corresponds to a single stage hydrotreating system. In FIG. 1, a
feed 105 including catalytic slurry oil is passed into a filter 110
to form a filtered feed 115 with a reduced or minimized content of
catalyst fines. The filtered feed 115 is then passed into a
hydrotreating stage 120 along with hydrogen 101. In FIG. 1,
hydrogen 101 is introduced into the feed prior to entering the
hydrotreating stage 120, but any other convenient method for
introducing hydrogen into the hydrotreating stage 120 can also be
used. The hydrotreating stage 120 produces a hydrotreated effluent
125. The hydrotreated effluent 125 can then be fractionated 130 to
generate a variety of products. The fractionated products can
include one or more naphtha fractions 141 and one or more light
diesel fractions 143. Both the naphtha fraction(s) 141 and the
light diesel fraction(s) 143 correspond to fractions with a sulfur
content of 15 wppm or less, or 10 wppm or less, or 5 wppm or less,
such as down to substantially no sulfur content. A bottoms fraction
149 corresponding to the 1050.degree. F.+(566.degree. C.+) portion
of the hydrotreated effluent can also be formed. Additionally, one
or more naphthenic product compositions can be formed. For example,
the 260.degree. C. to 566.degree. C. portion of the hydrotreated
effluent can be fractionated to form naphthenic oils having a
viscosity of 2.5 cSt (132), 6 cSt (134), 12 cSt (136), and 35 cSt
(138). Optionally, the 2.5 cSt naphthenic oil can instead
correspond to a heavy diesel fraction. Optionally, the 6 cSt
naphthenic oil can instead correspond to a light gas oil
fraction.
[0066] FIG. 2 shows another type of configuration, where solvent
deasphalting is used in place of filtration. In FIG. 2, the feed
105 is introduced into a solvent deasphalting stage 250, along with
a deasphalting solvent 251. The solvent deasphalting stage 250 can
generate a deasphalted oil 255 and an asphalt or rock fraction 259.
The rock fraction 259 can include the catalyst fines or particles
from the catalytic slurry oil. The deasphalted oil 255 can then be
introduced into hydrotreating stage 120, along with hydrogen 101.
The resulting hydrotreated effluent 125 can be fractionated 130 to
form a variety of products. In some aspects, deasphalting stage 250
can also remove some multi-ring structures that are difficult to
hydroprocess, thus allowing the hydrotreating conditions in
hydrotreating stage 120 to be milder.
[0067] FIG. 3 shows still another option for removing particles
from a catalyst slurry oil prior to hydrotreatment. In FIG. 3, a
vacuum fractionation 360 is performed on the feed 105 to form a
bottoms fraction 369 and fractionated feed 365. It is noted vacuum
fractionator 360 could be used to directly form a fractionated feed
365 from a FCC effluent, as opposed to first performing an
atmospheric fractionation to form a catalytic slurry oil and then
vacuum fractionating the feed 105 that includes the catalytic
slurry oil. The fractionated feed 365 can then be passed into
hydrotreating stage 120 along with hydrogen 101.
[0068] FIGS. 1 to 3 show examples of single stage hydroprocessing
configurations. The types of configurations shown in FIGS. 1 to 3
can also be incorporated into a multi-stage configuration, such as
a configuration that includes a second aromatic saturation
stage.
[0069] FIG. 4 shows an example of a multi-stage configuration for
producing naphthenic product compositions. In FIG. 4, a feed
including a catalytic slurry oil is filtered to form a filtered
feed 415. The filtered feed 415 can then be hydrotreated in
hydrotreating stage 420. The resulting hydrotreated effluent 425
can be fractionated in an atmospheric fractionator 480 to produce a
variety of fractions. The fractions can include a naphtha fraction
481, a diesel fraction 483, a heavy diesel fraction 482, a light
gasoil 484, and a bottoms fraction 485. The bottoms fraction 485
can correspond to a 343.degree. C.+ fraction, or a 370.degree. C.+
fraction, or a 400.degree. C.+ fraction, or another convenient type
of fraction that can be generated from atmospheric
distillation.
[0070] In the configuration shown in FIG. 4, heavy diesel fraction
482 and light gasoil 484 are passed into aromatic saturation stage
490. Bottoms fraction 485 is passed into a vacuum fractionator 450
for further fractionation. For example, bottoms fraction 485 can be
fractionated 460 to form a 12 cSt naphthenic base oil 466, a 35 cSt
naphthenic base oil 468, and a 566.degree. C.+ bottoms 469. The
naphthenic base oil fractions 466 and 468 can then also be passed
into aromatic saturation stage 490 for further hydroprocessing. The
bottoms 469 can be used for coke production and/or a portion can
also be passed into aromatic saturation stage 490. The separate
fractions for passage into aromatic saturation stage 490 are noted
based on aspects where block processing is used to separately
expose the fractions to aromatic saturation conditions. Optionally,
one or more wide cut fractions can be passed into aromatic
saturation stage 490, rather than forming distinct fractions prior
to aromatic saturation.
[0071] In other aspects, the additional vacuum fractionator 460 can
be omitted, and the bottoms fraction 485 plus one or more of diesel
fraction 483, heavy diesel fraction 482, and light gasoil fraction
484 can be passed into aromatic saturation stage 490 for further
hydroprocessing.
[0072] Aromatic saturation stage 490 can generate an effluent 495
that is then fractionated 430 to form a variety of products. The
variety of products can include, for example, a naphtha fraction
441, a diesel fraction 443, one or more light naphthenic base oils
432, and one or more heavy naphthenic base oils 436.
[0073] FIG. 5 shows a variation on the configuration in FIG. 1. In
FIG. 5, one or more the naphthenic product compositions, such as
products 132, 134, 136, or 138, can undergo aromatic extraction in
a solvent processing stage 550. This can produce raffinate products
535 with reduced or minimized aromatic contents. This can also
produce one or more extract fractions 539.
EXAMPLES
[0074] Various examples are provided below to demonstrate
hydroprocessing of catalytic slurry oils (without dewaxing) to form
naphthenic product compositions. In the various examples below,
representative catalytic slurry oil feeds were used. Table 1 shows
the range of properties for the representative catalytic slurry oil
feeds.
TABLE-US-00001 TABLE 1 Typical Catalytic Slurry Oil Properties
Hydrogen Mass % 7.26-7.38 Sulfur Mass % 3.0-3.1 Nitrogen Mass %
0.16-0.25 Micro Carbon Residue Mass % 12.5 Density at 15.degree. C.
(calculated) g/cm3 1.12 Kinematic Viscosity, 100.degree. C. cSt
29.6-31.6 SIMDIS .degree. C. 10% 355-357 50% 422-425 90% 534-541
Composition Wt % Saturates 6.2 Aromatics + Sulfides + Polars
93.8
Example 1--Naphthenic Base Oils from Hydrotreating Second Example
of Single Stage Upgrading Process
[0075] A catalytic slurry oil feed within the typical ranges
described in Table 1 was exposed to a stacked bed of commercially
available hydrotreating catalysts under conditions corresponding to
2400 psig (.about.16.5 MPa-g) of H2, a LHSV of 0.24 hr-1, and a
hydrogen treat gas rate of 10,500 scf/bbl (.about.1800 m3/m3). The
temperature during hydrotreatment was selected to generate a total
liquid product (C5+) with a sulfur content of roughly 150 wppm. The
resulting hydrotreated effluent was then fractionated to form a
fuels cut (including naphtha and diesel boiling range components),
a 566.degree. C.+ bottoms fraction, and four naphthenic base oil
compositions. The naphthenic base oil compositions corresponded to
a light naphthenic base oil with a kinematic viscosity at
100.degree. C. of 2.9 cSt; a medium naphthenic base oil with a
kinematic viscosity at 100.degree. C. of 6.0 cSt; a first heavy
naphthenic base oil with a kinematic viscosity at 100.degree. C. of
18.7 cSt; and a second heavy naphthenic base oil with a kinematic
viscosity at 100.degree. C. of 58.4 cSt. Table 2 shows the
properties of the naphthenic base oils.
TABLE-US-00002 TABLE 2 Naphthenic Base Oils from Single Stage
Hydrotreatment Sample 1 2 3 4 Sulfur (wppm) 19.1 107 341 396
Nitrogen (wppm) 1.6 31.4 164 209 KV @ 40.degree. C. 16.10 87.78 970
11002 (cSt) KV @ 70.degree. C. 83.57 423.92 (cSt) KV @ 100.degree.
C. 2.91 5.98 18.70 58.41 (cSt) Viscosity Index -45 -153 -232 -323
Density @15.degree. C. 0.9544 0.9910 1.0098 1.0266 (g/cm3) SIMDIS
(.degree. C.) T5/T50/T95 307/ 345/ 395/ 419/ 339/358 378/407
429/480 480/553 Total Aromatics 59 78 78 83 (D2502) (wt %)
Example 2--Naphthenic Base Oils from Hydrotreating and Solvent
Extraction
[0076] Naphthenic base oils 1 and 2 from Table 2 were further
processed using solvent extraction in N-Methyl Pyrrolidone. The
solvent extraction conditions are shown in Table 5, along with a
comparison of the properties of the naphthenic base oil prior to
extraction and the resulting raffinate naphthenic base oil. As
shown in Table 3, solvent extraction can reduce the aromatic
content of the raffinate naphthenic base oil while also improving
the viscosity index of the raffinate naphthenic base oil.
TABLE-US-00003 TABLE 3 Solvent Extracted Naphthenic Base Oils
Naphthenic Base Oil 1 Naphthenic Base Oil 2 Before After NMP Before
After NMP Extraction Extraction Extraction Extraction KV
@40.degree. C. 16.10 15.75 87.78 57.86 (cSt) KV @100.degree. C.
2.91 2.94 5.98 5.66 (cSt) Extraction Conditions Extraction Tower 60
50 Top T (.degree. C.) Extraction Tower 50 40 Bottom T (.degree.
C.) Dosage (vol/vol %) 50 100 H2O (wt %) 2.5 6 Yield 42.9 28
Aromatics (wt %) 59 44 78 39 Carbon, mol % (D2140) Cp 22 23 21 29
Cn 52 57 39 56 Ca 26 20 39 15
Example 3--Two Stage Naphthenic Oil Production Via Hydrotreating
and Aromatic Saturation
[0077] A feed within the ranges of Table 1 was hydrotreated under
conditions similar to those used in Example 1. The resulting
hydrotreated effluent was fractionated, which included formation of
a 3.6 cSt naphthenic base oil composition. The 3.6 cSt naphthenic
base oil had an aromatics content of roughly 60 wt %, a paraffin
content of 2.3 wt %, and a viscosity index of roughly -100. The 3.6
cSt naphthenic base oil composition was then exposed to several
types of aromatic saturation catalysts under aromatic saturation
conditions that included 2000 psig (.about.13.8 MPa-g) of H2 and a
hydrogen treat gas rate of 4600-5000 scf/bbl (.about.820-890
m3/m3). The temperature and LHSV were varied between roughly
500.degree. F. (260.degree. C.) and 575.degree. F. (302.degree. C.)
as shown in FIG. 7.
[0078] Three different aromatic saturation catalysts were used for
aromatic saturation. One aromatic saturation catalyst corresponded
to a commercially available aromatic saturation catalyst that
included noble metals on a refractory support. The second aromatic
saturation catalyst corresponded to 0.6 wt % Pt on an alumina bound
USY support. The third aromatic saturation catalyst corresponded to
0.9 wt % Pd and 0.3 wt % Pt on an alumina bound MCM-41 support.
[0079] During aromatic saturation, the commercially available
aromatic saturation catalyst was effective for substantially
complete saturation of the aromatics in the feed, resulting in
naphthenic base oils with roughly 73 mol % to 76 mol % naphthenic
carbons, 20 mol % to 23 mol % paraffinic carbons, and 3 mol % to 4
mol % aromatics carbons (ASTM D2140). The naphthenic base oils had
a viscosity index of between -4 and 7 and a kinematic viscosity at
100.degree. C. of roughly 3.0.
[0080] The catalyst with 0.6 wt % Pt supported on alumina bound USY
resulted in slightly less saturation of aromatic rings relative to
the commercially available catalyst. At temperatures of roughly
280.degree. C. and roughly 300.degree. C., the 0.6 wt % Pt/USY
catalyst generated an aromatic saturation effluent similar to the
commercial catalyst, including 73 mol % to 75 mol % naphthenic
carbons, 20 mol % to 23 mol % paraffinic carbons, and 4 mol % to 5
mol % aromatic carbons. The viscosity index of the effluent from
the 0.6 wt % Pt/USY catalyst was between 8 and 26 at the
temperatures of 280.degree. C. and 300.degree. C., which is higher
than the range for the commercially available catalyst. The
resulting kinematic viscosity at 100.degree. C. was also lower,
corresponding to roughly 2.7 to 2.9 cSt. It is noted that the
processing at 260.degree. C. resulted in substantially less
aromatic saturation, so that the aromatic carbon content was
roughly 10 mol %, with a corresponding viscosity index of roughly
-18. Although the 0.6 wt % Pt/USY catalyst appeared to have
modestly lower activity for aromatic saturation, the viscosity
index of the resulting effluent appeared to be higher.
[0081] The catalyst with 0.9 wt % Pd and 0.3 wt % Pd on alumina
bound MCM-41 appeared to have still lower activity for aromatic
saturation at the temperatures and space velocities shown in FIG.
7. At the temperatures of roughly 280.degree. C. and 300.degree.
C., the Pt+Pd/MCM-41 catalyst produced effluents with aromatic
contents ranging from roughly 7 wt % to 28 wt %. The naphthenic
carbon content 63 mol % to 72 mol %, while the aromatic carbon
content was 6 mol % to 15 mol %. The paraffinic carbon content
remained at 22 mol % to 23 mol %. The viscosity index of the
effluents ranged from -11 to 16, with kinematic viscosities of
roughly 2.8 to 3.0 cSt. Similar to the 0.6 wt % Pt/USY catalyst,
performing the aromatic saturation at 260.degree. C. resulted in
lower aromatic saturation. At 260.degree. C., the effluent had a
viscosity index of -31 with a kinematic viscosity of 3.2 cSt.
Example 4--Two Stage Upgrading Via Hydrotreating and Aromatic
Saturation
[0082] A feed within the ranges of Table 1 was hydrotreated under
conditions similar to those used in Example 1. The resulting
hydrotreated effluent was fractionated, which included form various
naphthenic base oil compositions. A 14.28 cSt naphthenic base oil
cut was further hydrotreated over a bulk metal hydrotreating
catalyst and then over a commercial aromatic saturation catalyst
after the separation of the H2S, NH3, and C1-C4 light ends.
Hydrotreating was conducted under the conditions that included 2000
psig (.about.13.8 MPa-g) of H2, a hydrogen treat gas rate of 10,000
scf/bbl (.about.1781 m3/m3), an LHSV of roughly 1.0 hr-1, and a
temperature of 375.degree. C. Aromatic saturation was conducted
under the conditions that included 2000 psig (.about.13.8 MPa-g) of
H2, a hydrogen treat gas rate of 10,000 scf/bbl (.about.1781
m3/m3), an LHSV of roughly 0.25 hr-1, and a temperature of either
roughly 225.degree. C. or 250.degree. C. Liquid products collected
from AROSAT were distilled to obtain naphthenic oils with a nominal
IBP of 700.degree. F.+ fraction.
[0083] Properties of the resulting naphthenic base oils, listed in
Table 4, show that the 2-stage process has produced naphthenic base
oils with a kinematic viscosity of roughly 9 cSt at 100.degree. C.
and a VI of -54. Aromatic reduction was greater than 99.5%. The
products contain 27-28 mol % paraffinic carbon, 69 mol % naphthenic
carbon and 3-4 mol % aromatic carbon.
TABLE-US-00004 TABLE 4 Two Stage Upgrading Feed and Products Feed
kV @ 60.degree. C. 111.3 kV@ 100.degree. C. 14.28 VI -244
Aromatics, wt % 76.5 Carbon Type, mole % (D2140) Cp 12 Cn 54 Ca 35
HDT Temp, .degree. C. 360-375 Pressure, psig 2000 LHSV, 1/h 1.0
H2/Oil, scf/bbl 10000 AROSAT Temp, .degree. C. 225 250 Pressure,
psig 2000 LHSV, 1/h 0.25 H2/Oil, scf/bbl 10000 Product kV @
40.degree. C. 155.9 148 kV @ 100.degree. C. 9.13 8.9 VI -54.6 -53.1
Aromatics, wt % 0.36 0.25 Carbon Type, mole % (D2140) Cp 28 27 Cn
69 69 Ca 4 3
Example 5--Property Comparisons Versus Conventional Base Oils
[0084] FIG. 6 shows the percentage of naphthenic carbon versus
viscosity index for the various base oils made using two stage
hydroprocessing of a catalytic slurry oil, similar to the method
described in Example 4 (triangle data points). The resulting
naphthenic base oils had viscosities ranging from roughly 3.0 cSt
to roughly 30 cSt. As shown in FIG. 6, the various naphthenic base
oils had viscosity index values of 30 or less, or 25 or less.
[0085] For comparison, the amount of naphthenic carbon versus
viscosity index is shown for a large number of naphthenic base oils
made from conventional naphthenic crude feeds (circle data points).
The comparative data points correspond to data points that were
available in various types of literature. The dividing line between
the two sets of data points demonstrates the unexpected disparity
between the viscosity index and naphthenic carbon content for the
naphthenic oils formed using conventional naphthenic feed versus
naphthenic oils formed from catalytic slurry oil.
[0086] FIG. 10 provides another comparison between base oils made
according to Example 4 and the comparative base oils shown in FIG.
6. In FIG. 10, the amount of paraffinic carbon according to ASTM
D2140 is plotted versus the weight percent of saturates in the base
oils. As shown in FIG. 10, the base oils made from catalytic slurry
oil included 30 mol % or less paraffinic carbon, while the
conventionally made naphthenic base oils included 33 mol % or more
paraffinic carbon, regardless of the amount of saturates in the
base oils.
[0087] As still another type of comparisons, FIG. 8 and FIG. 9 show
pour point versus kinematic viscosity for the two stage
hydroprocessing base oils made from catalytic slurry oil (triangle
data points). FIG. 8 corresponds to kinematic viscosity at
100.degree. C., while FIG. 9 corresponds to kinematic viscosity at
40.degree. C. For comparison, base oils made from catalytic slurry
oil according to the methods described in U.S. Pat. Nos. 8,585,889,
8,691,076, or 8,911,613 are also shown (circle data points). The
comparative base oils in FIG. 8 and FIG. 9 correspond to base oils
that were exposed to catalytic dewaxing as part of the
hydroprocessing to form the base oils.
[0088] As shown in FIG. 8 and FIG. 9, the comparative base oils
have higher kinematic viscosities at comparable pour point than the
base oils made according to the methods described herein. In
addition to being dewaxed, the comparative base oils also tend to
have one or more other differences in property, such as a
naphthenic carbon content less than 60 mol % and/or a viscosity
index greater than 30 and/or an aromatics content of greater than
5.0 wt %.
ADDITIONAL EMBODIMENTS
Embodiment 1
[0089] A method for processing a product fraction from a fluid
catalytic cracking (FCC) process, comprising: exposing a feed
comprising a catalytic slurry oil, the feed comprising a
343.degree. C.+ portion, to a hydrotreating catalyst under
effective hydrotreating conditions to form a hydrotreated effluent,
the 343.degree. C.+ portion of the feed comprising a density of
1.06 g/cm3 or more, and exposing at least a portion of the
343.degree. C.+ portion to a hydroprocessing catalyst under
effective hydroprocessing conditions to form a hydroprocessed
effluent, wherein a C5+ portion of the hydroprocessed effluent
comprises 50 mol % or more naphthenic carbons and 500 wppm or less
of sulfur, the C5+ portion of the hydroprocessed effluent
optionally comprising a density of 1.00 g/cm3 or less.
Embodiment 2
[0090] The method of Embodiment 1, wherein the C5+ portion of the
hydroprocessed effluent comprises 60 mol % or more of naphthenic
carbons (or 65 mol % or more, or 70 mol % or more), or wherein the
C5+ portion of the hydroprocessed effluent comprises 30 mol % or
less of paraffinic carbons (or 25 mol % or less), or a combination
thereof.
Embodiment 3
[0091] The method of any of the above embodiments, wherein the C5+
portion of the hydroprocessed effluent comprises 50 wt % or more
saturates (or 60 wt % or more, or 70 wt % or more).
Embodiment 4
[0092] The method of any of the above embodiments, wherein the C5+
portion of the hydroprocessed effluent comprises 15 wt % or less
aromatics (or 10 wt % or less), or wherein the C5+ portion of the
hydroprocessed effluent comprises 15 mol % or less of aromatic
carbons (or 10 mol % or less, of 5.0 mol % or less), or a
combination thereof.
Embodiment 5
[0093] The method of any of the above embodiments, wherein the C5+
portion of the hydroprocessed effluent comprises a kinematic
viscosity at 100.degree. C. of 2.0 cSt to 30 cSt, a viscosity index
of 25 or less, or a combination thereof.
Embodiment 6
[0094] The method of any of the above embodiments, further
comprising fractionating the C5+ portion of the hydroprocessed
effluent to form one or more naphthenic base oil compositions, the
one or more naphthenic base oil compositions comprising: a) at
least one naphthenic base oil composition comprising a kinematic
viscosity at 100.degree. C. of 1.5 cSt to 4.0 cSt, a viscosity
index of -20 to 25, and a T5 distillation point of 270.degree. C.
or more; b) at least one naphthenic base oil composition comprising
a kinematic viscosity at 100.degree. C. of 4.5 cSt to 8.0 cSt, a
viscosity index of -50 to 0, and a T5 distillation point of
300.degree. C. or more; c) at least one naphthenic base oil
composition comprising a kinematic viscosity at 100.degree. C. of
8.0 cSt to 20 cSt, a viscosity index of -80 to -20, and a T5
distillation point of 330.degree. C. or more; d) at least one
naphthenic base oil composition comprising a kinematic viscosity at
100.degree. C. of 25 cSt to 75 cSt, a viscosity index of -120 to
-50, and a T5 distillation point of 360.degree. C. or more; e) a
combination of two or more of a), b), c), and d); or f) a
combination of three or more of a), b), c), and d).
Embodiment 7
[0095] The method of Embodiment 6, wherein the one or more
naphthenic base oil compositions comprise 60 mol % or more of
naphthenic carbons (or 65 mol % or more, or 70 mol % or more); or
30 mol % or less paraffinic carbons (or 25 mol % or less); or 50 wt
% or more saturates (or 60 wt % or more, or 70 wt % or more), or 15
mol % or less of aromatic carbons (or 10 mol % or less, of 5.0 mol
% or less); or a combination of two or more thereof, or three or
more thereof.
Embodiment 8
[0096] The method of any of the above embodiments, wherein the
hydroprocessed effluent is formed without exposing the catalytic
slurry oil to a dewaxing catalyst under catalytic dewaxing
conditions, or wherein the hydroprocessed effluent is formed
without exposing the catalytic slurry oil to a catalyst comprising
a zeotype framework in the presence of hydrogen under
hydroprocessing conditions, or wherein the effective
hydroprocessing conditions comprise fixed bed hydroprocessing
conditions, or a combination thereof.
Embodiment 9
[0097] The method of any of the above embodiments, wherein the feed
comprises a fraction from a fluid catalytic cracking process having
a T5 distillation point of 343.degree. C. or more, a T95
distillation point of 566.degree. C. or less, or a combination
thereof, the method optionally further comprising treating the
fraction from the fluid catalytic cracking process to form a
treated fraction comprising a particle content of 500 wppm or less
of particles having a size of 25 .mu.m or more (or 100 wppm or
less), the catalytic slurry oil comprising at least a portion of
the treated fraction.
Embodiment 10
[0098] A naphthenic base oil composition, comprising 500 wppm or
less sulfur, 18 mol % to 30 mol % paraffinic carbons, 50 mol % or
more of naphthenic carbons, a kinematic viscosity at 100.degree. C.
of 2.0 cSt to 30 cSt, a viscosity index of 25 or less, and a T5
distillation point of 260.degree. C. or more.
Embodiment 11
[0099] The composition of Embodiment 10, wherein i) the composition
comprises 70 mol % or more naphthenic carbons and a viscosity index
of -50 to 25; ii) the composition comprises 60 mol % to 70 mol %
naphthenic carbons and a viscosity index of -100 to 10; or iii) the
composition comprises 50 mol % to 60 mol % naphthenic carbons and a
viscosity index of -150 to -20.
Embodiment 12
[0100] The composition of Embodiment 10, wherein the composition
comprises 25 mol % to 30 mol % paraffinic carbons, 65 mol % to 75
mol % of naphthenic carbons, a kinematic viscosity at 100.degree.
C. of 8.0 cSt to 15 cSt, and a viscosity index of -40 or less (or
-50 or less).
Embodiment 13
[0101] The composition of any of Embodiments 10-12, wherein the
composition comprises 50 wt % or more saturates (or 60 wt % or
more, or 70 wt % or more); or wherein the composition comprises 15
wt % or less aromatics (or 10 wt % or less, or 5 wt % or less); or
wherein the composition comprises 15 mol % or less of aromatic
carbons (or 10 mol % or less, of 5.0 mol % or less), or a
combination thereof.
Embodiment 14
[0102] A composition formed according to the method of any of
Embodiments 1-9.
Embodiment 15
[0103] A naphthenic base oil composition, comprising 500 wppm or
less sulfur, 18 mol % to 30 mol % paraffinic carbons and 60 mol %
or more of naphthenic carbons, the naphthenic base oil composition
further comprising: a) a kinematic viscosity at 100.degree. C. of
1.5 cSt to 4.5 cSt, a viscosity index of -20 to 25, and a T5
distillation point of 270.degree. C. or more; b) a kinematic
viscosity at 100.degree. C. of 4.5 cSt to 8.0 cSt, a viscosity
index of -50 to 0, and a T5 distillation point of 300.degree. C. or
more; c) a kinematic viscosity at 100.degree. C. of 8.0 cSt to 20
cSt, a viscosity index of -80 to -20, and a T5 distillation point
of 330.degree. C. or more; or d) a kinematic viscosity at
100.degree. C. of 20 cSt to 75 cSt, a viscosity index of -120 to
-50, and a T5 distillation point of 360.degree. C. or more.
[0104] 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.
[0105] 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.
* * * * *