U.S. patent application number 13/950891 was filed with the patent office on 2014-01-30 for vacuum gas oil conversion process.
This patent application is currently assigned to ExxonMobil Research and Engineering Company. Invention is credited to Stacey Erin Johnson, Steven S. Lowenthal, Benjamin S. Umansky, John Viets.
Application Number | 20140027345 13/950891 |
Document ID | / |
Family ID | 49993828 |
Filed Date | 2014-01-30 |
United States Patent
Application |
20140027345 |
Kind Code |
A1 |
Johnson; Stacey Erin ; et
al. |
January 30, 2014 |
VACUUM GAS OIL CONVERSION PROCESS
Abstract
An integrated thermal and catalytic process for improving the
yield of middle distillate from heavy petroleum oil feeds comprises
cracking the heavy portion (345.degree. C.+) of the feed in a
thermal conversion zone, followed by hydrotreating the thermally
cracked product and the lighter portion of the feed and then
separating the hydrotreated product into a bottoms fraction which
is passed to a catalytic cracking step.
Inventors: |
Johnson; Stacey Erin;
(Manassas, VA) ; Umansky; Benjamin S.; (Fairfax,
VA) ; Lowenthal; Steven S.; (Flanders, NJ) ;
Viets; John; (Fairfax, VA) |
Assignee: |
ExxonMobil Research and Engineering
Company
Annandale
NJ
|
Family ID: |
49993828 |
Appl. No.: |
13/950891 |
Filed: |
July 25, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61677045 |
Jul 30, 2012 |
|
|
|
Current U.S.
Class: |
208/76 |
Current CPC
Class: |
C10G 11/05 20130101;
C10G 69/06 20130101; C10G 69/02 20130101; C10G 2300/307 20130101;
C10G 51/04 20130101; C10G 2400/02 20130101; C10G 45/08 20130101;
C10G 2300/1074 20130101; C10G 2400/04 20130101; C10G 69/04
20130101 |
Class at
Publication: |
208/76 |
International
Class: |
C10G 51/04 20060101
C10G051/04 |
Claims
1. A thermal and catalytic process for converting a heavy petroleum
oil feed into lower boiling products, comprising: separating a
heavy hydrocarbon feed to form a light fraction boiling below about
345.degree. C. (650.degree. F.) and a heavy fraction boiling above
about 345.degree. C. (650.degree. F.); thermally cracking the heavy
fraction in a thermal conversion zone to produce a thermally
cracked product; combining the light fraction with the thermally
cracked heavy fraction; hydrotreating the combined light and heavy
fractions; separating the hydrotreated product in a fractionator
into a hydrotreated bottoms fraction and a hydrotreated light
fraction; catalytically cracking at least a portion of the
hydrotreated bottoms fraction; and fractionating the catalytically
cracked product to separate a naphtha fraction, a distillate
fraction and a bottoms fraction.
2. The process according to claim 1, wherein the heavy hydrocarbon
feed comprises a gas oil feed having a boiling point above
290.degree. C.
3. The process according to claim 2, wherein the gas oil feed
comprises a vacuum gas oil in which at least 75 wt % of the gas oil
feed boils in the range of 345.degree. to 565.degree. C. (ASTM D
2887).
4. The process according to claim 3, wherein the gas oil feed
comprises a vacuum gas oil in which at least 90 wt % of the gas oil
feed boils in the range of 345.degree. to 565.degree. C. (ASTM D
2887).
5. The process according to claim 2, wherein the gas oil feed
comprises up to 10 wt % of a resid boiling above 565.degree. C.
6. The process according to claim 4, wherein the gas oil feed
comprises up to 10 wt % of a resid boiling above 565.degree. C.
7. The process according to claim 1, wherein the C.sub.4- fraction
of the combined hydrotreated light and heavy fractions is by-passed
around the hydrotreating step.
8. The process according to claim 1, wherein the severity of the
thermal cracking step is from 25 to 450 equivalent seconds at
470.degree. C.
9. The process according to claim 4, wherein the severity of the
thermal cracking step is from 25 to 450 equivalent seconds at
470.degree. C.
10. The process according to claim 1, wherein the hydrotreating
step includes the following conditions: 6,000 to 10,000 kPag (about
870-1450 psig) hydrogen pressure, liquid hourly space velocity
(LHSV) of 0.2-0.8 hr.sup.-1 and a temperature of from 355 to
455.degree. C. (670 to 850.degree. F.).
11. The process according to claim 10, wherein the hydrotreating
step includes a hydrotreating catalyst containing at least one
Group 6 metal and at least one Group 8-10 metal on a metal oxide
support.
12. The process according to claim 11, wherein the metal oxide
support is selected from silica, alumina, silica-alumina, and
titania.
13. The process according to claim 1, wherein the catalytic
cracking step includes the following conditions: temperatures from
about 482 to about 740.degree. C. (900 to 1364.degree. F.);
hydrocarbon partial pressures from about 70 to 300 kPaa (about 15
to about 43 psia); a catalyst to feed (wt/wt) ratio from about 3 to
about 1, and a riser reactor residence time from 1 to 5
seconds.
14. The process according to claim 13, wherein the catalytic
cracking step includes a cracking catalyst containing an amorphous,
porous solid acid matrix selected from alumina, silica-alumina,
silica-magnesia, silica-zirconia, silica-thoria, silica-beryllia,
silica-titania, and silica-alumina-rare earth; and a zeolite.
15. The process according to claim 1, wherein the distillate
fraction has a Cetane Number of at least 45.
16. The process according to claim 5, wherein the gas oil feed has
a Conradson Carbon Residue (CCR) content greater than 1 wt %.
17. The process according to claim 6, wherein the gas oil feed has
a Conradson Carbon Residue (CCR) content greater than 1 wt %.
18. The process according to claim 1, wherein at least a portion of
the naphtha fraction is recycled back to the catalytic cracking
step.
19. The process according to claim 1, wherein at least a portion of
the bottoms fraction is recycled back to the catalytic cracking
step.
20. The process according to claim 18, wherein at least a portion
of the bottoms fraction is recycled back to the catalytic cracking
step.
Description
[0001] This application claims priority to U.S. Provisional
Application Ser. No. 61/677,045 filed Jul. 30, 2012, which is
herein incorporated by reference in its entirety.
FIELD OF THE INVENTION
[0002] The present invention relates to a process for the selective
conversion of a heavy hydrocarbon oil in a two-step process. The
first is thermal conversion and the second is catalytic cracking of
products from the thermal conversion. The present invention results
in a process for increasing the distillate production from the
heavy oil feed in the catalytic cracking unit. The product
distribution from the process can be varied by changing the
conditions in the thermal and catalytic cracking steps as well as
by changing the catalyst in the cracking step.
BACKGROUND
[0003] The upgrading of atmospheric and vacuum residual oils
(resids) to lighter, more valuable products has been accomplished
by thermal cracking processes such as visbreaking and coking. In
visbreaking, a vacuum resid or other heavy feed is sent to a
visbreaker where it is thermally cracked under relatively mild
conditions controlled to produce the desired products and minimize
coke formation. The products from the visbreaker have reduced
viscosity and pour points, and include naphtha, visbreaker gas oils
and visbreaker residues. The residues or bottoms from the
visbreaker are heavy oils such as heavy fuel oils. The conversion
in visbreakers is a function of the asphaltene and Conradson Carbon
Residue (or "CCR") content of the feed. Generally, lower levels of
asphaltene and CCR content in the hydrocarbon feed are favorable to
visbreaking. Higher values of asphaltene and CCR content lead to
increased coking and lower yields of light liquid products.
[0004] Petroleum coking operates under more severe conditions than
visbreaking. Residual feeds are converted to liquid hydrocarbon
products of lower boiling point (atmospheric) than that of the feed
while carbon is rejected in the form of relatively large amounts of
petroleum coke. Some coking processes, such as delayed coking, are
batch processes where the coke accumulates and is subsequently
removed from a large drum while in fluid coking, for example, the
Flexicoking.degree. process of ExxonMobil Research and Engineering
Co., the heavy oil feed is continuously subjected to thermal
cracking conditions in a fluidized bed. Lower boiling products are
formed by the thermal decomposition of the feed at elevated
reaction temperatures, typically from about 480 to 590.degree. C.
(about 895 to 1095.degree. F.), using heat supplied by combustion
of a portion of the fluidized coke particles in a heater vessel. In
the FLEXICOKING.degree. process, the excess coke is converted to
fuel gas in a gasifier by reaction with air and steam to produce a
clean fuel gas that can be used in boilers and furnaces.
Approximately 97% of the coke generated in the cracking reactor is
consumed in the process, with a small amount of product coke
recovered from the fines system.
[0005] The fluid catalytic cracking (FCC) process has become the
workhorse of the refinery for gasoline production while
hydrocracking, the other major catalytic cracking process remains
the source for road diesel, jet fuel and other distillates. Current
industry projects world-wide market growth for diesel relative to
gasoline. In response to this changing market demand, decreasing
naphtha yield while increasing both FCC distillate yield and
quality presents the potential for rebalancing the product slate to
match projections while retaining use of existing refinery
equipment. In order to be economically attractive, this must be
accomplished with no (or minimal) loss in bottoms conversion or
coke selectivity. Keeping the bottoms and coke yields at today's
levels ensures no increase in fuel oil production and ensures that
FCC regenerator air limits are not exceeded.
[0006] Currently, in many refineries, only a limited amount of
distillate material from the FCC (LCO) normally goes into the
diesel pool. FCC distillate has a very high aromatics content with
a low cetane index (<30 cetane index) as a result of the removal
of alkyl side chains besides having DBT (dibenzothiophene)
molecules in it that are difficult to hydrotreat. As a result FCC
distillate gets blended into fuel oil (downgraded). There is
accordingly a need in the industry for improved processes for
treating high boiling range hydrocarbon feeds such as vacuum gas
oils in order to increase the production of distillate boiling
range products from such feeds, especially of road diesel fuel if
the relevant product specifications can be met. To this end,
integrated thermal/catalytic treatment processes for heavy oil
feeds have been proposed, including those described in U.S.
2010/0018895 and U.S. 2010/0018896. The process described in U.S.
2010/0018895 includes two basic steps: the first is of thermal
conversion and the second is catalytic cracking of the higher
boiling products of the thermal conversion with an optional
hydrotreatment of the thermally cracked bottoms fraction to reduce
the proportion of heteroatoms sent to the FCCU. The variant of this
process described in U.S. 2010/0018896 uses a divided wall
fractionator to separate the bottoms fractions obtained from the
thermal and catalytic cracking steps.
[0007] During the thermal cracking step it is desirable but not
essential for the feed to be kept in the liquid phase during the
thermal treatment in order to control the residence time and hence,
the severity of the cracking and the conversion. With the
temperatures encountered during this step, relatively high
pressures are necessary, to be provided by robust feed pumps. These
may be provided by the feed system for existing visbreakers but if
other furnaces are used, for example, furnaces converted from FCC
preheat operation, upgraded equipment may be necessary. If the
bottoms hydrotreatment option described in U.S. 2010/0018895 is
utilized with a gas oil feed, high pressure pumps may be available
and incorporated into the integrated unit but depending on the
nature of the feed, additional problems may arise. If the gas oil
contains significant amounts of lighter ends, e.g. naphtha (boiling
below 200.degree. C.) and distillate (boiling below 350.degree.
C.), routing such feeds to either the thermal or catalytic cracking
steps may result in overcracking and reactor upsets as these units
are not typically designed for operations with such feeds. There is
therefore a need for developing a fully integrated
thermal/catalytic cracking process for use with heavy oil
feeds.
SUMMARY OF PREFERRED EMBODIMENTS OF THE INVENTION
[0008] We have now devised an integrated thermal/catalytic cracking
process which incorporates hydrotreatment of the thermally cracked
bottoms fraction before passing to the catalytic cracking step.
According to the present invention, the process comprises: [0009]
separating a heavy hydrocarbon, preferably a gas oil, feed to form
a light fraction boiling below about 345.degree. C. (650.degree.
F.) and a heavy fraction boiling above about 345.degree. C.
(650.degree. F.); [0010] thermally cracking the heavy fraction in a
thermal conversion zone to produce a thermally cracked product;
[0011] combining the light fraction with the thermally cracked
heavy fraction; [0012] hydrotreating the combined light and heavy
fractions; [0013] separating the hydrotreated product in a
fractionator into a hydrotreated bottoms fraction and a
hydrotreated light fraction; [0014] catalytically cracking at least
a portion of the hydrotreated bottoms fraction; and [0015]
fractionating the catalytically cracked product to separate a
naphtha fraction, a distillate fraction and a bottoms fraction.
[0016] Since the lightest portion (C.sub.4-) of the combined light
and heavy fractions from the thermal cracking step will not
normally require hydrotreatment, it may be by-passed around the
hydrotreatment step in order to increase the capacity of the
hydrotreater. This configuration with the hydrotreatment of the
thermally cracked heavy VGO (345.degree. C.+, 650.degree. F.+)
fraction increases the yield of high quality distillate (45+Cetane
Index) relative to the base case of sending the VGO fraction
directly to the FCCU, while at the same time reducing the amount of
naphtha. The quantity of distillate produced and reduction in the
quantity of naphtha will be refinery specific since they depend on
the sizes and capabilities of the available equipment.
[0017] The term "naphtha" or "naphtha fraction" is used here to
mean a hydrocarbon fraction in which at least 90 wt % of the
fraction boils in the range of about 15.degree. C. to about 210 C
(59.degree. F. to 430 F) as measured by ASTM D 86. The term
"distillate" or "distillate fraction" is used here to mean a
hydrocarbon fraction in which at least 90 wt % of the distillate
fraction boils in the range of about 200.degree. C. to about
345.degree. C. (392.degree. F. to 650.degree. F.) as measured by
ASTM D 86. In the C.sub.4- fraction, referred to here, at least 90
wt % of the fraction boils at temperatures below 0.degree. C.
(32.degree. F.) as measured by ASTM D 86.
FIGURES
[0018] The single FIGURE of the accompanying drawings illustrates a
simplified process schematic of an embodiment of the integrated
thermal cracking/hydrotreatment/catalytic cracking processes
herein.
DETAILED DESCRIPTION
Process Configuration
[0019] The FIGURE shows a very much simplified configuration for
one version of the process in which the light ends by-pass the
thermal cracking step with the lightest (C.sub.4-) fractions also
routed around the hydrotreater. The heavy feed is introduced though
through line 10 and enters separator 11 which splits out the
345.degree. C.- (650.degree. F.-) fraction and routes it though
line 12 around visbreaker furnace 13 and visbreaker (coil or drum)
14 to combine with the visbroken product in line 16. Depending upon
the severity regime in the furnace (temperature, retention time),
it may be possible to omit the coil or drum while still achieving a
sufficient degree of cracking. If the severity of the thermal
cracking step is relatively high, (nominally above 100 equivalent
seconds @875.degree. F./470.degree. C.), the combined fractions
pass to optional hot separator 20 in which the C.sub.4- light ends
are split out to pass through line 21 around the gas oil
hydrotreater 22 before being recombined with the hydrotreated
product fraction in line 23 which takes the combined fractions to
the hydrotreater fractionator 25 in which a separation between the
naphtha, middle distillate and bottoms (345.degree. C.+,
650.degree. F.+) fractions is made. The bottoms fraction from
fractionator 25 is sent to the FCCU 26 for cracking in the absence
of added hydrogen and in the presence of a fluid catalytic cracking
catalyst while the hydrotreated middle distillate is sent to the
recovery section as an additional contribution for potential use in
the refinery diesel pool.
[0020] From the FCCU 26, the catalytically cracked products pass by
way of line 27 to the FCC main column and product recovery section
where they and, optionally, the lower boiling fraction from the
hydrotreater fractionator, are separated into products including
naphtha, distillate and bottoms. The C.sub.4- fraction is taken off
the top of the fractionator and sent for further processing as
desired. Some, or all, of the naphtha product stream may be
optionally recycled back to the FCC reactor in the catalytic
cracking step and the bottoms from the fractionator may also be
recycled back to the FCC reactor in the catalytic cracking step for
further processing.
Heavy Oil Feed
[0021] The feedstock to the present conversion process is typically
a heavy oil feed having a Conradson Carbon Residue (CCR, ASTM
D4530) content of from 0 to 6 wt %, based on the total feed, and is
most preferably a vacuum gas oil (VGO). The vacuum gas oil (VGO)
will normally be a hydrocarbon fraction in which at least 90 wt %
boils in the range of about 290.degree. to about 565.degree. C.
(about 550.degree. to 1050.degree. F.) as measured by ASTM D 2887
(unless otherwise noted, all boiling point temperatures are
referenced at atmospheric pressure). It is preferred that the heavy
oil feed be suitable as a feed to the FCC unit. The bulk of this
fraction will boil above about 345.degree. C. (about 650.degree.
F.) with up to about 25 wt % of material boiling in the
290-345.degree. C. (550-650.degree. F.) may be present. The portion
boiling below about 345.degree. C. (650.degree. F.) is initially
removed in order to reduce cracking of the desired distillate to
naphtha in the thermal conversion step. While VGOs are typically
low in CCR content and low in metal content, feeds having >1 wt
% CCR may include a resid component, typically not more than 10 wt
% boiling above about 565.degree. C. (1050.degree. F.) with the
permissible amount depending upon the quality of the resid
component: if no significant quantities of heavy metals is present
and if the CCR is low, it may be possible to process higher resid
content feedstocks. The feedstock to the thermal conversion zone
may be heated to the necessary reaction temperature by an
independent furnace or by the feed furnace to the FCC unit
itself.
[0022] In preferred embodiments herein, the heavy oil feed
comprises a gas oil feed having a boiling point above 290.degree.
C. In other preferred embodiments, the gas oil feed comprises a
vacuum gas oil in which at least 75 wt % of the gas oil feed boils
in the range of 345.degree. to 565.degree. C. (ASTM D 2887). In yet
other preferred embodiments, the gas oil feed comprises a vacuum
gas oil in which at least 90 wt % of the gas oil feed boils in the
range of 345.degree. to 565.degree. C. (ASTM D 2887).
Thermal Conversion
[0023] The heavy oil feed is first thermally converted in a thermal
conversion zone. When the hydrocarbon feed contains a substantial
amount of VGO and little or no resid, the thermal conversion zone
can be operated at more severe conditions because VGO fractions
tend to be low in CCR and metals; this tends to limit the
production of excessive coke, gas make, toluene insolubles, or
reactor wall deposits as compared to a typical vacuum resid feed
that is thermally cracked.
[0024] The conditions used for the thermal cracking step may be
determined empirically and are generally expressed as a severity
which is dependent upon both the temperature and residence time of
the hydrocarbon feed in the thermal conversion zone. Severity has
been described as equivalent reaction time (ERT) in U.S. Pat. Nos.
4,892,644 and 4,933,067 to which reference is made herein for a
description of the ERT calculation. As described in U.S. Pat. No.
4,892,644, ERT is expressed as a time in seconds of residence time
at a fixed temperature of 427.degree. C., and is calculated using
first order kinetics. The ERT range in the U.S. Pat. No. 4,892,644
patent is from 250 to 1500 ERT seconds at 427.degree. C., more
preferably at 500 to 800 ERT seconds. As noted there, raising the
temperature causes the operation to become more severe: raising the
temperature from 427.degree. C. to 456.degree. C. leads to a
fivefold increase in severity.
[0025] In the present process, a similar methodology is used to
determine severities which are expressed in equivalent seconds at
470.degree. C. In the present process, severities are in the range
of 25-450 equivalent seconds at 470.degree. C. (875.degree. C.). At
a cracking severity of about 50 eq. seconds (470.degree.
F./875.degree. C.), an increase of 3 to 5 wt % in distillate
production relative to the base case (no hydrotreating) without
adverse effect on the operation of the VGO hydrotreater with a
distillate of 45-50 Cetane Number. Because the present feeds are
normally low in CCR, the present process can operate at severities
higher than those described for visbreaking of a vacuum resid.
These low CCR hydrocarbon feeds have a lower tendency to form wall
deposits and coke, and minimize the yield of poor quality naphthas
that are produced in the thermal conversion.
Thermal Conversion Products
[0026] The products from thermal conversion are conducted next to
the hydrotreating step to remove heteroatoms and improve
crackability in the FCCU. Optionally, the hot separator following
the visbreaker and ahead of the hydrotreater is used to route the
gas fraction (C.sub.4-) around the hydrotreater section since there
is no advantage as well as an increase in hydrotreater throughput
to be gained by doing so. The separation may be accomplished using
conventional separators such as a hot separator, a flash tower or a
distillation tower. In the separator, the thermally cracked
products can be separated into a bottoms fraction and a lower
boiling fraction comprised of a naphtha and/or a distillate,
depending on the conditions used in the thermal cracking step. This
fraction will have boiling points commensurate with these products
and can be sent to a fractionator for further separation into
desired products, for example, visbreaker naphtha etc. This lower
boiling fraction may also contain a thermally cracked C.sub.4-
fraction which may be separately isolated and sent to the
hydrotreater product fractionator with or without the naphtha
and/or distillate fraction.
[0027] The thermally cracked bottoms fraction contains higher
boiling material, e.g., fractions having a boiling point in excess
of about 345.degree. C. (650.degree. F.). The thermally cracked
bottoms fraction is sent to a FCC unit for catalytic cracking and
may be combined with other FCC feeds prior to the FCC unit.
[0028] A portion or all of the thermally cracked fraction is
hydrotreated in a gas oil hydrotreater prior to being sent to the
FCC unit. The gas oil hydrotreater is one adapted to operate with
feeds boiling in the 345-565.degree. C. (650-1050.degree. F.) range
without significant amounts of lower and higher boiling materials
although some higher boiling residual ends may be present if they
can be accommodated for treatment in the FCCU, as noted above. In
the present process, the feed to the VGO hydrotreater will also
contain the thermally cracked distillate fraction which undergoes a
limited degree of desulfurization in the hydrotreater; the limited
degree of desulfurization which does take place is not
disadvantageous since the thermally cracked distillate has a
relatively low content of dibenzothiophenes as compared to FCC
light cycle oil so that the extent of desulfurization required to
meet current road diesel specifications is itself limited. The
thermally cracked fraction, with or without the light (C.sub.4-)
ends, is contacted with hydrogen and a hydrotreating catalyst to
remove at least a portion of the sulfur and/or nitrogen
contaminants to produce a hydrotreated product fraction which may
be recombined with the by-passed light ends before being sent to
the hydrotreater fractionator. After hydrotreating, at least a
portion of the hydrotreated bottoms fraction is sent to an FCC unit
for further processing. In the present invention, the hydrotreated
naphtha and middle distillate fractions will not benefit from being
cracked in the FCC step and will, in any event, load up the unit,
they are preferably removed at this stage of the present processes
and sent to product recovery for use as blend components in the
refinery gasoline pool, heating oil, distillate, e.g. diesel, since
the aromatic and heteroatom content has been reduced in the
hydrotreater.
[0029] The hydrotreating step herein is preferably carried out at a
minimum temperature of about 280.degree. C., more usually from
300.degree. C. with maximum temperatures in this step of about
380.degree. or 400.degree. C. Pressures preferably range from a
minimum of about 1,500 or 3,000 kPag to a maximum of about 20,000
or, more usually, about 14,000 kPag. Space velocity in the
hydrotreating zone is preferably from about 0.1 to about 10 LHSV,
more commonly from about 0.1 to about 5 LHSV. Hydrogen treat gas
rates of from about 100 to about 2,000 m.sup.3/m.sup.3 (562 to
11,200 scf/B), more preferably 200 to 1000 m.sup.3/m.sup.3 (1125 to
5620 scf/B) may be utilized in the hydrotreating zone. Optimally,
it is recommended that the feed to the hydrotreater should not
contain material that boils higher than about 650.degree. C. (about
1200.degree. F.) with the Simdist 99 wt % (ASTM D7096-10) point not
greater than that same value. Higher boiling feeds will increase
the costs associated with implementing this technology. In
preferred embodiments herein, the recommended operating conditions
for the hydrotreater should be 6,000 to 10,000 kPag (about 870-1450
psig) hydrogen pressure, Liquid Hourly Space velocity of 0.2-0.8
hr-1 and temperature range of 355 to 455.degree. C. (670 to
850.degree. F.).
[0030] Hydrotreating catalysts suitable for use herein are those
containing at least one Group 6 (based on the IUPAC Periodic Table
having Groups 1-18) metal and at least one Groups 8-10 metal,
including mixtures thereof. Preferred metals include Ni, W, Mo, Co
and mixtures thereof. These metals or mixtures of metals are
typically present as oxides or sulfides on refractory metal oxide
supports. The mixture of metals may also be present as bulk metal
catalysts wherein the amount of metal is 30 wt % or greater, based
on the catalyst. Suitable metal oxide supports include oxides such
as silica, alumina, silica-alumina or titania, preferably alumina.
Preferred aluminas are porous aluminas such as gamma or eta. The
acidity of metal oxide supports can be controlled by adding
promoters and/or dopants, or by controlling the nature of the metal
oxide support, e.g., by controlling the amount of silica
incorporated into a silica-alumina support. The amount of metals
for supported hydrotreating catalysts, either individually or in
mixtures, ranges from 0.5 to 35 wt %, based on the catalyst. In the
case of preferred mixtures of Group 6 and Groups 8-10 metals, the
Group 8-10 metals are present in amounts of from 0.5 to 5 wt %,
based on the catalyst and the Group 6 metals are present in amounts
of from 5 to 30 wt % based on the catalyst. Non-limiting examples
of suitable commercially available hydrotreating catalysts include
RT-721, KF-840, KF-848, and Sentinel.TM.. Preferred catalysts are
low acidity, high metals content catalysts including KF-848 and
RT-721.
FCC Process
[0031] The conventional FCC process includes a riser reactor and a
regenerator wherein petroleum feed is injected into the reaction
zone in the riser containing a bed of fluidized cracking catalyst
particles which typically contain zeolites. Gases that may be inert
gases, hydrocarbon vapors, steam or some combination thereof are
normally employed as lift gases to assist in fluidizing the hot
catalyst particles.
[0032] Catalyst particles that have contacted feed produce product
vapors and catalyst particles containing strippable hydrocarbons as
well as coke. The catalyst exits the reaction zone as spent
catalyst particles and is separated from the reactor's effluent in
a separation zone. The separation zone for separating spent
catalyst particles from reactor effluent may employ separation
devices such as cyclones. Spent catalyst particles are stripped of
hydrocarbons using a stripping agent such as steam. The stripped
catalyst particles are then sent to a regeneration zone in which
any remaining hydrocarbons are stripped and coke is removed. In the
regeneration zone, coked catalyst particles are contacted with an
oxidizing medium, usually air, and coke is oxidized (burned) at
temperatures preferably in the range of about 650 to 760.degree. C.
(1202 to 1400.degree. F.). The regenerated catalyst particles are
then passed back to the riser reactor.
[0033] FCC catalysts may be amorphous, e.g., silica-alumina,
crystalline, e.g., molecular sieves including zeolites, or mixtures
thereof. A preferred catalyst particle comprises (a) an amorphous,
porous solid acid matrix, such as alumina, silica-alumina,
silica-magnesia, silica-zirconia, silica-thoria, silica-beryllia,
silica-titania, silica-alumina-rare earth and the like; and (b) a
zeolite such as a faujasite. The matrix can comprise ternary
compositions, such as silica-alumina-thoria,
silica-alumina-zirconia, magnesia and silica-magnesia-zirconia. The
matrix may also be in the form of a cogel. Silica-alumina is
particularly preferred for the matrix, and can contain about 10 to
40 wt % alumina. As discussed, promoters can be added. The catalyst
zeolite component includes zeolites which are iso-structural to
zeolite Y. These include the ion-exchanged forms such as the
rare-earth hydrogen and ultrastable (USY) form. The zeolite may
range in crystallite size from about 0.1 to 10 microns, preferably
from about 0.3 to 3 microns. The amount of zeolite component in the
catalyst particle will generally range from about 1 to about 60 wt
%, preferably from about 5 to about 60 wt %, and more preferably
from about 10 to about 50 wt %, based on the total weight of the
catalyst. The catalyst particle size will typically range from
about 10 to 300 microns in diameter, with an average particle
diameter of about 60 microns. The surface area of the matrix
material after artificial deactivation in steam will typically be
.ltoreq.350 m.sup.2/g, more typically about 50 to 200 m.sup.2/g,
and most typically from about 50 to 100 m.sup.2/g. While the
surface area of the catalysts will be dependent on such things as
type and amount of zeolite and matrix components used, it will
usually be less than about 500 m.sup.2/g, more typically from about
50 to 300 m.sup.2/g, and most typically from about 100 to 250
m.sup.2/g.
[0034] The cracking catalyst may also include an additive catalyst
in the form of a medium pore zeolite having a Constraint Index
(defined in U.S. Pat. No. 4,016,218) of about 1 to about 12.
Suitable medium pore zeolites include ZSM-5, ZSM-11, ZSM-12,
ZSM-22, ZSM-23, ZSM-35, ZSM-48, ZSM-57, SH-3 and MCM-22, either
alone or in combination. Preferably, the medium pore zeolite is
ZSM-5.
[0035] In the process embodiments herein, FCC process conditions in
the reaction zone include temperatures from about 482 to about
740.degree. C. (900 to 1364.degree. F.); hydrocarbon partial
pressures from about 70 to 300 kPaa (about 15 to about 43 psia,
preferably from about 150 to 250 kPaa (22 to about 36 psia); and a
catalyst to feed (wt/wt) ratio from about 3 to about 10, where the
catalyst weight is total weight of the catalyst composite. The
total pressure in the reaction zone is preferably from about
atmospheric to about 450 kPa (50 psi). Though not required, it is
preferred that steam be concurrently introduced with the feedstock
into the reaction zone, with the steam comprising up to about 50 wt
%, preferably from about 0.5 to about 5 wt % of the primary feed.
Also, it is preferred that vapor residence time in the reaction
zone be less than about 20 seconds, preferably from about 0.1 to
about 20 seconds, and more preferably from about 1 to about 5
seconds. Preferred conditions are short contact time conditions
which include riser outlet temperatures from 482-621.degree. C.
(900-1150.degree. F.), total pressures from about 100 to 450 kPa (0
to about 50 psi) and riser reactor residence times from 1 to 5
seconds.
[0036] Different feeds may require different cracking conditions.
In the present process, if it is desired to make the maximum amount
of distillate from the hydrocarbon feed, then the thermal cracker
will be run at maximum temperature consistent with avoiding excess
coke or coke precursor make.
[0037] Additionally or alternatively, the present invention can be
described according to one or more of the following
embodiments.
Embodiment 1
[0038] A thermal and catalytic process for converting a heavy
petroleum oil feed into lower boiling products, comprising: [0039]
separating a heavy hydrocarbon feed to form a light fraction
boiling below about 345.degree. C. (650.degree. F.) and a heavy
fraction boiling above about 345.degree. C. (650.degree. F.);
[0040] thermally cracking the heavy fraction in a thermal
conversion zone to produce a thermally cracked product; [0041]
combining the light fraction with the thermally cracked heavy
fraction; [0042] hydrotreating the combined light and heavy
fractions; [0043] separating the hydrotreated product in a
fractionator into a hydrotreated bottoms fraction and a
hydrotreated light fraction; [0044] catalytically cracking at least
a portion of the hydrotreated bottoms fraction; and [0045]
fractionating the catalytically cracked product to separate a
naphtha fraction, a distillate fraction and a bottoms fraction.
Embodiment 2
[0046] The process according to embodiment 1, wherein the heavy
hydrocarbon feed comprises a gas oil feed having a boiling point
above 290.degree. C.
Embodiment 3
[0047] The process according to embodiment 2, wherein the gas oil
feed has a Conradson Carbon Residue (CCR) content greater than 1 wt
%.
Embodiment 4
[0048] The process according to any of embodiments 2-3, wherein the
gas oil feed comprises a vacuum gas oil in which at least 75 wt %
of the gas oil feed boils in the range of 345.degree. to
565.degree. C. (ASTM D 2887).
Embodiment 5
[0049] The process according to any of embodiments 2-4, wherein the
gas oil feed comprises a vacuum gas oil in which at least 90 wt %
of the gas oil feed boils in the range of 345.degree. to
565.degree. C. (ASTM D 2887).
Embodiment 6
[0050] The process according to any of embodiments 2-5, wherein the
gas oil feed comprises up to 10 wt % of a resid boiling above
565.degree. C.
Embodiment 7
[0051] The process according to any prior embodiment, the C.sub.4-
fraction of the combined hydrotreated light and heavy fractions is
by-passed around the hydrotreating step.
Embodiment 8
[0052] The process according to any prior embodiment, wherein the
severity of the thermal cracking step is from 25 to 450 equivalent
seconds at 470.degree. C.
Embodiment 9
[0053] The process according to any prior embodiment, wherein the
hydrotreating step includes the following conditions: 6,000 to
10,000 kPag (about 870-1450 psig) hydrogen pressure, liquid hourly
space velocity (LHSV) of 0.2-0.8 hr.sup.-1 and a temperature of
from 355 to 455.degree. C. (670 to 850.degree. F.).
Embodiment 10
[0054] The process according to any prior embodiment, wherein the
hydrotreating step includes a hydrotreating catalyst containing at
least one Group 6 metal and at least one Group 8-10 metal on a
metal oxide support.
Embodiment 11
[0055] The process according to embodiment 10, wherein the metal
oxide support is selected from silica, alumina, silica-alumina, and
titania.
Embodiment 12
[0056] The process according to any prior embodiment, wherein the
catalytic cracking step includes the following conditions:
temperatures from about 482 to about 740.degree. C. (900 to
1364.degree. F.); hydrocarbon partial pressures from about 70 to
300 kPaa (about 15 to about 43 psia); a catalyst to feed (wt/wt)
ratio from about 3 to about 1, and a riser reactor residence time
from 1 to 5 seconds.
Embodiment 13
[0057] The process according to any prior embodiment, wherein the
catalytic cracking step includes a cracking catalyst containing an
amorphous, porous solid acid matrix selected from alumina,
silica-alumina, silica-magnesia, silica-zirconia, silica-thoria,
silica-beryllia, silica-titania, and silica-alumina-rare earth; and
a zeolite.
Embodiment 14
[0058] The process according to any prior embodiment, wherein the
distillate fraction has a Cetane Number of at least 45.
Embodiment 15
[0059] The process according to any prior embodiment, wherein at
least a portion of the naphtha fraction is recycled back to the
catalytic cracking step.
Embodiment 16
[0060] The process according to any prior embodiment, wherein at
least a portion of the bottoms fraction is recycled back to the
catalytic cracking step.
* * * * *