Title of Invention

A PROCESS FOR UPGRADING CRUDE OIL FROM A SUBTERRANEAN RESERVOIR OF HEAVY OIL OR BITUMEN

Abstract A process for the upgrading and demetallizing of heavy oils and bitumens is disclosed. A crude heavy oil and/or bitumen feed is supplied to a solvent extraction process (104) wherein DAO and asphaltenes are separated. The DAO is supplied to an FCC unit (106) having a low conversion activity catalyst for the removal of metals contained therein. The demetallized distillate fraction is supplied to a hydrotreater (110) for upgrading and collected as a synthetic crude product stream. The asphaltene fraction can be supplied to a gasifier (108) for the recovery of power, steam and hydrogen, which can be supplied to the hydrotreater (110) or otherwise within the process or exported. An optional coker (234) can be used to convert excess asphaltenes and/or decant oil to naphtha, distillate and gas oil, which can be supplied to the hydrotreater (220).
Full Text BACKGROUND OF THE INVENTION
The present invention generally relates to the upgrading of heavy oils and
bitumens. More particularly, the present invention relates to a process for the
upgrading of heavy oils and bitumens including one or more of the steps of
production, fractionation, solvent extraction, fluid catalytic cracking and
hydrotreating to produce synthetic crude and/or naphtha, distillate and gas oil
streams having reduced metal and/or sulfur content.
As world reserves of light, sweet crudes diminish and worldwide consumption of
oil increases, refiners seek methods for extracting useful oils from heavier crude
resources. The heavier crudes, which can include bitumens, heavy oils and tar
sands, pose processing problems due to significantly higher concentration of
metals, most notably nickel and vanadium. In addition, the heavier crudes
typically have higher sulfur and asphaltene content, posing additional problems in
the upgrading of crudes. Finally, tar sands, bitumens and heavy oils are
extremely viscous, resulting in problems in transporting the raw materials by
traditional means. Heavy oils and bitumens often must be maintained at
elevated temperatures to remain flowable, and/or mixed with a lighter
hydrocarbon diluent for pipeline transportation. The diluent can be expensive
and additional cost can be incurred in transporting it to the location where
production is occurring.
As the prices of light oil and natural gas continue to increase, the price of heavy
oils and bitumens remains relatively low due to the difficulty in the recovery and
upgrading to useable oils. The recovery of bitumens and other heavy crudes is
expensive due to substantial energy requirements in the production.
Extensive reserves in the form of "heavy crudes" exist in a number of countries,
including Western Canada, Venezuela, Russia, the United States, and
elsewhere. These deposits of heavy crudes often exist in areas that are
inaccessible by normal means. Generally, the term "heavy crude" refers to a
hydrocarbon material having an API gravity of less than 20. Typical heavy crude
oils are not fluid at ambient temperatures, and contain a high fraction of materials
boiling above 343°C (650°F) and a significant portion with a boiling point greater
than 566°C (1050°F). The high proportion of high boiling point hydrocarbons
materials typical in heavy oils make fractionation difficult without resorting to
vacuum fractionation.
High metals content in the hydrocarbon feed presents similar processing
difficulties. Metals and asphaltenes in the heavy hydrocarbon materials are
undesirable in the separated oil fractions as the metals tend to poison catalysts
conventionally used in upgrading the oil fractions to other useful products.
Asphaltenes will tend to foul/plug downstream equipment. Because of such
difficulties during processing by conventional methods, the highest boiling
portions are often thermally upgraded by coking or visbreaking processes. The
heaviest fractions of heavy oil and bitumen containing the bulk of the metal and
asphaltene can be separated by fractionation to recover lighter oils, which can be
upgraded catalytically. However, the heavier fraction is still left with some usable
oils that can not be extracted using fractionation techniques.
Metals present in heavy oils can include, for example, vanadium and nickel.
Vanadium is typically present in excess of 100 wt ppm, often greater than 200 wt
ppm. Nickel is typically present in excess of 50 wt ppm, with 75 wt ppm and
greater also common.
Solvent extraction of the residuum oil has been known since the 1930's, as
previously described in U.S. Pat. No. 2,940,920, to Garwin. With the introduction
of the commercially available ROSE® process technology, solvent deasphalting
processes have become more efficient and cost effective. Solvent deasphalting
technology is commonly used today as one method of bottom-of-the-barrel
upgrading in a deep conversion refinery and can also be used to produce fluid
catalytic cracker (FCC) feeds, lube bright stocks, deasphalted gas oil feeds for
hydrotreating and hydrocracking units, specialty resins, and heavy fuel and
asphalt blending components from heavy oil feedstocks. Improved techniques in
solvent extraction have been disclosed in U.S. Pat. No. 5,843,303 to Ganeshan.
Prior studies have focused on methods of increasing the transportability of heavy
crudes by decreasing their viscosities. U.S. Pat. No. 5,192,421 to Audeh et al.,
discloses an improved method of demetallization during the deasphalting
process, including the steps of deasphalting heavy asphalt-rich crudes, followed
by thermal treatment, to produce deasphalted crude having a reduced metal
content.
In U.S. Pat. No. 4,875,998, Rendall discloses the extraction of bitumen oils from
tar-sands with hot water. Specifically, bitumen oils are conditioned in hot water
and then extracted with a water immiscible hydrocarbon solvent to form a mixture
which settles into several phases. Each phase can be processed to produce
product bitumen oils and recycled process components. Other water or solvent
extraction processes are disclosed in U.S. Pat. Nos. 4,160,718 to Rendall;
4,347,118 to Funk, et al.; 3,925,189 to Wicks, III; and 4,424,112 to Rendall. All
patents and publications referenced to herein are hereby incorporated by
reference in their entireties.
SUMMARY OF THE INVENTION
The present invention provides a method for the conversion of heavy crude feed,
such as for example, bitumens, to useable lighter compounds having essentially
no asphaltene and very low metal content.
In one embodiment, a process for upgrading crude oil from a subterranean
reservoir of heavy oil or bitumen is provided. The process can include solvent
deasphalting at least a portion of the heavy oil or bitumen to form an asphaltene
fraction and a deasphalted oil (DAO) fraction essentially free of asphaltenes
having a reduced metals content. A feed comprising the DAO fraction can be fed
to a reaction zone of a fluid catalytic cracking (FCC) unit with FCC catalyst to
deposit a portion of the metals from the DAO fraction onto the FCC catalyst. A
hydrocarbon effluent having a reduced metal content can be recovered from the
FCC unit.
The process can also include converting asphaltenes to steam, power, fuel gas,
or a combination thereof for use in producing heavy oil or bitumen from a
reservoir. The process can also include supplying the asphaltene fraction from
the solvent deasphalting to the asphaltenes conversion. The process can also
include removing metallized FCC catalyst from the FCC unit.
In one embodiment, a process for upgrading crude oil from a subterranean
reservoir of heavy oil or bitumen is provided. The process can include converting
asphaltenes to steam, power, fuel gas, or a combination thereof for use in
producing heavy oil or bitumen from a reservoir. Means can be provided for
solvent deasphalting at least a fraction of the produced heavy oil or bitumen
containing high metals to form an asphaltene fraction and a deasphalted oil
(DAO) fraction essentially free of asphaltenes and having a reduced metals
content. The asphaltene fraction from the solvent deasphalting can be supplied
to the asphaltenes conversion. A feed comprising the DAO fraction can be fed to
a reaction zone of a fluid catalytic cracking (FCC) unit with FCC catalyst to
deposit metals from the deasphalted oil fraction onto FCC catalyst. A
demetallized hydrocarbon effluent can be recovered from the FCC unit; and
metallized FCC catalyst can be removed from the FCC unit.
The heavy oil or bitumen production can include extraction from mined tar sands.
The asphaltenes conversion can include gasification of a portion of the
asphaltenes fraction to provide power, steam, fuel gas or combinations thereof
for mining and extraction. The heavy oil or bitumen production can include
injecting a mobilizing fluid through one or more injection wells completed in
communication with the reservoir to mobilize the heavy oil or bitumen and
producing the mobilized heavy oil or bitumen from at least one production well in
communication with the reservoir. The mobilizing fluid can comprise steam
generated primarily by combustion of asphaltenes recovered in the asphaltenes
fraction from the solvent deasphalting.
The solvent deasphalting can have a high lift for maximizing the production of
deasphalted oils. The process can include feeding a portion of the asphaltenes
fraction to a delayed coker unit to produce coker liquids and coke. Lower boiling
hydrocarbon fractions can be introduced to the FCC unit with the DAO fraction.
The FCC unit can be operated at a conversion from 30 to 65 percent by volume
of the feed to the FCC unit. The operating conditions in the FCC unit can be
adjusted to control proportions of naphtha, distillate and gas oil in the
hydrocarbon effluent from the FCC unit. The process can include hydrotreating
the hydrocarbon effluent from the FCC unit to produce a low sulfur hydrocarbon
effluent. The hydrotreating can be done at a moderate pressure of from 3.5 to
10.5 MPa (500 to 1500 psi). The process can further include gasifying
asphaltenes recovered in the asphaltenes fraction from the solvent deasphalting
•to produce hydrogen for the hydrotreating.
In another embodiment, a process for upgrading crude oil from a subterranean
reservoir of heavy oil or bitumen is provided. The process can include converting
asphaltenes to steam, power, fuel gas, or a combination thereof for use in
producing heavy oil or bitumen from a reservoir. The process also can include
solvent deasphalting at least a fraction of the produced heavy oil or bitumen
containing high metals to form an asphaltene fraction and a deasphalted oil
(DAO) fraction essentially free of asphaltenes having a reduced metals content.
The asphaltene fraction can be supplied from the solvent deasphalting to the
asphaltenes conversion. Steam can be generated by combustion of asphaltenes
recovered in the asphaltenes fraction from the solvent deasphalting. A feed
comprising the DAO fraction, along with other lower boiling hydrocarbon
fractions, can be supplied to a reaction zone of a fluid catalytic cracking (FCC)
unit with FCC catalyst to recover a demetallized hydrocarbon effluent from the
FCC unit at a conversion from 30 to 65 percent by volume of the feed to the FCC
unit. The hydrocarbon effluent from the FCC unit can be hydrotreated to produce
a low sulfur hydrocarbon effluent.
The heavy oil or bitumen production can include injecting steam through one or
more injection wells completed in communication with the reservoir to mobilize
the heavy oil or bitumen, and producing the mobilized heavy oil or bitumen from
at least one production well completed in communication with the reservoir. The
heavy oil or bitumen production can include extraction from mined tar sands.
The process can further include feeding a portion of the asphaltenes fraction to a
delayed coker unit to produce coker liquids and coke. The process can include
feeding the coker liquids to the hydrotreating with the FCC hydrocarbon effluent.
The process can also include supplying decant oil from the FCC unit to
combustion, gasification or a combination thereof. The operating conditions in
the FCC unit can be adjusted to control proportions of naphtha, distillate and gas
oil in the hydrocarbon effluent from the FCC unit. The hydrotreating can be
effected at a moderate pressure of from 3.5 to 10.5 MPa (500 to 1500 psi). The
process can include gasifying asphaltenes recovered in the asphaltenes fraction
from the solvent deasphalting to produce hydrogen for the hydrotreating.
In another embodiment, the application provides an apparatus for upgrading
crude oil from a subterranean reservoir of heavy oil or bitumen. The apparatus
can include means for converting asphaltenes to steam, power, fuel gas, or a
combination thereof for use in producing heavy oil or bitumen from a reservoir.
Means can be provided for solvent deasphalting at least a portion of the
produced heavy oil or bitumen containing high metals to form an asphaltene
fraction and a deasphalted oil (DAO) fraction essentially free of asphaltenes
having a reduced metals content. Means can be provided for supplying the
asphaltenes fraction from the solvent deasphalting to the asphaltenes
conversion. Means can be provided for supplying a feed comprising the DAO
fraction to a reaction zone of a fluid catalytic cracking (FCC) unit with FCC
catalyst to deposit metals from the deasphalted oil fraction onto FCC catalyst.
The apparatus can further include means for recovering a demetallized
hydrocarbon effluent from the FCC unit; and means for removing metallized FCC
catalyst from the FCC unit.
The apparatus can include means for injecting a mobilizing fluid through one or
more injection wells completed in communication with the reservoir to mobilize
the heavy oil or bitumen, and means for producing the mobilized heavy oil or
bitumen from at least one production well in communication with the reservoir.
The apparatus can include means for generating the mobilizing fluid comprising
steam primarily by combustion of asphaltenes recovered in the asphaltenes
fraction from the solvent deasphalting means. The apparatus can include means
for extracting heavy oil or bitumen from mined tar sands. The solvent
deasphalting means can provide a high lift. The apparatus can further include
means for feeding a portion of the asphaltenes fraction to a delayed coker unit to
produce coker liquids and coke. The apparatus can further include means for
operating the FCC unit at a conversion from 30 to 65 percent by volume of the
feed to the FCC unit. The apparatus can include means for adjusting operating
conditions in the FCC unit to control proportions of naphtha, distillate and gas oil
in the hydrocarbon effluent from the FCC unit. The apparatus can include means
for hydrotreating the hydrocarbon effluent from the FCC unit to produce a low
sulfur hydrocarbon effluent. The apparatus can include means for effecting the
hydrotreating at a moderate pressure of from 3.5 to 10 MPa (500 to 1500 psi).
The apparatus can also include means for gasifying asphaltenes recovered in the
asphaltenes fraction from the solvent deasphalting to produce hydrogen for the
hydrotreating.
In another embodiment, an apparatus for producing and upgrading crude oil from
a subterranean reservoir of heavy oil or bitumen is provided. The apparatus can
include means for injecting steam through one or more injection wells completed
in communication with the reservoir to mobilize the heavy oil or bitumen, means
for producing the mobilized heavy oil or bitumen from at least one production well
completed in communication with the reservoir, means for solvent deasphalting
at least a fraction of the produced heavy oil or bitumen containing high metals to
form a resin-lean asphaltene fraction and a deasphalted oil (DAO) fraction
essentially free of asphaltenes having a reduced metals content, means for
generating steam for the injection means by combustion of asphaltenes
recovered in the asphaltenes fraction from the solvent deasphalting means,
means for supplying a feed comprising the DAO fraction and other lower boiling
hydrocarbon fractions to a reaction zone of a fluid catalytic cracking (FCC) unit
with FCC catalyst to recover a demetallized hydrocarbon effluent from the FCC
unit at a conversion rate from 30 to 65 percent by volume of the DAO containing
feed to the FCC unit, and means for hydrotreating the hydrocarbon effluent from
the FCC unit to produce a low sulfur hydrocarbon effluent.
The apparatus can include means for feeding a portion of the asphaltenes
fraction to a delayed coker unit to produce coker liquids and coke. The
apparatus can include means for feeding the coker liquids to the hydrotreating
means with the FCC hydrocarbon effluent. The apparatus can include means for
supplying decant oil from the FCC unit to combustion, gasification or a
combination thereof. The apparatus can include means for adjusting operating
conditions in the FCC unit to control proportions of naphtha, distillate and gas oil
in the hydrocarbon effluent from the FCC unit. The apparatus can include means
for effecting the hydrotreating at a moderate pressure of from 3.5 to 10 MPa (500
to 1500 psi). The apparatus can include means for gasifying asphaltenes
recovered in the asphaltenes fraction from the solvent deasphalting means to
produce hydrogen for the hydrotreating means.
BRIEF DESCRIPTION OF THE ACCOMPANYING DRAWINGS
For a more detailed description of the illustrated embodiments of the present
invention, reference will now be made to the accompanying drawings, wherein:
Fig. 1 shows a process according to one embodiment of the invention for the
treatment of heavy oils and/or bitumens requiring no import of power, steam or
hydrogen.
Fig. 2 shows a process according to one embodiment of the invention for the
partial upgrading of heavy oil or bitumen feedstock.
Fig. 3 shows the process of Fig. 2 wherein an FCC unit has been added.
Fig. 4 shows the process of Fig. 2 including a gasifier and a hydrotreating unit.
Fig. 5 shows the process of Fig. 4 with an added coker unit.
DETAILED DESCRIPTION OF THE INVENTION
Detailed embodiments of the present invention are disclosed herein. However, it
is understood that the disclosed embodiments are merely exemplary of the
invention, which can be embodied in various forms. Specific structural, functional
and process details disclosed herein are not intended to be limiting, but are
merely illustrations that can be modified within the scope of the attached claims.
The present invention can convert heavy oils and/or bitumen having a high metal
content to lower boiling hydrocarbons having a substantially reduced metal
content. The present invention can also provide for the simultaneous production
of asphaltenes for use as fuel in the generation of steam and energy necessary
for the production of the heavy oil or bitumen. A first portion of the metals is
removed during solvent extraction of the heavy oil or bitumen feed, with
substantially all remaining metals being removed during subsequent treatment in
an FCC unit. The present invention provides a substantial economic advantage
by eliminating the need to transport natural gas or other fuel to the location of the
reservoir for steam and or power generation. The heavy oil can be upgraded by
front-end removal of the asphaltene fraction, which can frequently contain a
substantial portion of undesirable sulfur, nitrogen and metal compounds. The
deasphalted oil is liquid at ambient condition and can be transported using
traditional methods.
As shown in Fig. 1, a crude feed 100, which can include heavy oils and/or
bitumens, is supplied to a residuum oil solvent extraction (ROSE) unit 104. The
feed may optionally include a hydrocarbon solvent to assist in reducing the
viscosity of the feed. The ROSE unit 104 separates the feed into at least two
fractions: a first fraction which can include deasphalted oils and resins, and a
second fraction which can include asphaltenes. A portion of the metals present
in the initial feed are separated from the distillate feed and preferentially remain
with the separated asphaltenes. The deasphalted oils and resins are supplied to
a fluid catalytic cracking (FCC) unit 106, which can include a low activity catalyst,
to upgrade the oils and effectively remove remaining metals.
The asphaltenes from the ROSE unit 104 can be converted to pelletized form
using known equipment or can alternatively be supplied to a gasifier 108, which
burns and/or partially oxidizes the asphaltenes to produce steam, hydrogen and
low energy gas, as needed. The effluent from FCC unit 106 can be supplied to a
hydrotreater unit 110 where it can be upgraded, desulfurized and separated to
produce naphtha, distillate and gas oil streams. The decant oil from the FCC 106
can be supplied to the gasifier 108. The steam, hydrogen and low energy fuel
gas produced by the gasifier 108 can be supplied to associated processes as
needed. The product streams from the hydrotreater 110 can be combined to
form a synthetic crude if desired.
Heavy oils and bitumens can be recovered through thermal processes in which
heat is generated above ground or in situ. The simplest thermal process is
steam injection, wherein steam is used as a driving fluid to displace oil. Steam
Assisted Gravity Drainage (SAGD) is a technique wherein steam is injected
directly into a formation for enhanced recovery of oils. Steam is injected through
one or more wells into the top of a formation and water and hydrocarbons can be
recovered from one or more wells positioned at the bottom of the formation.
SAGD processes generally have a high recovery rate and a high oil rate at
economic oil-to-steam ratios. Production using SAGD processes can be
improved, if desired, by using techniques well known in the art, such as for
example, injecting steam into the wells at a higher rate than others, applying
electrical heating to the reservoir, and employing solvent C02 as an additive to
the injection steam. SAGD techniques are disclosed in U.S. Pat. No. 6,357,526
to Abdel-Halim, et al.
Heavy crudes can also be recovered by a variety of traditional mining techniques,
including employing shovels, trucks, conveyors and the like, to recover
substantially solid bitumens and tar sands. The shovels can be electrically or
hydraulically powered. Tar sand deposits can be excavated using traditional
techniques for the recovery of heavy oils contained therein. The excavated sand
deposits can optionally be pre-conditioned to facilitate the extraction and
separation of bitumen oils. The tar-sands can be crushed to a smaller size using
conventional crushers, and can be further broken down using mechanical
crushing and/or agitation. The crushed tar-sands can be readily slurried with hot
water for transportation and supplied to a bitumen extraction and separation
means. Conditioning of tar-sands is further disclosed in U.S. Pat. No. 4,875,998
to Rendall.
The conditioned heavy oil or bitumen, mixed with steam and/or water can be
passed through a water-oil separator to separate the fluids and produce a heavy
oil or bitumen stream essentially free of water and solids. The heavy oil or
bitumen can be separated in a continuous fractionation process, normally taking
place at atmospheric pressure and a controlled bottom temperature of less than
400^ (750°F). Temperature of the fractionation tower bottoms can be controlled
to prevent thermal cracking of the crude feed. If desired, vacuum fractionation
can be used.
The heavy oil or bitumen, or the resid from atmospheric and/or vacuum
distillation, can be supplied to a solvent deasphalting unit, which can be a
conventional unit, employing equipment and methodologies for solvent
deasphalting which are widely available in the art, for example, under the trade
designations ROSE, SOLVAHL, or the like. Desirably, a ROSE unit is employed.
The solvent deasphalting unit can separate the heavy oil or bitumen into an
asphaltene-rich fraction and a deasphalted oil (DAO) fraction. As is well known,
the deasphalting unit can be operated and conditions varied to adjust the
properties and contents of the DAO and asphaltenes fractions. Desirably, the
deasphalting unit can be controlled to ensure high lift in which a majority of the
resins present in the feed are separated as deasphalted oils rather than
asphaltenes. The asphaltene phase can be essentially free of resins. The
asphaltene phase can be heated and steam stripped to form an asphaltene
product stream. The solvent-DAO phase can be heated to separate the
components into solvent and DAO phases. The DAO phase can be recovered,
heated and steam stripped to form a DAO product stream for further treatment.
The ROSE process can be readily modified for use herein by the skilled artisan,
although where no fractionation is employed, such modifications should of course
be made to accommodate the entire crude feed, and not just the resid fraction of
the feed. Deasphalting can also be accomplished by dissolving the crude
feedstock in an aromatic solvent, followed by the addition of an excess of an
aliphatic solvent to precipitate the asphaltenes. Subcritical extraction, where
hydrocarbon solvents can be mixed with alcohols, can be used. Most
deasphalting processes employ light aliphatic hydrocarbons, such as for
example, propane, butane, and pentane, to precipitate the asphalt components
from the feed.
The DAO fraction can be supplied to an FCC unit containing a conventional
cracking catalyst. The FCC unit can include a stripper section and a riser
reactor. Fresh catalysts can be added to the FCC unit, typically via the
regenerator. Spent catalyst, including coke and metals deposited thereon, can
be regenerated by complete or partial combustion in a regenerator to supply
regenerated catalyst for use in the reactor. The flue gases can be withdrawn
from the top of a regeneration reactor through a flue gas line. A decant oil
stream containing heavy oils and catalyst fines can be withdrawn from the FCC
unit and supplied as a fuel oil and/or to a gasifier and/or coker. Exemplary FCC
processes are disclosed in U.S. Patents 4,814,067 to Gartside, et al.; 4,404,095
to Haddad, et al.; 3,785,782 to Cartmell; 4,419,221 to Castagnos, Jr.; 4,828,679
to Cormier, Jr., et al.; 3,647,682 to Rabo, et al.; 3,758,403 to Rosinski, et al.; and
RE 33,728 to Dean, et al.
The catalyst inventory employed in the FCC unit of the present invention
desirably provides equilibrium catalyst microactivity test conversions between 35
and 60% per volume feed. Higher conversion does not generally provide any
benefit in the present invention and has the disadvantage of higher catalyst
replacement rates. By maintaining lower catalyst activity, catalyst consumption
can be optimized for more economic usage of the catalyst.
In catalytic cracking, catalyst particles are heated and introduced into a fluidized
cracking zone with a hydrocarbon feed. The cracking zone temperature is
typically maintained between 480° and 565 °C (900° and 1050°F) at a pressure
between about 0.17 and 0.38 MPa (25 and 55 psia). The circulation rate of the
catalyst in the reactor can range from about 1.8 to 4.5 kg/kg of hydrocarbon feed
(4 to 10lb/lb of hydrocarbon feed). Any of the known catalysts useful in fluidized
catalytic cracking can be employed in the practice of the present invention,
including but not limited to Y-type zeolites, USY, REY, RE-USY, faujasite and
other synthetic and naturally occurring zeolites and mixtures thereof. Other
suitable cracking catalysts include, but are not limited to, those containing silica
and/or alumina, including acidic catalysts. The catalyst can contain refractory
metal oxides such as magnesia or zirconia. The catalyst can contain crystalline
aluminosilicates, zeolites, or molecular sieves. Discarded or used catalyst from a
high activity FCC process can be conveniently and inexpensively employed in
the place of fresh catalyst.
The FCC unit can produce some lighter gases such as fuel gas, liquefied
petroleum gas (LPG), or the like, which can be used as a fuel. These may
contain sulfur compounds which can be removed, if desired, using a small
conventional sulfur removal unit with amine absorption, or the like.
The asphaltene fraction from the ROSE unit can be supplied to a pelletizer and
pelletized, as is known by those skilled in the art. A suitable pelletizer is
described in U.S. Pat. No. 6,357,526 to Abel-Halim, et al. The asphaltene pellets
can be transported in a dewatered form by truck, conveyor, or other means, to a
boiler or gasifier, or can be slurried with water and transferred via pipeline. A
portion of the asphaltenes can be passed or transported to a solids fuel mixing
facility, such as a tank, bin or furnace, for storage or use as a solid fuel. The
boiler can be any conventionally designed boiler according to any suitable type
known to those skilled in the art, but is desirably a circulating fluid bed boiler,
which burns the pellets to generate steam for use in the SAGD process for the
production of the heavy oil or bitumen. Alternatively, the boiler can provide
electric power, or steam for the excavation and extraction equipment in a tar
sand mining operation, including shovels, trucks, conveyors, hot water and so
forth, as needed. The quantity of asphaltenes produced can be large enough to
satisfy all of the steam and power requirements in the production of the heavy oil
or bitumen, thus eliminating the need for imported fuel or steam, resulting in a
significant reduction in the cost of production.
A gasifier can alternatively or additionally be employed, with the asphaltene
fraction being conveniently pelletized and slurried to supply the water for
temperature moderation in the gasification reactor. If desired, excess asphaltene
pellets not required for the boiler(s) and/or gasification can be shipped to a
remote location for combustion or other use. Steam can be generated by heat
exchange with the gasification reaction products, and C02 can also be recovered
in a manner well known to those in the art for injection into the reservoir with
steam for enhanced production of heavy oils and bitumen. Hydrogen gas, and/or
a low value fuel gas, can be recovered from the gasification effluent and
exported, or the hydrogen can be supplied to an associated hydrotreating unit, as
described below. Power can also be generated by expansion of the gasification
reaction products and/or steam via a turbine generator. The power, steam
and/or fuel gas can be used in the heavy oil or bitumen production, e.g. mining
operations or SAGD, as described above. During startup, it may be desirable to
import asphalt pellets, natural gas, or other fuel to fire the boiler to supply
sufficient steam and/or energy for the production of heavy oil or bitumen until the
recovered asphaltene fraction is sufficient to meet the requirements for steam
generation.
Alternatively or additionally, at least a portion of the asphaltene fraction and/or
slurry oil can be supplied to a coker unit for maximizing distillates recovery.
Coking processes are well known for converting very heavy low value residuum
feeds from vacuum or atmospheric distillation columns to obtain coke and gas oil.
Typically, the asphaltene fraction is heated to high temperatures in a coker unit,
e.g. 480-510'C (900-950 °F) to generate lighter components which are recovered
as a vapor, and coke which forms as a solid residue in the coking unit. The
coker unit can be a delayed coker, a flexicoker, a fluid coker, or the like as
desired, all of which are well known in the art. In a delayed coking process, the
feed is held at a temperature of approximately 450°C and a pressure from 75 to
170 kPag (10 to 25 psig) to deposit solid coke while cracked vapors are taken
overhead. Coke produced in the coker can be transported to a storage area for
use as a solid fuel.
Product vapors from the coker can be withdrawn from the coker and supplied to
an associated process, desirably a hydrotreating process. Optionally, the coker
vapors can be separated by distillation into naphtha, distillate and gas oil
fractions prior to being supplied to the hydrotreatment unit. By limiting the feed to
the coker in the present process to the excess asphaltenes fraction and FCC
slurry oil that is not needed for generating steam, hydrogen and power, the size
of the coker can be advantageously reduced relative to front-end coker
processing schemes.
Hydrotreatment of the FCC effluent (and any coker liquids) can improve the
quality of the various products and/or crack residuum oils to lower-boiling, more
valuable products. Mild hydrotreating can remove unwanted sulfur, nitrogen,
oxygen, and metals, as well as hydrogenate any olefins. However, removal of
sulfur and metals via a front-end hydrotreating process before FCC processing
requires relatively large amounts of hydrogen, often requiring a separate
hydrogen production unit or other source.
The hydrotreater in the present invention operates downstream from the FCC
unit to treat the hydrocarbon feed after the metals have been removed, and
primarily serves to remove sulfur from the feed. The hydrotreater can operate at
between 0.8 and 21 MPa (100-3000 psig) and 350° and 500 Mild operating conditions for the hydrotreater can include a fixed bed operating at
between 1.5 and 2.2 MPa (200-300 psig) and 350° to 400 without catalyst regeneration. Severe operating conditions for the hydrotreater
are from 7 to 21 MPa (1000 to 3000 psig) and 350° to 500 "C (650° to 930°F),
and requiring catalyst regeneration. Desirably, the pressure is maintained in a
moderate range between 3.5 and 10.5 MPa (500 to 1500 psi). Hydrogen
consumption increases with increased severity of operating conditions and also
depends upon the amount of metal and sulfur removed and the feed content of
aromatic materials and olefins, which also consume hydrogen. Because the
metal content of the feed to the hydrotreater is negligible, a guard bed is not
needed and high activity catalyst can be employed. Gas and LPG products from
the hydrotreater will contain sulfur compounds, which can be removed in a
conventional sulfur recovery unit as described above. The sulfur recovery unit
processing the hydrotreater light ends can be the same unit as for the FCC
effluent, sized appropriately to accommodate both feeds, or separate sulfur
recovery units can be employed.
By placing the solvent deasphalting and FCC units upstream of the hydrotreater,
and removing metals prior to hydrotreating, the present invention decreases the
dependence of the process on the production of large quantities of hydrogen,
and decreases the need for separate hydrogen production facilities.
One advantage to the present invention is that individual aspects of the present
invention can be added to existing bitumen processing facilities, or that said
facilities can be constructed in a stepwise manner incorporating any number of
the aspects of the present invention, as desired. Referring to Figs. 2-5, wherein
like numerals are used in reference to like parts, the stepwise construction of a
heavy oil and/or bitumen recovery process is shown.
Referring initially to Fig. 2, the base case upgrade in the stepwise construction is
shown. A heavy oil and/or bitumen feed is obtained by excavation 202 and/or
steam assisted gravity drainage 204. Solvent can be added to the feed as
necessary (not shown) to facilitate transfer of the heavy oil/bitumen feed to the
diluent recovery unit (DRU) 206 wherein the crude undergoes atmospheric
distillation. The residue from the distillation column can be supplied to an on-site
or nearby ROSE unit 208 for separation of the DAO and resins from the
asphaltenes. The asphaltene fraction can be removed from the ROSE unit and
supplied to an aquaform unit 210 for the preparation of asphaltene pellets 212.
The asphaltene pellets 212 can be used as fuel, exported or stored. The
DAO/resin fraction can be added to an imported diluent and collected as partially
upgraded synthetic crude 214.
Referring to Fig. 3, an FCC unit 216 has been added to the Fig. 2 process. The
FCC unit 216 is desirably at the same location or in close proximity to the ROSE
unit 208. The DAO/resin fraction can be supplied to an FCC unit 216 having a
low activity catalyst as previously described herein. The FCC unit 216 removes
substantially all remaining metals in the feed not previously removed by the
ROSE unit 208.
Referring to Fig. 4, the Fig. 2 process includes a gasifier 218, and a hydrotreater
220 has been added downstream of the FCC unit 216. The asphaltene fraction
from the ROSE unit 208 can be supplied to the gasifier 218 which partially
oxidizes the asphaltene to produce hydrogen 222, fuel gas 224, power 226,
which can either be exported or supplied to the SAGD unit 204, and steam 230,
which can be supplied to the SAGD unit 204. A decant oil stream recovered from
the FCC unit 216 can be supplied to the gasifier 218, or used as fuel 228. An
essentially metal free stream of partially upgraded synthetic crude can be
supplied from the FCC unit 216 to the hydrotreater 220, which can optionally
include separating the naphtha, distillate, and gas oil prior to hydrotreating. The
hydrotreated naphtha, distillate, and gas oil can be blended to produce a
synthetic crude 232. The gasifier 218 and hydrotreater 220 are desirably located
in the same plant, and especially in close proximity to the FCC unit 216 and/or
ROSE unit 208, or on-site with the heavy oil or bitumen production.
Referring to Fig. 5, a coker unit 234 has been added to the process of Fig. 4 for
improved recovery. A portion of the asphaltene fraction from the ROSE unit 208
can be supplied to coker unit 234. The coker unit 234 can produce a cracked
effluent which can include naphthas, distillates and gas oils, and can be
combined with the FCC unit 216 effluent and supplied to the hydrotreater 220 for
further upgrading to a metal free synthetic crude 232. The coker unit is desirably
located on-site or in close proximity to the ROSE unit 208 and/or FCC unit 216.
Another advantage to the present invention is an energy cost of near zero once
the facilities are installed and operational. Because the asphaltene product can
be readily converted to transportable, combustible fuel, the need for imported
hydrogen, fuel and/or energy can be eliminated. The current process can thus
be self-sufficient with respect to power, hydrogen and steam requirements for the
SAGD and hydrotreater processes in the recovery and upgrade of heavy oils
and/or bitumens. Similarly, power can be provided to mining equipment reducing
requirements as compared to traditional mining processes. The capital costs
associated with the present invention are slightly higher than those associated
with other methods for the recovery of bitumens, such as for example, processes
employing front end delayed coking or ebullated bed hydrocracking. However,
the present invention has a better return on investment, lower complexity and
simpler operation, less coke disposal, complete energy self sufficiency, and can
be constructed or be added as an upgrade in a stepwise fashion.
Example. Referring to the process shown in Fig. 5, feed comprising 28,900 m3/d
(182,000 BPD (42-gallon barrels per day)) of 10-15 API diluted bitumen and
heavy oils is supplied to a diluent recovery unit (DRU) 308. The DRU 308
supplies 24,800 m3/d (156,000 BPD) feed to the ROSE unit 314, where the unit
314 separates the feed into a DAO fraction and an asphaltene fraction. A 3,400
m3/d (21,500 BPD) stream of the asphaltene fraction is supplied to the gasifier
338, and a 3,400 m3/d (21,500 BPD) stream is supplied to the coker unit 354.
An 18,000 m3/d (113,000 BPD) resid oil stream is supplied from the ROSE unit
314 to the fluid catalytic cracking (FCC) unit 328. FCC unit 328 removes
remaining metals and separates the feed into a light fraction of reduced metal
content and a heavy decant oil. A 3,800 m3/d (23,700 BPD) stream of the
decant oil is supplied from the FCC unit 328 to the gasifier 338. A 12,600 m3/d
(80,000 BPD) stream of a light fraction consisting primarily of distillates, naphtha
and gas oil is supplied from the FCC unit 328 to the hydrotreater 332 where it is
combined with a 2,100 m3/d (13,000 BPD) stream of gas oil collected from the
coker 354 and supplied to the hydrotreater 332. Hydrotreater 332 produces 37-
41 API synthetic crude at a rate of 16,000 m3/d (100,000 BPD).
Numerous embodiments and alternatives thereof have been disclosed. While
the above disclosure includes the best mode belief in carrying out the invention
as contemplated by the inventors, not all possible alternatives have been
disclosed. For that reason, the scope and limitation of the present invention is
not to be restricted to the above disclosure, but is instead to be defined and
construed by the appended claims.



WE CLAIM :
1. A process for upgrading crude oil from a subterranean reservoir of heavy
oil or bitumen, comprising:
converting asphaltenes to steam, power, fuel gas, or a combination
thereof for use in producing heavy oil or bitumen from a reservoir;
solvent deasphalting at least a portion of the heavy oil or bitumen to form
an asphaltene fraction and a deasphalted oil (DAO) fraction essentially free of
asphaltenes having a reduced metals content;
supplying the asphaltenes fraction from the solvent deasphalting to the
asphaltenes conversion;
supplying a feed comprising the DAO fraction to a reaction zone of a fluid
catalytic cracking (FCC) unit with FCC catalyst to deposit a portion of the metals
from the DAO fraction onto the FCC catalyst, wherein lower boiling hydrocarbon
fractions are introduced to the FCC unit with the DAO fraction;
recovering a hydrocarbon effluent having a reduced metal content from
the FCC unit; and
removing metallized FCC catalyst from the FCC unit.
2. The process as claimed in claim 1, comprising producing heavy oil or
bitumen by extraction from mined tar sands.
3. The process as claimed in claim 1 comprising producing heavy oil or
bitumen by injecting a mobilizing fluid through one or more injection wells
completed in communication with the reservoir to mobilize the heavy oil or
bitumen and producing the mobilized heavy oil or bitumen from at least one
production well completed in communication with the reservoir.
4. The process as claimed in claim 3 wherein the mobilizing fluid comprises
steam generated primarily by combustion of asphaltenes recovered from the
asphaltenes fraction from the solvent deasphalting.

5. The process as claimed in claim 6, wherein the asphaltenes conversion
comprises gasification of a portion of the asphaltenes fraction to provide power,
steam, fuel gas or combinations thereof for the mining and extraction.
6. The process as claimed in claim 1 wherein the solvent deasphalting has a
high lift.
7. The process as claimed in claim 1 comprising feeding a portion of the
asphaltenes fraction to a delayed coker unit to produce coker liquids and coke.
8. The process as claimed in claim 1 wherein the FCC unit is operated at a
conversion from 30 to 65 percent by volume of the feed to the FCC unit.
9. The process as claimed in claim 1 wherein operating conditions in the
FCC unit are adjusted to control proportions of naphtha, distillate and gas oil in
the hydrocarbon effluent from the FCC unit.
10. The process as claimed in claim 1 comprising hydrotreating the
hydrocarbon effluent from the FCC unit to produce a low sulfur hydrocarbon
effluent.
11. The process as claimed in claim 10 wherein the hydrotreating is effected
at a moderate pressure of from 3.5 to 10 MPa.
12. The process as claimed in claim 10 comprising gasifying asphaltenes
recovered in the asphaltenes fraction from the solvent deasphalting to produce
hydrogen for the hydrotreating.
13. A process for upgrading crude oil from a subterranean reservoir of heavy
oil or bitumen, comprising:
converting asphaltenes to steam, power, fuel gas, or a combination
thereof for use in producing heavy oil or bitumen from a reservoir;
solvent deasphalting at least a portion of the heavy oil or bitumen
containing metals to form an asphaltene fraction and a deasphalted oil (DAO)
fraction essentially free of asphaltenes having a reduced metals content;
supplying the asphaltene fraction from the solvent deasphalting to the
asphlatenes conversion;
generating steam by combustion of asphaltenes recovered in the
asphaltenes fraction from the solvent deasphalting;
supplying a feed comprising the DAO fraction to a reaction zone of a fluid
catalytic cracking (FCC) unit with FCC catalyst to recover a demetallized
hydrocarbon effluent from the FCC unit at a conversion rate from 30 to 65
percent by volume of the feed to the FCC unit;
recovering a hydrocarbon emuent having a reduced metal content from
the FCC unit; and
hydrotreating the hydrocarbon effluent to produce a low sulfur
hydrocarbon effluent.
14. The process as claimed in claim 13 wherein the heavy oil or bitumen
production comprises injecting steam through one or more injection wells
completed in communication with the reservoir to mobilize the heavy oil or
bitumen; and producing the mobilized heavy oil or bitumen from at least one
production well completed in communication with the reservoir.
15. The process as claimed in claim 13 wherein the heavy oil or bitumen
production comprises extraction from mined tar sands.
16. The process as claimed in claim 13 comprising feeding a portion of the
asphaltenes fraction to a delayed coker unit to produce coker liquids and coke.
17. The process as claimed in claim 16 comprising feeding the coker liquids to
the hydrotreating with the FCC hydrocarbon effluent.
18. The process as claimed in claim 13 comprising supplying decant oil from
the FCC unit to combustion, gasification or a combination thereof.

19. The process as claimed in claim 13 wherein operating conditions in the
FCC unit are adjusted to control proportions of naphtha, distillate and gas oil in
the hydrocarbon effluent from the FCC unit.
20. The process as claimed in claim 13 wherein the hydrotreating is effected
at a moderate pressure of from 3.5 to 10.5 MPa.
21. The process as claimed in claim 13 comprising gasifiring asphaltenes
recovered in the asphaltenes fraction from the solvent deasphalting to produce
hydrogen for the hydrotreating.


A process for the upgrading and demetallizing of heavy oils and bitumens
is disclosed. A crude heavy oil and/or bitumen feed is supplied to a solvent
extraction process (104) wherein DAO and asphaltenes are separated. The DAO
is supplied to an FCC unit (106) having a low conversion activity catalyst for the
removal of metals contained therein. The demetallized distillate fraction is
supplied to a hydrotreater (110) for upgrading and collected as a synthetic crude
product stream. The asphaltene fraction can be supplied to a gasifier (108) for
the recovery of power, steam and hydrogen, which can be supplied to the
hydrotreater (110) or otherwise within the process or exported. An optional coker
(234) can be used to convert excess asphaltenes and/or decant oil to naphtha,
distillate and gas oil, which can be supplied to the hydrotreater (220).

Documents:

03218-kolnp-2006 abstract.pdf

03218-kolnp-2006 claims.pdf

03218-kolnp-2006 correspondence others.pdf

03218-kolnp-2006 description(complete).pdf

03218-kolnp-2006 drawings.pdf

03218-kolnp-2006 form-1.pdf

03218-kolnp-2006 form-3.pdf

03218-kolnp-2006 form-5.pdf

03218-kolnp-2006 international publication.pdf

03218-kolnp-2006 priority document.pdf

03218-kolnp-2006-correspondence others-1.1.pdf

03218-kolnp-2006-form-3-1.1.pdf

03218-kolnp-2006-gpa.pdf

03218-kolnp-2006-priority document-1.1.pdf

3218-KOLNP-2006-(02-01-2012)-FORM-27.pdf

3218-KOLNP-2006-(02-04-2012)-CORRESPONDENCE.pdf

3218-KOLNP-2006-ABSTRACT 1.1.pdf

3218-KOLNP-2006-AMANDED PAGES OF SPECIFICATION.pdf

3218-kolnp-2006-assignment.pdf

3218-kolnp-2006-correspondence.pdf

3218-KOLNP-2006-DRAWINGS 1.1.pdf

3218-kolnp-2006-examination report.pdf

3218-KOLNP-2006-FORM 1 1.1.pdf

3218-kolnp-2006-form 18.1.pdf

3218-kolnp-2006-form 18.pdf

3218-KOLNP-2006-FORM 2.pdf

3218-KOLNP-2006-FORM 3 1.1.pdf

3218-kolnp-2006-form 3.pdf

3218-KOLNP-2006-FORM 5 1.1.pdf

3218-kolnp-2006-form 5.pdf

3218-kolnp-2006-gpa.pdf

3218-kolnp-2006-granted-abstract.pdf

3218-kolnp-2006-granted-claims.pdf

3218-kolnp-2006-granted-description (complete).pdf

3218-kolnp-2006-granted-drawings.pdf

3218-kolnp-2006-granted-form 1.pdf

3218-kolnp-2006-granted-form 2.pdf

3218-kolnp-2006-granted-specification.pdf

3218-KOLNP-2006-OTHERS 1.1.pdf

3218-KOLNP-2006-OTHERS 1.2.pdf

3218-kolnp-2006-others.pdf

3218-KOLNP-2006-PETITION UNDER RULE 137.pdf

3218-KOLNP-2006-REPLY TO EXAMINATION REPORT.pdf

3218-kolnp-2006-reply to examination report1.1.pdf

3218-kolnp-2006-translated copy of priority document.pdf

abstract-03218-kolnp-2006.jpg


Patent Number 248978
Indian Patent Application Number 3218/KOLNP/2006
PG Journal Number 38/2011
Publication Date 23-Sep-2011
Grant Date 19-Sep-2011
Date of Filing 03-Nov-2006
Name of Patentee KELLOGG BROWN &ROOT, LLC
Applicant Address 601, JEFFERSON, HOUSTON,TX 77002
Inventors:
# Inventor's Name Inventor's Address
1 IQBAL, RASHID 3103, SCENIC ELM STREET, HOUSTON,TX 77059
2 ENG, ODETTE 4906, GLEN HOLLOW, SUGAR LAND, TX 77479
3 NICCUM, PHILLIP 1115, HAWTHORNE, HOUSTON, TX 77006
4 ANSHUMALI 6526, EMERALD CANYON, KATY, TX 77450
PCT International Classification Number C10G 55/06; B01J8/18
PCT International Application Number PCT/US2005/013219
PCT International Filing date 2005-04-20
PCT Conventions:
# PCT Application Number Date of Convention Priority Country
1 10/711,176 2004-08-30 U.S.A.