Note: Descriptions are shown in the official language in which they were submitted.
CA 02837345 2013-12-19
TITLE OF THE INVENTION
Integrated Central Processing Facility (CPF) in Oil Field Upgrading (OFU)
FIELD OF THE INVENTION
The present invention relates to improved heavy oil and/or bitumen recovery
and
upgrading processes and systems resulting in upgraded oil.
BACKGROUND OF THE INVENTION
It is well known that heavy oil and/or bitumen are difficult to transport from
their
production areas due to their high viscosities at typical handling
temperatures. On the
other hand, light oils generally have much lower viscosity values and
therefore flow
more easily through pipelines. Regardless of the recovery method used for
their
extraction, heavy oil and/or bitumen generally need to be diluted by blending
the
heavy oil and/or bitumen with at least one low density and low viscosity
diluent to
make the heavy oil and/or bitumen transportable, in particular over long
distances.
The diluents used are typically gas condensate, naphtha, lighter oil, or a
combination
of any of the three. For example in Canada, when making transportable oil and
using
gas condensate as a diluent, the volume of gas condensate added to the bitumen
is
typically 30 to 35% of the total product.
There are several disadvantages of adding diluent to heavy oil and/or bitumen
to
produce transportable oil including:
= Well remoteness makes the construction of pipelines for sending or
returning
the diluents to the heavy hydrocarbon production zone considerably
expensive; and
= Availability of diluents, typically light hydrocarbons, such as gas
condensates,
is steadily decreasing worldwide, making them more expensive to procure.
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Chemical processing has become an attractive alternative for converting heavy
oil
and/or bitumen into transportable oil, and in some cases chemical processing
is the
only viable alternative for transporting heavy oil and/or bitumen to
refineries and
market places.
Most chemical processes for converting heavy oil and/or bitumen into
transportable
oil are thermal cracking based systems. Thermal cracking based systems range
from
moderate thermal cracking such as visbreaking to more severe thermal cracking
such
as coking systems. These processes are generally applied to the heaviest
hydrocarbons
in the heavy oil and/or bitumen, typically the fraction called the vacuum
residue
("VR") which contains a high concentration of asphaltenes.
One disadvantage of the above chemical processes is the limited conversion of
heavy
hydrocarbons into lighter hydrocarbons due to the generation and instability
of
asphaltenes during these processes. These processes reduce the stability of
the heavy
oil due to the disruption of the asphaltenes-resins interactions. This
instability
increases with increased conversion levels, resulting in the precipitation of
asphaltenes and the formation of problematic deposits in equipment and pipes.
In coking systems, asphaltenes are converted into coke which requires the
addition of
complex and expensive equipment to deal with the coke.
Another disadvantage of the above chemical processes is the production of
cracked
material by-products (e.g. olefins and di-olefins). If left untreated, olefins
and di-
olefins may react with oxygen (such as oxygen in the air) or other reactive
compounds
(e.g. organic acids, carbonyls, amines, etc.) to form long chain polymers,
commonly
referred to as gums, which further foul downstream process equipment. To
reduce the
olefins and di-olefins in the final product, expensive hydro-processing and
hydrogen
generation infrastructures must be used to treat the cracked material.
The disadvantages described above translate into significant cost and
complexity,
rendering small scale applications of these technologies uneconomical. In Long
Lake,
Alberta, Canada, Steam Assisted Gravity Drainage ("SAGD") technology is used
to
recover bitumen. The bitumen is mixed with a light hydrocarbon as a diluent,
which
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dilutes the thick bitumen and enables it to flow ("DilBit"). The DilBit is
then
upgraded into premium crude oil at the onsite upgrader using a paraffinic
solvent de-
asphalting ("SDA") unit, followed by thermal cracking and hydrocracking
technologies. The bitumen is upgraded into 40 API synthetic oil and the
rejected
asphaltenes are fed into a gasifier to generate the hydrogen for hydrocracking
as well
as the energy required to extract the bitumen from the reservoir. Such
complexity is
typical of current technological state-of-the-art processes in bitumen
recovery and
treatment.
Several patents have been published which discuss attempts to address these
problems
(US7981277, US4443328, US2009/0200209, CA2232929, CA2217300, and
CA2773000). Each of these references, however, suffer from one or more of the
following disadvantages:
= The simultaneous removal of water and asphaltenes is not contemplated,
resulting in the asphaltenes causing equipment plugging issues as
discussed above;
= There is no water in the asphaltenes feed so more valuable lighter
hydrocarbons must be precipitated with the asphaltenes to act as a
viscosity-reducing diluent. This substantially reduces recovery which
lowers profit;
= Only applicable to mine applications;
= Overcracking of the bitumen in the upright cylindrical reactor (US
4443328) is not addressed; and
= Production of olefins and di-olefins in the thermally cracked material is
not addressed.
There is a need for improved heavy oil and/or bitumen recovery and upgrading
processes.
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SUMMARY OF THE INVENTION
The term "heavy oil" as used herein comprises hydrocarbons that are highly
viscous
and do not flow easily. In one instance, heavy oil has been defined as having
an
average API gravity of 200 or lower. In some instances, depending on reservoir
conditions, said heavy oil further comprises at least one dissolved gas,
asphaltenes,
water, and mineral solids. In another instance, depending on production
methods,
said heavy oil further comprises at least one solvent and/or any other
production
additive or the like. "Bitumen" is a subset of heavy oil and typically is
characterized
by having an API gravity of 12 or lower. In its natural state, such as in
Canada's Oil
Sands or Venezuela's Orinoco Oil Belt, bitumen generally includes fine solids
such as
mineral solids and C5-insoluble asphaltenes in the range of 10 to 18% w/w.
The term "asphaltenes" as used herein refers to the heaviest and most polar
molecules
component of a carbonaceous material such as crude oil, bitumen or coal and
are
defined as a solubility class of materials that are insoluble in an n-alkane
(usually n-
pentane or n-heptane) but soluble in aromatic solvents such as toluene. In
crude oil,
asphaltenes are found, along with saturated and aromatic hydrocarbons and
resins
("SARA"). Asphaltenes consist primarily of carbon, hydrogen, nitrogen, oxygen,
and
sulfur, as well as trace amounts of vanadium and nickel. The density is
approximately
1.2 g/cc and the hydrogen to carbon atomic ratio is approximately 1.2,
depending on
the asphaltenes source and the solvent used for extraction. The asphaltenes
fraction is
also responsible for a large percentage of the contaminants contained in the
bitumen
(for example Athabasca bitumen is typically 72%-76% w/w of the metals, 53%-58%
w/w of coke precursors, and 26%-31% w/w of the heteroatoms ¨ sulphur, nitrogen
and oxygen), making bitumen very challenging to process into clean and
valuable
products.
The term "mineral solids" as used herein refers to non-volatile, non-
hydrocarbon solid
minerals. Depending on the hydrocarbon reservoir, these mineral solids may
have a
density of from 2.0 g/cc to about 3.0 g/cc and may comprise silicon, aluminum
(e.g.
silicas and clays), iron, sulfur, and titanium and range in size from less
than 1 micron
to about 1,000 microns in diameter.
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The term "paraffinic solvent" (also known as alkane or aliphatic solvent) as
used
herein means a solvent containing normal paraffins, isoparaffins and blends
thereof in
the C3 to C20 carbon range, preferably in the C4 to C8 carbon range and most
preferably in the C5 to C7 carbon range. These paraffinic solvents may be
produced
from the processing of gas streams commonly referred to as natural gas
condensates
or from refinery hydrocarbon streams commonly referred to as naphthas. The
presence of non-paraffinic hydrocarbons in said paraffinic solvent, such as
aromatics,
olefins and naphthenes (as well as other undesirable compounds, such as but
not
limited to heteroatom containing molecules), counteract the function of the
paraffinic
solvent and hence should preferably be limited to less than 20% w/w,
preferably less
than 10% w/w and most preferably to less than 5% w/w of the total paraffinic
solvent
content. In one embodiment, the paraffinic solvent comprises a natural gas
condensate, preferably having about 1.8% w/w n-butane, 25.1% w/w n-pentane,
27.7% w/w iso-pentane, 22.3% w/w n-hexane, 13.7% w/w n-heptane, 5.4% w/w n-
octane and 4% w/w of the counteracting components mentioned previously. In
another embodiment, the paraffinic solvent comprises 1.4% w/w n-butane, 96.8%
w/w n-pentane, 1.5% w/w iso-pentane and 0.3% w/w of the counteracting
components mentioned previously. In another embodiment, the paraffinic solvent
comprises 95% w/w n-hexane, 3.3% w/w iso-hexane and 1.7% w/w of the
counteracting components previously mentioned. In yet another embodiment, the
paraffinic solvent comprises 99% w/w n-heptane, 0.1% w/w iso-octane and 0.9%
w/w
of the counteracting components previously mentioned. Preferably the
paraffinic
solvent choice is dictated by preferred economics.
The terms "upgraded oil" or "transportable oil" as used herein are used
interchangeably and refer to a hydrocarbon oil having the collection of
product quality
specifications such that the oil meets at least one pipeline and/or operating
specification, preferably such that the oil must meet in order for it to be
shipped
through a pipeline (including but not limited to common carrier, private,
gathering,
and facility pipelines). These specifications differ from region to region and
from
operator to operator, taking into account location as well as climate/seasonal
conditions and the final user requirements. For example, in Canada, one common
carrier pipeline requires the transportable or upgraded oil to have a
temperature not
greater than 38 C, a Reid vapour pressure not greater than 103 kilopascals, a
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sediment and water content not greater than 0.5 %v, a density not greater than
940
kilograms per cubic metre at 15 C, a kinematic viscosity not greater than 350
square
millimetres per second determined at the carrier's reference line temperature
and
olefins content as determined by an HNMR test, not greater than 1.0% olefins
by
mass as 1-decene equivalent.
The term "water droplet" as used herein refers to a volume of water,
preferably a
small volume of water having a predetermined shape, preferably an
approximately
spherical shape. Water droplets are introduced into the continuous heavy
hydrocarbon
+ paraffinic solvent phase facilitating agglomeration of destabilized
asphaltenes
particles increasing floc size, preferably by charge site binding and by
molecular
bridging. In one instance, the addition of water droplets into the system of
the present
invention increases the settling rate of the destabilized asphaltenes and
decreases the
size and cost of the separator equipment used. Preferably the addition of
water
droplets in the process is such that entrainment is reduced, preferably
minimized,
more preferably avoided. In one embodiment, water droplets are introduced
proximate
the heavy oil and paraffinic solvent mixture inlet of the separator and
distant the de-
asphalted oil ("DA0")¨paraffinic solvent outlet of the separator, reducing
entrainment
in the DAO¨paraffinic solvent stream.
The preferred average water droplet diameter varies based on the
characteristics of the
specific system; preferably said average diameter is in the range of from
about 5 to
about 500 microns, more preferably from about 50 to about 150 microns.
Preferably, the amount and specification of water droplets added to the heavy
hydrocarbon + paraffinic solvent phase is such that it facilitates
agglomeration of
destabilized asphaltenes particles, resulting in increased floc size. More
preferably
the amount of water droplets may be from about 0.5 to about 1.5 vol/vol of the
C5-
Insolubles being rejected from the original heavy hydrocarbon or bitumen. The
amount and temperature of the water droplets added to the phase may be
adjusted
depending on the feed and process characteristics (e.g. temperature, density
and
viscosity of the continuous heavy hydrocarbon + paraffinic solvent phase,
water
droplet size distribution, location of the water droplets injection point
relative to the
continuous phase level, mixing energy, water quality, etc.).
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A further benefit of the addition of water droplets into the continuous heavy
hydrocarbon + paraffinic solvent phase is an increased collision between water
droplets due to the increased population of water droplets in the heavy
hydrocarbon +
paraffinic solvent continuous phase, facilitating the coalescence and removal
of
contaminants in the oil, in one embodiment, the coalescence and removal of
higher
salinity water originally present in the oil.
The water used for water droplets to be added to the heavy hydrocarbon +
paraffinic
solvent phase, in the present invention, may be any source of water known to a
person
of ordinary skill in the art, which is not detrimental to the process as
described herein.
In one embodiment, the water droplet to be added to the phase, has the
following
specification:
DESCRIPTION WATER SPECIFICATION
pH @ 25 C 8.5 ¨ 9.5
Dissolved 02, wt. ppb 5 max.
Total Hardness as CaCO3, wt. ppm 0.2 max.
Calcium as CaCO3, wt. ppm 0.1 max.
Sodium as CaCO3, wt. ppm 0.5 max.
Sulfates as CaCO3, wt. ppm 0.1 max.
Total Alkalinity as CaCO3, wt. ppm Nil
Silica as Si02, wt. ppm 0.1 max.
Chlorides as Chlorine, wt. ppm 1 max.
Total Dissolved Solids, wt. ppm 10 max.
Conductivity @ 25 C, MHOS/cm 15 max.
Droplets may be formed using spray nozzles or any other method of producing
droplets known to a person of ordinary skill in the art.
According to one aspect, the present invention is directed to a system for
recovery and
upgrading of heavy oil to a transportable oil, said system comprises combining
oil-
water-mineral solids separation, solvent de-asphalting and fractionation, and
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optionally, thermal cracking and olefin conversion, preferably in an
integrated
processing unit, more preferably in a single integrated processing unit.
In one embodiment, said system increases the value of hydrocarbon recovery and
upgrading heavy oil and/or bitumen, by combining oil-water-mineral solids
separation, solvent de-asphalting and fractionation, and optionally, thermal
cracking
and olefin conversion, such that small scale field upgrading becomes
economically
viable.
The present invention is also directed to at least one process, preferably a
plurality of
processes to produce upgraded oil which meets at least one pipeline and/or
operating
specification.
Further, this invention is particularly suited to heavy oil generated from oil
sands
which contain bitumen, gas, asphaltenes, water, and mineral solids. These
heavy oil
production methods include, but are not limited to, Steam Assisted Gravity
Drainage
("SAGD"), Cyclic Steam Stimulation ("CSS"), mining, pure solvent extraction
based
or steam-solvent combinations (e.g. vapour extraction process ("Vapex"),
NSolvTM,
expanding solvent steam assisted gravity drainage ("ES-SAGD"), enhanced
solvent
extraction incorporating electromagnetic heating ("ESEIEH")), or any other oil
recovery technology known to a person of ordinary skill in the art.
Further, this invention is applicable to heavy oil production methods
including
offshore oil production and the like.
According to one embodiment of the invention, there is provided at least one
process
for upgrading oil comprising:
a) optionally pre-treating a heavy oil (comprising at least one dissolved gas,
asphaltenes, water, and mineral solids), to remove at least one dissolved gas
and
optionally a predetermined amount of water from the heavy oil, b) adding a
paraffinic
solvent to the heavy oil, at a predetermined paraffinic solvent:heavy oil
ratio,
facilitating separation of asphaltenes, water, and mineral solids from the
heavy oil
resulting in a de-asphalted or partially de-asphalted oil ("DA0")¨paraffinic
solvent
stream, preferably a low asphaltenes content DAO-paraffinic solvent stream and
an
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asphaltenes-mineral solids-paraffinic solvent-water slurry stream, optionally
a water
feed is introduced for the generation of water droplets to further facilitate
separation
of asphaltenes, water, and mineral solids from the heavy oil; c) optionally
separating
the paraffinic solvent and water from the asphaltenes-mineral solids-
paraffinic
solvent-water slurry stream, preferably said paraffinic solvent may be used in
said
process; d) optionally separating the DA0- paraffinic solvent stream into a
paraffinic
solvent rich stream and a DAO stream; and e) optionally adding diluent to the
DA0
stream resulting in transportable oil, in one embodiment said diluent being
selected
from the paraffinic solvent used in step (b) or any other diluent known to an
ordinary
person skilled in the art, and combinations thereof.
In one embodiment, step (d) further comprises at least one fractionating step,
preferably at least one supercritical paraffinic solvent recovery step
followed by at
least one fractionating step.
According to yet another embodiment of the invention, subsequent to step (c),
said
process further comprises (f) fractionating said DAO-paraffinic solvent stream
resulting in a paraffinic solvent rich stream, at least one distillate
hydrocarbon fraction
stream, preferably at least two distillate hydrocarbon fraction streams, and
at least one
heavy residue fraction stream; said process further comprises: cracking a
portion of
said at least one heavy residue fraction stream, preferably in a thermal
cracker or a
catalytic cracker, and in one embodiment a catalytic steam cracker, comprising
a
heater, optionally said thermal cracker or catalytic steam cracker further
comprises a
soaker, said thermal cracker or said catalytic steam cracker forming at least
one
cracked stream, wherein said at least one cracked stream is mixed with said
DA0-
paraffinic solvent stream to be fractionated; in one embodiment, said soaker
comprises a conventional up-flow soaker; in another embodiment, said soaker
comprises a high efficiency soaker; (g) treating said at least one distillate
hydrocarbon
fraction, for reduction of olefins and di-olefins, and optionally heteroatom
reduction,
wherein said treating comprises hydrotreatment or olefins-aromatics
alkylation, and
combinations thereof, resulting in at least one treated distillate hydrocarbon
fraction
stream; h) mixing said at least one treated distillate hydrocarbon fraction
stream with
the uncracked portion of said at least one heavy residue fraction stream
forming an
upgraded oil; optionally when there are at least two distillate hydrocarbon
fraction
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streams wherein at least one distillate hydrocarbon fraction stream is
untreated, said
at least one untreated distillate hydrocarbon fraction stream is further added
to said
upgraded oil.
In one embodiment, when said soaker is a high efficiency soaker, said at least
one
heavy residue fraction stream is cracked into a light cracked stream and a
heavy
cracked stream. Wherein said heavy cracked stream is recycled to step (b) and
said
light cracked stream is mixed with said DAO-paraffinic solvent stream.
In one embodiment, said process further comprises at least one fractionating
step,
preferably at least one supercritical paraffinic solvent recovery step
followed by at
least one fractionating step.
According to another embodiment of the invention, said a) optionally treating
a heavy
oil (comprising at least one dissolved gas, asphaltenes, water, and mineral
solids), to
reduce at least one dissolved gas and optionally a predetermined amount of
water
from the heavy oil, comprises introducing said heavy oil to a gravity
separator, a
centrifuge and/or separating means understood by those skilled in the art.
According to a yet another embodiment of the invention, there is provided a
process
for upgrading heavy oil wherein when using a catalytic steam cracker, adding
at least
one catalyst to said heavy residue fraction stream to be cracked. In one
embodiment
said at least one catalyst is a nano-catalyst. In yet another embodiment said
nano-
catalyst has a particle size of from about 20 to about 120 nanometers,
preferably said
nano-catalyst is comprised of a metal selected from rare earth oxides, group
IV
metals, and mixtures thereof in combination with NiO, CoOx, alkali metals and
Mo03.
In a preferred embodiment, in step (b), the presence of water within the heavy
oil is
advantageous, as the water forms a slurry with the rejected asphaltenes,
reducing
hydraulic limitations in the handling of asphaltenes and allowing for higher
recovery
of DA0 in the present process.
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Preferably in any of the above embodiments, the paraffinic solvent:heavy oil
ratio is
from about 0.6 to about 10.0 w/w, more preferably from about 1.0 to about 6.0
w/w.
Preferably separation of asphaltenes, water, and mineral solids from the heavy
oil
resulting in a de-asphalted or partially de-asphalted oil ("DA0")¨paraffinic
solvent
stream and an asphaltenes-mineral solids-paraffinic solvent-water slurry
stream is
carried out at a temperature from about ambient temperature to about critical
temperature of said paraffinic solvent. More preferably at a temperature from
about
35 C to about 267 C, most preferably from about 60 C to about 200 C.
Preferably
said separation is carried out at a pressure of from about the paraffinic
solvent vapour
pressure to higher than the paraffinic solvent critical pressure, more
preferably from
about 10% higher than the paraffinic solvent vapour pressure to about 20%
higher
than the paraffinic solvent critical pressure. Preferably said separation is
carried out in
at least one solvent de-asphalting ("SDA") unit.
Preferably in any of the above embodiments, said separation removes at least a
minimum amount of asphaltenes resulting in a transportable oil according to
the
present invention.
Preferably in any of the above embodiments, when a cracking step is involved,
said
separation removes at least a minimum amount of asphaltenes allowing cracking
to
proceed by reducing the formation of problematic deposits in equipment and
pipes,
according to the present invention.
Preferably in any of the above embodiments, when a catalytic cracking step is
involved, said separation removes at least a minimum amount of asphaltenes
allowing
catalytic cracking to proceed.
In one embodiment, when a catalytic cracking step is involved, said catalytic
cracking
is catalytic steam cracking
In one embodiment, at least about 30% of n-05 insoluble asphaltenes are
removed to
reduce any negative impact on the catalysts used in catalytic steam cracking.
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Preferably said cracking step, comprises a heater and an optional conventional
soaker
or a high efficiency soaker ("HES"), wherein said cracking step is carried out
at a
temperature range of from about 300 C to about 480 C, more preferably from
about
400 C to about 465 C. Preferably said cracking step is carried out at a
pressure range
of from about atmospheric pressure to about 4500kPa, more preferably from
about
1000kPa to about 4000kPa. Preferably said cracking step has a liquid hourly
space
velocity ("LHSV") of from about 0.1 to about 10 111,
more preferably from about
0.5 III to about 5 114. Preferably said cracking step is carried out in at
least one
thermal cracking unit or at least one catalytic steam cracking unit.
In any of the above embodiments, said process further comprises at least one
mixing
step, wherein said at least one mixing step is selected from those known to a
person of
ordinary skill in the art. In yet a further preferred embodiment, said at
least one
mixing step comprises sonic-mixing.
In one embodiment, the high efficiency soaker (HES) is a soaking drum, where
sufficient residence time is provided to crack a heated heavy residue fraction
stream
(feed) to a desired conversion while enhancing selectivity towards more
valuable
distillate products, and reduced asphaltenes content from the upgraded oil.
After
being processed through a feed heater the hot heavy residue fraction stream is
introduced into the HES preferably via a distributor proximate the top section
of the
drum and the hot heavy residue fraction stream flows downward towards the
lower
section of the drum for further cracking. The HES reaction section preferably
allows
for plug-type flow. In one embodiment the HES reaction section comprises trays
resulting in plug-type flow, preferably avoiding back-mixing and bypassing.
These
trays are preferably perforated sieve trays, but other type of trays known to
a person
of ordinary skill in the art, such as but not limited to, shed trays, random
(e.g. Berl
saddles or Raschig Rings) or structured packings, may also be used. The number
of
trays or the height of packing is a function of the desired conversion. As the
reacting
hot heavy residue fraction is exposed to increased residence time, the
conversion to
lighter hydrocarbon fractions also increases. Steam, preferably in the range
of 0.01 to
0.10 w/w of feed, is introduced, preferably injected into the drum, preferably
via a
distributor proximate the bottom thereof, more preferably located below the
bottom
tray, flowing upward and counter-current to the reacting heavy residue
fraction. To
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avoid quenching of the reaction and/or foaming inside the HES, the injected
steam is
preferably superheated to the same or higher temperature as the reacting hot
heavy
residue fraction. The injected steam further reduces the partial pressure of
the
hydrocarbons present, promoting disengagement, preferably fast disengagement
of the
lighter hydrocarbon fractions from the reacting hot heavy residue fraction,
helping to
recover these lighter hydrocarbon fractions from the bottom heavy cracked
stream.
Another advantage of the injected steam is the reduction of the residence time
to
which the lighter distillate fractions are exposed to cracking conditions.
When a catalyst is used, such as in a catalytic steam cracker, the steam also
reacts to
saturate olefins reducing olefins content in the top light cracked stream. The
light
hydrocarbons resulting from the reaction flow upward with the steam and exit
at the
top of the HES as a top light cracked stream, whereas the heavy unconverted
hydrocarbons flow downwards resulting in a bottom heavy cracked stream and is
sent
for further treatment.
Preferably said at least one distillate hydrocarbon fraction is treated to
reduce olefins
and di-olefins and optionally heteroatoms, wherein said treatment comprises
hydrotreatment or olefins-aromatics alkylation. Preferably, said olefins-
aromatics
alkylation further comprises contacting the feed material with at least one
catalyst.
Preferably, said olefins-aromatics alkylation is carried out at a temperature
of from
about 50 C to about 350 C, more preferably from about 150 C to about 320 C.
Preferably said olefins-aromatics alkylation is carried out at a pressure of
from about
atmospheric pressure to about 8000 kPa, more preferably said pressure is from
about
2000 kPa to about 5000 kPa, most preferably said pressure is about 10% higher
than
vapour pressure of the distillate hydrocarbon fraction to be treated.
Preferably said
olefins-aromatics alkylation is carried out at a weight hourly space velocity
("WHSV") of from about 0.1 hi to about 20 III, more preferably from about 0.5
11-1 to
about 2 III.
Preferably, said at least one catalyst is an acid catalyst. Preferably said at
least one
acid catalyst is a heterogeneous catalyst. In one embodiment said
heterogeneous
catalyst is selected from the group consisting of amorphous silica-alumina,
structured
silica-alumina molecular sieves, MCM-41, crystalline silica-alumina zeolites,
zeolites
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of the families MWW, BEA, MOR, MFI and FAU, solid phosphoric acid (SPA),
aluminophosphase and silico-aluminophosphates, zeolites of the AEL family,
heteropolyacids, acidic resins, acidified metals and mixtures thereof. The
preference
for a heterogeneous catalyst facilitates separation of the process liquid and
catalyst. In
accordance with the invention, said at least one acid catalyst should be
selected so that
it has sufficient acid strength to catalyze the olefins-aromatics alkylation
reaction, as
well as an acid strength distribution to retain sufficient activity in contact
with a feed
material that may contain basic compounds. Said at least one acid catalyst
should
further be selected so that the acid sites are accessible to large molecules,
which is
typical of the distillate hydrocarbon fraction. The operating temperature and
catalyst
acid strength distribution should be selected in combination to obtain the
best
compromise between the highest olefins-aromatics alkylation activity and least
catalyst inhibition by compounds in the feed that are strongly adsorbing, or
are basic
in nature.
In yet another embodiment, the invention further comprises at least one
supercritical
paraffinic solvent recovery step. Preferably said step is carried out at a
temperature
higher than the critical temperature of said paraffinic solvent to be
recovered; more
preferably said step is carried out at a temperature from about 20 C to about
50 C
above said paraffinic solvent critical temperature. Preferably said step is
carried out
at a pressure higher than the critical pressure of said paraffinic solvent to
be
recovered, more preferably from about 10% to about 20% higher than said
paraffinic
solvent critical pressure.
BRIEF DESCRIPTION OF THE FIGURES
Figure 1 depicts the present invention, in a preferred embodiment in a field
upgrading
facility.
Figure 2 depicts the system of Figure 1 with the addition of a supercritical
paraffinic
solvent recovery step.
Figure 3 depicts the system of Figure 1 with the addition of a cracking step
and an
olefins treating step.
CA 02837345 2013-12-19
- 15 -
Figure 4 depicts the system of Figure 3 with the addition of a supercritical
paraffinic
solvent recovery step.
Figure 5 depicts the system of Figure 3 with the replacement of the soaker
with a high
efficiency soaker.
Figure 6 depicts the system of Figure 5 with the addition of a supercritical
paraffinic
solvent recovery step.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Referring now to Figure 1, a heavy oil feed stream further comprising gas,
asphaltenes, water and mineral solids 10 is fed into a separator 20 separating
the feed
stream 10 into a gas stream 30, a heavy oil, asphaltenes, water and mineral
solids
stream 40 and a water stream 50. The gas stream 30 is sent for further
treatment. The
water stream 50 is sent to treatment. Heavy oil, asphaltenes, water and
mineral solids
stream 40 is mixed with a paraffinic solvent 60, forming a heavy oil,
asphaltenes,
water, mineral solids and paraffinic solvent stream 70 and introduced into a
mixer 80.
The outlet from mixer 80, a reduced viscosity stream 90, is combined with
additional
paraffinic solvent 100 and a recycle overflow stream 110 containing de-
asphalted oil
and paraffinic solvent from secondary separator 340, resulting in a heavy oil,
asphaltenes, water,-mineral solids, paraffinic solvent and de-asphalted oil
stream 120.
Stream 120 is introduced into mixer 130 resulting in a mixed heavy oil,
asphaltenes,
water, mineral solids, paraffinic solvent and de-asphalted oil stream 140.
Stream 140
is fed into a primary separator 150 producing an overflow de-asphalted oil and
paraffinic solvent stream 160 and an underflow asphaltenes, water, mineral
solids,
residual heavy oil and residual paraffinic solvent stream 170. Optionally,
primary
separator 150 includes a localized heater (not shown) proximate the outlet of
overflow
de-asphalted oil and paraffinic solvent stream 160, creating a localized
temperature
increase resulting in a further asphaltenes reduced overflow de-asphalted oil
and
paraffinic solvent stream 160.
CA 02837345 2013-12-19
- 16 -
The overflow de-asphalted oil and paraffinic solvent stream 160, from primary
separator 150, is depressurized via a control valve 445 and fed into a heater
180 and
then fed into a fractionator 190. A steam stream 200 is also introduced into
the
fractionator 190. The fractionation results in a top paraffinic solvent, water
stream
210 and a bottom de-asphalted oil stream 220. The top paraffinic solvent,
water
stream 210 is processed in a reflux drum 230 to produce a water stream 235 and
a
paraffinic solvent stream 240. Water stream 235 is sent for further treatment.
Paraffinic solvent stream 240 is split into a paraffinic solvent stream 250
and a
paraffinic solvent stream 260. The paraffinic solvent stream 250 is mixed with
de-
asphalted oil stream 220 resulting in an upgraded oil stream 270. Paraffinic
solvent
stream 260 is combined with make-up paraffinic solvent 280 and additional
recovered
paraffinic solvent 410 (resulting from fractionator 370) to form a paraffinic
solvent
stream 290.
Underflow asphaltenes, water, mineral solids, residual heavy oil and residual
paraffinic solvent stream 170 is combined with paraffinic solvent stream 300,
resulting in asphaltenes, water, mineral solids, residual heavy oil, residual
paraffinic
solvent and additional paraffinic solvent stream 310 which is introduced into
a mixer
320 resulting in a mixed asphaltenes, water, mineral solids, residual heavy
oil,
residual paraffinic solvent and additional paraffinic solvent stream 330.
Stream 330 is
fed into a secondary separator 340 producing an overflow de-asphalted oil and
paraffinic solvent stream 110 and an underflow asphaltenes, water, mineral
solids,
residual heavy oil and residual paraffinic solvent stream 350.
Underflow stream 350 is depressurized via control valve 355 and mixed with
steam
360 and introduced into fractionator 370 producing a top paraffinic solvent
water
stream 380 and a bottom asphaltenes, water, mineral solids, residual heavy
oil,
residual paraffinic solvent stream 390. Stream 390 is further sent to
treatment.
Paraffinic solvent water stream 380 is processed in reflux drum 400, producing
paraffinic solvent stream 410 and water stream 405. Water stream 405 is sent
for
further treatment. Stream 410 is combined with additional recovered paraffinic
solvent stream 260 and make-up paraffinic solvent stream 280 resulting in
paraffinic
solvent stream 290. Paraffinic solvent stream 290 is split into paraffinic
solvent
streams 60, 100 and 300.
CA 02837345 2013-12-19
- 17 -
Referring now to Figure 2, the process is similar to the process of Figure 1
with the
addition of a supercritical paraffinic solvent recovery step between primary
separator
150 and heater 180. The supercritical paraffinic solvent recovery step is an
energy
efficient mode of paraffinic solvent recovery resulting in a paraffinic
solvent reduced
stream into fractionator 190. Overflow stream 160 from primary separator 150
is
heated via heater 425 and fed into a supercritical paraffinic solvent recovery
unit 430,
producing a paraffinic solvent stream 440 and a de-asphalted oil, residual
paraffinic
solvent stream 450. Stream 450 is fed into heater 180 as per Figure 1.
Paraffinic
solvent stream 440 is combined with paraffinic solvent stream 260.
For a description of other components depicted in Figure 2 reference is made
to
Figure 1.
Referring now to Figure 3, the process is similar to the process of Figure 1
with the
addition of a cracking step and an olefins treating step as well as the
removal of heater
180. Stream 160 in this Figure is mixed with another stream resulting from a
cracker,
consisting of a heater 490 and a soaker 510 before entering fractionator 190'.
Fractionator 190' results in two bottom heavy residue fraction streams, 220
and 460.
Stream 460 and steam 470 are fed into a heater 490 resulting in a heated
stream 500
which is fed into soaker 510, resulting in a cracked stream 520. Cracked
stream 520 is
mixed into overflow stream 160 forming stream 530, which is introduced into
fractionator 190' resulting in paraffinic solvent water stream 210, light
distillate
stream 540, heavy distillate (HGO) stream 580, and the two bottom heavy
residue
fraction streams 220 and 460. Light distillate stream 540 is combined with
paraffinic
solvent stream 250 forming stream 550. Stream 550 is fed into an olefins
treating unit
560, resulting in a low olefin and low di-olefin content stream 570. Streams
570, 580
and 220 are combined, forming an upgraded oil stream 270.
For a description of other components depicted in Figure 3 reference is made
to
Figure 1.
Referring now to Figure 4, the system is similar to Figure 3 except a
supercritical
paraffinic solvent recovery step is added between primary separator 150 and
CA 02837345 2013-12-19
- 18 -
fractionator 190' of Figure 3. Overflow stream 160 from primary separator 150
is
heated via heater 425 and fed into a supercritical paraffinic solvent recovery
unit 430,
producing a paraffinic solvent stream 440 and a de-asphalted oil, residual
paraffinic
solvent stream 450. Stream 450 is combined with cracked stream 520 resulting
in
stream 530. Stream 440 is added to paraffinic solvent stream 260.
For a description of other components depicted in Figure 4 reference is made
to
Figures 1, 2 and 3 described above.
Referring now to Figure 5, the process is similar to the process of Figure 3
with the
replacement of soaker 510 with a high efficiency soaker 590 resulting in an
asphaltenes, gases and olefins content reduced stream into fractionator 190'.
Heated
stream 500 and steam 600 are fed into high efficiency soaker 590, resulting in
a top
light cracked stream 520 and a bottom heavy cracked stream 610. Top light
cracked
stream 520 is mixed into overflow stream 160 forming stream 530, which is
introduced into fractionator 190' resulting in a paraffinic solvent water
stream 210,
light distillate stream 540, heavy distillate (HGO) stream 580, and the two
bottom
heavy residue fraction streams 220 and 460. Bottom heavy cracked stream 610 is
combined with stream 110 prior to mixer 130 and fed into primary separator
150.
For a description of other components depicted in Figure 5 reference is made
to
Figure 3 described above.
Referring now to Figure 6, the system is similar to Figure 5 except a
supercritical
paraffinic solvent recovery step is added between primary separator 150 and
fractionator 190' of Figure 5. Overflow stream 160 from primary separator 150
is
heated via heater 425 and fed into a supercritical paraffinic solvent recovery
unit 430,
producing a paraffinic solvent stream 440 and a de-asphalted oil, residual
paraffinic
solvent stream 450. Stream 450 is combined with light cracked stream 520
resulting
in stream 530 which is fed into fractionator 190'. Stream 440 is added to
paraffinic
solvent stream 260.
For a description of other components depicted in Figure 6 reference is made
to
Figure 5 described above.
CA 02837345 2013-12-19
- 19 -
In any of the above Figures, for the generation of water droplets, a water
feed 65 is
introduced into primary separator 150 and secondary separator 340 (see Figure
1).
EXAMPLES
The present invention is further illustrated in the following examples.
Table 1 Heavy Oil Recovery (Asphaltenes + Water + Mineral Solids Separation)
-
Feed Heavy Oil Recovery (Asphaltenes = Water + Mineral Solids
Separation)
Athabasca Bitumen
25%w Bitumen, 75%w Water Example 1.1 Example 1.2 Example 1.3
Example 1.4
Paraffinic Solvent n-Pentarie Condensate n-liesane n-
Heptane
Paraffinic Solvent sp.gr. la 15.56 C 0.6310 0.6540 0.6638
0.6882
Extraction 7, C 80 80 50 80
Paraffinic Solvent/Bitumen, why 3.09 5.60 4.14 4.37
Recovered Oil Asohaitenes Recovered Oil Asphaltenes Recovered Oil Asphaltenes
Recovered OH Asphaltenes
Recovered, %w 83.30 16.70 83.61 16.39 83.45
16.55 83.45 16.55
Recovered, %v 85.97 14.03 86.23 13.77 86.10
13.90 86.10 13.90
API 8.00 12.47 12.38 12.42 12.42
sp.gr. 0 15.56 C 1.0143 0.9829 1.2071 0.9834 1.2078 0.9832
1.2075 0.9832 11075
Viscosity, cSt @ 7.5 C 8.2E+06 47430 53460 49280
47640
Viscosity, cSt @ 20 C 7.9E+05 8810 9750 9100
81340 Cl
MCR %w 14.33 7.17 50.04 7.25 5044 7.21 50.24
7.21 50.24
C54nsoluble Asphaitenes, %w 15.47 1.31 86.10 1.85 84.95
1.45 86.18 1.24 87.24
Composition, %vi
0
C 83.62 84.16 80.96 84.16 80.90 84.16
80.93 84.16 80.93 n.)
co
li 10.28 10.75 7.92 10,74 7.91 10.74
7.91 10.74 7.91 W
S 4.84 4.32 7.45 4.33 7.46 4.32 7.46
4.32 7.46 --.1
i
N 0.47 0.31 1.24 0.31 1.26 0.31 1.25
0.31 1.25 W
O 0.76 0.45 2.28 0.45 2.31 0.45 2.29
0.45 2.20 IV ilai
,NI + V, pprnw 344 104 1544 _ 104 1569 _ 104 1557
104 1557 C> U1
n.)
Feed Heavy Oil Recovery (Asphaltenes + Water + Mineral Solids
Separation) 0
I--,
Athabasca Bitumen
254w Bitumen, 7514w Water Example 2.1 Example 2.2 Example 2.3
Example 2.4 W
I
Paraffinic Solvent -Pentane Condensate n-Hexane n-Heptane
I--,
Paraffinic Solvent sp.gr. gg 15.56 C 0.6310 0.6540 0.6638
0.6882 1\.)
I
Extraction 7, C 100 100 100 100
Paraffinic Solvent/Bitumen, We/ 2.83 5.29 4.03 4.45
I--,
lt3
Recovered 011 Asphaltenes Recovered 011 Asphaltenes Recovered 011 AsOltaftenes
Recovered Oil Mphaltenea
Recovered, 14w 83.45 16.55 83,76 16.24 83.61
16.39 83.92 16.08
Recovered, =Av 86.10 13,90 86.31 13.63 86.23
13.77 86.50 13,50
API 8.00 12.42 12.34 12.38 12.30
sp.gr. gt 15.56 C 1.0143 0.9832 1.2075 0.9837 1.2082 0.9834
1.2078 0.9840 1.2086
Viscosity, cSt @ 7.5 C 8.2E+06 47560 54030 51250
50480
Viscosity, cSt @ 20 C 7.9E+05 8830 9850 9410 9300
MCR, .4w 14.33 7.21 50.24 7.29 50.65 7.25
50.65 /.37 51.07
C54nsoluble Asphattenes, %w 15.47 1.23 87.27 1.82 85.81
1.59 86,28 1.30 89.40
Composition. %w
C 83.62 84.16 80.93 84.16 80.88 84.16
80.90 84.16 80.85
H 10.28 10.74 7.91 10.74 7.91 10.74
7.91 10.73 7.90
S 4.84 4.32 7.46 4.33 7.47 4.33 7.46
4.34 7.48
N 0.47 0.31 1.25 0.31 1.27 0.31 1.26
0.31 1.28
O 0.76 0.45 2.29 0.45 2.32 0.45 2.31
0.45 2.33
NI + V, ppmw 344 104 1557 104 1582 104 1570 105
1595
=
Table 1 Heavy Oil Recovery (Asphaltenes + Water + Mineral Solids Separation)
(continued)
Feed Heavy Oil Recovery (Asphaltenes + Water + Mineral Solids
Separation)
Athabasca Bitumen -
25%w Bitumen, 75%w Water Example 3.1 Example 3.2 Example 3.3
Example 3.4
Paraffinic Solvent n-Pentane Condensate n-Hexane n-Haptana
Paraffinic Solvent sp.gr. a 15.56 C 0.6310 0.6540 0.6638
0.6882
Extraction 7, C 130 130 130 130
Paraffinic Solvent/Bitumen, why 2.29 4.41 3.64 4.45
Recovered 011 Asphaltenes Recovered 05 Aeohaltenes Recovered 011 Asphaltenes
Recovered 011 Asphaltenes
Recovered, %w 83.76 16.24 84.07 15.93 83.76
16,24 84.23 15.77
Recovered, %v 86.37 13.63 86.63 13.37 86.37
13.63 88.77 13.23
API 8.00 12.34 12.25 12.34 12.21
sp.gr. @ 15.56C 1.0143 0.9837 1.2082 0.9843 1.2089
0.9837 1.2082 0.9846 1.2093
Viscosity, cSt @ 7.5 C 62E+08 48240 52870 51380
53310 =
Viscosity, cSt 84 20 C 7.9E+05 8940 9670 9430
9740 C)
NCR, Sinv 14.33 7.29 50.65 7.37 51.07 7.29
50.65 7.41 51.28
C54nsoluble Asphaltenes, %w 15.47 1.12 89.48 1.49 89.25
1.51 87.48 1.44 90.41
COrnpositkrn. %w
0
n.)
c 83.62 84.16 80.88 84.16 80.82 84.16
80.88 84.16 80.79 CO
H 10.28 10.74 7.91 10.73 7.90 10.74
7.91 10.72 7.90 W
S 4.84 4.33 7.47 4.34 7.49 4.33 7.47
4.34 7.50 ...3
14 0.47 0.31 1.27 0.31 1.28 0.31 1.27
0.31 1.29 1 W
O 0.76 0.45 2.32 0.45 2.35 0.45 2.32
0.46 2.36 1,..) ib=
,-+
NI + V, ppmw 344 I 104 1582 105 1609 104 1582
105 1623 U1
i
n.)
Feed Heavy 011 Recovery (Asphaltenes + Water + Mineral Solids
Separation) 0
1-4
Athabasca Bitumen
W
2514w Bitumen, 75%w Water
Example 4.1 Example 42 Example 4.3
Example 4.4
1
'.
Paraffinic Solvent n=Pentane Condensate n-Hexane n-Heptane
1-4
Paraffinic Solvent sp.gr. 0 15.5VC 0.6310 0.6540 0.6638 0.6882
"
1
Extracgon 7, C 180 180 180 180
1-4
Paraffinic Solvent/Bitumen, whv 1.30 2.48 2.46 3.70
lt3
Recovered 011 Assffialtenes Recovereg Oil Asphaltenes Recovered 011 Aspha flea
_Recovered 011 Asphaltenes
Recovered, %w 83.92 16.08 84.38 15.62 84.07
15.93 84.38 15.62
Recovered, %v 86.50 13.50 86.90 13,10 86.63
13.37 86.90 13.10
API 8.00 12.30 12.17 12.25 12.17
sp.gr. 15.56 C 1.0143 0.9840 1.2086 0.9849 1.2096
0.9843 1,2089 0.9849 1.2096
Viscosity, cSt et 7.5 C 8.2E+06 45240 49510 48290
54670
Viscosity, cSt igli 20 C 7.9E+05 8470 9150 8950 9950
NCR, 14w 14.33 7.33 50.86 7.45 51.50 7.37
51.07 7.45 51.50
C54nsoluble Asphattenes, %w 15.47 0.62 92.97 0.89 94.23
0.93 92.20 1.50 90.94
Comoosition. 'My
C 83.62 84.16 80.85 84.15 80.76 84.16
80.82 84.15 80.76
11 10.28 10.73 7.90 10.72 7.89 10.73
7.90 10.72 7.89
S 4.84 4.34 7.48 4.35 7.51 4.34 7.49
4.35 7.51
14 0.47 0.31 1.28 0.31 1.30 031 1.29
0.31 1.30
O 0.76 0.45 2.33 0.46 2.37 0.45 2.35
0.46 2.37
NI +V, pprnw 344 105 1895 105 1636 105 1609 105
1636
CA 02837345 2013-12-19
- 22 -
Figure 7
Paraffinic Solvent/Bitumen Ratio vs Temperature
6.00
1
--....*N.,
S ____________ X ________
, X
..,,
;
1 'N.=.,
¨=¨n-05
I lop
¨id- ¨ Condensate
.1
(?) 2.00
.g
c
1
z 1.00
0.00 1 ___
70 90 110 130 150 170 190
Temperature ( C)
CA 02837345 2013-12-19
- 23 -
Table 2 System of Figure 1 vs. Prior Art System
Example 5
Feed Heavy Oil Recovery Field Upgrader Products
Athabasca Bitumen
25%w Bitumen, 75%w Water
Paraffinic Solvent Condensate
Paraffinic Solvent sp.gr. @ 15.56T 0.6540
Extraction T, T 100
Paraffinic Solvenaltumen, wilt.. 5.29
Diluent Condensate
Diluent/Recovered Oil (DAo), w/w 0.20
Diluent %v 23
Recovered Oil MAO) Asphaltenes Total Asphaltenes Rejected Upgraded Oil
Properties
Weight on Bitumen, %w 100.00 83.76 16.24 16.24 100.51
Volume on Bitumen, %v 100.00 86.37 13.63 13.63 112.65
API 8.00 12.34 23.03
sp.gr. @ 15.56 C 1.0143 0.9837 1.2082 1.2082 0.9157
Viscosity, cSt @ 7.5T 8.2E+06 54030 350
Viscosity, eSt @ 20 C 7.9E+05 9850 148
MCR, %w 14.33 7.29 50.65 50.65 6.08
C5.4nsoluble Asphaltenes, %w 15.47 1.82 85.87 85.87 1.52
Composition, %w
C 83.62 84.16 80.88 80.88 85.52
H 10.28 10.74 7.91 7.91 10.23
S 4.84 4.33 7.47 7.47 3.61
N 0.47 0.31 1.27 1.27 0.26
O 0.76 0.45 2.32 2.32 0.38
Ni + V, ppmw 344 104 1582 1582 87
Prior Art
Athabasca Bitumen
25%w Bitumen, 75Ow Water
Paraffinic Solvent
Paraffinic Solvent sp.gr. @ 15.56 C
Extraction T, T
Paraffinic Solvent/Bitumen, w/w
Diluent Condensate
Diluent/Bitumen, why 0.32
Diluent %v 34
Total Asphaltenes Rejected Dilbit
Properties
Weight on Bitumen, %w 100.00 0.00 132.49
Volume on Bitumen, %v 100.00 150.38
API 8.00 25.25
sp.gr. @ 15.56 C 1.0143 0.9027
Viscosity, at 7.5 C 8.2E+06 350
Viscosity, at ( ) 20 C 7.9E+05 158
MCR, %w 14.33 10.82
C5-Insoluble Asphaltenes, %w 15.47 11.68
Composition. %w
C 83.62 85.75
H 10.28 9.64
s 4.84 3.65
N 0.47 0.35
O 0.76 0.57
Ni ... V. ppmw 344 260
Table 3 System of Figure 3
Example 6
Feed Harry 041Recovary DA0 Bypassing Thomal
Cracker - Thermal Cracking Olefins Treating = Aikylation 55111
Pogrrider Pradacts
_
Affirms. Bilumeil
2514se Bauman, 751kir Watar
Paraffinic Want Condensate
,
Paraffinic Soirent spit. 0 15.56=C 88540
Extraction 7,4C 110
Paraffinic Soirenggityman, veer 248
Heavy PAO 45.1C+ $y094.6410 Thermal Cracker, 94947
Thermal Coavars4an of 560.C. Fra4550n:
0
-Total. %a 55*
- Per Pins, Ur 55
Recycle Weeder 45
0
L1415V, If. 5
n.)
WAR., ..0 4/2
CO
Olafina Convarsion, %sr
100 .....1
W
i
Olefins Treating ProductVcdume 1049,945
321
1,..)
W
..P.=
04
i
Recovered ON (01.01 Aaalialtanes Light PAO 454.C. Ham PAO 454.C4 Heavy PAO
454"Ce Feed C3. Gas Product. p.0116,84144 AaDhaloneeR=luted C4 = 343 C Fetti
gleffils Alkviadon Products C3- Gas 10945i Asohaltenes Relactod 0d64 08 5-
71
Roo-Via
IV
Weight on Bitumen, 446, 10019 4431 15.62 32.16 311 4861
3,34 45.27 5.00 30.50 3268 3.34 15,62 8564 0
Volume on Bitumen, 'Ay 150.04 14.60 13.10 3519 217
48.04 5929 3573 34.47 13.10 87.10 I-1
API 015 12.17 21.50 637 637 2225
31.96 2416 10.29 W
ap.gr. fa 15.510C 1.0143 0.9649 1.21191 0.9243 1.5263
11243 6.0165 5.6155 0.8974 12099 0.9354 I
Viscosity, at 6 7..PC 0.2E406 49510 51 93E408 5.31.011
136 4 10 216 I-1
Viscosity, cSt 11 UPC 71E405 01511 21 2.2E407 2.2E407
62 3 7 126 NJ
10012,%w 1433 7.45 11.50 0.00 12.03 1213
13.49 011 666 51.50 612 I
05.00s00.60. Asidtaltame, low 15.47 4.89 9423 0.00
144 144 0.81 016 0.00 9423 5.02 I-1
Ceragesitiod.0
l0
C 83.62 14,15 1025 05.41 8330 4326
65.21 04.17 80.17 90.76 6521
H 1028 18.72 7.69 11.48 1025 10.25
9.65 10.99 1019 7.09 1646
17I 414
4.35
7.51
2.92
5.22
5.22
3.95
2.42
009
2.42
7.51
1.30
311
047 0.31 1.30 5.10 0.45 545
0,49 016
0,33
o 2.74 OA 2.37 0.09 1119 011
0.67 6.13 0.13 2.37 0.44
IA 45, ppm 0 0 . 344 105 1830 169
149 204 0 1636 121
New , 454.....11946 overclodunliztliwl Will rAVA,Affi=I=61111.414=Pd.
Table 4 System of Figure 5
hemp]. 7
Feed Heavy Oil Rummy 0643 Bypassang
Thwrial Crimea Thmhal Cracking 013fins Treating -Alkylagon Fish]
Upgrader Preduel3
.
Athabasca Shinn..
UV* Bitanosn, 7514000044
Paraffinic Solvent n.P4nt8ns
Paraffinic Solvarisp.gr.(9 15.54K 03310
Extraction 7,C SI
Paraffinic Solventhltumen, w/vi 3.09
Heavy SAO 454.C. Bypassing Theme Cracker, 13w 7
CO
Therm. Convinsion of 560*Co Racine.:
-1o10,11333 or
- Par Pus, 'Mc 45
0
&cycle Ratio ses 4.7
n.)
LBW 13' 1
CO
V01157,..0 407
W
.....3
Olefin, Conversion, %w
100 . W
0131ins Treating Product Solon* Loss, %a
3.31 0.
1,J
(...ri
Cri
R....snd oil tool AsolialtaM U.00000 454'C- Busy DAB WC+ Hens SAO 454`C. Feed
C3. Gas Preen I. C4+ Oil Prodegb Asohaltenes Redacted C4 = urc Feed 0133ns
Alkvbfilon Produots gzag Total Asphalt...3n Selected 1085114.4 001
mean,0
Weight on Bltumon, 1436 100.00 03.30 16.70 33.16 3.54
47.60 2.31 40.84 3.95 27.85 27.85 2.81 20.58 70.94
Seisms on Oilmen, %v 1036 5537 14113 3529 3.51 47.16
4316 3.41 32.55 31.46 17.44 $3.41 W
API SAO 12.47 31.56 6.73 173 24.75
31.55 211.19 20.62 I
sp.gr..15.551S 1.0143 0.6529 1.3071 0.9243 1.0237 13237
0.0056 1.179 03677 0.5573 12010 0.0352
Vlsccally. cSte 7.5*C 82E416 47430 51 63E411 4.6E306 50
4 10 159 n.)
Visco02y, 3St 0 MC 78E005 3310 20 2.4E07 2.4E307 se
3 7 74 I
RICR,%w 14.33 7.17 58334 0.00 11.67 11.67 0.66
52.77 0.00 030 50.57 5.70
C54..seleble Asphaltenas.51a. 15.47 1.31 61618 0.00 2.13
2.13 BOO 92.64 030 0.00 87.31 0.10 l0
C00000000 140
C 33.62 83.15 50.96 85.41 53.38 83.38
85.17 32.33 8000 58.00 81.22 65.19
11 10.28 10.75 732 11.48 18.29 18.29 1351
7.77 11.14 1124 7.69 10.59
S 4.34 4.32 7.35 2.92 5.20 5.20
3.57 720 286 2.44 740 3.53
N 6.47 0.31 1.24 0.15 0.45 0.45
0.41 123 0.09 0.09 126 6.23
o 0.78 0.45 2.211 0,09 0.87 067
013 1.21 022 0.13 235 5.41
Ni + V, perms 344 104 1544 0 1116 166 78
1573 0 4 1549 SO
Not.= : 454.C. mood.' Is neyelml und stabollatal !VA. commrsbn b selilowd.
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Examples 1.1 ¨ 4.4, listed in Table 1 demonstrate the asphaltenes, water, and
mineral
solids separation from heavy oil under different conditions. The examples
illustrate
separation using four paraffinic solvents (n-05, gas condensate, n-C6 and n-
C7) at
four temperatures (80 C, 100 C, 130 C and 180 C). The results indicate that
for a
preferred target of complete removal of the asphaltenes fraction, generally a
lower
paraffinic solvent to bitumen ratio is required as the temperature increases
as it is
depicted in Figure 7. The results also show a significant improvement in the
properties of the de-asphalted oil ("DAO") from the original feed, resulting
in a de-
asphalted oil with an increased API, reduced viscosity, and reduced micro-
carbon,
sulfur, nitrogen, nickel and vanadium content. The properties of the de-
asphalted oil
were similar in the above examples.
Example 5 shown in Table 2, compares the system of Figure 1 with the Prior Art
system. Table 2 depicts the system of Figure 1, Athabasca bitumen treated for
heavy
oil, asphaltenes, water, mineral solids separation using gas condensate as the
paraffinic solvent for the solvent de-asphalting step and the prior art system
of
upgrading Athabasca bitumen using gas condensate as a diluent, forming Dilbit
(34%v condensate). As is shown, the system of the present invention results in
an
upgraded oil containing a lower amount of gas condensate (23%v) meeting
density
and viscosity values consistent with pipeline specifications as discussed
herein, as
well as having an economic advantage (e.g. lower gas condensate volume in the
upgraded oil) compared to the prior art.
Example 6, shown in Table 3, depicts the system of Figure 3. Athabasca bitumen
was
treated for heavy oil, asphaltenes, water, mineral solids separation using gas
condensate as the paraffinic solvent with a paraffinic solvent to bitumen
ratio of 2.48
w/w and a temperature of 180 C resulting in a DAO.
93%w of the heavy 454 C+ fraction of the DAO was treated through thermal
cracking
at a LHSV of 5 111 and a weighted average bed temperature ("WABT") of 442 C
resulting in 55%w conversion of the 560 C+ fraction per pass. Any portion of
the
454 C+ fraction remaining subsequent to thermal cracking was recycled to the
thermal cracker to undergo further conversion until a stated 95%w total
conversion of
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the 560 C+ fraction in the original heavy 454 C+ feed was achieved. This
recycling
eventually resulted in a total feed to the thermal cracker of 4.5 times the
original
93%w of the heavy 454 C+ fraction.
The light C4-343 C cracked product together with the light C4-343 C fraction
of the
DAC, were sent for olefins-aromatics alkylation to achieve essentially 100%
olefins
conversion. The resultant olefins-aromatics alkylation product was blended
with the
remaining 343 C+ fraction from both the thermal cracker and the fraction
bypassing
the thermal cracker resulting in the final upgraded oil.
Example 7, shown in Table 4, depicts the system of Figure 5. Athabasca bitumen
was
treated for heavy oil, asphaltenes, water, mineral solids separation using gas
condensate as the paraffinic solvent with a paraffinic solvent to bitumen
ratio of 3.09
w/w and a temperature of 80 C resulting in a DAO.
93%w of the heavy 454 C+ fraction of the DAO was treated through thermal
cracking
at a LHSV of 1 111 and a weighted average bed temperature ("WABT") of 407 C
resulting in 45%w conversion of the 560 C+ fraction per pass. In contrast to
Example
6, the incorporation of a high efficiency soaker resulted in a top light
cracked stream
and a bottom heavy cracked stream. The bottom heavy cracked stream consisting
of
both thermally cracked generated asphaltenes and other heavy hydrocarbons was
recycled through the heavy oil, asphaltenes, water, mineral solids separation
process
allowing for the further rejection of asphaltenes and for the recovery of the
other
heavy hydrocarbons. Any portion of the 454 C+ fraction remaining was recycled
to
the thermal cracker to undergo further conversion until a stated 95%w total
conversion of the 560 C+ fraction in the original heavy 454 C+ feed was
achieved.
This recycling eventually resulted in a total feed to the thermal cracker of
4.7 times
the original 93%w of the heavy 454 C+ fraction.
The light C4-343 C cracked product together with the light C4-343 C fraction
of the
DAO were sent for olefins-aromatics alkylation to achieve essentially 100%
olefins
conversion. The resultant olefins-aromatics alkylation product was blended
with the
remaining 343 C+ fraction from both the thermal cracker and the fraction
bypassing
the thermal cracker resulting in the final upgraded oil.
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The data in Examples 5 through 7 show an improvement to the properties of the
upgraded oil, from the original feed, with an increased API, reduced
viscosity, and
reduced micro-carbon, sulfur, nitrogen, nickel, vanadium and olefins content,
while
still exhibiting high liquid volume product yields, as well as an economic
advantage,
over the prior art.
As many changes can be made to the preferred embodiment of the invention
without
departing from the scope thereof, it is intended that all matter contained
herein be
considered illustrative of the invention and not in a limiting sense.
