U.S. patent application number 16/115737 was filed with the patent office on 2019-03-14 for reactor staging for slurry hydroconversion of polycyclic aromatic hydrocarbon feeds.
The applicant listed for this patent is ExxonMobil Research and Engineering Company. Invention is credited to John P. Greeley, Gregory R. Johnson, Paul Podsiadlo, Kevin Sutowski.
Application Number | 20190078029 16/115737 |
Document ID | / |
Family ID | 63684441 |
Filed Date | 2019-03-14 |
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United States Patent
Application |
20190078029 |
Kind Code |
A1 |
Johnson; Gregory R. ; et
al. |
March 14, 2019 |
REACTOR STAGING FOR SLURRY HYDROCONVERSION OF POLYCYCLIC AROMATIC
HYDROCARBON FEEDS
Abstract
Methods for processing heavy oil feeds are provided comprising
first and second hydroconversion reactors at differing
hydroconversion conditions.
Inventors: |
Johnson; Gregory R.; (Bound
Brook, NJ) ; Greeley; John P.; (Manasquan, NJ)
; Podsiadlo; Paul; (Humble, TX) ; Sutowski;
Kevin; (Basking Ridge, NJ) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
ExxonMobil Research and Engineering Company |
Annandale |
NJ |
US |
|
|
Family ID: |
63684441 |
Appl. No.: |
16/115737 |
Filed: |
August 29, 2018 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62555734 |
Sep 8, 2017 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C10G 67/02 20130101;
C10G 65/12 20130101; C10G 65/10 20130101 |
International
Class: |
C10G 65/10 20060101
C10G065/10; C10G 67/02 20060101 C10G067/02 |
Claims
1. A method for processing a heavy oil feedstock, comprising:
providing a heavy oil feedstock having a 10% distillation point of
at least 650.degree. F. (343.degree. C.); exposing the heavy oil
feedstock to a catalyst under first effective slurry
hydroconversion conditions in a first hydroconversion reactor to
form a first effluent, the first effective slurry hydroconversion
conditions comprising a temperature of 840.degree. F. (449.degree.
C.) to 1000.degree. F. (538.degree. C.) and a pressure of 1500 psig
to 3000 psig; exposing at least a portion of the first effluent to
a catalyst under second effective slurry hydroconversion conditions
in a second hydroconversion reactor to form a second effluent; the
second effective slurry hydroconversion conditions comprising a
temperature of 750.degree. F. (399.degree. C.) to 840.degree. F.
(449.degree. C.) and a pressure of 1500 psig to 3000 psig; wherein
the temperature of the second effective slurry hydroconversion
conditions is lower than the temperature of the first effective
slurry hydroconversion conditions.
2. The method of claim 1, further comprising exposing the first
effluent to a separator; wherein the separator removes naphtha and
distillate fractions from the first effluent prior to a exposing
the first effluent to the second hydroconversion reactor.
3. The method of claim 2, wherein the separator comprises a first
separator and a second separator; further comprising exposing the
first effluent to the first separator, thereby forming a first
separator bottoms fraction and a first separator light fraction;
wherein the first separator bottoms fraction comprises 650.degree.
F.+ (343.degree. C.+) hydrocarbons and the first separator light
fraction comprises 650.degree. F.- (343.degree. C.-) hydrocarbons
and treat gas; exposing at least a portion of the first separator
bottoms fraction to the second hydroconversion reactor; exposing
the first separator light fraction to the second separator, thereby
forming a second separator bottoms fraction comprising liquid
160.degree. F.+ (71.degree. C.+) hydrocarbons and a second
separator light fraction comprising 160.degree. F.- (71.degree.
C.-) hydrocarbons and treat gas; and exposing at least a portion of
the second separator light fraction to the second hydroconversion
reactor.
4. The method of claim 2, wherein the separator comprises a first
separator and a second separator; further comprising exposing the
first effluent to the first separator, thereby forming a first
separator bottoms fraction comprising liquid 160.degree. F.+
(71.degree. C.+) hydrocarbons and a first separator light fraction
comprising 160.degree. F.- (71.degree. C.-) hydrocarbons and treat
gas; exposing at least a portion of the first separator light
fraction to the second hydroconversion reactor; exposing at least a
portion of the first separator bottoms fraction to the second
separator; thereby forming a second separator bottoms fraction and
a second separator light fraction; wherein the second separator
bottoms fraction comprises 650.degree. F.+ (343.degree. C.+)
hydrocarbons and the second separator light fraction comprises
650.degree. F.- (343.degree. C.-) hydrocarbons and treat gas; and
exposing at least a portion of the second separator bottoms
fraction to the second hydroconversion reactor.
5. The method of claim 1, wherein the first effective slurry
hydroconversion conditions and the second slurry hydroconversion
conditions are effective for a combined conversion of at least 70
wt % of the heavy oil feedstock relative to a conversion
temperature of at least 700.degree. F. (371.degree. C.).
6. The method of claim 1, wherein the second effluent has an API
gravity of at least 12.
7. The method of claim 5, wherein the second effluent has an API
gravity of at least 12.
8. The method of claim 1, wherein the heavy oil feedstock comprises
at least one of fluid catalytic cracker main column bottoms, steam
cracker tar, and coker gas oil.
9. The method of claim 1, wherein the catalyst comprises
MoS.sub.2.
10. The method of claim 1, wherein the catalyst is present in the
heavy oil feedstock at a concentration of 50 wppm to 500 wppm.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional
Application Ser. No. 62/555,734 filed on Sep. 8, 2017, which is
herein incorporated by reference in its entirety.
FIELD
[0002] This invention provides methods for slurry hydroprocessing
of polyaromatic hydrocarbon feeds, such as fluid catalytic cracker
(FCC) main column bottoms (MCB), steam cracker tar, and coker gas
oil.
BACKGROUND
[0003] Slurry hydroprocesssing provides a method for conversion of
high boiling, low value petroleum fractions into higher value
liquid products. Slurry hydroconversion technology can process
difficult feeds, such as feeds with high concentrations of
polycyclic aromatic hydrocarbons (PAH), while still maintaining
high liquid yields. Slurry hydroconversion units have been used to
process challenging streams present in refinery/petrochemical
complexes such as FCC MCB, steam cracked tar, and coker gas oil.
Slurry hydroprocessing offers a means for converting low-value
heavy feedstocks into fuels using a technology that is not as
susceptible to fouling as emerging fixed-bed technologies. In a
fixed-bed reactor, there is a risk that feeds containing polycyclic
aromatic hydrocarbons will lead to deposits forming on the reactor
internals and catalyst bed, resulting in a build-up of pressure
that hinders process operability. Because a slurry hydroconversion
reactor does not have an internal catalyst bed, these risks are
largely avoided. Unfortunately, slurry hydroprocessing is also an
expensive refinery process from both a capital investment
standpoint and a hydrogen consumption standpoint.
[0004] Various slurry hydroprocessing configurations have
previously been described. For example, U.S. Pat. No. 5,755,955 and
U.S. Patent Application Publication 2010/0122939 provide examples
of configurations for performing slurry hydroprocessing. U.S.
Patent Application Publication 2011/0210045 also describes examples
of configurations for slurry hydroconversion, including examples of
configurations where the heavy oil feed is diluted with a stream
having a lower boiling point range, such as a vacuum gas oil stream
and/or catalytic cracking slurry oil stream, and examples of
configurations where a bottoms portion of the product from slurry
hydroconversion is recycled to the slurry hydroconversion
reactor.
[0005] U.S. Pat. No. 9,605,217 relates to a multi-stage slurry
hydroconversion process using multiple reactor stages in series at
different pressures.
[0006] U.S. Patent Application Publication 2013/0075303 describes a
reaction system for combining slurry hydroconversion with a coking
process. An unconverted portion of the feed after slurry
hydroconversion is passed into a coker for further processing. The
resulting coke is described as being high in metals.
[0007] U.S. Patent Application Publication 2013/0112593 describes a
reaction system for performing slurry hydroconversion on a
deasphalted heavy oil feed. The asphalt from a deasphalting process
and a portion of the unconverted material from the slurry
hydroconversion can be gasified to form hydrogen and carbon
oxides.
[0008] Current slurry hydroconversion technology converts high PAH
feeds into lighter to molecules suitable for higher value
dispositions such as gasoline or diesel. In a slurry
hydroconversion process, high temperatures (>830.degree. F.) are
used to thermally crack heavy hydrocarbons in the presence of
hydrogen. With higher reactor temperature, the rate of the cracking
reaction is accelerated, reducing the reactor volume required to
achieve a target conversion at a given feed rate. A negative side
effect of operating at higher temperature is that the desaturation
of aromatics becomes more thermodynamically favored. This
phenomenon results in higher liquid product densities having lower
economic value than would be achieved in the absence of
desaturation. It would be beneficial to have a process that can
both achieve high rates of conversion, but also maintain a lower
liquid product density to increase economic value.
[0009] This application provides a process for enabling high feed
conversion without sacrificing product density by using multiple
slurry hydroconversion reactor stages operated at different
temperatures. The first stage is operated at high temperature to
efficiently crack the feed to lighter boiling point components and
at least one additional reactor stage is operated at lower
temperature to reverse the aromatic desaturation that occurred in
the first stage. In lieu of using a second slurry hydroconversion
stage, the liquid product could be hydrogenated using a
conventional fixed-bed catalyst hydrogenation process. However, the
presence of slurry catalyst, demetallization products, and coke in
the liquid effluent from the first reactor stage could create
fouling risks for the fixed-bed hydrogenation reactor. By using a
slurry reactor as hydrogenation step, these risks are avoided. In
general, a slurry reactor system will be more robust to poor feed
quality than a fixed-bed process.
SUMMARY
[0010] In various aspects, methods for processing a heavy oil
feedstock are provided. In certain aspects, the methods comprise
providing a heavy oil feedstock having a 10% distillation point of
at least about 650.degree. F. (343.degree. C.); exposing the heavy
oil feedstock to a catalyst under first effective slurry
hydroconversion conditions in a first hydroconversion reactor to
form a first effluent, the first effective slurry hydroconversion
conditions comprising a temperature of about 840.degree. F.
(449.degree. C.) to about 1000.degree. F. (538.degree. C.) and a
pressure of about 1500 psig to 3000 psig; exposing at least a
portion of the first effluent to a catalyst under second effective
slurry hydroconversion conditions in a second hydroconversion
reactor to form a second effluent; the second effective slurry
hydroconversion conditions comprising a temperature of about
750.degree. F. (399.degree. C.) to about 840.degree. F.
(449.degree. C.) and a pressure of about 1500 psig to about 3000
psig; wherein the temperature of the second effective slurry
hydroconversion conditions is lower than the temperature of the
first effective slurry hydroconversion conditions.
[0011] In another aspect, the method further comprises exposing the
first effluent to a separator; wherein the separator removes
naphtha and distillate fractions from the first effluent prior to a
exposing the first effluent to the second hydroconversion reactor.
In certain aspects the separator comprises a first separator and a
second separator; further comprising exposing the first effluent to
the first separator, thereby forming a first separator bottoms
fraction and a first separator light fraction; wherein the first
separator bottoms fraction comprises 650.degree. F.+ (343.degree.
C.+) hydrocarbons and the first separator light fraction comprises
650.degree. F.- (343.degree. C.-) hydrocarbons and treat gas;
exposing at least a portion of the first separator bottoms fraction
to the second hydroconversion reactor; exposing the first separator
light fraction to the second separator, thereby forming a second
separator bottoms fraction comprising liquid 160.degree. F.+
(71.degree. C.+) hydrocarbons and a second separator light fraction
comprising 160.degree. F.- (71.degree. C.-) hydrocarbons and treat
gas; and exposing at least a portion of the second separator light
fraction to the second hydroconversion reactor. In an alternative
aspect, the separator comprises a first separator and a second
separator; further comprising exposing the first effluent to the
first separator, thereby forming a first separator bottoms fraction
comprising liquid 160.degree. F.+ (71.degree. C.+) hydrocarbons and
a first separator light fraction comprising 160.degree. F.-
(71.degree. C.-) hydrocarbons and treat gas; exposing at least a
portion of the first separator light fraction to the second
hydroconversion reactor; exposing at least a portion of the first
separator bottoms fraction to the second separator; thereby forming
a second separator bottoms fraction and a second separator light
fraction; wherein the second separator bottoms fraction comprises
650.degree. F.+ (343.degree. C.+) hydrocarbons and the second
separator light fraction comprises 650.degree. F.- (343.degree.
C.-) hydrocarbons and treat gas; and exposing at least a portion of
the second separator bottoms fraction to the second hydroconversion
reactor.
[0012] In yet another aspect, the first effective slurry
hydroconversion conditions and the second slurry hydroconversion
conditions are effective for a combined conversion of at least
about 70 wt % of the heavy oil feedstock relative to a conversion
temperature of at least about 700.degree. F. (371.degree. C.).
Additionally or alternatively, the second effluent may have an API
gravity of at least 12. In another aspect, the heavy oil feedstock
comprises at least one of fluid catalytic cracker main column
bottoms, steam cracker tar, and coker gas oil. The catalyst may
comprise MoS.sub.2 in a concentration of 50 wppm to 500 wppm.
BRIEF DESCRIPTION OF THE FIGURES
[0013] FIG. 1 shows an example of a slurry hydroconversion reaction
system according to the present disclosure.
[0014] FIG. 2 shows an example of a slurry hydroconversion reaction
system according to the present disclosure.
[0015] FIG. 3 provides a graphical depiction of conversion of a PAH
feed hydroprocessed using a reaction system according to the
present disclosure.
[0016] FIG. 4 provides a graphical depiction of liquid product API
of a PAH feed hydroprocessed using a reaction system according to
the present disclosure.
DETAILED DESCRIPTION OF THE EMBODIMENTS
Overview
[0017] In various aspects, a process for hydroconverting heavy
feeds rich in polycyclic aromatic hydrocarbons, such as bottoms
from a fluid catalytic cracking (FCC) process, using a multistage
slurry reactor system is provided. The feed enters a slurry reactor
operated at a high temperature to initiate thermally-driven
hydrocracking reactions. The operating temperature and pressure of
this stage are maximized to drive the conversion of multi-ring
aromatic compounds having boiling points greater than 650
F..degree. into lighter compounds. The process involves at least
one additional reactor stage operated at lower temperature to
promote the saturation of aromatic and olefinic compounds,
increasing the API gravity of the hydrocracked liquid product. An
optional interstage, highpressure separator system allows for
recovery of naphtha and distillate after the first reactor stage to
prevent over-cracking of these desired products. With respect to
existing slurry hydroconversion process configurations, the present
disclosure allows one to achieve both high boiling point conversion
and a high product API gravity, which tend to be mutually
exclusive.
[0018] In an embodiment, a feed high in polycyclic aromatic
hydrocarbons, such as FCC MCB, steam cracker tar, or coker gas oil,
is passed into an initial slurry hydroconversion reactor operated a
temperature of at least about 840.degree. F. (449.degree. C.)--e.g.
at least about 850.degree. F. (454.degree. C.), at least about
860.degree. F. (460.degree. C.), at least about 870.degree. F.
(465.degree. C.), at least about 880.degree. F. (471.degree.
C.)--or from about 840.degree. F. (449.degree. C.) to about
1000.degree. F. (538.degree. C.)--e.g. from about 850.degree. F.
(454.degree. C.) to about 980.degree. F. (527.degree. C.), from
about 860.degree. F. (460.degree. C.) to about 950.degree. F.
(510.degree. C.). The high temperature in the initial reaction
stage results in a preferred conversion of the feed, but also in
increased aromatic desaturation (i.e. increased density). The
conversion products from the initial slurry hydroconversion reactor
can optionally be separated by an interstage separator to pull out
desired naphtha and distillate boiling range products.
[0019] The bottoms portion from the initial low pressure
hydroconversion reactor is then passed into a second slurry
hydroconversion reactor operated at a temperature of about
840.degree. F. (449.degree. C.) or less--e.g. about 830.degree. F.
(443.degree. C.) or less, about 820.degree. F. (438.degree. C.) or
less, about 810.degree. F. (432.degree. C.) or less, about
800.degree. F. (427.degree. C.) or less--or from about 700.degree.
F. (371.degree. C.) to about 840.degree. F. (449.degree. C.)--e.g.
from about 720.degree. F. (382.degree. C.) to about 830.degree. F.
(443.degree. C.), from about 750.degree. F. (399.degree. C.) to
about 820.degree. F. (438.degree. C.). The lower temperature in the
second reaction stage promotes aromatic saturation of portions of
the feed desaturated in the first, high-temperature reaction stage,
which in turn lowers the gravity of the final hydroprocessed
products.
Feedstocks
[0020] In various aspects, a hydroprocessed product is produced
from a heavy oil feed component. Examples of heavy oils include,
but are not limited to, heavy crude oils, distillation residues,
heavy oils coming from catalytic treatment (such as heavy cycle
bottom slurry oils from fluid catalytic cracking), thermal tars
(such as oils from visbreaking, steam cracking, or similar thermal
or non-catalytic processes), oils (such as bitumen) from oil sands
and heavy oils derived from coal.
[0021] Heavy oil feedstocks can be liquid or semi-solid. Examples
of heavy oils that can be hydroprocessed, treated or upgraded
according to this invention include bitumens and residuum from
refinery distillation processes, including atmospheric and vacuum
distillation processes. Such heavy oils can have an initial boiling
point of 650.degree. F. (343.degree. C.) or greater. Preferably,
the heavy oils will have a 10% distillation point of at least
650.degree. F. (343.degree. C.), alternatively at least 660.degree.
F. (349.degree. C.) or at least 750.degree. F. (399.degree. C.). In
some aspects the 10% distillation point can be still greater, such
as at least 900.degree. F. (482.degree. C.), or at least
950.degree. F. (510.degree. C.), or at least 975.degree. F.
(524.degree. C.), or at least 1020.degree. F. (549.degree. C.) or
at least 1050.degree. F. (566.degree. C.). In this discussion,
boiling points can be determined by a convenient method, such as
ASTM D86, ASTM D2887, or another suitable standard method.
[0022] Steam cracker tar (SCT) as used herein is also referred to
in the art as "pyrolysis fuel oil". The terms can be used
interchangeably herein. The tar will typically be obtained from the
first fractionator downstream from a steam cracker (pyrolysis
furnace) as the bottoms product of the fractionator, nominally
having a boiling point of at least about 550.degree. F.+
(.about.288.degree. C.+). Boiling points and/or fractional weight
distillation points can be determined by, for example, ASTM D2892.
Alternatively, SCT can have a T5 boiling point (temperature at
which 5 wt % will boil off) of at least about 550.degree. F.
(.about.288.degree. C.). The final boiling point of SCT can be
dependent on the nature of the initial pyrolysis feed and/or the
pyrolysis conditions, and typically can be about 1450.degree. F.
(.about.788.degree. C.) or less.
[0023] SCT can have a relatively low hydrogen content compared to
heavy oil fractions that are typically processed in a refinery
setting. In some aspects, SCT can have a hydrogen content of about
8.0 wt % or less, about 7.5 wt % or less, or about 7.0 wt % or
less, or about 6.5 wt % or less. In particular, SCT can have a
hydrogen content of about 5.5 wt % to about 8.0 wt %, or about 6.0
wt % to about 7.5 wt %. Additionally or alternately, SCT can have a
micro carbon residue (or alternatively Conradson Carbon Residue) of
at least about 10 wt %, or at least about 15 wt %, or at least
about 20 wt %, such as up to about 40 wt % or more.
[0024] SCT can also be highly aromatic in nature. The paraffin
content of SCT can be about 2.0 wt % or less, or about 1.0 wt % or
less, such as having substantially no paraffin content. The
naphthene content of SCT can also be about 2.0 wt % or less or
about 1.0 wt % or less, such as having substantially no naphthene
content. In some aspects, the combined paraffin and naphthene
content of SCT can be about 1.0 wt % or less. With regard to
aromatics, at least about 30 wt % of SCT can correspond to 3-ring
aromatics, or at least 40 wt %. In particular, the 3-ring aromatics
content can be about 30 wt % to about 60 wt %, or about 40 wt % to
about 55 wt %, or about 40 wt % to about 50 wt %. Additionally or
alternately, at least about 30 wt % of SCT can correspond to 4-ring
aromatics, or at least 40 wt %. In particular, the 4-ring aromatics
content can be about 30 wt % to about 60 wt %, or about 40 wt % to
about 55 wt %, or about 40 wt % to about 50 wt %. Additionally or
alternately, the 1-ring aromatic content can be about 15 wt % or
less, or about 10 wt % or less, or about 5 wt % or less, such as
down to about 0.1 wt %.
[0025] SCT can also have a higher density than many types of crude
or refinery fractions. In various aspects, SCT can have a density
at 15.degree. C. of about 1.08 g/cm.sup.3 to about 1.20 g/cm.sup.3,
or 1.10 g/cm.sup.3 to 1.18 g/cm.sup.3. By contrast, many types of
vacuum resid fractions can have a density of about 1.05 g/cm.sup.3
or less. Additionally or alternately, density (or weight per
volume) of the heavy hydrocarbon can be determined according to
ASTM D287-92 (2006) Standard Test Method for API Gravity of Crude
Petroleum and Petroleum Products (Hydrometer Method), which
characterizes density in terms of API gravity. In general, the
higher the API gravity, the less dense the oil. API gravity can be
5.degree. or less, or 0.degree. or less, such as down to about
-10.degree. or lower.
[0026] Contaminants such as nitrogen and sulfur are typically found
in SCT, often in organically-bound form. Nitrogen content can range
from about 50 wppm to about 10,000 wppm elemental nitrogen or more,
based on total weight of the SCT. Sulfur content can range from
about 0.1 wt % to about 10 wt %, based on total weight of the
SCT.
[0027] Coker bottoms represent another type of cracked feed
suitable for hydroprocessing, optionally in combination with a
catalytic slurry oil and/or steam cracker tar and/or other cracked
fractions. Coking is a thermal cracking process that is suitable
for conversion of heavy feeds into fuels boiling range products.
The feedstock to a coker typically also includes 5 wt % to 25 wt %
recycled product from the coker, which can be referred to as coker
bottoms. This recycle fraction allows metals, asphaltenes,
micro-carbon residue, and/or other solids to be returned to the
coker, as opposed to being incorporated into a coker gas oil
product. This can maintain a desired product quality for the coker
gas oil product, but results in a net increase in the amount of
light ends and coke that are generated by a coking process. The
coker bottoms can correspond to a fraction with a T10 distillation
point of at least 550.degree. F. (288.degree. C.), or at least
300.degree. C., or at least 316.degree. C., and a T90 distillation
point of 566.degree. C. or less, or 550.degree. C. or less, or
538.degree. C. or less. The coker recycle fraction can have an
aromatic carbon content of about 20 wt % to about 50 wt %, or about
30 wt % to about 45 wt %, and a micro carbon residue content of
about 4.0 wt % to about 15 wt %, or about 6.0 wt % to about 15 wt
%, or about 4.0 wt % to about 10 wt %, or about 6.0 wt % to about
12 wt %.
[0028] In addition to initial boiling points and/or 10%
distillation points, other distillation points may also be useful
in characterizing a feedstock. For example, a feedstock can be
characterized based on the portion of the feedstock that boils
above 1050.degree. F. (566.degree. C.). In some aspects, a
feedstock can have a 70% distillation point of 1050.degree. F. or
greater, or a 60% distillation point of 1050.degree. F. or greater,
or a 50% distillation point of 1050.degree. F. or greater, or a 40%
distillation point of 1050.degree. F. or greater.
[0029] Density, or weight per volume, of the heavy hydrocarbon can
be determined according to ASTM D287-92 (2006) Standard Test Method
for API Gravity of Crude Petroleum and Petroleum Products
(Hydrometer Method), and is provided in terms of API gravity. In
general, the higher the API gravity, the less dense the oil. API
gravity is 20.degree. or less in one aspect, 15.degree. or less in
another aspect, and 10.degree. or less in another aspect.
[0030] Heavy oil feedstocks (also referred to as heavy oils) can be
high in metals. For example, the heavy oil can be high in total
nickel, vanadium and iron contents. In one embodiment, the heavy
oil will contain at least 0.00005 grams of Ni/V/Fe (50 ppm) or at
least 0.0002 grams of Ni/V/Fe (200 ppm) per gram of heavy oil, on a
total elemental basis of nickel, vanadium and iron. In other
aspects, the heavy oil can contain at least about 500 wppm of
nickel, vanadium, and iron, such as at least about 1000 wppm.
[0031] Contaminants such as nitrogen and sulfur are typically found
in heavy oils, often in organically-bound form. Nitrogen content
can range from about 50 wppm to about 10,000 wppm elemental
nitrogen or more, based on total weight of the heavy hydrocarbon
component. The nitrogen containing compounds can be present as
basic or non-basic nitrogen species. Examples of basic nitrogen
species include quinolines and substituted quinolines. Examples of
non-basic nitrogen species include carbazoles and substituted
carbazoles.
Slurry Hydroprocessing
[0032] FIG. 1 shows an example of a reaction system according to
the present disclosure. In
[0033] FIG. 1, a feed mixture 105, which is a mixture of heavy
feed, catalyst slurry, and Hz-rich treat gas, is admitted to slurry
hydroprocessing reactor 101 operated at temperature of at least
about 840.degree. F. (449.degree. C.)--e.g. at least about
850.degree. F. (454.degree. C.), at least about 860.degree. F.
(460.degree. C.), at least about 870.degree. F. (465.degree. C.),
at least about 880.degree. F. (471.degree. C.)--or from about
840.degree. F. (449.degree. C.) to about 1000.degree. F.
(538.degree. C.)--e.g. from about 850.degree. F. (454.degree. C.)
to about 980.degree. F. (527.degree. C.), from about 860.degree. F.
(460.degree. C.) to about 950.degree. F. (510.degree. C.). Feed
mixture 105 can be heated prior to entering reactor 101 in order to
achieve a desired temperature for the slurry hydroprocessing
reaction.
[0034] The effluent 106 from slurry hydroprocessing reactor 101 is
passed into one or more separation stages--two are shown in FIG. 1.
For example, an initial separation stage can be a high pressure
separator 102. A lower boiling point portion 107--e.g. treat gas
and 650.degree. F.- (343.degree. C.-) hydrocarbons--leaving as
vapor from separator 102 can be passed to a second high pressure
separator 103. In separator 103, distillate and naphtha are
separated from light ends (C.sub.1 to C.sub.4 hydrocarbons) and
treat gas. Liquid product 110 comprising naphtha and distillate
exit separator 103 from the bottom and light ends stream 109 is
transported to slurry hydroprocessing reactor 104. As used herein,
naphtha and distillate fractions include naphtha fractions,
kerosene fractions, diesel fractions, and other heavier (gas oil)
fractions. Each of these types of fractions can be defined based on
a boiling range, such as a boiling range that includes at least
.about.90 wt % of the fraction, or at least .about.95 wt % of the
fraction. For example, for many types of naphtha fractions, at
least .about.90 wt % of the fraction, or at least .about.95 wt %,
can have a boiling point in the range of .about.85.degree. F.
(.about.29.degree. C.) to .about.350.degree. F. (.about.177.degree.
C.). For some heavier naphtha fractions, at least .about.90 wt % of
the fraction, and preferably at least .about.95 wt %, can have a
boiling point in the range of .about.85.degree. F.
(.about.29.degree. C.) to .about.400.degree. F. (.about.204.degree.
C.). For a kerosene fraction, at least .about.90 wt % of the
fraction, or at least .about.95 wt %, can have a boiling point in
the range of .about.300.degree. F. (.about.149.degree. C.) to
.about.600.degree. F. (.about.288.degree. C.). For a kerosene
fraction targeted for some uses, such as jet fuel production, at
least .about.90 wt % of the fraction, or at least .about.95 wt %,
can have a boiling point in the range of .about.300.degree. F.
(.about.149.degree. C.) to .about.550.degree. F.
(.about.288.degree. C.). For a diesel fraction, at least .about.90
wt % of the fraction, and preferably at least .about.95 wt %, can
have a boiling point in the range of .about.350.degree. F.
(.about.177.degree. C.) to .about.700.degree. F.
(.about.371.degree. C.). For a (vacuum) gas oil fraction, at least
.about.90 wt % of the fraction, and preferably at least .about.95
wt %, can have a boiling point in the range of .about.650.degree.
F. (.about.343.degree. C.) to .about.1100.degree. F.
(.about.593.degree. C.). Optionally, for some gas oil fractions, a
narrower boiling range may be desirable. For such gas oil
fractions, at least .about.90 wt % of the fraction, or at least
.about.95 wt %, can have a boiling point in the range of
.about.650.degree. F. (.about.343.degree. C.) to
.about.1000.degree. F. (.about.538.degree. C.), or
.about.650.degree. F. (.about.343.degree. C.) to .about.900.degree.
F. (.about.482.degree. C.).
[0035] Unconverted feed 108 from separator 102 is also sent to
reactor 104. Reactor 104 is operated at lower temperature than
reactor 101 to reverse the aromatic desaturation that occurred in
separator 102. Typical operating temperature of reactor 104 include
about 840.degree. F. (449.degree. C.) or less--e.g. about
830.degree. F. (443.degree. C.) or less, about 820.degree. F.
(438.degree. C.) or less, about 810.degree. F. (432.degree. C.) or
less, about 800.degree. F. (427.degree. C.) or less--or from about
700.degree. F. (371.degree. C.) to about 840.degree. F.
(449.degree. C.)--e.g. from about 720.degree. F. (382.degree. C.)
to about 830.degree. F. (443.degree. C.), from about 750.degree. F.
(399.degree. C.) to about 830.degree. F. (443.degree. C.). Effluent
111 from reactor 104 achieves greater conversion of feed mixture
105 at a lower density than conventional slurry hydroprocessing
systems.
[0036] FIG. 2 shows an alternative example of a reaction system
according to the present disclosure. In FIG. 2, a feed mixture 205,
which is a mixture of heavy feed, catalyst slurry, and Hz-rich
treat gas, is admitted to slurry hydroprocessing reactor 201
operated at temperature of at least about 840.degree. F.
(449.degree. C.)--e.g. at least about 850.degree. F. (454.degree.
C.), at least about 860.degree. F. (460.degree. C.), at least about
870.degree. F. (465.degree. C.), at least about 880.degree. F.
(471.degree. C.)--or from about 840.degree. F. (449.degree. C.) to
about 1000.degree. F. (538.degree. C.)--e.g. from about 850.degree.
F. (454.degree. C.) to about 980.degree. F. (527.degree. C.), from
about 860.degree. F. (460.degree. C.) to about 950.degree. F.
(510.degree. C.). Feed mixture 205 can be heated prior to entering
reactor 201 in order to achieve a desired temperature for the
slurry hydroprocessing reaction.
[0037] The effluent 206 from slurry hydroprocessing reactor 201 is
passed into one or more separation stages--two are shown in FIG. 2.
For example, an initial separation stage can be a high pressure
separator 202. A higher boiling point portion 107--e.g. 160.degree.
F.+(71.degree. C.+) hydrocarbons--leaving as liquid from separator
202 can be passed to a second high pressure separator 203. In
separator 203, distillate and naphtha 210 are separated from
unconverted feed 209 of feed mixture 205. Light ends (C.sub.1 to
C.sub.4 hydrocarbons) and treat gas 208 are sent to second slurry
hydroprocessing reactor 204 along with unconverted feed 209.
[0038] Reactor 204 is operated at lower temperature than reactor
201 to reverse the aromatic desaturation that occurred in separator
202. Typical operating temperature of reactor 104 include about
840.degree. F. (449.degree. C.) or less--e.g. about 830.degree. F.
(443.degree. C.) or less, about 820.degree. F. (438.degree. C.) or
less, about 810.degree. F. (432.degree. C.) or less, about
800.degree. F. (427.degree. C.) or less--or from about 700.degree.
F. (371.degree. C.) to about 840.degree. F. (449.degree. C.)--e.g.
from about 720.degree. F. (382.degree. C.) to about 830.degree. F.
(443.degree. C.), from about 750.degree. F. (399.degree. C.) to
about 830.degree. F. (443.degree. C.). Effluent 211 from reactor
204 achieves greater conversion of feed mixture 205 at a lower
density than conventional slurry hydroprocessing systems.
[0039] The reaction conditions in a slurry hydroprocessing reactor
can vary based on the nature of the catalyst, the nature of the
feed, the desired products, and/or the desired amount of
conversion. With regard to catalyst, suitable catalyst
concentrations can range from about 50 wppm to about 20,000 wppm
(or about 2 wt %), e.g. about 50 wppm to about 10,000 wppm, about
50 wppm to about 1,000 wppm, about 50 wppm to about 500 wppm,
depending on the nature of the catalyst. Catalyst can be
incorporated into a hydrocarbon feedstock directly, or the catalyst
can be incorporated into a side or slip stream of feed and then
combined with the main flow of feedstock. Still another option is
to form catalyst in-situ by introducing a catalyst precursor into a
feed (or a side/slip stream of feed) and forming catalyst by a
subsequent reaction.
[0040] Catalytically active metals for use in hydroprocessing can
include those from Group IVB, Group VB, Group VIB, Group VIIB, or
Group VIII of the Periodic Table. Examples of suitable metals
include iron, nickel, molybdenum, vanadium, tungsten, cobalt,
ruthenium, and mixtures thereof. The catalytically active metal may
be present as a solid particulate in elemental form or as an
organic compound or an inorganic compound such as a sulfide (e.g.,
molybdenum sulfide) or other ionic compound. Metal or metal
compound nanoaggregates may also be used to form the solid
particulates.
[0041] A catalyst in the form of a solid particulate is generally a
compound of a catalytically active metal, or a metal in elemental
form, either alone or supported on a refractory material such as an
inorganic metal oxide (e.g., alumina, silica, titania, zirconia,
and mixtures thereof). Other suitable refractory materials can
include carbon, coal, and clays. Zeolites and non-zeolitic
molecular sieves are also useful as solid supports. One advantage
of using a support is its ability to act as a "coke getter" or
adsorbent of asphaltene precursors that might otherwise lead to
fouling of process equipment.
[0042] In some aspects, it can be desirable to form catalyst for
slurry hydroprocessing in situ, such as forming catalyst from a
metal sulfate (e.g., iron sulfate monohydrate) catalyst precursor
or another type of catalyst precursor that decomposes or reacts in
the hydroprocessing reaction zone environment, or in a pretreatment
step, to form a desired, well-dispersed and catalytically active
solid particulate (e.g., as iron sulfide). Precursors also include
oil-soluble organometallic compounds containing the catalytically
active metal of interest that thermally decompose to form the solid
particulate (e.g., iron sulfide) having catalytic activity. Other
suitable precursors include metal oxides that may be converted to
catalytically active (or more catalytically active) compounds such
as metal sulfides. In a particular embodiment, a metal oxide
containing mineral may be used as a precursor of a solid
particulate comprising the catalytically active metal (e.g., iron
sulfide) on an inorganic refractory metal oxide support (e.g.,
alumina).
[0043] The reaction conditions within the slurry hydroconversion
reactors can include the temperatures described above and pressures
of about 1200 psig (8.3 MPag) to about 3400 psig (23.4 MPag), e.g.
about 1500 psig (10.3 MPag) to about 3000 psig (20.7 MPag). Because
the catalyst is in slurry form within the feedstock, the space
velocity for a slurry hydroconversion reactor can be characterized
based on the volume of feed processed relative to the volume of the
reactor used for processing the feed. Suitable space velocities for
slurry hydroconversion can range, for example, from about 0.05
v/v/hr.sup.-1 to about 5 v/v/hr.sup.-1, such as about 0.1
v/v/hr.sup.-1 to about 2 v/v/hr.sup.-1.
[0044] The reaction conditions for slurry hydroprocessing can be
selected so that the net conversion of feed across all slurry
hydroprocessing reactors (if there is more than one arranged in
series) is at least about 60%, such as at least about 70%, or at
least about 75%. For slurry hydroprocessing, conversion is defined
as conversion of compounds with boiling points greater than a
conversion temperature, such as 700.degree. F. (371.degree. C.), to
compounds with boiling points below the conversion temperature. The
portion of a heavy feed that is unconverted after slurry
hydroprocessing can be referred to as pitch or a bottoms fraction
from the slurry hydroprocessing.
[0045] In some alternative aspects, multiple slurry hydroconversion
stages and/or reactors can be used for conversion of a feed. In
such aspects, the effluent from a first slurry hydroconversion
stage can be fractionated to separate out one or more product
fractions. For example, the feed can be fractionated to separate
out one or more naphtha fractions and/or distillate fuel (such as
diesel) fractions. Such a fractionation can also separate out lower
boiling compounds, such as compounds containing 4 carbons or less
and contaminant gases such as H.sub.2S or NH.sub.3. The remaining
higher boiling fraction of the feed can have a boiling range
roughly corresponding to an atmospheric resid, such as a 10 wt %
boiling point of at least about 650.degree. F. (343.degree. C.) or
at least about 700.degree. F. (371.degree. C.). At least a portion
of this higher boiling fraction can be passed into a second (or
later) slurry hydroconversion stage for additional conversion of
the 975.degree. F.+ (524.degree. C.) portion, or optionally the
1050.degree. F.+ (566.degree. C.) portion of the feed. By
separating out the lower boiling portions after performing an
intermediate level of conversion, the amount of "overcracking" of
desirable products can be reduced or minimized.
[0046] Using multiple stages of slurry hydroconversion reactors can
allow for selection of different processing conditions in the
stages and/or reactors. As described herein, the temperature in the
first slurry hydroconversion reactor can be higher than the
temperature in a second reactor. In such an aspect, the first
effective hydroprocessing conditions for use in the first slurry
hydroconversion reactor can include a temperature that is at least
about 5.degree. C. greater than a temperature for the second
effective slurry hydroprocessing conditions in the second reactor,
or at least about 10.degree. C. greater, or at least about
15.degree. C. greater, or at least about 20.degree. C. greater, or
at least about 30.degree. C. greater, or at least about 40.degree.
C. greater, or at least about 50.degree. C. greater.
[0047] The benefits of the present disclosure can be seen clearly
with respect to the examples.
Example: Multi-Stage Slurry Hydroprocessing with a Lower
Temperature Second Stage
[0048] An experiment was conducted documenting the conversion of a
700.degree. F.+ cut of an FCC MCB feed into lighter hydrocarbons as
a function of process temperature. The FCC MCB feed had the
properties shown in Table 1. The reactions were carried out in an
autoclave operated in semi-batch mode with flowing H.sub.2 treat
gas at 2100 psig for 3 hours. The autoclave was charged at the
beginning of the reaction with the MCB FCC feed and a catalyst
slurry comprising MoS.sub.2 blended with heavy oil. The charge
weight of catalyst slurry was such that the liquid contents of the
autoclave had a Mo concentration of 500 wppm at the start of the
reaction. Single stage reactions were performed at 810.degree. F.
(432.degree. C.), 830.degree. F. (443.degree. C.), 860.degree. F.
(460.degree. C.), and 880.degree. F. (471.degree. C.) for
comparative data. A two stage reaction was performed by flowing
H.sub.2 treat gas at 2100 psig for 3 hours at a first temperature
of 860.degree. F. (460.degree. C.) followed by flowing H.sub.2
treat gas at 2100 psig for 3 hours at a second temperature of
810.degree. F. (432.degree. C.). Each reaction was carried out with
a fresh charge of feed and catalyst slurry. All products and
unreacted feedstock were extracted from the autoclave after
completion of each reaction.
TABLE-US-00001 TABLE 1 FCC MCB Feed Properties Density at
60.degree. F. (g/cm.sup.3) 1.115 API Gravity -4.56 Sulfur (wt %)
3.07 Nitrogen (wt %) 0.18 n-heptane insolubles (wt %) 4.4 hydrogen
content (wt %) 7.31 SIMDIST T5 (.degree. F./.degree. C.) 626/330
T50 (.degree. F./.degree. C.) 797/425 T95 (.degree. F./.degree. C.)
1129/609
[0049] FIGS. 3 and 4 provide graphical representation of the
results. FIG. 3 provides evidence that the rate of the
hydrocracking reaction can be enhanced by operating the slurry
reactor at higher temperature. In this series of experiments,
higher conversions of the feed were obtained at higher reaction
temperatures over the range of 810.degree. F. (432.degree. C.) to
880.degree. F. (471.degree. C.), and notably, the two-stage
reaction provides comparable wt. % conversion to the 880.degree. F.
(471.degree. C.) case despite the high temperature reaction
occurring at 860.degree. F. (460.degree. C.). As described above,
however, at high temperatures, thermodynamics favors desaturation
of aromatic compounds, which is evidenced by API gravities shown in
FIG. 4. As shown, API gravity of the the liquid product obtained
from hydrocracking of an FCC MCB feed passes through a maximum as
the reaction temperature varies from 810.degree. F. (432.degree.
C.) to 880.degree. F. (471.degree. C.). This results from an
interplay between kinetics and thermodynamics. As temperature
increases, the hydrocracking reaction becomes faster, which leads
to a less dense product on account of the molecules having been
broken down into smaller molecules to a greater extent. At too high
of a temperature (>830.degree. F.), aromatic desaturation begins
to dominate, which causes the product API gravity to decrease. An
intermediate temperature balances these two competing effects,
resulting in the highest product API gravity for a single stage
process being attained at about 830.degree. F.
[0050] The two stage configuration exploits these trends with
temperature variation to achieve both high boiling point conversion
and high product API gravity. The first stage, operated at high
temperature, maximizes the boiling point conversion due to the
hydrocracking reaction, which is irreversible. The second stage is
operated at lower temperature to enable aromatic saturation, a
reversible reaction for which equilibrium is sensitive to
temperature. The benefit of this strategy is seen in the right most
columns in FIGS. 3 and 4. The product API gravity from the
two-stage process is higher than that from the single-stage process
at intermediate-temperature (830.degree. F.). Additionally, the
boiling point conversion from the two-stage process is comparable
to that from the single-stage process at high-temperature
(880.degree. F.).
ADDITIONAL EMBODIMENTS
Embodiment 1
[0051] A method for processing a heavy oil feedstock, comprising:
providing a heavy oil feedstock having a 10% distillation point of
at least about 650.degree. F. (343.degree. C.); exposing the heavy
oil feedstock to a catalyst under first effective slurry
hydroconversion conditions in a first hydroconversion reactor to
form a first effluent, the first effective slurry hydroconversion
conditions comprising a temperature of about 840.degree. F.
(449.degree. C.) to about 1000.degree. F. (538.degree. C.) and a
pressure of about 1500 psig to 3000 psig; exposing at least a
portion of the first effluent to a catalyst under second effective
slurry hydroconversion conditions in a second hydroconversion
reactor to form a second effluent; the second effective slurry
hydroconversion conditions comprising a temperature of about
750.degree. F. (399.degree. C.) to about 840.degree. F.
(449.degree. C.) and a pressure of about 1500 psig to about 3000
psig; wherein the temperature of the second effective slurry
hydroconversion conditions is lower than the temperature of the
first effective slurry hydroconversion conditions.
Embodiment 2
[0052] The method of embodiment 1, further comprising exposing the
first effluent to a separator; wherein the separator removes
naphtha and distillate fractions from the first effluent prior to a
exposing the first effluent to the second hydroconversion
reactor.
Embodiment 3
[0053] The method of embodiment 2, wherein the separator comprises
a first separator and a second separator; further comprising
exposing the first effluent to the first separator, thereby forming
a first separator bottoms fraction and a first separator light
fraction; wherein the first separator bottoms fraction comprises
650.degree. F.+ (343.degree. C.+) hydrocarbons and the first
separator light fraction comprises 650.degree. F.- (343.degree.
C.-) hydrocarbons and treat gas; exposing at least a portion of the
first separator bottoms fraction to the second hydroconversion
reactor; exposing the first separator light fraction to the second
separator, thereby forming a second separator bottoms fraction
comprising liquid 160.degree. F.+ (71.degree. C.+) hydrocarbons and
a second separator light fraction comprising 160.degree. F.-
(71.degree. C.-) hydrocarbons and treat gas; and exposing at least
a portion of the second separator light fraction to the second
hydroconversion reactor.
Embodiment 4
[0054] The method of embodiment 2, wherein the separator comprises
a first separator and a second separator; further comprising
exposing the first effluent to the first separator, thereby forming
a first separator bottoms fraction comprising liquid 160.degree.
F.+ (71.degree. C.+) hydrocarbons and a first separator light
fraction comprising 160.degree. F.- (71.degree. C.-) hydrocarbons
and treat gas; exposing at least a portion of the first separator
light fraction to the second hydroconversion reactor; exposing at
least a portion of the first separator bottoms fraction to the
second separator; thereby forming a second separator bottoms
fraction and a second separator light fraction; wherein the second
separator bottoms fraction comprises 650.degree. F.+ (343.degree.
C.+) hydrocarbons and the second separator light fraction comprises
650.degree. F.- (343.degree. C.-) hydrocarbons and treat gas; and
exposing at least a portion of the second separator bottoms
fraction to the second hydroconversion reactor.
Embodiment 5
[0055] The method of any of the previous embodiments, wherein the
first effective slurry hydroconversion conditions and the second
slurry hydroconversion conditions are effective for a combined
conversion of at least about 70 wt % of the heavy oil feedstock
relative to a conversion temperature of at least about 700.degree.
F. (371.degree. C.).
Embodiment 6
[0056] The method of any of the previous embodiments, wherein the
second effluent has an API gravity of at least 12.
Embodiment 7
[0057] The method of any of the previous embodiments, wherein the
heavy oil feedstock comprises at least one of fluid catalytic
cracker main column bottoms, steam cracker tar, and coker gas
oil.
Embodiment 8
[0058] The method of any of the previous embodiments, wherein the
catalyst comprises MoS.sub.2.
Embodiment 9
[0059] The method of any of the previous embodiments, wherein the
catalyst is present in the heavy oil feedstock at a concentration
of 50 wppm to 500 wppm.
* * * * *