Note: Descriptions are shown in the official language in which they were submitted.
CA 02520943 2005-09-23
METHOD FOR DIRECT SOLVENT EXTRACTION OF HEAVY OIL FROM OIL
SANDS USING A HYDROCARBON SOLVENT
TECHNICAL FIELD
This invention relates to the field of mining. In particular, extracting heavy
oil and/or
bitumen from oil sands using hydrocarbon solvents.
BACKGROUND
US 6,214,213 to Tipman et al. describes a treatment process for a froth
produced by a
water extraction process practiced on oil sands in which the froth, having
been recovered from
a primary separation vessel, is treated by adding a paraffinic solvent to the
froth and mixing the
solvent with the froth to induce inversion.
US 6,007,708 to Allcock et a~. describes a method for recovering bitumen from
oil
sands by mixing mined oil sand with water to produce a slurry and pumping the
slurry through
a pipeline to a primary separation vessel and separating the slurry in the
primary separation
vessel into froth, middlings and tailings.
CA 857306 to Dobson describes a hot water process for treating bituminous tar
sands.
Dobson describes forming a mixture of bituminous sands and water and
separating the mixture
into a primary froth, a middlings layer and a tailings layer followed by
further processing of the
middlings layer.
CA 2,445,645 to Bara et al. describes a process for treating an aqueous
aerated oils
sand slurry by concentrating bitumen by injecting the slurry into an elongate
closed vessel,
passing the injected slurry through the elongate closed vessel and into a
separation vessel.
UK 2,044,796 to Robinson et al. describes a process for extracting bitumen
from oil
sands by conditioning the oil sands with cold water, removing the resulting
dispersion of clay
and further treating with hot water.
US 3,527,692 to Titus describes a method for simultaneous transportation and
recovery
of shale oil from a slurry by transporting the slurry in a pipeline and
heating the slurry to a
temperature of between 550°F to 600°F.
US 3,556,980 to Clark et al. describes a process for removing water from a
bituminous
emulsion and recovering the bitumen by imparting shearing energy to an aqueous
bituminous
emulsion to coalesce and remove the water.
CA 02520943 2005-09-23
US 3,575,842 to Simpson describes a process for extracting a soluble component
from
a particulate solid material by preparing a slurry; passing the slurry, in a
series of slugs
separated by slugs of gas, in a conduit; withdrawing and injecting liquid at
various points along
the conduit; and collecting the withdrawn liquid.
US 3,925,189 to Wicks describes an improved method of pipeline transporting
and
recovering hydrocarbons from tar sands. Wicks describes mixing the tar sands
with a solvent
to form a slurry and pumping the slurry uphill at an angle of between
5° and 7° to the
horizontal to encourage release of the hydrocarbons for the slurry by the time
the slurry has
reached the terminal end of the pipeline.
US 3,993,555 to Park et al. describes a method for extracting bitumen from tar
sand by
contacting the bitumen in the tar sand with a solvent having a freezing point
below the freezing
point of water in the tar sand and subsequently separating the solvent-bitumen
mixture by
freezing the water in the tar sand.
US 4,946,597 to Sury describes a process for separating a recovering bitumen
from tar
sands by mixing cold slurry with a flotation agent and a frothing agent and
subjecting the
resulting mixture to froth floatation for recovery of a bitumen product.
US 5,039,227 to Leung et al. describes a mixing circuit for slurrying oil sand
in water.
Leung et al. describes a process for mixing the oil sand with water to produce
a slurry by
introducing a stream of recycled slurry into a circular mixing chamber formed
by an
open-topped mixer vessel to vortex water and oil sand into a slurry.
US 5,264,118 to Cymerman et al. describes a process for simultaneously
transporting
and conditioning oil sands by mixing the oil sand with hot water, entraining
air into the mixture
to form an aerated slurry and pumping the slurry through a pipeline.
US 5,626,743 to Humphreys describes a hot water extraction process for
extracting
bitumen from tar sands. Humphreys describes providing a slurry comprising tar
sand, hot
water and a conditioning agent, mixing and aerating the slurry to form a froth
and separating
the froth from the slurry.
US 5,746,909 to Calta describes a process for recovering tar from tar sands by
forming
a slurry comprising tar sand, an anionic surfactant, at least one high boiling
alkane and water.
The slurry is mixed to form a mixture of tar-free sand and an emulsion
comprising tar. The
emulsion is separated from the sand and then further treated to recover the
tar.
US 5,770,049 to Humphreys describes a process for extracting bitumen from tar
sands
by providing a slurry comprising tar sand, hot water and a conditioning agent
including an
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CA 02520943 2005-09-23
alkali metal bicarbonate and mixing and aerating the slurry to produce a froth
and separating
the froth from the slurry.
SUMMARY
This invention is based in part on the discovery that an extraction of a heavy
oil from an
oil sand ore directly into a solvent phase is efficient and that a solubility
of a heavy oil fraction
of an oil sand ore in a solvent is more effective for extracting heavy oil
from the oil sand ore
than ablation of the oil sand ore. The percent of heavy oil recovery is
independent of ore
grade. Secondary floatation, addition of air, caustic, diesel, conditioning
agents, and frothing
agents are not required to increase recovery of heavy oil.
In various embodiments, there is provided a method comprising: a) mixing a
slurry with
at least one hydrocarbon solvent thereby producing a solvent-slurry mixture;
b) agitating the
solvent-slurry mixture thereby producing an emulsion; and c) providing the
emulsion to a
primary separation facility. The method may further comprise preparing the
slurry by mining
an oil sand deposit to produce a mined oil sand and mixing the mined oil sand
with water. The
method may further comprise recovering a heavy oil fraction from the emulsion
at the primary
separation facility.
In another embodiment, there is provided a method comprising: a) preparing a
slurry
having a temperature of between about 5°C and about 25°C by
mining an oil sand deposit to
produce a mined oil sand and mixing the mined oil sand with water; b) mixing
the slurry with
at least one hydrocarbon solvent thereby producing a solvent-slurry mixture;
c) agitating the
solvent-slurry mixture by transporting the solvent-slurry mixture along a
pipeline, thereby
producing an emulsion; and d) providing the emulsion to a primary separation
facility. The
method may further comprise recovering a diluted heavy oil fraction from the
emulsion at the
primary separation facility. The mixing may also be provided in the pipeline.
In various embodiments, there is provided a method comprising: a) preparing a
slurry
having a temperature of about 5°C to about 25°C by mining an oil
sand deposit to produce a
mined oil sand comprising a heavy oil adhered to an inert particles and mixing
the mined oil
sand with water; b) mixing the slurry with at least one hydrocarbon solvent to
produce a
solvent-slurry mixture; c) agitating the solvent-slurry mixture by
transporting the solvent-slurry
mixture along a pipeline, to produce an emulsion comprising i) a solution of
the heavy oil
dissolved in the hydrocarbon solvent ii) an aqueous phase and iii) the inert
particles; and d)
separating the phases of the emulsion into a diluted heavy oil fraction
comprising the heavy oil
CA 02520943 2005-09-23
and a tailings fraction by applying a phase separation force over a phase
separation period;
wherein the heavy oil is separated from the inert particles by dissolving the
heavy oil in the
hydrocarbon solvent. The mixing may be provided in the pipeline. The pipeline
may be a
hydrotransport pipeline. The agitating may have a duration of at least two
minutes.
In various embodiments, the phase separation force may be a G-force of at
least 1, a
G-force of between 1 and 4000, a G-force of between 1 and 1000, or a G-force
of between 1
and 10. The phase separation force may be gravity, a centrifugal force or a
centripetal force.
In various embodiments, the phase separation period is at least 4 minutes,
less than
4 minutes, or between about 1 to about 4 minutes.
In various embodiments, the diluted heavy oil fraction may be recovered from
the
emulsion at a primary separation facility. The primary separation facility may
be a primary
separation vessel. The primary separation vessel may have a pressure rating
greater than the
vapour pressure of the hydrocarbon solvent at a maximum operating temperature.
The primary
separation vessel may have a vapour recovery unit. The primary separation
vessel may have a
volume that provides a minimum emulsion residence time of four minutes. The
primary
separation facility may be a hydrocyclone facility.
In various embodiments, the at least one hydrocarbon solvent may be a light
hydrocarbon solvent. The at least one hydrocarbon solvent may be selected from
the group
consisting of: a branched alkane, an unbranched alkane, a cyclic alkane, and
an aromatic
hydrocarbon. The at least one hydrocarbon solvent may be at least one C4 to C
16 alkane. The
at least one hydrocarbon solvent may be at least two hydrocarbon solvents
selected from the
group consisting of: a branched alkane, an unbranched alkane, a cyclic alkane,
and an aromatic
hydrocarbon. The at least one hydrocarbon solvent may be a paraffinic solvent.
The at least
one hydrocarbon solvent may be a naphthenic solvent. The at least one
hydrocarbon solvent
may be selected from the group consisting of: benzene, toluene, xylene and
ethyl benzene.
The at least one hydrocarbon solvent may be selected from the group consisting
of: n-pentane,
naphtha, VarsolTM, paint thinner, NapthaTM, paraffinic solvent, reformate and
hexane.
In various embodiments, the at least one hydrocarbon solvent may have a
density of
less than 0.9 g/mL, of between about 0.4 g/mL and about 0.9 g/mL, of between
about 0.5 g/mL
and about 0.8 g/mL, or of between about 0.6 g/mL and about 0.7 g/mL.
In various embodiments, the emulsion may have a temperature from about
5°C to about
25°C. The water may have a temperature from about 5°C to about
25°C.
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CA 02520943 2005-09-23
In various embodiments, the slurry may have a density of about 1.1 g/cc to
about
1.7 g/cc, of about 1.3 g/cc to about 1.65 g/cc, or of about 1.4 g/cc to about
1.5 g/cc.
In various embodiments, the emulsion may have a solvent to bitumen ratio of
about
1.5:1 by weight to about 3:1 by weight, of about 1.5:1 by weight to about
2.5:1 by weight, or of
about 2:1 by weight.
As used herein the term "hydrocarbon solvent" refers to a solvent that
contains
hydrogen and carbon, is capable of dissolving heavy oil and will separate from
an aqueous
phase when subjected to a phase separation force, such as gravity or
centrifugal forces. The
term "hydrocarbon solvent" also encompasses the term "light hydrocarbon
solvent" as is
commonly used in the art. A "light hydrocarbon solvent" is typically any non-
polar,
hydrophobic solvent that has a density less than 0.9 g/ml or less than diesel
when measured at
standard temperature and pressure.
As used herein, the term "paraffinic solvent" refers to an alkane solvent of
the general
formula CnH2"+2. The term "paraffinic solvent" is typically referred to by a
skilled practitioner
of the art as a blend of straight chain and/or branched chain and/or cyclic
alkanes and/or
alkenes and/or alkynes containing between 4 to 8 carbon atoms and the blend
does not contain
aromatic compounds. All of these definitions are intended to be covered by the
single term
"paraffinic solvent".
As used herein the term "naphthenic solvent" refers to a cycloalkane solvent
of the
general formula C"H2". A "naphthenic solvent" also encompasses "naphtha" as
used by those
skilled in the art. The term "naphtha" as used in the art, refers to a blend
of hydrocarbon
solvents having between 5 to 16 carbons and may contain aromatic groups. All
of these
definitions are intended to be covered by the single term "naphthenic
solvent".
As used herein the term "heavy oil" refers to the primary hydrocarbon
component of an
oil sand ore. These are typically types of crude oil, a naturally occurring
petroleum. Crude oil
comprises pentanes and heavier hydrocarbons. Crude oil is commonly classified
as light,
medium, heavy or extra heavy, referring to a gravity as measured on the
American Petroleum
Institute (API) Scale. The API gravity is measured in degrees and is
calculated using the
formula API Gravity = (141.5/S.G.) - 131.5.
Light oil has an API gravity higher than 31.1 ° (lower than 870
kilograms/cubic metre),
medium oil has an API gravity between 31.1° and 22.3° (870
kilograms/cubic metre to 920
kilograms/cubic metre), heavy oil has an API gravity between 22.3° and
10° (920
kilograms/cubic metre to 1,000 kilograms/cubic metre), and extra heavy oil
(e.g. bitumen) has
CA 02520943 2005-09-23
an API gravity of less than 10° (higher than 1,000 kilograms/cubic
metre). The Canadian
government has only two classifications, light oil with a specific gravity of
less than 900
kilograms/cubic metre (greater than 25.7° API) and heavy oil with a
specific gravity of greater
than 900 kilograms/cubic metre (less than 25.7° API). As used herein
"heavy oil" may refer to
both heavy and extra heavy oils or any oil having an API less than
22.3°.
As used herein a "phase separation force" is a force that can be measured in G-
forces.
Gravity, centrifugal force and centripetal force are examples of phase
separation forces.
As used herein a "phase separation period" is a duration of time required for
the
separation of a solution of heavy oil and hydrocarbon solvent to separate from
an aqueous
phase. The duration of time required may be dependent on the relative
densities of the two
phases and the magnitude of the phase separation force applied.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is process flow diagram of methods described herein.
Figure 2 is a graph showing solvent to heavy oil (S:B) ratio vs. seconds of
settling time
at 10°C of the emulsion.
Figure 3 is a graph showing solvent to heavy oil (S:B) ratio vs. mg of solvent
loss per
Kg of water from the emulsion.
DETAILED DESCRIPTION
In one embodiment, there is provided a method comprising: A) preparing a
slurry by
mining an oil sand deposit to produce a mined oil sand and mixing the mined
oil sand with
water; B) mixing the slurry with at least one hydrocarbon solvent thereby
producing a
solvent-slurry mixture; C) agitating the solvent-slurry mixture thereby
producing an emulsion;
D) providing the emulsion to a primary separation facility; and E) recovering
a heavy oil
fraction from the emulsion at the primary separation facility.
A) Preparin _~y
Oil sand, also referred to as tar sand or heavy oil sand, comprises water-
wetted sand
grains coated with heavy oil or bitumen. Large deposits of tar sands are found
around the
world, including Northern Alberta, Canada and the largest of these deposits,
the Athabasca
formation, extends from the surface to depths of over fifteen hundred feet
below an
overburden.
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CA 02520943 2005-09-23
Oil sand deposits are composed primarily of particulate silica (sand) and a
heavy oil
content which varies from about 5% to more than 20% by weight. An average
heavy oil
content of an oil sand deposit is about 10% to about 12% by weight of the
total oil sand
deposit. Clay and silt component in an oil sand is from about 10% to about 30%
by weight.
Water content is from about 1% to about 10% by weight. The heavy oil is
typically viscous
having an API gravity of about 6° to about 20°.
An oil sand deposit can be broken up using mining techniques known to the
skilled
practitioner. For example, an oil sand deposit may be mined using heavy
equipment such as
drilling equipment, crushers, bulldozers, trucks and shovels to mechanically
fragment the
deposit. Alternatively, explosives and modern blasting techniques can be used
to fragment the
oil sand deposit or high-pressure water can be used to ablate the oil sand
deposit. One or a
combination of these methods may be used to produce a fragmented oil sand
deposit.
A slurry is prepared by mixing the fragmented oil sand deposit with water. The
water
may be of any temperature (from 1°C to 99°C) and is often
provided as extremely hot water in
order to reduce the viscosity of the heavy oil, though it is not necessary for
the operation of
methods described herein to use hot water. Water is often provided at
temperatures of between
50°C to 85°C to form a slurry having a temperature of between
25°C and 45°C. In one
embodiment, the water added to the fragmented oil sand has a temperature of
between about
1°C and about 50°C. In another embodiment, the water has a
temperature of about 5°C to
about 25°C. The water may have a temperature of 6°C, 7°C,
8°C, 9°C, 10°C, 11°C, 12°C,
13°C, 14°C, 15°C, 16°C, 17°C, 18°C,
19°C, 20°C, 21°C, 22°C, 23°C, or
24°C. The slurry,
produced by addition of the water to the fragmented oil sand, behaves more
like a fluid than the
fragmented oil sand alone. The water in the slurry acts as a transportation
medium in which
the fragmented oil sand is carried.
The slurry may be produced with a density of about 1.1 g/cc to about 1.7 g/cc.
In one
embodiment, the density may be from about 1.3 g/cc to about 1.65 g/cc. The
density may be
1.1 g/cc, 1.15 g/cc, 1.2 g/cc, 1.25 g/cc, 1.3 g/cc, 1.35 g/cc, 1.4 g/cc, 1.45
g/cc, 1.5 g/cc, 1.55
g/cc, 1.6 g/cc, 1.65 g/cc, 1.7 g/cc, 1.75 g/cc, 1.8 g/cc, 1.85 g/cc, 1.9 g/cc,
or 1.95 g/cc. The
slurry is typically produced with a density of about 1.5 g/cc, which may be
achieved by mixing
the water and the fragmented oil sand in an approximate "g of oil sand : ml of
water" ratio
of 2:1. These densities are generally achieved using water have a temperature
of between
about 10°C to about 30°C to produce a slurry having a
temperature of between about 5°C to
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CA 02520943 2005-09-23
about 25°C. Nevertheless, the skilled practitioner will be able to
produce slurries having the
desired density at any desired temperature.
B) Producing a Solvent-Slurry Mixture
The slurry is mixed with a hydrocarbon solvent to produce a solvent-slurry
mixture.
The hydrocarbon solvent used will be able to dissolve the heavy oil and
separate from an
aqueous phase, once a solution of heavy oil and solvent is achieved, when
subjected to a
G-force equal to or greater than 1. The hydrocarbon solvent will often be a
non-polar,
hydrophobic solvent having a density of between 0.4 g/mL and 0.9 g/mL when
measured at
standard temperature and pressure. The hydrocarbon solvent may have a density
of 0.4 g/mL,
0.45 g/mL, 0.5 g/mL, 0.55 g/mL, 0.6 g/mL, 0.65 g/mL, 0.7 g/mL, 0.75 g/mL, 0.8
g/mL
0.85 g/mL or 0.9 g/mL The hydrocarbon solvent may be a substituted or
unsubstituted,
branched or unbranched, cyclic or non-cyclic, alkane, alkene, alkyne or
aromatic hydrocarbon.
The hydrocarbon solvent is often an alkane having a carbon chain of 4 to 16
carbon atoms.
The hydrocarbon solvent may be a paraffinic solvent or a naphthenic solvent or
a mixture
thereof. Specific examples of hydrocarbon solvents include, but are not
limited to: benzene,
toluene, xylene, ethyl benzene, n-pentane, hexane, naphtha, VarsolTM,
NapthaTM, paint thinner
and mixtures thereof.
The solvent-slurry mixture may be produced to have a solvent to heavy oil
ratio of
between about 1.5:1 to about 3:1 by weight. The solvent to heavy oil ratio, by
weight, may be
1.5:1, 1.6:1, 1.7:1, 1.8:1, 1.9:1, 2:1, 2.1:1, 2.2:1, 2.3:1, 2.4:1, 2.5:1,
2.6:1, 2.7:1, 2.8:1, 2.9:1 or
3:1.
In a particular embodiment, the solvent is added to the slurry in a pipeline.
The
pipeline may be, for example, a hydrotransport pipeline. Pipeline operating
pressure may
range from atmospheric pressure to 3500 kPag, though it is possible that
higher pressures may
be realized in future designs.
The slurry may be added to the pipeline first and the solvent added to the
slurry after
the slurry has traveled along the pipeline a distance. The solvent and the
slurry may be added
to the pipeline simultaneously. The solvent may be added to the pipeline first
and the slurry
added to the pipeline after the solvent has traveled along the pipeline for a
distance. The
solvent and the slurry may be added to the pipeline simultaneously or at
separate times, but the
solvent and the slurry should be made to contact each other such that the
ratio of the solvent to
the heavy oil is between about 1.5:1 to about 3:1 by weight.
8
CA 02520943 2005-09-23
If solvent to heavy oil ratios exceed 3:1, then a rag layer begins to form. A
rag layer is
a layer that forms upon precipitation of asphaltenes. A rag layer becomes
detrimental to the
process when the layer becomes so thick that it hinders separation of the
emulsion. The larger
the rag layer becomes, the more energy that will be required to recover the
heavy oil.
Oil sand ore particles have an intrinsic water layer in between the surface of
an inert
particle (e.g. sand) and the heavy oil in the ore. The intrinsic water layer
provides a barrier to
the hydrocarbon solvent such that the hydrocarbon solvent does not attach to
the surface of the
inert particle. Adding the hydrocarbon solvent to the slurry causes the heavy
oil to dissolve
into a solvent phase, thereby producing a solution. The solution comprises the
heavy oil
dissolved in the hydrocarbon solvent.
C) Producing the Emulsion
The solvent-slurry mixture is agitated to produce the emulsion. The emulsion
comprises the water (from both the intrinsic water layer and the added water),
the solution of
the heavy oil and the hydrocarbon solvent, and the inert material in the oil
sand ore. These
three components of the emulsion form two phases of the emulsion: a diluted
heavy oil
fraction and a tailings fraction. The agitating is sufficiently turbulent so
as to promote contact
between the various components of the emulsion. Any air entrained during the
agitation will
de-aerate rapidly and easily due to the low viscosity of the diluted heavy oil
fraction. Air
blowers are not required for methods described herein. The emulsion generally
behaves like
conventional oil and water emulsions found in oil systems.
Agitating the solvent-slurry mixture causes more of the heavy oil to dissolve
in the
hydrocarbon solvent. The solution has a viscosity and a density that is less
than the viscosity
and the density of the heavy oil. The density and the viscosity of the
solution is lower than that
of the water. The density and the viscosity of the solution is less then that
of the water at
temperatures of between about 1°C to about 99°C, of between
about 1°C to about 50°C, of
between about 5°C and about 25°C, and of between about
5°C and 10°C.
Agitating the solvent-slurry mixture may be achieved by transportation of the
solvent-slurry mixture along a pipeline, typically the pipeline is a
hydrotransport pipeline. The
pipeline may be uphill, downhill, horizontal or a combination thereof. The
pipeline may have a
pump or a plurality of pumps to facilitate transportation of the materials in
the pipeline. The
pump may also facilitate the agitation of the solvent-slurry mixture. The
pipeline may also be
heated. The heating may be for the purposes of heating the solvent-slurry
mixture to a desired
9
CA 02520943 2005-09-23
temperature, or simply to ensure that the solvent-slurry mixture does not
freeze when an
outdoor temperature around the pipeline is below a freezing temperature of a
fluid in the
pipeline.
The difference in: a) the viscosity and the density of the water; and b) the
viscosity and
the density of the solution results in the emulsion being an unstable
emulsion. The emulsion
will separate over time using only gravity as a means for separation. Gravity
will also separate
the inert material from the oil sand ore from both the water and the solution.
The rate of
separation of the solution and the water from the emulsion is determined by
the difference
between the viscosity and the density of the solution compared with the water.
If there is a
large difference between the viscosity and the density of the solution when
compared with the
water, then the emulsion will separate quickly. If there is a small difference
between the
viscosity and the density of the solution when compared with the water then
the emulsion will
separate slowly. Figure 2 describes the relationship between a solvent:heavy
oil ratio of the
emulsion and the settling time required.
It is also possible to separate the emulsion using other known separation
techniques,
including, but not limited to, hydrocyclones, centrifuges and other gravity,
centripetal force or
centrifugal force generating machines.
D) Primar~Separation Facility_
The emulsion is separated into a diluted heavy oil product and a tailings
fraction at a
primary separation facility. Separation techniques are known in the art and a
typical primary
separation facility is a primary separation vessel.
A primary separation vessel is a body that holds the emulsion for a phase
separation
period sufficient to allow a gravitational separation of the emulsion to
occur. The diluted
heavy oil fraction will float to the top of the separated emulsion and the
tailings fraction will
sink to the bottom of the separated emulsion. The bottom of the primary
separation vessel is
often equipped with a flush nozzle in order to remove the tailings as they
build up.
The emulsions produced by methods described herein will clean phase separate
into a
diluted heavy oil and a tailings fraction. Furthermore, the clean phase
separation occurs
without the need to de-aerate using heat, steam treatment or mechanical
energy. The separated
diluted heavy oil product may be skimmed from the surface of the separated
emulsion in the
primary separation vessel or be collected in an overflow launder.
Significantly, there is no
CA 02520943 2005-09-23
middling layer formed within the primary separation vessel. Thus, the
conventional
requirements to remove a middling layer and process through a flotation cell
is not required.
Separating the emulsion may be achieved by subjecting the emulsion to G-forces
of 1
or higher. G-forces of 1, 2, 3, 4, 5, 6, 7, 8, 9 or 10 may be used to separate
the emulsion. The
larger the G-force that is applied, the less time that is required for
separation to occur.
G-forces may be applied by simply allowing gravity to act on the emulsion, or
by providing
rotational velocity to the emulsion. Rotational velocity can be applied by
means of a centrifuge
or a hydrocyclone.
Another type of primary separation facility is a hydrocyclone facility. These
facilities
are capable of separating liquids of different densities and solids from
liquids by providing
centrifugal forces to the emulsion. The liquids of different densities
accelerate at different
rates when the same centrifugal force is applied to them, resulting in a
separation of the liquids
with different densities.
The phase separation period will be dependent on the magnitude of the
separation force
applied to the emulsion. The phase separation period may be less than 4
minutes, greater than
4 minutes, or between about 1 minute to about 4 minutes. The phase separation
period may be
30 seconds, 1 minute, 1.5 minutes, 2, minutes, 2.5 minutes, 3, minutes, 3.5
minutes and 4
minutes.
The diluted heavy oil, once separated from the emulsion is sent to a solvent
recovery
unit or to an upgrader facility to further process the diluted heavy oil into
a commercial oil
product and to recover the solvent. Once the solvent is removed from the
diluted heavy oil
product, it may be recycled and reused. Some solvent will not be recoverable
and Figure 3
describes the relationship between the solvent:heavy oil ration of the
emulsion and the mg of
solvent lost per Kg of water.
E) Recovering Heav~0i1 and Solvent
The diluted heavy oil product may be delivered to a solvent recovery unit. The
solvent
recovery unit removes the solvent from the diluted heavy oil product by
heating the diluted
heavy oil product in a solvent recovery column so that the solvent vapourizes
and is separated
from the heavy oil. The vapourized solvent is collected by condensing the
vapourized solvent
in a solvent condenser and may be recycled for use in preparation of the
solvent-slurry mixture.
The leftover heavy oil may then be sent to an upgrader facility to upgrade the
heavy oil into a
11
CA 02520943 2005-09-23
commercial oil product. Techniques well known to the skilled practitioner in
the art may be
used to recover the solvent and upgrade the heavy oil.
FXAMP1.F~
Example I
200 gram samples of average grade oil sand containing 10 wt.% bitumen (as
determined by Dean-Stark method) were mixed with 100 ml of water in individual
containers
to form a slurry having a density of about 1.5 g/cc, the temperature of the
slurry was
approximately 15 degrees C.
To the first four sample containers n-pentane solvent was added at
solvent:bitumen
ratios ranging from 1.5:1 to 6:1. Several tests were repeated at 2:1
solvent:bitumen with the oil
sands in the form of large lumps. The containers were sealed and shaken by
hand for 45
seconds to 2 minutes in duration. Each sample container was observed for
settling time,
interphase, presence of solids in the diluted bitumen layer and bitumen in the
solids/slurry. ,
Several tests were also conducted with a commercially available naphtha at
solvent:bitumen ratios of 2:1, along with commercial VarsolTM and a typical
over-the-counter
paint thinner.
The average settling time for an n-pentane test at a solvent:bitumen of 2:1
was four
minutes, with a light diluted bitumen product that appeared to contain no
solids or water, a
clean interphase and a visually clean solids phase. Settling times increased
with
solvent:bitumen ratio. Samples treated with the paint thinner behaved
similarly to the
n-pentane tests.
A solvent:bitumen ratio of 6:1 n-pentane yielded a settling time of
approximately 20
seconds, with clean washed solids. The formation of a rag layer at the
interphase of the
water/hydrocarbon layers was also observed.
Solvent:bitumen ratios of 1.5:1 resulted in settling times upwards of 7-9
minutes, an
ill-defined/dirty interphase between the slurry and diluted bitumen phases and
presence of
bitumen on the solids.
Average settling times with the naphtha solvent at 2:1 solvent:bitumen ratio
were in the
order of 5-6 minutes, with a rough interphase and the presence of globular
bitumen in the
slurry phase. Samples tested with VarsolTM had similar results to the naphtha.
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CA 02520943 2005-09-23
Example II
100 gram samples of average grade oil sand containing 11.2 wt.% bitumen (as
determined by Dean-Stark method) were mixed with 50 ml of water in individual
containers to
form a slurry having a density of about 1.5 g/cc, the temperature of the
slurry was maintained
at 10 degrees C.
To the slurry samples was added paraffinic solvent consisting of approximately
50% pentanes
and 50% hexanes (by volume) at solvent:bitumen ratios ranging from 2:1 to 3:1
and each test
was performed in duplicate.
The containers were sealed and shaken by machine on a moderate shaking setting
for 2
minutes as to simulate the conditions found within a hydro-transport pipeline.
(Typical
hydro-transport pipeline velocities are in the order 5 meters per second.
Thus, 2 minutes of
shake time is the equivalent of 600 meters of hydro-transport pipeline.)
Settling times were observed and recorded. The time for phase separation
ranged from
approximately 4 minutes at 2:1 solvent:bitumen ratios to under 2 minutes at
3:1
solvent:bitumen ratios.
It was observed that at the higher 3:1 solvent:bitumen ratio the interphase
between the
dilute bitumen layer and aqueous layer became ragged, as there was the
formation of a rag
layer. This phenomenon was witnessed during the table tops tests and has also
been observed
in the third stage froth settler at Shell Albian Sands facility, which employs
a paraffinic solvent
process. This rag layer is attributed to asphaltene precipitation caused by a
high
solvent:bitumen ratio.
The diluted bitumen phase was removed from each of sample containers and
tested for
BS&W, while the water/solids phase was weighed and analysed for solvent
content via a gas
chromatograph (GC). All diluted bitumen samples analysed were found to have a
BS&W of
0.0%.
The percentage recovery of the bitumen was back calculated as follows:
For a 100 gram sample, there is .112 x 100 = 11.2 grams of
bitumen. To this was added 50 ml, or 50 ml x 1 g/ml = 50 grams of
water. Thus the starting mass of sample = 150 grams.
Therefore: 150g - mass of water/solids layer after solvent
extraction = mass of bitumen extracted into the solvent.
Specifically, in the 2:1 solvent:bitumen experiments, the
mass differential averaged out to 10 grams.
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CA 02520943 2005-09-23
(lOg/11.2g) x 100 = 89.3 % recovery of the asphaltene.
The GC analysis of the water phase showed an average
solvent content of 166 mg/ kg.
When converted to a basis of barrels of solvent loss/1000
barrels of bitumen produced (density of bitumen and solvent taken
as 975 kg/m3 and 630 kg/m3 respectively) this number equates to
1.28 bbl/1000, which is less than the maximum of 4 bbl/1000bb1 as
per government regulations.
Although the foregoing invention has been described in some detail by way of
illustration and example for purposes of clarity of understanding, it will be
readily apparent to
those of skill in the art in light of the teachings of this invention that
changes and modification
may be made thereto without departing from the spirit or scope of the appended
claims.
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