U.S. patent application number 13/572035 was filed with the patent office on 2014-02-13 for co-production of heavy and light base oils.
This patent application is currently assigned to EXXONMOBIL RESEARCH AND ENGINEERING COMPANY. The applicant listed for this patent is Jason Thomas Calla, Michel Daage, Ajit Bhaskar Dandekar, Krista Marie Prentice. Invention is credited to Jason Thomas Calla, Michel Daage, Ajit Bhaskar Dandekar, Krista Marie Prentice.
Application Number | 20140042056 13/572035 |
Document ID | / |
Family ID | 48980342 |
Filed Date | 2014-02-13 |
United States Patent
Application |
20140042056 |
Kind Code |
A1 |
Daage; Michel ; et
al. |
February 13, 2014 |
CO-PRODUCTION OF HEAVY AND LIGHT BASE OILS
Abstract
A suitable feedstock for forming lubricant base oils is
separated into at least a lower boiling portion and a higher
boiling portion. The lower boiling portion is combined with a feed
suitable for use as a fuels hydrocracking feed. The combined feed
is hydrocracked and catalytically dewaxed in order to form fuels
and Group II, Group II+, or Group III light neutral basestocks. The
higher boiling portion of the feedstock is solvent processed in
order to form Group I heavy neutral base oils and/or Group I
brightstock base oils. The higher boiling portion of the feedstock
can correspond to both a bottoms fraction and one or more
additional fractions boiling above a fractionation cut point.
Inventors: |
Daage; Michel; (Hellertown,
PA) ; Calla; Jason Thomas; (Fairfax, VA) ;
Prentice; Krista Marie; (Bethlehem, PA) ; Dandekar;
Ajit Bhaskar; (Vienna, VA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Daage; Michel
Calla; Jason Thomas
Prentice; Krista Marie
Dandekar; Ajit Bhaskar |
Hellertown
Fairfax
Bethlehem
Vienna |
PA
VA
PA
VA |
US
US
US
US |
|
|
Assignee: |
EXXONMOBIL RESEARCH AND ENGINEERING
COMPANY
Annandale
NJ
|
Family ID: |
48980342 |
Appl. No.: |
13/572035 |
Filed: |
August 10, 2012 |
Current U.S.
Class: |
208/60 |
Current CPC
Class: |
C10G 21/003 20130101;
C10G 2400/04 20130101; C10G 2400/10 20130101; C10M 101/02 20130101;
C10G 65/12 20130101; C10G 47/00 20130101; C10G 67/16 20130101; C10G
53/06 20130101; C10M 177/00 20130101 |
Class at
Publication: |
208/60 |
International
Class: |
C10G 65/12 20060101
C10G065/12 |
Claims
1. A method for forming fuel and lubricant products, comprising:
separating a feedstock into at least a first fraction having a T5
boiling point greater than 600.degree. F. (316.degree. C.) and a
T95 boiling point of 1150.degree. F. (621.degree. C.) or less and a
bottoms fraction; deasphalting the bottoms fraction to form a
deasphalted bottoms fraction and an asphalt product; extracting the
deasphalted bottoms in the presence of an extraction solvent to
form a raffinate stream and an extract stream, an aromatics content
of the raffinate stream being lower than an aromatics content of
the deasphalted bottoms; dewaxing the raffinate stream in the
presence of a dewaxing solvent to form a lubricant base oil product
and a wax product; hydroprocessing a combined feedstock
corresponding to the first fraction and a fuels feedstock, at least
a portion of the combined feedstock having a boiling point greater
than 700.degree. F. (371.degree. C.), the fuels feedstock having a
T5 boiling point greater than 350.degree. F. (177.degree. C.) and a
T95 boiling point of 1150.degree. F. (621.degree. C.) or less,
under first effective hydroprocessing conditions to form a
hydroprocessed effluent; separating the hydroprocessed effluent to
form at least a gas phase effluent and a liquid phase effluent;
hydroprocessing at least a portion of the liquid phase effluent in
the presence of at least a dewaxing catalyst under second effective
hydroprocessing conditions to form a dewaxed effluent, the first
effective hydroprocessing conditions and the second effective
hydroprocessing conditions being effective for conversion of at
least 60% of the portion of the combined feedstock boiling above
700.degree. F. (371.degree. C.) to a portion boiling below
700.degree. F. (371.degree. C.); and fractionating the dewaxed
effluent to form at least a distillate fuel product having a T95
boiling point of 750.degree. F. (399.degree. C.) or less and a
lubricant base oil product having a viscosity index of at least 80,
a sulfur content of 300 wppm or less, and an aromatics content of
10 wt % or less.
2. The method of claim 1, wherein separating the feedstock
comprises: separating the feedstock into at least a first fraction
having a T5 boiling point greater than 600.degree. F. (316.degree.
C.) and a T95 boiling point of 950.degree. F. (510.degree. C.) or
less, a second fraction having a T5 boiling point of at least the
T95 boiling point of the first fraction, and a bottoms fraction;
and wherein extracting the deasphalted bottoms comprises:
extracting the deasphalted bottoms and the second fraction in the
presence of an extraction solvent to form a raffinate stream and an
extract stream, an aromatics content of the raffinate stream being
lower than an aromatics content of the combined deasphalted bottoms
and second fraction.
3. The method of claim 2, wherein the first fraction has a T95
boiling point of 850.degree. F. or less.
4. The method of claim 2, wherein, second fraction has a T95
boiling point of 1100.degree. F. or less.
5. The method of claim 1, wherein the first fraction has a T5
boiling point of at least 650.degree. F.
6. The method of claim 1, wherein the first effective
hydroprocessing conditions comprise exposing the combined feedstock
to a hydrotreating catalyst, a hydrocracking catalyst, or a
combination thereof under effective hydrotreating conditions,
effective hydrocracking conditions, or a combination thereof.
7. The method of claim 6, wherein the hydrocracking catalyst is
USY, zeolite Beta, or a combination thereof.
8. The method of claim 1, wherein the second effective
hydroprocessing conditions comprise effective dewaxing
conditions.
9. The method of claim 1, wherein the second effective
hydroprocessing conditions further comprise exposing the at least a
portion of the liquid effluent to a hydrocracking catalyst under
second effective hydrocracking conditions.
10. The method of claim 1, wherein the first effective
hydroprocessing conditions and the second effective hydroprocessing
conditions are effective for conversion of at least 70% of the
portion of the combined feedstock boiling above 700.degree. F.
(371.degree. C.) to a portion boiling below 700.degree. F.
(371.degree. C.).
11. The method of claim 1, wherein separating the hydroprocessed
effluent to form at least a gas phase effluent comprises separating
the hydroprocessed effluent to form a lower boiling fraction having
a T95 boiling point of 400.degree. F. (204.degree. C.) or less.
12. The method of claim 1, wherein separating the hydroprocessed
effluent to form at least a liquid phase effluent comprises forming
a first liquid phase effluent with a T95 boiling point of
650.degree. F. (343.degree. C.) or less, and a second liquid phase
effluent having a T5 boiling point of at least 650.degree. F.
(343.degree. C.).
13. The method of claim 1, wherein the liquid phase effluent has a
sulfur content of 300 wppm or less.
14. The method of claim 1, further comprising dividing an initial
feed into the feedstock and the fuels feedstock.
15. The method of claim 1, further comprising hydrofinishing at
least a portion of the dewaxed effluent under effective
hydrofinishing conditions.
16. The method of claim 1, wherein separating feedstock comprises:
separating the feedstock into at least a first fraction having a T5
boiling point greater than 600.degree. F. (316.degree. C.) and a
T95 boiling point of 950.degree. F. (510.degree. C.) or less, a
second fraction having a T5 boiling point of at least the T95
boiling point of the first fraction, and a bottoms fraction, the
method further comprising: extracting the second fraction in the
presence of an extraction solvent to form a second raffinate stream
and a second extract stream, an aromatics content of the second
raffinate stream being lower than an aromatics content of the
second fraction; and dewaxing the second raffinate stream in the
presence of a dewaxing solvent to form a second lubricant base oil
product and a second wax product.
17. The method of claim 1, wherein the first effective
hydroprocessing conditions comprise a temperature of 550.degree. F.
(288.degree. C.) to 840.degree. F. (449.degree. C.), hydrogen
partial pressures of from 250 psig to 5000 psig (1.8 MPag to 34.6
MPag), and a hydrogen treat gas rate 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), and wherein
the second effective hydroprocessing conditions comprise a
temperature of from 200 to 450.degree. C., a hydrogen partial
pressure of from 1.8 MPag to 34.6 MPag (250 psig to 5000 psig), and
a hydrogen treat gas rate of from 35.6 m.sup.3/m.sup.3 (200 SCF/B)
to 1781 m.sup.3/m.sup.3 (10,000 scf/B).
Description
FIELD
[0001] Systems and methods are provided for production of lubricant
oil basestocks.
BACKGROUND
[0002] Dewaxing is a commonly used technique for improving the
properties of a petroleum fraction for use in various products,
such as fuels or lubricant base stocks. Historically, solvent
dewaxing was the first type of dewaxing used for modifying the
properties of a feedstock. Solvent extraction and dewaxing allowed
for separation of a feedstock into a raffinate fraction for use as
a distillate fuel or lubricant, an aromatics fraction, and a waxy
fraction. More recently, catalytic dewaxing has been commonly used
for improving the properties of feeds for use in fuels or lubricant
base stocks.
[0003] U.S. Pat. No. 4,259,170 describes a process for
manufacturing lube basestocks. In the process, one or more lower
boiling fractions from a vacuum distillation tower are solvent
dewaxed to form lubricant base stocks. One or more higher boiling
fractions are catalytically dewaxed in order to provide a pour
point improvement for the higher boiling fractions that is greater
than the amount that can be achieved by solvent dewaxing.
[0004] U.S. Pat. No. 6,773,578 describes a process for preparing
lubes with high viscosity index values. The process includes
obtaining a first feedstock that includes at least 95% of material
that boils below 1150.degree. F. (621.degree. C.), and a second
feedstock that includes at least 95% of material that boils above
1150.degree. F. (621.degree. C.). The feedstock containing the
portion that boils below 1150.degree. F. is catalytically dewaxed.
The feedstock containing the portion that boils above 1150.degree.
F. is solvent dewaxed and optionally also catalytically dewaxed.
Performing solvent dewaxing on the above 1150.degree. F. portion is
described as reducing the difference between the cloud point and
the pour point for the resulting products.
[0005] U.S. Pat. No. 7,354,508 describes a process for preparing a
heavy and a light lubricating base oil. A feedstock for forming
lubricant basestocks is separated into a lower boiling fraction and
a higher boiling fraction. The lower boiling fraction and higher
boiling fraction are dewaxed under different conditions. Solvent
dewaxing is generally mentioned as a type of dewaxing. However,
catalytic dewaxing is identified as the preferred type of dewaxing
for dewaxing of both fractions.
SUMMARY
[0006] In an aspect, a method for forming fuel and lubricant
products is provided. The method includes separating a feedstock
into at least a first fraction having a T5 boiling point greater
than 600.degree. F. (316.degree. C.) and a T95 boiling point of
1150.degree. F. (621.degree. C.) or less and a bottoms fraction;
deasphalting the bottoms fraction to form a deasphalted bottoms
fraction and an asphalt product; extracting the deasphalted bottoms
in the presence of an extraction solvent to form a raffinate stream
and an extract stream, an aromatics content of the raffinate stream
being lower than an aromatics content of the deasphalted bottoms;
dewaxing the raffinate stream in the presence of a dewaxing solvent
to form a lubricant base oil product and a wax product;
hydroprocessing a combined feedstock corresponding to the first
fraction and a fuels feedstock, at least a portion of the combined
feedstock having a boiling point greater than 700.degree. F.
(371.degree. C.), the fuels feedstock having a T5 boiling point
greater than 350.degree. F. (177.degree. C.) and a T95 boiling
point of 1150.degree. F. (621.degree. C.) or less, under first
effective hydroprocessing conditions to form a hydroprocessed
effluent; separating the hydroprocessed effluent to form at least a
gas phase effluent and a liquid phase effluent; hydroprocessing at
least a portion of the liquid phase effluent in the presence of at
least a dewaxing catalyst under second effective hydroprocessing
conditions to form a dewaxed effluent, the first effective
hydroprocessing conditions and the second effective hydroprocessing
conditions being effective for conversion of at least 60% of the
portion of the combined feedstock boiling above 700.degree. F.
(371.degree. C.) to a portion boiling below 700.degree. F.
(371.degree. C.); and fractionating the dewaxed effluent to form at
least a distillate fuel product having a T95 boiling point of
750.degree. F. (399.degree. C.) or less and a lubricant base oil
product having a viscosity index of at least 80, a sulfur content
of 300 wppm or less, and an aromatics content of 10 wt % or
less.
[0007] In another aspect, separation of the feedstock includes
separating the feedstock into at least a first fraction having a T5
boiling point greater than 600.degree. F. (316.degree. C.) and a
T95 boiling point of 950.degree. F. (510.degree. C.) or less, a
second fraction having a T5 boiling point of at least the T95
boiling point of the first fraction, and a bottoms fraction. In
such an aspect, extracting the deasphalted bottoms includes
extracting the deasphalted bottoms and the second fraction in the
presence of an extraction solvent to form a raffinate stream and an
extract stream, an aromatics content of the raffinate stream being
lower than an aromatics content of the combined deasphalted bottoms
and second fraction.
[0008] In still another aspect, separation of the feedstock
includes separating the feedstock into at least a first fraction
having a T5 boiling point greater than 600.degree. F. (316.degree.
C.) and a T95 boiling point of 950.degree. F. (510.degree. C.) or
less, a second fraction having a T5 boiling point of at least the
T95 boiling point of the first fraction, and a bottoms fraction. In
such an aspect, the method further includes extracting the second
fraction in the presence of an extraction solvent to form a second
raffinate stream and a second extract stream, an aromatics content
of the second raffinate stream being lower than an aromatics
content of the second fraction; and dewaxing the second raffinate
stream in the presence of a dewaxing solvent to form a second
lubricant base oil product and a second wax product.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] FIG. 1 schematically shows an example of a configuration
suitable for processing a feedstock to form light and heavy base
oil products.
DETAILED DESCRIPTION
[0010] 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.
Overview
[0011] In various embodiments, methods are provided for producing a
plurality of lubricant base oil products. A suitable feedstock for
forming lubricant base oils is separated into at least a lower
boiling portion and a higher boiling portion. The lower boiling
portion is combined with a feed suitable for use as a fuels
hydrocracking feed. The combined feed is hydrocracked and
catalytically dewaxed in order to form fuels and Group II, Group
II+, or Group III light neutral basestocks. The higher boiling
portion of the feedstock is solvent processed in order to form
Group I heavy neutral base oils and/or Group I brightstock base
oils. This provides a desirable combination that cannot be readily
achieved by solvent dewaxing or catalytic dewaxing of the full
lubricant feedstock.
[0012] Group I basestocks or base oils are defined as base oils
with less than 90 wt % saturated molecules and/or at least 0.03 wt
% sulfur content. Group I basestocks also have a viscosity index
(VI) of at least 80 but less than 120. Group II basestocks or base
oils contain at least 90 wt % saturated molecules and less than
0.03 wt % sulfur. Group II basestocks also have a viscosity index
of at least 80 but less than 120. Group III basestocks or base oils
contain at least 90 wt % saturated molecules and less than 0.03 wt
% sulfur, with a viscosity index of at least 120. In addition to
the above formal definitions, some Group I basestocks may be
referred to as a Group I+ basestock, which corresponds to a Group I
basestock with a VI value of 103 to 108. Some Group II basestocks
may be referred to as a Group II+ basestock, which corresponds to
a. Group II basestock with a VI of at least 113. Some Group III
basestocks may be referred to as a Group III+ basestock, which
corresponds to a Group III basestock with a VI value of at least
140.
[0013] Conventionally, a feedstock for lubricant base oil
production is processed either using solvent dewaxing or using
catalytic dewaxing. For example, in a lube solvent plant, a vacuum
gas oil (VGO) or another suitable feed is fractionated into light
neutral (LN) and heavy neutral (HN) distillates and a bottom
fraction by some type of vacuum distillation. The bottoms fraction
is subsequently deasphalted to recover an asphalt fraction and a
brightstock. The LN distillate, HN distillate, and brightstock are
then solvent extracted to remove the most polar molecules as an
extract and corresponding LN distillate, HN distillate, and
brightstock raffinates. The raffinates are then solvent dewaxed to
obtain a LN distillate, HN distillate, and brightstock basestocks
with acceptable low temperature properties. It is beneficial to
hydrofinish the lubricant basestocks either before or after the
solvent dewaxing step. The resulting lubricant basestocks ma
contain a significant amount of aromatics (up to 25%) and high
sulfur (>300 ppm). Thus, the typical base oils formed from
solvent dewaxing alone are Group I basestocks. As an alternative, a
raffinate hydroconversion step can be performed prior to the
solvent dewaxing. The hydroconversion is essentially a treatment
under high H.sub.2 pressure in presence of a metal sulfide based
hydroprocessing catalyst which remove most of the sulfur and
nitrogen. The amount of conversion in the hydroconversion reaction
is typically tuned to obtain a predetermined increase in viscosity
index and 95%+ saturates. This allows the solvent dewaxed lubricant
basestock products to be used as Group II or Group II+ basestocks.
Optionally, the wax recovered from a solvent dewaxing unit may also
be processed by catalytic dewaxing to produce Group III or Group
III+ lubricant basestocks.
[0014] For production of lubricant base oils in an all catalytic
process, a VGO (or another suitable feed) is hydrocracked under
medium pressure conditions to obtain a hydrocracker bottoms with
reduced sulfur and nitrogen contents. One or more LN and/or FIN
distillate fractions may then be recovered from the desulfurized
hydrocracker bottoms. The recovered fractions are then
catalytically dewaxed, such as by using a shape selective dewaxing
catalyst, followed by hydrofinishing. This process typically
results in production of Group II, Group II+, and Group III base
oils. However, due to the conversion in the hydrocracker, the
amount of heavy neutral base oils that are produced is limited.
Feedstocks
[0015] A wide range of petroleum and chemical feedstocks can be
hydroprocessed in accordance with the disclosure. Suitable
feedstocks include whole and reduced petroleum crudes, atmospheric
and vacuum residua, propane deasphalted residua, e.g., brightstock,
cycle oils, FCC tower bottoms, gas oils, including vacuum gas oils
and coker gas oils, light to heavy distillates including raw virgin
distillates, hydrocrackates, hydrotreated oils, slack waxes,
Fischer-Tropsch waxes, raffinates, and mixtures of these
materials.
[0016] One way of defining a feedstock is based on the boiling
range of the feed. One option for defining a boiling range is to
use an initial boiling point for a feed and/or a final boiling
point for a feed. Another option, which in some instances may
provide a more representative description of a feed, is to
characterize a feed based on the amount of the feed that boils at
one or more temperatures. For example, a "T5" boiling point for a
feed is defined as the temperature at which 5 wt % of the feed will
boil off. Similarly, a "T95" boiling point is a temperature at 95
wt % of the feed will boil.
[0017] Typical feeds include, for example, feeds with an initial
boiling point of at least 650.degree. F. (343.degree. C.), or at
least 700.degree. F. (371.degree. C.), or at least 750.degree. F.
(399.degree. C.). Alternatively, a feed may be characterized using
a T5 boiling point, such as a feed with a T5 boiling point of at
least 650.degree. F. (343.degree. C.), or at least 700.degree. F.
(371.degree. C.), or at least 750.degree. F. (399.degree. C.). In
some aspects, the final boiling point of the feed can be at least
1100.degree. F. (593.degree. C.), such as at least 1150.degree. F.
(621.degree. C.) or at least 1200.degree. F. (649.degree. C.). In
other aspects, a feed may be used that does not include a large
portion of molecules that would traditional be considered as vacuum
distillation bottoms. For example, the feed may correspond to a
vacuum gas oil feed that has already been separated from a
traditional vacuum bottoms portion. Such feeds include, for
example, feeds with a final boiling point of 1150.degree. F.
(621.degree. C.), or 1100.degree. F. (593.degree. C.) or less, or
1050.degree. F. (566.degree. C.) or less. Alternatively, a feed may
be characterized using a T95 boiling point, such as a feed with a
T95 boiling point of 1150.degree. F. (621.degree. C.) or less, or
1100.degree. F. (593.degree. C.) or less, or 1050.degree. F.
(566.degree. C.) or less. An example of a suitable type of
feedstock is a wide cut vacuum gas oil (VGO) feed, with a T5
boiling point of at least 700.degree. F. (371.degree. C.) and a T95
boiling point of 1100.degree. F. or less. Optionally, the initial
boiling point of such a wide cut VGO feed can be at least
700.degree. F. and/or the final boiling point can be at least
1100.degree. F. It is noted that feeds with still lower initial
boiling points and/or T5 boiling points may also be suitable, so
long as sufficient higher boiling material is available so that the
overall nature of the process is a lubricant base oil production
process and/or a fuels hydrocracking process.
[0018] The above feed description corresponds to a potential feed
for producing lubricant base oils. In some aspects, methods are
provided for producing both fuels and lubricants. Because fuels are
a desired product, feedstocks with lower boiling components may
also be suitable. For example, a feedstock suitable for fuels
production, such as a light cycle oil, can have a T5 boiling point
of at least 350.degree. F. (177.degree. C.), such as at least
100.degree. F. (201.degree. C.). Examples of a suitable boiling
range include a boiling range of from 350.degree. F. (177.degree.
C.) to 700.degree. F. (371.degree. C.), such as from 330.degree. F.
(200.degree. C.) to 650.degree. F. (343.degree. C. Thus, a portion
of the feed used for fuels and lubricant base oil production can
include components having a boiling range from 170.degree. C. to
350.degree. C. Such components can be part of an initial feed, or a
first feed with a T5 boiling point of 650.degree. F. (343.degree.
C.) can be combined with a second feed, such as a light cycle oil,
that includes components that boil between 200.degree. C. and
350.degree. C.
[0019] In embodiments involving an initial sulfur removal stage
prior to hydrocracking, the sulfur content of the feed can be at
least 300 ppm by weight of sulfur, or at least 1000 wppm, or at
least 2000 wppm, or at least 1000 wppm, or at least 10,000 wppm, or
at least 20,000 wppm. In other embodiments, including some
embodiments where a previously hydrotreated and/or hydrocracked
feed is used, the sulfur content can be 2000 wppm or less, or 1000
wppm or less, or 500 wppm or less, or 100 wppm or less.
[0020] In some embodiments, at least a portion of the feed can
correspond to a feed derived from a biocomponent source. In this
discussion, a biocomponent feedstock refers to a hydrocarbon
feedstock derived from a biological raw material component, from
biocomponent sources such as vegetable, animal, fish, and/or algae.
Note that, for the purposes of this document, vegetable fats/oils
refer generally to any plant based material, and can include
fat/oils derived from a source such as plants of the genus
Jatropha. Generally, the biocomponent sources can include vegetable
fats/oils, animal fats/oils, fish oils, pyrolysis oils, and algae
lipids/oils, as well as components of such materials, and in some
embodiments can specifically include one or more type of lipid
compounds. Lipid compounds are typically biological compounds that
are insoluble in water, but soluble in nonpolar (or fat) solvents.
Non-limiting examples of such solvents include alcohols, ethers,
chloroform, alkyl acetates, benzene, and combinations thereof.
[0021] The biocomponent feeds usable in the present disclosure can
include any of those which comprise primarily triglycerides and
free fatty acids (FFAs). The triglycerides and FFAs typically
contain aliphatic hydrocarbon chains in their structure having from
8 to 36 carbons, preferably from 10 to 26 carbons, for example from
14 to 22 carbons. Types of triglycerides can be determined
according to their fatty acid constituents. The fatty acid
constituents can be readily determined using Gas Chromatography
(GC) analysis. This analysis involves extracting the fat or oil,
saponifying (hydrolyzing) the fat or oil, preparing an alkyl (e.g.,
methyl) ester of the saponified fat or oil, and determining the
type of (methyl) ester using GC analysis. In one embodiment, a
majority (i.e., greater than 50%) of the triglyceride present in
the lipid material can be comprised of C.sub.10 to C.sub.26, for
example C.sub.12 to C.sub.18, fatty acid constituents, based on
total triglyceride present in the lipid material. Further, a
triglyceride is a molecule having a structure substantially
identical to the reaction product of glycerol and three fatty
acids. Thus, although a triglyceride is described herein as being
comprised of fatty acids, it should be understood that the fatty
acid component does not necessarily contain a carboxylic acid
hydrogen. Other types of feed that are derived from biological raw
material components can include fatty acid esters, such as fatty
acid alkyl esters (e.g., FAME and/or FAEE).
[0022] Biocomponent based feedstreams typically have relatively low
nitrogen and sulfur contents. For example, a biocomponent based
feedstream can contain up to 500 wppm nitrogen, for example up to
300 wppm nitrogen or up to 100 wppm nitrogen, instead of nitrogen
and/or sulfur, the primary heteroatom component in biocomponent
feeds is oxygen. Biocomponent diesel boiling range feedstreams,
e.g., can include up to 10 wt % oxygen, up to 12 wt % oxygen, or up
to 14 wt % oxygen. Suitable biocomponent diesel boiling range
feedstreams, prior to hydrotreatment, can include at least 5 wt %
oxygen, for example at least 8 wt % oxygen.
[0023] Alternatively, a feed of biocomponent origin can be used
that has been previously hydrotreated. This can be a hydrotreated
vegetable oil feed, a hydrotreated fatty acid alkyl ester feed, or
another type of hydrotreated biocomponent feed. A hydrotreated
biocomponent feed can be a biocomponent feed that has been
previously hydroprocessed to reduce the oxygen content of the feed
to 500 wppm or less, for example to 200 wppm or less or to 100 wppm
or less. Correspondingly, a biocomponent feed can be hydrotreated
to reduce the oxygen content of the feed, prior to other optional
hydroprocessing, to 500 wppm or less, for example to 200 wppm or
less or to 100 wppm or less. Additionally or alternately, a
biocomponent feed can be blended with a mineral feed, so that the
blended feed can be tailored to have an oxygen content of 500 wppm
or less, for example 200 wppm or less or 100 wppm or less, in
embodiments where at least a portion of the feed is of a
biocomponent origin, that portion can be at least 2 wt %, for
example at least 5 wt %, at least 10 wt %, at least 20 wt %, at
least 25 wt %, at least 35 wt %, at least 50 wt %, at least 60 wt
%, or at least 75 wt %. Additionally or alternately, the
biocomponent portion can be 75 wt % or less, for example 60 wt % or
less, 50 wt % or less, 35 wt % or less, 25 wt % or less, 20 wt % or
less, 10 wt % or less, or 5 wt % or less.
[0024] The content of sulfur, nitrogen, and oxygen in a feedstock
created by blending two or more feedstocks can typically be
determined using a weighted average based on the blended feeds. For
example, a mineral feed and a biocomponent feed can be blended in a
ratio of 80 wt % mineral feed and 20 wt % biocomponent feed. In
such a scenario, if the mineral feed has a sulfur content of 1000
wppm, and the biocomponent feed has a sulfur content of 10 wppm,
the resulting blended feed could be expected to have a sulfur
content of 802 wppm.
Feed Fractionation and Lubricant Base Oil Products
[0025] In various embodiments, at least two lubricant base oil
products can be made from a feedstock. As an initial process, a
suitable feedstock can be separated to form at least a lower
boiling feedstock portion, a higher boiling feedstock portion, and
a bottoms portion. Such a separation can be performed, for example,
using a vacuum distillation unit. One method for determining the
amounts in the various portions is by selecting cut point
temperatures. The cut point temperatures may vary depending on the
nature of the feedstock. Generally, the cut point between the lower
boiling portion and the higher boiling portion can be between
850.degree. F. (454.degree. C.) and 950.degree. F. (510.degree.
C.), such as at least 875.degree. F. (468.degree. C.) or less than
925.degree. F. (496.degree. C.) or less than 900.degree. F.
(482.degree. C.). The cut point between the higher boiling portion
and the bottoms portion can be between 1050.degree. F. (566.degree.
C.) and 1150.degree. F. (621.degree. C.), such as less than
1100.degree. F. (593.degree. C.). In some alternative aspects, it
may be desirable to increase the relative amount of light neutral
base oils that are produced. In such aspects, the cut point between
the lower boiling portion and the higher boiling portion may be
higher, such as at least 950.degree. F. (510.degree. C.), or at
least 1000.degree. F. (538.degree. C.), and less than 1150.degree.
F. (621.degree. C.), such as less than 1100.degree. F. (593.degree.
C.) or less than 1050.degree. F. (566.degree. C.).
[0026] It is noted that the above fractionation temperatures
represent the split between lighter feedstock portions, heavier
feedstock portions, and a bottoms portion. If desired, additional
fractions could also be formed based on additional cut points. For
the purposes of the discussion herein, any such additional
fractions can be processed according to boiling range. Thus, if
additional fractions are formed with a T95 boiling point of less
than 850.degree. F. (454.degree. C.) to 950.degree. F. (510.degree.
C.), all such additional fractions would be processed as part of
the lower boiling feedstock portion.
[0027] Another factor in selecting a cut point temperature for
fractionating a feedstock is selecting a cut point to achieve a
desired viscosity for the Group I lubricant base oils and/or
brightstock. During hydroprocessing to form light neutral base
oils, some changes in the viscosity of a base oil can be made by
selecting appropriate hydroprocessing conditions. However, for
heavy neutral base oils and brightstock produced from solvent
extraction and solvent dewaxing, the ability to modify the
viscosity of a feed to produce a desired viscosity product is
limited. As a result, the fractionation cut point should be
selected to produce heavy neutral base oils and/or brightstock from
solvent processing that has a desired viscosity. For example, the
fractionation cut points can be selected so that the heavy neutral
base oil produced from solvent processing has a viscosity of at
least 6.0 cSt at 100.degree. C., such as at least 7.0 cSt or at
least 8.0 cSt.
[0028] After fractionation to form a lower boiling feedstock
portion, a higher boiling feedstock portion, and a bottoms portion,
each of the portions can be further processed. The lower boiling
feedstock portion can be hydroprocessed to form Group II, Group
II+, or Group III base oils. The higher boiling feedstock portion
can be solvent dewaxed to form Group I base oils. The bottoms
portion can be deasphalted, followed by solvent dewaxing along with
the higher boiling feedstock portion.
[0029] In some alternative aspects, a feedstock may correspond to a
feed where molecules traditionally considered as corresponding to a
vacuum bottoms portion are not present, such as in a feed that
corresponds to a vacuum gas oil from a previous vacuum distillation
process. In such aspects, it may be desirable to form only the
lighter feedstock portion and the heavier feedstock portion. Of
course, some portion during the separation will correspond to a
"bottoms", but the boiling range of such a "bottoms" will fall
within the boiling range definition for the heavy portion of the
feedstock. In these types of aspects, solvent deasphalting of a
bottoms fraction is optional. Instead, all of the heavier portion
of the feedstock after separation can be processed by solvent
extraction followed by solvent dewaxing.
[0030] In still other alternative aspects, it may be desirable to
increase the relative proportion of light neutral base oils
relative to heavy neutral base oil. In such aspects, it may
sometimes be desirable to separate the feedstock into only a
lighter portion and a bottoms portion, without forming a fraction
corresponding to the "heavy portion." In these types of aspects,
all of the feedstock separated into the bottoms portion is
processed by solvent deasphalting, solvent extraction, and solvent
dewaxing.
Solvent Processing for Production of Group I Heavy Neutral
Basestock
[0031] One of the fractions formed during vacuum distillation of
the feedstock is a bottoms portion. This bottoms portion can
include a variety of types of molecules, including asphaltenes.
Solvent deasphalting can be used to separate asphaltenes from the
remainder of the bottoms portion. This results in a deasphalted
bottoms fraction and an asphalt or asphaltene fraction.
[0032] Solvent deasphalting is a solvent extraction process.
Typical solvents include alkanes or other hydrocarbons containing 3
to 6 carbons per molecule. Examples of suitable solvents include
propane, n-butane, isobutene, and n-pentane. Alternatively, other
types of solvents may also be suitable, such as supercritical
fluids. During solvent deasphalting, a feed portion is mixed with
the solvent. Portions of the feed that are soluble in the solvent
are then extracted, leaving behind a residue with little or no
solubility in the solvent. Typical solvent deasphalting conditions
include mixing a feedstock fraction with a solvent in a weight
ratio of from 1:2 to 1:10, such as 1:8 or less. Typical solvent
deasphalting temperatures range from 40.degree. C. to 150.degree.
C. The pressure during solvent deasphalting can be from 50 psig
(345 kPag) to 500 psig (3447 kPag).
[0033] The portion of the deasphalted feedstock that is extracted
with solvent often referred to as deasphalted oil. In various
aspects, the bottoms from vacuum distillation can be used as the
feed to the solvent deasphalter, so the portion extracted with the
solvent can also be referred to as deasphalted bottoms. The yield
of deasphalted oil from a solvent deasphalting process varies
depending on a variety of factors, including the nature of the
feedstock, the type of solvent, and the solvent extraction
conditions. A lighter molecular weight solvent such as propane will
result in a lower yield of deasphalted oil as compared to
n-pentane, as fewer components of a bottoms fraction will be
soluble in the shorter chain alkane. However, the deasphalted oil
resulting from propane deasphalting is typically of higher quality,
resulting in expanded options for use of the deasphalted oil. Under
typical deasphalting conditions, increasing the temperature will
also usually reduce the yield while increasing the quality of the
resulting deasphalted oil. In various embodiments, the yield of
deasphalted oil from solvent deasphalting can be 85 wt % or less of
the feed to the deasphalting process, or 75 wt % or less.
Preferably, the solvent deasphalting conditions are selected so
that the yield of deasphalted oil is at least 65 wt %, such as at
least 70 wt % or at least 75 wt %. The deasphalted bottoms
resulting from the solvent deasphalting procedure are then combined
with the higher boiling portion from the vacuum distillation unit
for solvent processing.
[0034] After a deasphalting process, the yield of deasphalting
residue is typically at least 15 wt % of the feed to the
deasphalting process, but is preferably 35 wt % or less, such as 30
wt % or less or 25 wt % or less. The deasphalting residue can be
used, for example, for making various grades of asphalt.
[0035] 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-methylpyrrolidone. 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 5 wt % to 25 wt %. For typical feeds, the aromatics
contents will be at least 10 wt %.
[0036] 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.
[0037] 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.
[0038] Solvent dewaxing typically involves mixing the raffinate
feed from the solvent extraction unit with chilled dewaxing solvent
to form an oil-solvent solution. Precipitated wax is thereafter
separated by, for example, filtration. The temperature and solvent
are selected so that the oil is dissolved by the chilled solvent
while the wax is precipitated.
[0039] An example of a suitable solvent dewaxing process involves
the use of a cooling tower where solvent is prechilled and added
incrementally at several points along the height of the cooling
tower. The oil-solvent mixture is agitated during the chilling step
to permit substantially instantaneous mixing of the prechilled
solvent with the oil. The prechilled solvent is added incrementally
along the length of the cooling tower so as to maintain an average
chilling rate at or below 10.degree. F. per minute, usually between
1 to 5.degree. F. per minute. The final temperature of the
oil-solvent/precipitated wax mixture in the cooling tower will
usually be between 0 and 50.degree. F. (-17.8 to 10.degree. C.).
The mixture may then be sent to a scraped surface chiller to
separate precipitated wax from the mixture.
[0040] Representative dewaxing solvents are aliphatic ketones
having 3-6 carbon atoms such as methyl ethyl ketone and methyl
isobutyl ketone, low molecular weight hydrocarbons such as propane
and butane, and mixtures thereof. The solvents may be mixed with
other solvents such as benzene, toluene or xylene.
[0041] In general, the amount of solvent added will be sufficient
to provide a liquid/solid weight ratio between the range of 5/1 and
20/1 at the dewaxing temperature and a solvent/oil volume ratio
between 1.5/1 to 5/1. The solvent dewaxed oil is typically dewaxed
to an intermediate pour point, preferably less than +10.degree. C.,
such as less than 5.degree. C. or less than 0.degree. C. The
resulting solvent dewaxed oil is suitable for use in forming one or
more types of Group I base oils. The aromatics content will
typically be greater than 10 wt % in the solvent dewaxed oil.
Additionally, the sulfur content of the solvent dewaxed oil will
typically be greater than 300 wppm.
Hydroprocessing for Production Light Neutral Basestocks
[0042] The lower boiling portions from the vacuum distillation can
be hydroprocessed to form Group II, Group II+, or even Group III
base oils. A suitable type of processing is to process the lower
boiling portions from the vacuum distillation in a fuels
hydrocracking process train. In this type of aspect, the lower
boiling portion from vacuum distillation is mixed with a feed
suitable for use in fuels hydrocracking, such as a vacuum gas oil
or a light cycle oil. Suitable fuels hydrocracking feeds can be
similar to the feeds used for the initial separation to form a
lower boiling portion, a higher boiling portion, and the bottoms
portion. Optionally, the fuels hydrocracking feed and the feed for
forming the various portions by vacuum distillation can be the same
feed. Additionally or alternately, other components can also be
introduced into the feed for the hydroprocessing reaction system,
such as slack wax or other waxy components. In still another
alternative aspect, the lower boiling portion from vacuum
distillation can be hydroprocessed without blending with another
feed.
[0043] In the discussion below, a stage can correspond to a single
reactor or a plurality of reactors. Optionally, multiple parallel
reactors can be used to perform one or more of the processes, or
multiple parallel reactors can be used for all processes in a
stage. Each stage and/or reactor can include one or more catalyst
beds containing hydroprocessing catalyst. Note that a "bed" of
catalyst in the discussion below can refer to a partial physical
catalyst bed. For example, a catalyst bed within a reactor could be
filled partially with a hydrocracking catalyst and partially with a
dewaxing catalyst. For convenience in description, even though the
two catalysts may be stacked together in a single catalyst bed, the
hydrocracking catalyst and dewaxing catalyst can each be referred
to conceptually as separate catalyst beds.
[0044] In the discussion herein, reference will be made to a
hydroprocessing reaction system. The hydroprocessing reaction
system corresponds to the one or more stages, such as two stages
and/or reactors and an optional intermediate separator, that are
used to expose a feed to a plurality of catalysts under
hydroprocessing conditions. The plurality of catalysts can be
distributed between the stages and/or reactors in any convenient
manner, with some preferred methods of arranging the catalyst
described herein.
[0045] Various types of hydroprocessing can be used in the
production of lubricant base oils, including production of
lubricant base oils as one of several products generated during a
fuels hydrocracking process. Typical processes include a
hydrocracking process to provide uplift in the viscosity index (VI)
of the feed. The hydrocracked feed can then be dewaxed to improve
cold flow properties, such as pour point or cloud point. The
hydrocracked, dewaxed feed can then be hydrofinished, for example,
to remove aromatics from the lubricant base stock product. This can
be valuable for removing compounds that are considered hazardous
under various regulations. In addition to the above, a preliminary
hydrotreatment and/or hydrocracking stage can also be used for
contaminant removal.
[0046] After separation in the vacuum distillation apparatus, the
lower boiling portion of the feedstock is passed into a
hydroprocessing reaction system. The hydroprocessing reaction
system can be, for example, a reaction system suitable for
performing fuels hydrocracking. Typically this will correspond to a
two stage hydrocracker, but alternatively the reaction system may
include a first hydrotreater stage and a second hydrocracker stage.
In still other aspects, the hydrocracking may be performed in a
single stage and/or reactor, or more than two stages may be used. A
separator can be used between the first stage and the second stage,
such as a high temperature separator, to allow for removal of
H.sub.2, NH.sub.3, and/or other contaminant gases and light ends in
between the stages of the reaction system. In order to maximize
diesel production, and to improve the cold flow properties of the
hydrocracker bottoms, at least a portion of the catalyst in the
second hydrocracker stage can be a dewaxing catalyst. Optionally,
the hydrocracker bottoms or the entire liquid effluent from the
hydrocracker can also be exposed to a hydrofinishing catalyst. The
hydrofinishing catalyst can be included as part of a final bed in
the second hydrocracker stage or in a separate reactor.
Hydrotreatment Conditions
[0047] In some aspects, at least a portion of the catalyst in the
hydrocracking reaction system can correspond to hydrotreatment
catalyst. For example, one or more beds of catalyst in the first
stage of a two stage reaction system can be hydrotreating catalyst.
Optionally, the first stage can correspond to a hydrotreatment
stage, with hydrocracking being performed in the second stage.
[0048] Hydrotreatment is typically used to reduce the sulfur,
nitrogen, and aromatic content of a feed. The catalysts used for
hydrotreatment of the heavy portion of the crude oil from the flash
separator can include conventional hydroprocessing catalysts, such
as those that comprise 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.
[0049] 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.; a surface area
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 oil) boiling range feed in a
conventional manner may be used. It is within the scope of the
present disclosure that more than one type of hydroprocessing
catalyst can be used in one or multiple reaction vessels.
[0050] The at least one Group VIII non-noble metal, in oxide form,
can typically be present in an amount ranging from 2 wt % to 40 wt
%, preferably from 4 wt % to 15 wt %. The at least one Group VI
metal, in oxide form, can typically be present in an amount ranging
from 2 wt % to 70 wt %, preferably for supported catalysts from 6
wt % to 40 wt % or from 10 wt % to 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.
[0051] The hydrotreatment 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 in this disclosure, can be either pure hydrogen
or a hydrogen-containing gas, which is a gas stream containing
hydrogen in an amount that is sufficient for the intended
reaction(s), optionally including one or more other gasses (e.g.,
nitrogen and light hydrocarbons such as methane), and which will
not adversely interfere with or affect either the reactions or the
products. Impurities, such as H.sub.2S and NH.sub.3 are undesirable
and would typically be removed from the treat gas before it is
conducted to the reactor. The treat gas stream introduced into a
reaction stage will preferably contain at least 50 vol. % and more
preferably at least 75 vol. % hydrogen.
[0052] Hydrogen can be supplied at a rate of from 100 SCF/B
(standard cubic feet of hydrogen per barrel of feed) (17
Nm.sup.3/m.sup.3) to 1500 SCF/B (253 Nm.sup.3/m.sup.3). Preferably,
the hydrogen is provided in a range of from 200 SCF/B (34
Nm.sup.3/m.sup.3) to 1200 SCF/B (202 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.
[0053] 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); liquid hourly space
velocities (LHSV) of 0.1 hr.sup.-1 to 10 hr.sup.-1; and hydrogen
treat rates of 200 scf/B (35.6 m.sup.3/m.sup.3) to 10,000 scf/B
(1781 m.sup.3/m.sup.3), or 500 (89 m.sup.3/m.sup.3) to 10,000 scf/B
(1781 m.sup.3/m.sup.3).
Hydrocracking Conditions
[0054] In various aspects, the reaction conditions in the reaction
system can be selected to generate a desired level of conversion of
a feed. 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 700.degree. F. (371.degree.
C.). In an aspect, the amount of conversion in the stage(s) of the
reaction system can be selected to enhance diesel production while
achieving a substantial overall yield of fuels. The amount of
conversion can correspond to the total conversion of molecules
within any stage of the fuels hydrocracker or other reaction system
that is used to hydroprocess the lower boiling portion of the feed
from the vacuum distillation unit. Suitable amounts of conversion
of molecules boiling above 700.degree. F. to molecules boiling
below 700.degree. F. include converting at least 55% of the
700.degree. F.+ portion of the feedstock to the stage(s) of the
reaction system, such as at least 60% of the 700.degree. F.+
portion, or at least 70%, or at least 75%. Additionally or
alternately, the amount of conversion for the reaction system can
be 85% or less, or 80% or less, or 75% or less, or 70% or less.
Still larger amounts of conversion may also produce a suitable
hydrocracker bottoms for forming lubricant base oils, but such
higher conversion amounts will also result in a reduced yield of
lubricant base oils. Reducing the amount of conversion can increase
the yield of lubricant base oils, but reducing the amount of
conversion to below the ranges noted above may result in
hydrocracker bottoms that are not suitable for formation of Group
II, Group II+, or Group III lubricant base oils.
[0055] in order to achieve a desired level of conversion, the fuel
hydrocracking reaction system or other reaction system can include
at least one hydrocracking catalyst. 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 silicoaluminophosphates. One example of
suitable zeolite is USY, such as a USY zeolite with cell size of
24.25 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 20, and preferably at least 40 or 50.
Zeolite Beta is another example of a potentially suitable
hydrocracking 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, zircons,
or combinations thereof, with alumina, silica, alumina-silica being
the most common (and preferred, in one embodiment).
[0056] In various aspects, the conditions selected for
hydrocracking for fuels hydrocracking and/or lubricant base stock
production 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
the first stage and/or the second stage can be selected to achieve
a desired level of conversion in the reaction system. A
hydrocracking process in the first stage (or otherwise under sour
conditions) can be carried out at temperatures of 550.degree. F.
(288.degree. C.) to 840.degree. F. (449.degree. C.), hydrogen
partial pressures of from 250 psig to 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 181 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 600.degree. F. (343.degree. C.) to 815.degree. F. (435.degree.
C.), hydrogen partial pressures of from 500 psig to 3000 psig (3.5
MPag-20.9 MPag), and hydrogen treat gas rates of from 213
m.sup.3/m.sup.3 to 1068 m.sup.3/m.sup.3 (1200 SCF/B to 6000 SCF/B).
The LHSV relative to only the hydrocracking catalyst can be from
0.25 h.sup.-1 to 50 h.sup.-1 if such as from 0.5 h.sup.-1 to 20
h.sup.-1, and preferably from 1.0 h.sup.-1 to 4.0 h.sup.-1.
[0057] In some aspects, a portion of the hydrocracking catalyst
and/or the dewaxing 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 350.degree. F. (177.degree. C.) or
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 performer in the
first stage, the second stage can be operated as a "sweet" or low
contaminant stage.
[0058] 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 350.degree. F.
(177.degree. C.) or at least 400.degree. F. (204.degree. C.) to
having an upper end cut point temperature of 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 300.degree. F. (149.degree. C.).
[0059] 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 oils. In such aspects, the portion boiling above the
distillate fuel range is subjected to further hydroprocessing in a
second hydroprocessing stage.
[0060] A hydrocracking process in a second stage (r otherwise under
non-sour conditions) can be performed under conditions similar to
those used for a first stage hydrocracking process, or the
conditions can be different. In an embodiment, the conditions in a
second stage can have less severe conditions than a hydrocracking
process in a first (sour) stage. The temperature in the
hydrocracking process can be 40.degree. F. (22.degree. C.) less
than the temperature for a hydrocracking process in the first
stage, or 80.degree. F. (44.degree. C.) less, or 120.degree. F.
(66.degree. C.) less. The pressure for a hydrocracking process in a
second stage can be 100 psig (690 kPa) less than a hydrocracking
process in the first stage, or 200 psig (1380 kPa) less, or 300
psig (2070 kPa) less. Additionally or alternately, suitable
hydrocracking conditions for a second (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 550.degree. F. (288.degree. C.) to 840.degree. F. (449.degree.
C.), hydrogen partial pressures of from 250 psig to 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 can include
temperatures in the range of 600.degree. F. (343.degree. C.) to
815.degree. F. (435.degree. C.), hydrogen partial pressures of from
500 psig to 3000 psig (3.5 MPag-20.9 MPag), and hydrogen treat gas
rates of from 213 m.sup.3/m.sup.3 to 1068 m.sup.3/m.sup.3 (1200
SCF/B to 6000 SCF/B). The liquid hourly space velocity can vary
depending on the relative amount of hydrocracking catalyst used
versus dewaxing catalyst. Relative to the combined amount of
hydrocracking and dewaxing catalyst, the LHSV can be from 0.2
h.sup.-1 to 10 h.sup.-1, such as from 0.5 h to 5 h and/or from 1
h.sup.-1 to 4 h.sup.-1. Depending on the relative amount of
hydrocracking catalyst and dewaxing catalyst used, the LHSV
relative to only the hydrocracking catalyst can be from 0.25
h.sup.-1 to 50 h.sup.-1 such as from 0.5 h.sup.-1 to 20 h.sup.-1,
and preferably from 1.0 h.sup.-1 to 4.0 h.sup.-1.
[0061] In still another embodiment, 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.
Catalytic Dewaxing Process
[0062] In order to enhance diesel production and to improve the
quality of lubricant base oils produced from the bottoms of the
reaction system, at least a portion of the catalyst in the final
reaction stage can be a dewaxing catalyst. Typically, the dewaxing
catalyst is located in a bed downstream from any hydrocracking
catalyst stages and/or any hydrocracking catalyst present in a
stage. This can allow the dewaxing to occur on molecules that have
already been hydrotreated or hydrocracked to remove a significant
fraction of organic sulfur- and nitrogen-containing species. The
dewaxing catalyst can be located in the same reactor as at least a
portion of the hydrocracking catalyst in a stage. Alternatively,
the effluent from a reactor containing hydrocracking catalyst,
possibly after a gas-liquid separation, can be fed into a separate
stage or reactor containing the dewaxing catalyst. Depending on the
aspects, the amount of hydrocracking catalyst relative to the
amount of dewaxing catalyst can vary from 10:90 to 90:10, such as
from 20:80 to 70:30, and preferably from 60:40 to 40:60.
Optionally, in some aspects it may be possible to omit the
hydrocracking catalyst, so that only a dewaxing catalyst is used.
Optionally, in some aspects it may be possible to omit the dewaxing
catalyst, so that only a hydrocracking catalyst is used.
[0063] Suitable dewaxing catalysts can include molecular sieves
such as crystalline aluminosilicates (zeolites). In an embodiment,
the molecular sieve can comprise, consist essentially of, or be
ZSM-5, ZSM-22, ZSM-23, ZSM-35, ZSM-48, zeolite Beta, or a
combination thereof, for example ZSM-23 and/or ZSM-48, or ZSM-48
and/or zeolite Beta. Optionally but preferably, molecular sieves
that are selective for dewaxing by isomerization as opposed to
cracking can be used, such as ZSM-48, zeolite Beta, ZSM-23, or a
combination thereof. Additionally or alternately, the molecular
sieve can comprise, consist essentially of, or be a 10-member ring
1-D molecular sieve. Examples include EU-1, ZSM-35 (or ferrierite),
ZSM-11, ZSM-57, NU-87, SAPO-11, ZSM-48. ZSM-23, and ZSM-22.
Preferred materials are EU-2, EU-11, ZBM-30, ZSM-48, or ZSM-23.
ZSM-48 is most preferred. Note that a zeolite having the ZSM-23
structure with a silica to alumina ratio of from 20:1 to 40:1 can
sometimes be referred to as SSZ-32. Other molecular sieves that are
isostructural with the above materials include Theta-1, NU-10,
EU-13, KZ-1, and NU-23. Optionally but preferably, the dewaxing
catalyst can include a binder for the molecular sieve, such as
alumina, titania, silica, silica-alumina, zirconia, or a
combination thereof, for example alumina and/or titania ter silica
and/or zirconia and/or titania.
[0064] Preferably, the dewaxing catalysts used in processes
according to the disclosure are catalysts with a low ratio of
silica to alumina. For example, for ZSM-48, the ratio of silica to
alumina, in the zeolite can be less than 200:1, such as less than
110:1, or less than 100:1, or less than 90:1, or less than 75:1. In
various embodiments, the ratio of silica to alumina can be from
50:1 to 200:1, such as 60:1 to 160:1, or 70:1 to 100:1.
[0065] In various embodiments, the catalysts according to the
disclosure further include a metal hydrogenation component. The
metal hydrogenation component is typically a. Group VI and/or a
Group VIII metal. Preferably, the metal hydrogenation component is
a Group VIII noble metal. Preferably, the metal hydrogenation
component is Pt, Pd, or a mixture thereof. In an alternative
preferred embodiment, the metal hydrogenation component can be a
combination of a non-noble Group VIII metal with a Group VI metal.
Suitable combinations can include Ni, Co, or Fe with Mo or W,
preferably Ni with Mo or W.
[0066] The metal hydrogenation component may be added to the
catalyst in any convenient manner. One technique for adding the
metal hydrogenation component is by incipient wetness. For example,
after combining a zeolite and a binder, the combined zeolite and
binder can be extruded into catalyst particles. These catalyst
particles can then be exposed to a solution containing a suitable
metal precursor. Alternatively, metal can be added to the catalyst
by ion exchange, where a metal precursor is added to a mixture of
zeolite (or zeolite and binder) prior to extrusion.
[0067] The amount of metal in the catalyst can be at least 0.1 wt %
based on catalyst, or at least 0.15 wt %, or at least 0.2 wt %, or
at least 0.25 wt %, or at least 0.3 wt %, or at least 0.5 wt %
based on catalyst. The amount of metal in the catalyst can be 20 wt
% or less based on catalyst, or 10 wt % or less, or 5 wt % or less,
or 2.5 wt % or less, or 1 wt % or less. For embodiments where the
metal is Pt, Pd, another Group VIII noble metal, or a combination
thereof, the amount of metal can be from 0.1 to 5 wt %, preferably
from 0.1 to 2 wt %, or 0.25 to 1.8 wt %, or 0.4 to 1.5 wt %. For
embodiments where the metal is a combination of a non-noble Group
VIII metal with a Group VI metal, the combined amount of metal can
be from 0.5 wt % to 20 wt %, or 1 wt % to 15 wt %, or 2.5 wt % to
10 wt %.
[0068] The dewaxing catalysts useful in processes according to the
disclosure can also include a binder. In some embodiments, the
dewaxing catalysts used in process according to the disclosure are
formulated using a low surface area binder, a low surface area
binder represents a binder with a surface area of 100 m.sup.2/g or
less, or 80 m.sup.2/g or less, or 70 m.sup.2/g or less. The amount
of zeolite in a catalyst formulated using a binder can be from 30
wt % zeolite to 90 wt % zeolite relative to the combined weight of
binder and zeolite. Preferably, the amount of zeolite is at least
50 wt % of the combined weight of zeolite and binder, such as at
least 60 wt % or from 65 wt % to 80 wt %.
[0069] A zeolite can be combined with binder in any convenient
manner. For example, a bound catalyst can be produced by starting
with powders of both the zeolite and binder, combining and mulling
the powders with added water to form a mixture, and then extruding
the mixture to produce a bound catalyst of a desired size.
Extrusion aids can also be used to modify the extrusion flow
properties of the zeolite and binder mixture. The amount of
framework alumina in the catalyst may range from 0.1 to 3.33 wt %,
or 0.1 to 2.7 wt %, or 0.2 to 2 wt %, or 0.3 to 1 wt %.
[0070] Process conditions in a catalytic dewaxing zone in a sour
environment can include a temperature of from 200 to 450.degree.
C., preferably 270 to 400.degree. C., a hydrogen partial pressure
of from 1.8 MPag to 34.6 MPag (250 psig to 5000 psig), preferably
4.8 MPag to 20.8 MPag, and a hydrogen circulation rate of from 35.6
m.sup.3/m.sup.3 (200 SCF/B) to 1781 m.sup.3/m.sup.3 (10,000 scf/B),
preferably 178 m.sup.3/m.sup.3 (1000 SCF/B) to 890.6
m.sup.3/m.sup.3 (5000 SCF/B). In still other embodiments, the
conditions can include temperatures in the range of 600.degree. F.
(343.degree. C.) to 815.degree. F. (435.degree. C.), hydrogen
partial pressures of from 500 psig to 3000 psig (3.5 MPag-20.9
MPag), and hydrogen treat gas rates of from 213 m.sup.3/m.sup.3 to
1068 m.sup.3/m.sup.3 (1200 SCF/B to 6000 SCF/B). These latter
conditions may be suitable, for example, if the dewaxing stage is
operating under sour conditions. The liquid hourly space velocity
can vary depending on the relative amount of hydrocracking catalyst
used versus dewaxing catalyst. Relative to the combined amount of
hydrocracking and dewaxing catalyst, the LHSV can be from 0.2
h.sup.-1 to 10 h.sup.-1, such as from 0.5 h.sup.-1 to 5 h.sup.-1
and/or from 1 h.sup.-1 to 4 h.sup.-1. Depending on the relative
amount of hydrocracking catalyst and dewaxing catalyst used, the
LHSV relative to only the dewaxing catalyst can be from 0.25
h.sup.-1 to 50 h.sup.-1 such as from 0.5 h.sup.-1 to 20 h.sup.-1
and preferably from 1.0 h.sup.-1 to 4.0 h.sup.-1.
[0071] Additionally or alternately, the conditions for dewaxing can
be selected based on the conditions for a preceding reaction in the
stage, such as hydrocracking conditions or hydrotreating
conditions. Such conditions can be further modified using a quench
between previous catalyst bed(s) and the bed for the dewaxing
catalyst. Instead of operating the dewaxing process at a
temperature corresponding to the exit temperature of the prior
catalyst bed, a quench can be used to reduce the temperature for
the hydrocarbon stream at the beginning of the dewaxing catalyst
bed. One option can be to use a quench to have a temperature at the
beginning of the dewaxing catalyst bed that is the same as the
outlet temperature of the prior catalyst bed. Another option can be
to use a quench to have a temperature at the beginning of the
dewaxing catalyst bed that is at least 10.degree. F. (6.degree. C.)
lower than the prior catalyst bed, or at least 20.degree. F.
(11.degree. C.) lower, or at least 30.degree. F. (16.degree. C.)
lower, or at least 40.degree. F. (21.degree. C.) lower.
[0072] As still another option, the dewaxing catalyst in the final
reaction stage can be mixed with another type of catalyst, such as
hydrocracking catalyst, in at least one bed in a reactor. As yet
another option, a hydrocracking catalyst and a dewaxing catalyst
can be co-extruded with a single binder to form a mixed
functionality catalyst.
Hydrofinishing and/or Aromatic Saturation Process
[0073] In some aspects, a hydrofinishing and/or aromatic saturation
stage can also be provided. The hydrofinishing and/or aromatic
saturation can occur after the last hydrocracking or dewaxing
stage. The hydrofinishing and/or aromatic saturation can occur
either before or after fractionation. If hydrofinishing and/or
aromatic saturation occurs after fractionation, the hydrofinishing
can be performed on one or more portions of the fractionated
product, such as being performed on the bottoms from the reaction
stage (i.e., the hydrocracker bottoms). Alternatively, the entire
effluent from the last hydrocracking or dewaxing process can be
hydrofinished and/or undergo aromatic saturation.
[0074] In some situations, a hydrofinishing process and an aromatic
saturation process can refer to a single process performed using
the same catalyst. Alternatively, one type of catalyst or catalyst
system can be provided to perform aromatic saturation, while a
second catalyst or catalyst system can be used for hydrofinishing.
Typically a hydrofinishing and/or aromatic saturation process will
be performed in a separate reactor from dewaxing or hydrocracking
processes for practical reasons, such as facilitating use of a
lower temperature for the hydrofinishing or aromatic saturation
process. However, an additional hydrofinishing reactor following a
hydrocracking or dewaxing process but prior to fractionation could
still be considered part of a second stage of a reaction system
conceptually.
[0075] Hydrofinishing and/or aromatic saturation catalysts can
include catalysts containing Group VI metals, Group VIII metals,
and mixtures thereof. In an embodiment, preferred metals include at
least one metal sulfide having a strong hydrogenation function. In
another embodiment, the hydrofinishing catalyst can include a Group
VIII noble metal, such as Pt, Pd, or a combination thereof. The
mixture of metals may also be present as bulk metal catalysts
wherein the amount of metal is 30 wt % or greater based on
catalyst. Suitable metal oxide supports include low acidic oxides
such as silica, alumina, silica-aluminas or titanic, preferably
alumina. The preferred hydrofinishing catalysts for aromatic
saturation will comprise at least one metal having relatively
strong hydrogenation function on a porous support. Typical 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 is often as high as
20 wt % for non-noble metals. In an embodiment, a preferred
hydrofinishing 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. If separate catalysts are used for aromatic
saturation and hydrofinishing, an aromatic saturation catalyst can
be selected based on activity and/or selectivity for aromatic
saturation, while a hydrofinishing catalyst can be selected based
on activity for improving product specifications, such as product
color and polynuclear aromatic reduction.
[0076] Hydrofinishing conditions can include temperatures from
125.degree. C. to 425.degree. C., preferably 180.degree. C. to
280.degree. C., a hydrogen partial pressure from 500 psig (3.4 MPa)
to 3000 psig (20.7 MPa), preferably 1500 psig (10.3 MPa) to 2500
psig (17.2 MPa), and liquid hourly space velocity from 0.1
hr.sup.-1 to 5 hr.sup.-1 LHSV, preferably 0.5 hr.sup.-1 to 1.5
hr.sup.-1. Additionally, a hydrogen treat gas rate 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)
can be used.
[0077] After hydroprocessing, the bottoms from the hydroprocessing
reaction system can have a viscosity index (VI) of at least 95,
such as at least 105 or at least 110. The amount of saturated
molecules in the bottoms from the hydroprocessing reaction system
can be at least 90%, while the sulfur content of the bottoms is
less than 300 wppm. Thus, the bottoms from the hydroprocessing
reaction system can be suitable for use as a Group II, Group II+,
or Group III lubricant base oil.
Example of Configuration for Integrated Reaction System
[0078] FIG. 1 shows a schematic example of configuration for
forming lubricant base oils using both solvent processing and
hydroprocessing. In the embodiment shown in FIG. 1, a feedstock for
lubricant base oil production 105 is introduced into a vacuum
distillation tower 110. The vacuum distillation tower 110
fractionates the feedstock 105 into at least a lower boiling
portion 153, a higher boiling portion 133, and a bottoms portion
113. The bottoms portion 113 is passed into a deasphalter 120 for
solvent deasphalting. This results in an asphalt output 128 and a
deasphalted bottoms stream 123. The higher boiling portion 133 and
deasphalted bottoms 123 are then solvent extracted 130. This
results in an aromatics-rich extract 138 and a raffinate 143 with
reduced aromatics content. The raffinate 143 is then solvent
dewaxed 140 to form a wax output 148 and Group I heavy neutral and
brightstock base oils 145. Optionally, solvent extraction process
130 and/or solvent dewaxing process 140 can represent a plurality
of solvent extraction and/or dewaxing units. In such an option, the
deasphalted bottoms stream 123 and higher boiling portion 133 can
be solvent processed separately, allowing for separate production
of a Group I base oil and a brightstock.
[0079] In the configuration shown in FIG. 1, the lower boiling
portion 153 from vacuum distillation unit 110 is combined with a
fuels feedstock 155 and passed into a first hydroprocessing stage
150. The combined feeds are exposed to one or more hydroprocessing
catalyst in the presence of hydrogen. As shown in FIG. 1, the
effluent from first hydroprocessing stage 150 is passed into a
separator 160. Alternatively, the effluent from stage 150 could be
cascaded directly into stage 170 or all catalyst beds could be
located in a single stage. The separator shown in FIG. 1
fractionates the effluent from the first stage into a naphtha, and
light ends portion 168, a distillate boiling range portion 166, and
a first stage bottoms portion 173. Alternatively, separator 160 can
be a flash separator that separates the feed only into a lower
boiling portion (such as a naphtha and light ends portion) and a
higher boiling portion. Alternatively, separator 160 can be a
gas-liquids separator the separates the gas phase portion of the
effluent from the liquid portion of the effluent.
[0080] The highest boiling portion 173 from separator 160 is then
passed into second hydroprocessing stage 170. In the configuration
shown in FIG. 1, the second hydroprocessing stage includes at least
a portion of dewaxing catalyst. The effluent 183 from the second
hydroprocessing stage 170 is then separated using an atmospheric
separator to form at least a naphtha and light ends portion 188, a
distillate fuel portion 186, and a lubricant base oil portion 185.
This lubricant base oil portion corresponds to a Group II, Group
II+, and/or Group III lubricant base oil portion.
Examples of Fuels Hydrocracking on a Combined Feed
[0081] In the following examples, a lower boiling portion of a
lubricant base oil feedstock was mixed with a fuels hydrocracking
feed for hydroprocessing. The hydroprocessing configuration
included hydrotreatment of the combined feed; gas-liquid separation
to remove contaminant gases from the hydrotreated liquid effluent;
hydrocracking of the hydrotreated liquid effluent; and dewaxing of
the effluent from hydrocracking. The hydroprocessing conditions, in
combination, correspond to conditions suitable for sufficient
conversion of the feedstock to produce a lubricant base oil yield
of 20 wt %.
[0082] The hydrotreatment was performed by exposing the combined
feed to a conventional NiMo catalyst in the presence of hydrogen at
a temperature of 675.degree. F. (357.degree. C.). The hydrocracking
was performed by exposing the hydrotreated liquid effluent to a USY
catalyst in the presence of hydrogen at, the temperature shown
below in Table 1. The USY catalyst was a commercially available low
acidity catalyst with an Si to Al content of at least 20 that
include a noble metal as a hydrogenation metal. The hydrocracked
effluent was then dewaxed in the presence of an alumina-bound
ZSM-48 dewaxing catalyst having an Si to Al ratio of 90:1 or less
with 0.6 wt % of Pt supported on the catalyst. The dewaxing
temperature is shown in Table 1. The ratio by volume of
hydrocracking catalyst to dewaxing catalyst was 1:1. The LHSV over
the hydrocracking catalyst was 4 hr.sup.-1 and the LHSV over the
dewaxing catalyst was 4 hr.sup.-1.
[0083] The combined feedstock corresponded to a combination of a
light cycle oil feed having a boiling range of from 350.degree. F.
(177.degree. C.) to 700.degree. F. (371.degree. C.) and a lower
boiling portion of one of two vacuum gas oil lubricant feeds having
a boiling range of from 700.degree. F. (371.degree. C.) to
900.degree. F. (482.degree. C.). The feed included 65 wt % of the
light cycle oil and 35 wt % of the lower boiling portion of the
lubricant feed.
TABLE-US-00001 TABLE 1 Sample USY T (.degree. F.) Dewaxing
(.degree. F.) Lube Yield (wt %) VI 1 640 615 21 113 2 608 608 19
116
[0084] After processing, the feed was fractionated to recover the
lubricant boiling range portion. As shown in Table 1, the lubricant
base oil yield was 20 wt % for both types of lubricant feeds.
Similar viscosity index values were also obtained for both types of
lubricant feeds, resulting in a lubricant base oil suitable for use
in forming Group II+ light neutral base oils.
PCT and EP Clauses:
[0085] Embodiment 1. A method for forming fuel and lubricant
products, comprising: separating a feedstock into at least a first
fraction having a T5 boiling point greater than 600.degree. F.
(316.degree. C.) and a T95 boiling point of 1150.degree. F.
(621.degree. C.) or less and a bottoms fraction; deasphalting the
bottoms fraction to form a deasphalted bottoms fraction and an
asphalt product; extracting the deasphalted bottoms in the presence
of an extraction solvent to form a raffinate stream and an extract
stream, an aromatics content of the raffinate stream being lower
than an aromatics content of the deasphalted bottoms; dewaxing the
raffinate stream in the presence of a dewaxing solvent to form a
lubricant base oil product and a wax product; hydroprocessing a
combined feedstock corresponding to the first fraction and a fuels
feedstock, at least a portion of the combined feedstock having a
boiling point greater than 700.degree. F. (371.degree. C.), the
fuels feedstock having a T5 boiling point greater than 350.degree.
F. (177.degree. C.) and a T95 boiling point of 1150.degree. F.
(621.degree. C.) or less, under first effective hydroprocessing
conditions to form a hydroprocessed effluent; separating the
hydroprocessed effluent to form at least a gas phase effluent and a
liquid phase effluent; hydroprocessing at least a portion of the
liquid phase effluent in the presence of at least a dewaxing
catalyst under second effective hydroprocessing conditions to form
a dewaxed effluent, the first effective hydroprocessing conditions
and the second effective hydroprocessing conditions being effective
for conversion of at least 60% of the portion of the combined
feedstock boiling above 700.degree. F. (371.degree. C.) to a
portion boiling below 700.degree. F. (371.degree. C.); and
fractionating the dewaxed effluent to form at least a distillate
fuel product having a T95 boiling point of 750.degree. F.
(399.degree. C.) or less and a lubricant base oil product having a
viscosity index of at least 80, a sulfur content of 300 wpm or
less, and an aromatics content of 10 wt % or less.
[0086] Embodiment 2. The method of Embodiment 1, wherein separating
the feedstock comprises: separating the feedstock into at least a
first fraction having a T5 boiling point greater than 600.degree.
F. (316.degree. C.) and a T95 boiling point of 950.degree. F.
(510.degree. C.) or less, a second fraction having a T5 boiling
point of at least the T95 boiling point of the first fraction, and
a bottoms fraction; and wherein extracting the deasphalted bottoms
comprises: extracting the deasphalted bottoms and the second
fraction in the presence of an extraction solvent to form a
raffinate stream and an extract stream, an aromatics content of the
raffinate stream being lower than an aromatics content of the
combined deasphalted bottoms and second fraction.
[0087] Embodiment 3. The method of Embodiment 1, wherein separating
the feedstock comprises separating the feedstock into at least a
first fraction having a T5 boiling point greater than 600.degree.
F. (316.degree. C.) and a T95 boiling point of 950.degree. F.
(510.degree. C.) or less, a second fraction having a T5 boiling
point of at least the T95 boiling point of the first fraction, and
a bottoms fraction; the method further comprising extracting the
second fraction in the presence of an extraction solvent to form a
second raffinate stream and a second extract stream, an aromatics
content of the second raffinate stream being lower than an
aromatics content of the second fraction; and dewaxing the second
raffinate stream in the presence of a dewaxing solvent to form a
second lubricant base oil product and a second wax product.
[0088] Embodiment 4. The method of Embodiments 2 or 3, wherein the
first fraction has a T95 boiling point of 900.degree. F. or less,
such as 850.degree. F. or less, and the second fraction has a T5
boiling point of at least 850.degree. F., such as at least
900.degree. F.
[0089] Embodiment 5. The method of any of Embodiments 2 to 4,
wherein the second fraction has a T95 boiling point of 1100.degree.
F. or less.
[0090] Embodiment 6. The method of any of the above embodiments,
wherein the first fraction has a T5 boiling point of at least
650.degree. F., such as at least 700.degree. F.
[0091] Embodiment 7. The method of any of the above embodiments,
wherein the first effective hydroprocessing conditions comprise
exposing the combined feedstock to a hydrotreating catalyst, a
hydrocracking catalyst, or a combination thereof under effective
hydrotreating conditions, effective hydrocracking conditions, or a
combination thereof.
[0092] Embodiment 8. The method of Embodiment 7, wherein the
hydrocracking catalyst is USY, zeolite Beta, or a combination
thereof.
[0093] Embodiment 9. The method of any of the above embodiments,
wherein the second effective hydroprocessing conditions comprise
effective dewaxing conditions.
[0094] Embodiment 10. The method of any of the above embodiments,
wherein the second effective hydroprocessing conditions further
comprise exposing the at least a portion of the liquid effluent to
a hydrocracking catalyst under second effective hydrocracking
conditions.
[0095] Embodiment 11. The method of any of the above embodiments,
wherein the first effective hydroprocessing conditions and the
second effective hydroprocessing conditions are effective for
conversion of at least 70% of the portion of the combined feedstock
boiling above 700.degree. F. (371.degree. C.) to a portion boiling
below 700.degree. F. (371.degree. C.), such as at least 75%.
[0096] Embodiment 12. The method of any of the above embodiments,
wherein separating the hydroprocessed effluent to form at least a
gas phase effluent comprises separating the hydroprocessed effluent
to form a lower boiling fraction having a T95 boiling point of
400.degree. F. (204.degree. C.) or less, such as 350.degree. F.
(177.degree. C.) or less.
[0097] Embodiment 13. The method of any of the above embodiments,
wherein separating the hydroprocessed effluent to form at least a
liquid phase effluent comprises forming a first liquid phase
effluent with a T95 boiling point of 700.degree. F. (371.degree.
C.) or less, such as 650.degree. F. (343.degree. C.) or less, and a
second liquid phase effluent having a T5 boiling point of at least
650.degree. F. (343.degree. C.), such as at least 700.degree. F.
(371.degree. C.).
[0098] Embodiment 14. The method of any of the above embodiments,
wherein the liquid phase effluent has a sulfur content of 300 wppm
or less, such as 100 wppm or less.
[0099] Embodiment 15. The method of any of the above embodiments,
further comprising dividing an initial feed into the feedstock and
the fuels feedstock.
[0100] Embodiment 16. The method of any of the above embodiments,
further comprising hydrofinishing at least a portion of the dewaxed
effluent under effective dewaxing conditions.
[0101] Embodiment 17. The method of any of the above embodiments,
wherein the first effective hydroprocessing conditions comprise a
temperature of 550.degree. F. (2.degree. C.) to 840.degree. F.
(449.degree. C.), hydrogen partial pressures of from 250 psig to
5000 psig (1.8 MPag to 34.6 MPag), and a hydrogen treat gas rate 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), and wherein the second effective hydroprocessing
conditions comprise a temperature of from 200 to 450.degree. C.,
preferably 270 to 400.degree. C., a hydrogen partial pressure of
from 1.8 MPag to 34.6 MPag (250 psig to 5000 psig), preferably 4.8
MPag to 20.8 MPag and a hydrogen treat gas rate of from 35.6
m.sup.3/m.sup.3 (200 SCF/B) to 1781 m.sup.3/m.sup.3 (10,000 scf/B),
preferably 178 m.sup.3/m.sup.3 (1000 SCF/B) to 890.6
m.sup.3/m.sup.3 (5000 SCF/B).
[0102] 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 disclosure
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 disclosure. 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 disclosure, including all features
which would be treated as equivalents thereof by those skilled in
the art to which the disclosure pertains. All documents described
herein are incorporated by reference herein, including any priority
documents and/or testing procedures to the extent they are not
inconsistent with this text.
[0103] The present disclosure 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.
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