Note: Descriptions are shown in the official language in which they were submitted.
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METHODS AND APPARATUSES FOR OBTAINING A HEAVY OIL
PRODUCT FROM A MIXTURE
FIELD
[0001] The present disclosure relates to methods and apparatus for
obtaining a heavy
oil product from a mixture recovered from a subterranean reservoir.
BACKGROUND
[0002] This section is intended to introduce various aspects of the art.
This discussion is
believed to facilitate a better understanding of particular aspects of the
present techniques.
Accordingly, it should be understood that this section should be read in this
light, and not
necessarily as admissions of prior art.
[0003] Modern society is greatly dependent on the use of hydrocarbon
resources for fuels
and chemical feedstocks. Subterranean rock formations that can be termed
"reservoirs" may
contain resources such as hydrocarbons that can be recovered. Removing
hydrocarbons from
the subterranean reservoirs depends on numerous physical properties of the
subterranean rock
formations, such as the permeability of the rock containing the hydrocarbons,
the ability of the
hydrocarbons to flow through the subterranean rock formations, and the
proportion of
hydrocarbons present, among other things.
[0004] Easily produced sources of hydrocarbons are dwindling, leaving less
conventional
sources to satisfy future needs. As the costs of hydrocarbons increase, less
conventional
sources become more economical. One example of less conventional sources
becoming more
economical is that of oil sand production. The hydrocarbons produced from less
conventional
sources may have relatively high viscosities, for example, ranging from 1000
centipoise (cP) to
20 million cP with American Petroleum Institute (API) densities ranging from 8
degree ( ) API, or
lower, up to 20 API, or higher. The hydrocarbons recovered from less
conventional sources
may include heavy oil. However, the hydrocarbons produced from the less
conventional
sources may be difficult to recover using conventional techniques.
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[0005] Several methods have been developed to recover heavy oil from, for
example, oil
sands. Strip or surface mining may be performed to access oil sands. Once
accessed, the oil
sands may be treated with hot water to extract the heavy oil. For subterranean
reservoirs
where heavy oil is not close to the Earth's surface, heat may be added and/or
dilution may be
used to reduce the viscosity of the heavy oil and recover the heavy oil within
the subterranean
reservoir. Heat may be supplied through a heating agent like steam. The heat
may be injected
into the subterranean reservoir via an injection well or wellbore. If the
heating agent is steam,
the steam may be condensed to water at the steam/cooler-oil-sands interface in
the
subterranean reservoir and supply latent heat of condensation to heat the
heavy oil in the oil
sands, thereby reducing viscosity of the heavy oil and causing the heavy oil
to flow more easily.
The heavy oil recovered from the subterranean reservoir may or may not be
produced via a
production well or wellbore. The production well or wellbore may be the same
well or wellbore
as the injection well or wellbore.
[0006] Cold and/or heated solvents (e.g., propane or higher alkanes) may
be injected
into the subterranean reservoir either alone or in combination with steam to
decrease the
viscosity of heavy oil. The solvent injected may dilute the heavy oil, and/or
transfer thermal
energy to the heavy oil, thereby reducing the viscosity of the heavy oil. As
with a recovery
process employing steam, when solvents are used for the recovery of heavy oil,
heavy oil
having a reduced viscosity may flow downwards to a well for recovery of the
heavy oil through
the well. The heavy oil whose viscosity has been reduced by a solvent or a
steam and solvent
combination may have a greater reduction in viscosity than a heavy oil whose
viscosity has
been reduced by steam alone under substantially similar conditions within the
subterranean
reservoir. Processes using solvent to at least assist in reducing the
viscosity of the heavy oil
may be referred to as solvent-based recovery processes.
[0007] Canadian Patent Nos. 2,633,061 and 2,299,790 disclose variations of
a method of
recovering heavy oil that involve heating a solvent to vapor under pressure
until a condensation
temperature of the solvent vapor is above a naturally-occurring temperature in
a subterranean
reservoir. The solvent vapor is then injected, under pressure, into the
subterranean reservoir
where the solvent vapor may condense. The latent heat of condensation,
together with warm
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solvent, reduces the viscosity of the heavy oil in the subterranean reservoir
while precipitating
out asphaltenes from the heavy oil. This reduced-viscosity blend of heavy oil
and solvent is
then recovered from the subterranean reservoir.
[0008] Canadian Patent No. 2,769,356 discloses a method using a pentane
and/or
hexane solvent. When the solvent is produced as part of a blend of heavy oil
and solvent, the
solvent is allowed to remain within the blend of heavy oil and solvent to
enhance subsequent
blend treating and transportation steps.
[0009] Canadian Patent No. 2,349,234 discloses a process in which a
solvent is injected
into a subterranean reservoir at a pressure. The pressure is above that which
allows the
solvent to vaporize. The pressure is also sufficient to cause geomechanical
formation dilation
or pore fluid compression in the subterranean reservoir. After allowing the
solvent to mix with
the heavy oil in the subterranean reservoir, the pressure in the subterranean
reservoir is
reduced to produce solvent vapor and drive the diluted heavy oil from the
subterranean
reservoir.
[0010] Heavy oil may include heavy end components and light end
components. The
heavy end components may comprise a heavy viscous liquid or solid made up of
heavy
hydrocarbon molecules, such as C30+ molecules. The heavy viscous liquid may be
composed of
C30+ molecules that, when separated from the heavy oil, have a higher density
and viscosity
than a density and viscosity of the heavy oil containing both heavy end
components and light
end components. For example, in Athabasca bitumen, about 70 weight (wt.) % of
the bitumen
contains C30+ molecules with about 18 wt. % of the Athabasca bitumen being
classified as
asphaltenes. The heavy end components may include asphaltenes in the form of
solids or
viscous liquids. The presence of heavy end components within mixtures of heavy
oil and
solvent produced by a solvent-based recovery process can cause handling
problems at surface
facilities above the subterranean reservoir.
[0011] The heavy end components can separate or precipitate from a mixture
of the
solvent and heavy oil at certain temperatures and at certain heavy oil to
solvent ratios. The
precipitation or separation of the heavy end components from the mixture may
result in
blockage of equipment at the surface region.
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(0012) Asphaltenes contain heavy metal compounds that may be harmful to
catalysts
(e.g., catalyst poisoning) used in heavy oil upgrading processes. A heavy oil
product having
some or all asphaltenes removed may not require severe and costly heavy oil
upgrading (e.g.,
cocking, heavy oil fluid catalytic cracking, etc.). A heavy oil product having
some or all
asphaltenes removed may be refined using less costly processes (e.g., hydro
cracking, catalytic
cracking, etc.). Consequently, it may be desirable to remove some or all of
the heavy end
components, like asphaltenes, from the heavy oil to produce a heavy oil
product.
[0013] It may be desirable to remove some or all of the solvents from the
mixture of
solvent and heavy oil to produce the heavy oil product. The solvents can cause
separation,
precipitation or viscosity effects of the heavy end components in the heavy
oil, thereby making
handling and treatment of the heavy oil product at a surface facility
difficult. It may be
desirable to remove solvent when producing the heavy oil product at, for
example, a refining
facility.
[0014] It may be desirable to transport the heavy oil product by pipeline
to, for example
but not limited to, a refinery. The heavy oil product having some or all of
the asphaltenes
removed may have a reduced viscosity making it suitable for transportation by
pipeline. Heavy
oil products containing no or only small amounts of asphaltenes may be easier
to transport by
pipeline because of their lower viscosities and reduced tendencies to
precipitate asphaltenes in
pipeline equipment.
[0015] It may be desirable to provide a heavy oil product that contains at
least some of
the heavy end components while still making the heavy oil product suitable for
transportation
by pipeline. The heavy oil product containing at least some of the heavy end
components may
be made suitable for transportation by pipeline by, for example, adding
solvent or retaining
some or all of the solvent from the mixture of heavy oil and solvent in the
heavy oil product to
reduce a viscosity of the heavy oil product. If, for example, there is no
facility or procedure that
can process asphaltenes, which are precipitates, at a production site, it may
be desirable to
transport the asphaltenes with other heavy end components to a site with
facilities that
perform such processes.
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[0016] In view of the above, there is a need to provide methods and
apparatuses for
obtaining a heavy oil product from a mixture recovered from the subterranean
reservoir using a
solvent-based recovery process where, for example, the handling and treatment
of the mixture
to produce the heavy oil product is improved.
SUMMARY
[0017] The present disclosure provides apparatuses and methods for
treatment of heavy
oil and solvent mixtures, among other things.
[0018] A method of obtaining a heavy oil product from a mixture of a first
solvent and
heavy oil recovered from a subterranean reservoir may comprise forming a
treated mixture by
treating the mixture to prevent substantial precipitation of heavy end
components of the heavy
oil from the mixture, and producing a recovered solvent and the heavy oil
product by
separating a portion of the first solvent from the treated mixture.
[0019] A method of obtaining a heavy oil product from a mixture of a first
solvent and
heavy oil recovered from a subterranean reservoir may comprise forming a
treated mixture
containing asphaltene precipitates by treating the mixture, wherein treating
the mixture
comprises precipitating asphaltenes in the heavy oil from the mixture;
providing separated
asphaltenes and a separated treated mixture by separating the asphaltene
precipitates from
the treated mixture; and producing a recovered solvent and the heavy oil
product by separating
a portion of the first solvent from the separated treated mixture. The heavy
oil product may
have a lower content of asphaltenes than the asphaltenes in the mixture.
[0020] An apparatus for obtaining a heavy oil product from a mixture of a
first solvent
and heavy oil recovered from a subterranean reservoir may comprise a treating
apparatus
configured to receive and treat the mixture to prevent substantial
precipitation of heavy end
components of the heavy oil from the mixture; and a solvent separation
apparatus in fluid
communication with the treating apparatus that is configured to separate out a
portion of the
first solvent to produce a separated first solvent, the heavy oil product, and
a water product.
[0021] An apparatus for obtaining a heavy oil product from a mixture of a
first solvent
and heavy oil recovered from a subterranean reservoir may comprise a treating
apparatus
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configured to receive and treat the mixture to cause precipitation of
asphaltenes of the heavy
oil from the mixture to form a treated mixture containing asphaltene
precipitates; an
asphaltene separation apparatus in fluid communication with the treating
apparatus that is
configured to receive the treated mixture and separate the asphaltenes
precipitates from the
treated mixture to provide separated asphaltenes and a separated treated
mixture; and a
solvent separation apparatus in fluid communication with the asphaltene
separation apparatus
that is configured to receive the separated treated mixture and separate a
portion of the first
solvent from the separated treated mixture to produce a separated first
solvent, the heavy oil
product, and a water product. The heavy oil product may have a lower content
of asphaltenes
than the asphaltenes in the mixture.
In one particular embodiment the invention provides a method of obtaining a
heavy oil product from a mixture of a first solvent and heavy oil recovered
from a subterranean
reservoir, the method comprising: drilling an injection well and a production
well through a
subterranean reservoir; vaporizing a first solvent; injecting the first
solvent into the
subterranean reservoir via the injection well; recovering a mixture of the
first solvent and heavy
oil recovered from the subterranean reservoir; forming a treated mixture by
treating the
mixture to prevent substantial precipitation of heavy end components of the
heavy oil from the
mixture; and producing a recovered solvent and the heavy oil product by
separating a portion
of the first solvent from the treated mixture; wherein the heavy oil product
is obtained from a
solvent-based in-situ recovery process.
In another particular embodiment the invention provides an apparatus for
obtaining a mixture of a first solvent and heavy oil from a subterranean
reservoir and obtaining
a heavy oil product from the mixture, the apparatus comprising: an injection
well; a production
well in fluid connection with the injection well through a subterranean
reservoir; a first solvent
vaporizer for vaporizing the first solvent; an injectant supply system for
injecting the first
solvent into the injection well; a production well in fluid connection with
the injection well
through a subterranean reservoir for recovering the mixture of the first
solvent and heavy oil
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recovered from a subterranean reservoir; a treating apparatus configured to
receive and treat
the mixture to prevent substantial precipitation of heavy end components of
the heavy oil from
the mixture; and a solvent separation apparatus in fluid communication with
the treating
apparatus that is configured to separate out a portion of the first solvent to
produce a
separated first solvent, the heavy oil product, and a water product.
[0022] The foregoing has broadly outlined the features of the present
disclosure so that
the detailed description that follows may be better understood. Additional
features will also be
described herein.
DESCRIPTION OF THE DRAWINGS
[0023] These and other features, aspects and advantages of the present
disclosure will
become apparent from the following description and the accompanying drawings,
which are
briefly discussed below.
[0024] FIG. 1 is a drawing of a system that may be used for implementing a
solvent-
based recovery process used for recovering heavy oil from a subterranean
reservoir;
[0025] FIG. 2 is an illustration of deposited asphaltene fraction versus
temperature for a
plurality of mixtures of heavy oil and solvent having various specified
concentrations of the
solvent n-heptane;
[0026] FIG. 3 is an illustration of deposited asphaltene fraction for
mixtures of heavy oil
and different solvents, each mixture having a concentration of solvent of 70
weight (wt.) % at
different temperatures;
[0027] FIG. 4 is a drawing of an apparatus for treating a mixture of heavy
oil and solvent;
[0028] FIG. 5 is an illustration of an asphaltene precipitation phase
diagram for a mixture
of Athabasca bitumen and a solvent;
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[0029] FIG. 6 is a drawing of an apparatus for treating a mixture of heavy
oil and solvent;
[0030] FIG. 7 is a flow diagram illustrating a method according to the
present disclosure;
and
[0031] FIG. 8 is a flow diagram illustrating a method according to the
present disclosure.
[0032] It should be noted that the figures are merely examples and no
limitations on the
scope of the present disclosure are intended thereby. Further, the figures are
generally not
drawn to scale, but are drafted for the purpose of convenience and clarity in
illustrating various
aspects of the disclosure.
DETAILED DESCRIPTION
[0033] For the purpose of promoting an understanding of the principles of
the
disclosure, reference will now be made to the features illustrated in the
drawings and specific
language will be used to describe the same. It will nevertheless be understood
that no
limitation of the scope of the disclosure is thereby intended. Any alterations
and further
modifications, and any further applications of the principles of the
disclosure as described
herein are contemplated as would normally occur to one skilled in the art to
which the
disclosure relates. It will be apparent to those skilled in the relevant art
that some features that
are not relevant to the present disclosure may not be shown in the drawings
for the sake of
clarity.
[0034] At the outset, for ease of reference, certain terms used in this
application and
their meanings as used in this context are set forth. To the extent a term
used herein is not
defined below, it should be given the broadest definition persons in the
pertinent art have
given that term as reflected in at least one printed publication of issued
patent. Further, the
present techniques are not limited by the usage of the terms shown below, as
all equivalents,
synonyms, new developments, and terms or processes that serve the same or a
similar purpose
are considered to be within the scope of the present disclosure.
[0035] A "hydrocarbon" is an organic compound that primarily includes the
elements
hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number
of other
elements may be present in small amounts. Hydrocarbons generally refer to
components
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found in heavy oil or in oil sands. However, the techniques described herein
are not limited to
heavy oils, but may also be used with any number of other subterranean
reservoirs.
Hydrocarbon compounds may be aliphatic or aromatic, and may be straight
chained, branched,
or partially or fully cyclic.
[0036] "Bitumen" is a naturally occurring heavy oil material. Generally,
it is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending upon
the degree of loss of more volatile components. It can vary from a very
viscous, tar-like, semi-
solid material to solid forms. The hydrocarbon types found in bitumen can
include aliphatics,
aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.)% aliphatics (which can range from 5 wt.% - 30 wt.%, or
higher);
19 wt.% asphaltenes (which can range from 5 wt.% - 30 wt.%, or higher);
30 wt.% aromatics (which can range from 15 wt.% - 50 wt.%, or higher);
32 wt.% resins (which can range from 15 wt.% - 50 wt.%, or higher); and
some amount of sulfur (which can range in excess of 7 wt.%).
The percentage of the hydrocarbon types found in bitumen can vary. In addition
bitumen can
contain some water and nitrogen compounds ranging from less than 0.4 wt.% to
in excess of
0.7 wt.%. The metals content, while small, may be removed to avoid
contamination of
synthetic crude oil. Nickel can vary from less than 75 ppm (parts per million)
to more than 200
ppm. Vanadium can range from less than 200 ppm to more than 500 ppm. The term
"heavy
oil" includes bitumen, as well as lighter materials that may be found in a
sand or carbonate
reservoir.
[0037] "Heavy oil" includes oils that are classified by the American
Petroleum Institute
(API), as heavy oils, extra heavy oils, or bitumens. Thus the term "heavy oil"
includes bitumen.
Heavy oil may have a viscosity of about 1000 centipoise (cP) or more, 10,000
cP or more,
100,000 cP or more or 1,000,000 cP or more. In general, a heavy oil has an API
gravity between
22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per
centimeter
cubed (g/cm3)) and 10.0' API (density of 1,000 kg/m3 or 1 g/cm3). An extra
heavy oil, in general,
has an API gravity of less than 10.0' API (density greater than 1,000 kg/m3 or
greater than 1
g/cm3). For example, a source of heavy oil includes oil sand or bituminous
sand, which is a
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combination of clay, sand, water, and bitumen. The recovery of heavy oils is
based on the
viscosity decrease of fluids with increasing temperature or solvent
concentration. Once the
viscosity is reduced, the mobilization of fluids by steam, hot water flooding,
or gravity is
possible. The reduced viscosity makes the drainage quicker and therefore
directly contributes
to the recovery rate. A heavy oil may include heavy end components and light
end
components.
[0038] "Heavy end components" in heavy oil may comprise a heavy viscous
liquid or
solid made up of heavy hydrocarbon molecules. Examples of heavy hydrocarbon
molecules
include, but are not limited to, molecules having greater than or equal to 30
carbon atoms
(C30+). The amount of molecules in the heavy hydrocarbon molecules may include
any number
within or bounded by the preceding range. The heavy viscous liquid or solid
may be composed
of molecules that, when separated from the heavy oil, have a higher density
and viscosity than
a density and viscosity of the heavy oil containing both heavy end components
and light end
components. For example, in Athabasca bitumen, about 70 weight (wt.) % of the
bitumen
contains C30+ molecules with about 18 wt. % of the Athabasca bitumen being
classified as
asphaltenes. The heavy end components may include asphaltenes in the form of
solids or
viscous liquids.
[0039] "Light end components" in heavy oil may comprise those components
in the
heavy oil that have a lighter molecular weight than heavy end components. The
light end
components may include what can be considered to be medium end components.
Examples of
light end components and medium end components include, but are not limited
to, light and
medium hydrocarbon molecules having greater than or equal to 1 carbon atom and
less than
30 carbon atoms. The amount of molecules in the light and medium end
components may
include any number within or bounded by the preceding range. The light end
components and
medium end components may be composed of molecules that have a lower density
and
viscosity than a density and viscosity of heavy end components from the heavy
oil.
[0040] A "fluid" includes a gas or a liquid and may include, for example,
a produced or
native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold water,
or a mixture of
these among other materials. "Vapor" refers to steam, wet steam, mixtures of
steam and wet
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steam, any of which could possibly be used with a solvent and other
substances, and any
material in the vapor phase.
[0041] Two locations in a subterranean reservoir are in "fluid
communication" when a
path for fluid flow exists between the two locations. For example, fluid
communication exists
between an injection well and a production well when mobilized material can
flow down to the
production well from the injection well for collection and production.
[0042] "Facility" or "surface facility" is a tangible piece of physical
equipment through
which hydrocarbon fluids are either produced from a subterranean reservoir or
injected into a
subterranean reservoir, or equipment that can be used to control production or
completion
operations. In its broadest sense, the term facility is applied to any
equipment that may be
present along the flow path between a subterranean reservoir and its delivery
outlets.
Facilities may comprise production wells, injection wells, well tubulars,
wellbore head
equipment, gathering lines, manifolds, pumps, compressors, separators, surface
flow lines,
steam generation plants, processing plants, and delivery outlets. In some
instances, the term
"surface facility" is used to distinguish from those facilities other than
wells.
[0043] "Pressure" is the force exerted per unit area by the gas on the
walls of the
volume. Pressure may be shown in this disclosure as pounds per square inch
(psi), kilopascals
(kPa) or megapascals (MPa). "Atmospheric pressure" refers to the local
pressure of the air.
"Absolute pressure" (psia) refers to the sum of the atmospheric pressure (14.7
psia at standard
conditions) plus the gauge pressure. "Gauge pressure" (psig) refers to the
pressure measured
by a gauge, which indicates only the pressure exceeding the local atmospheric
pressure (i.e., a
gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia).
The term "vapor
pressure" has the usual thermodynamic meaning. For a pure component in an
enclosed system
at a given pressure, the component vapor pressure is essentially equal to the
total pressure in
the system. Unless otherwise specified, the pressures in the present
disclosure are absolute
pressures.
[0044] A "subterranean reservoir" is a subsurface rock or sand reservoir
from which a
production fluid, or resource, can be harvested. The rock formation may
include sand, granite,
silica, carbonates, clays, and organic matter, such as bitumen, heavy oil
(e.g., bitumen), oil, gas,
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or coal, among others. Subterranean reservoirs can vary in thickness from less
than one foot
(0.3048 meters (m)) to hundreds of feet (hundreds of meters). The resource is
generally a
hydrocarbon, such as a heavy oil impregnated into a sand bed.
[0045] "Thermal recovery processes" include any type of hydrocarbon
recovery process
that uses a heat source to enhance the recovery, for example, by lowering the
viscosity of a
hydrocarbon. The processes may use injected mobilizing fluids, such as but not
limited to hot
water, wet steam, dry steam, or solvents alone, or in any combination, to
lower the viscosity of
the hydrocarbon. Any of the thermal recovery processes may be used in concert
with solvents.
For example, thermal recovery processes may include cyclic steam stimulation
(CSS), steam
assisted gravity drainage (SAGD), steam flooding, in-situ combustion and other
such processes.
[0046] "Solvent-based recovery processes" include any type of hydrocarbon
recovery
process that uses a solvent, at least in part, to enhance the recovery, for
example, by diluting or
lowering a viscosity of the hydrocarbon. Solvent-based recovery processes may
be used in
combination with other recovery processes, such as, for example, thermal
recovery processes.
In solvent-based recovery processes, a solvent is injected into a subterranean
reservoir. The
solvent may be heated or unheated prior to injection, may be a vapor or liquid
and may be
injected with or without steam. Solvent-based recovery processes may include,
but are not
limited to, solvent assisted cyclic steam stimulation (SA-CSS), solvent
assisted steam assisted
gravity drainage (SA-SAGD), solvent assisted steam flood (SA-SF), vapor
extraction process
(VAPEX), heated vapor extraction process (H-VAPEX), cyclic solvent process
(CSP), heated cyclic
solvent process (H-CSP), solvent flooding, heated solvent flooding, liquid
extraction process,
heated liquid extraction process, solvent extraction process (SEP), thermal
solvent extraction
processes (TSEP), and any other such recovery process employing solvents
either alone or in s
combination with steam. A solvent-based recovery process may be a thermal
recovery process
if the solvent is heated prior to injection into the subterranean reservoir.
The solvent-based
recovery process may employ gravity drainage.
[0047] "Substantial" when used in reference to a quantity or amount of a
material, or a
specific characteristic of the material, refers to an amount that is
sufficient to provide an effect
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that the material or characteristic was intended to provide. The exact degree
of deviation
allowable may in some cases depend on the specific context.
[0048] A "wellbore" is a hole in the subsurface made by drilling or
inserting a conduit
into the subsurface. A wellbore may have a substantially circular cross
section or any other
cross-sectional shape, such as an oval, a square, a rectangle, a triangle, or
other regular or
irregular shapes. The term "well," when referring to an opening in the
formation, may be used
interchangeably with the term "wellbore." Further, multiple pipes may be
inserted into a single
wellbore, for example, as a liner configured to allow flow from an outer
chamber to an inner
chamber.
[0049] An "injectant supply system" may be a surface facility used to
supply an injectant
to a well located in the subterranean reservoir. The injectant may include a
vapor comprising
steam, solvent or a combination of steam and solvent, of or a gas, such as,
for example, a non-
condensable gas. The injectant supply system may be provided with the
injectant, which is
then vaporized. The vapor may be provided to a well for injection into the
subterranean
reservoir.
[0050] "Permeability" is the capacity of a structure to transmit fluids
through the
interconnected pore spaces of the structure. The customary unit of measurement
for
permeability is the milliDarcy (mD).
[0051] "Reservoir matrix" refers to the solid porous material forming the
structure of the
subterranean reservoir. The subterranean reservoir is composed of the solid
reservoir matrix,
typically rock or sand, around pore spaces in which resources such as heavy
oil may be located.
The porosity and permeability of a subterranean reservoir is defined by the
percentage of
volume of void space in the rock or sand reservoir matrix that potentially
contains resources
and water.
[0052] A "vapor chamber" is a region of a subterranean reservoir
containing heavy oil
that forms around a well that is injecting vapor into the subterranean
reservoir. The vapor
chamber has a temperature and a pressure that is generally at or close to a
temperature and
pressure of the vapor injected into the subterranean reservoir. The vapor
chamber may form
when heavy oil has, due to heat from the vapor and the action of gravity, at
least partially
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mobilized through the pore spaces of the reservoir matrix. The mobilized heavy
oil may be at
least partially replaced in the pore spaces by vapor, thus forming the vapor
chamber. In
practice, layers in the subterranean reservoir containing heavy oil may not
necessarily have
pore spaces that contain 100 percent (%) heavy oil and may contain only 70 -
80 volume (vol.) %
heavy oil with the remainder possibly being water. A water and/or gas
containing layer in the
subterranean reservoir may comprise 100% water and/or gas in the pore spaces,
but generally
contains 5 - 70 vol.% gas and 20 - 30 vol.% water with any remainder possibly
being heavy oil.
[0053] The terms "approximately," "about," "substantially," and similar
terms are intended
to have a broad meaning in harmony with the common and accepted usage by those
of
ordinary skill in the art to which the subject matter of this disclosure
pertains. It should be
understood by those of skill in the art who review this disclosure that these
terms are intended
to allow a description of certain features described and claimed without
restricting the scope of
these features to the precise numeral ranges provided. Accordingly, these
terms should be
interpreted as indicating that insubstantial or inconsequential modifications
or alterations of
the subject matter described and are considered to be within the scope of the
disclosure.
[0054] The articles "the", "a" and "an" are not necessarily limited to
mean only one, but
rather are inclusive and open ended so as to include, optionally, multiple
such elements.
[0055] "At least one," in reference to a list of one or more entities
should be understood
to mean at least one entity selected from any one or more of the entity in the
list of entities,
but not necessarily including at least one of each and every entity
specifically listed within the
list of entities and not excluding any combinations of entities in the list of
entities. This
definition also allows that entities may optionally be present other than the
entities specifically
identified within the list of entities to which the phrase "at least one"
refers, whether related or
unrelated to those entities specifically identified. Thus, as a non-limiting
example, "at least one
of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at
least one of A and/or
B") may refer, to at least one, optionally including more than one, A, with no
B present (and
optionally including entities other than B); to at least one, optionally
including more than one,
B, with no A present (and optionally including entities other than A); to at
least one, optionally
including more than one, A, and at least one, optionally including more than
one, B (and
13
CA 02856460 2014-07-10
optionally including other entities). In other words, the phrases "at least
one," "one or more,"
and "and/or" are open-ended expressions that are both conjunctive and
disjunctive in
operation. For example, each of the expressions "at least one of A, B and C,"
"at least one of A,
B, or C," "one or more of A, B, and C," "one or more of A, B, or C" and "A, B,
and/or C" may
mean A alone, B alone, C alone, A and B together, A and C together, B and C
together, A, B and
C together, and optionally any of the above in combination with at least one
other entity.
[0056] Any of the ranges disclosed may include any number within and/or
bounded by
the range given.
[0057] As an example of a solvent-based recovery process, reference is
made to Figure 1.
FIG. 1 illustrates a system 10 that may be used for implementing the solvent-
based recovery
process for recovering heavy oil from a subterranean reservoir. The solvent-
based recovery
process illustrated in Fig. 1 is a solvent-extraction process (SEP). The
system 10 may include an
injection well 30 and a production well 70 that extend between a surface
region 20 and a
subterranean reservoir 24 that is present within a subsurface region 22.
[0058] The injection well 30 may be vertically and then horizontally
drilled through the
subterranean reservoir 24. The production well 70 may be drilled vertically
and then
horizontally through the subterranean reservoir 24. A horizontal section of
the production well
70 may lie below a horizontal section of the injection well 30. The injection
well 30 and the
production well 70 may be drilled from the same pad at the surface region 20
or from a
different pad at the surface region 20. The surface region 20 may be a surface
of the
subterranean reservoir 24. Drilling the injection well 30 and the production
well 70 from the
same pad may make it easier for the production well 70 to track (i.e., follow
a similar path of)
the injection well 30. The injection well 30 and the production well 70 may be
vertically
separated by a suitable distance, such as about 3 to 10 meters (m). The
injection well 30 and
the production well 70 may be vertically separated by the aforementioned
amounts in the
horizontal and/or vertical sections of the respective injection well 30 and
production well 70.
Any of the aforementioned ranges may be within a range that includes or is
bounded by any of
the preceding examples.
14
CA 02856460 2014-07-10
[0059] The injection well 30 may be in fluid communication with an
injectant supply
system 40 for providing a solvent 44 to the injection well 30. The injectant
supply system 40
may provide the solvent 44 from any suitable source (e.g., a storage structure
42). The solvent
44 may be supplied to a vaporization assembly 50 to generate a vapor 52. The
vapor 52 may be
provided to the injection well 30. The vapor 52 may be injected into the
subterranean reservoir
24 at a predetermined temperature and pressure.
[0060] The vapor 52 may mobilize heavy oil in the subterranean reservoir
24. The heavy
oil may drain down to the injection well 30 and/or the production well 70 and
form a vapor
chamber 60. The vapor 52 may have a temperature higher than an initial
temperature in the
subterranean reservoir 24. In the case of the Athabasca Oil Sands in Canada,
the initial
temperature in the subterranean reservoir is about 8 Celsius ( C), but the
initial temperature in
the subterranean reservoir may differ from one subterranean reservoir to
another. For
example, the vapor 52 may have a temperature of at least 30 C, but no more
than about
250 C. The temperature may be any number within or bounded by the preceding
range
[0061] The vapor 52 may condense upon injection into the subterranean
reservoir 24,
releasing latent heat of condensation and transferring heat to the
subterranean reservoir 24
and/or generating a condensate 54. When the vapor 52 is injected into the
subterranean
reservoir 24 via the injection well 30, the vapor 52 may decrease in
temperature (or lose
thermal energy) while being conveyed through the injection well 30 to the
subterranean
reservoir 24. The vapor 52 may decrease in temperature while being conveyed
through the
subterranean reservoir 24 from the injection well 30 to an interface 62
between the vapor
chamber 60 and heavy oil 26 that is not within the vapor chamber 60. If the
vapor 52 is a single
component vapor stream, the vapor 52 may be superheated prior to being
injected into the
subterranean reservoir 24. A portion of the vapor 52 may condense prior to
reaching the
interface 62.
[0062] Condensation of the vapor 52 may heat the heavy oil 26 within the
subterranean
reservoir 24. Heating the heavy oil may decrease a viscosity of the heavy oil
26 and increase
flowability of the heavy oil under gravity. The vapor 52 and/or condensate 54
may combine
with, mix with, be dissolved in, dissolve, and/or dilute the heavy oil 26,
thereby further
CA 02856460 2014-07-10
decreasing the viscosity of the heavy oil 26. An energy/heat transfer between
the vapor 52 and
the heavy oil 26 and/or the mixing of the vapor 52 with the heavy oil 26 may
generate a
mixture 74 of the heavy oil 26 having a reduced viscosity and a solvent. The
mixture may flow
to the production well 70 and/or the injection well 30.
[0063] The vapor 52 may be injected into the subterranean reservoir 24 at
a pressure
that is below a threshold maximum pressure of the subterranean reservoir 24.
Threshold
maximum pressures may include, for example, a characteristic pressure of the
subterranean
reservoir. The characteristic pressure may be a fracture pressure of the
subterranean reservoir,
a hydrostatic pressure within the subterranean reservoir, a lithostatic
pressure within the
subterranean reservoir, a gas cap pressure for a gas cap that is present
within the subterranean
reservoir, and/or an aquifer pressure for an aquifer that is located above
and/or under the
subterranean reservoir. The threshold maximum pressure may be related to
and/or based
upon the characteristic pressure of the subterranean reservoir. Injection of
the vapor 52 at a
pressure that is below the threshold maximum pressure of the subterranean
reservoir 24 may
prevent (or at least reduce) damage to the subterranean reservoir 24 and a
reservoir matrix of
the subterranean reservoir 24. Injection of the vapor 52 at a pressure that is
below the
threshold maximum pressure may prevent or reduce escape of the vapor 52 from
the
subterranean reservoir 24.
[0064] A composition of the solvent 44 may be selected such that a dew
point
temperature of the vapor 52 and a bubble point temperature of the mixture 74
of the heavy oil
and the solvent differ by at least a temperature difference. Illustrative, non-
exclusive examples
of the temperature difference include temperature differences between 10 C
and 100 C
inclusive. The temperature difference may be any number within or bounded by
the preceding
range.
[0065] The solvents used in the solvent-based recovery process may be, for
example,
hydrocarbons. The solvent may be a single hydrocarbon or a mixture of
hydrocarbons of
various molecular weights. Compounds with a larger number of carbon atoms
(e.g., greater
than or equal to 20 carbon atoms) may exhibit a lower vapor pressure at a
given temperature
when compared to compounds with less carbon atoms. Injecting the vapor stream
52 that is
16
CA 02856460 2014-07-10
formed from a solvent 44, having a higher number of carbon atoms, may permit
the vapor 52 to
be injected at a lower pressure for a given temperature when compared to
injection of solvent
having a smaller number of carbon atoms.
[0066] The solvent 44 may be obtained from any suitable source. As
illustrative, non-
exclusive examples, the solvent 44 may be obtained from a gas plant condensate
and/or a
crude oil refinery naphtha cut.
[0067] The mixture 74 may be produced from the subterranean reservoir 24
by at least
one of the injection well 30 and the production well 70. The mixture 74 of the
heavy oil and
solvent 44 may be pumped by at least one of the injection well 30 and the
production well 70
so that the mixture 74 emerges at the surface region 20 as a product stream
72. The product
stream 72 may include the mixture 74 of the heavy oil and the solvent as well
as light
hydrocarbon gases. Light hydrocarbon gases may include hydrocarbon and/or
carbon
compounds with four or fewer carbon atoms, such as methane, ethane, propane
and/or
butane. Light hydrocarbon gases may include any number of carbon atoms
included or
bounded within the preceding range. Light hydrocarbon gases may emerge from
the
production well 70 separately in the form of casing gases.
[0068] The injection well 30 may comprise injection wells. The production
well 70 may
comprise production wells. If the production well 70 comprises production
wells, the product
stream 72 from the production wells may be combined and then sent to a surface
facility. If the
production well 70 comprises a single well, the product stream 72 from the
production well 70
may be sent to the surface facility.
[0069] The mixture 74 of the heavy oil and the solvent may encounter
difficulties at the
surface region 20 if the mixture 74 contains heavy end components,
particularly asphaltenes,
such as those previously discussed. Processing of the mixture of the heavy oil
and the solvent
into a heavy oil product may depend on an intended product of the recovery
process. For
example, it may be desirable to produce a heavy oil product from the mixture
with the heavy oil
product having the asphaltenes, and possibly other heavy end components,
removed or
substantially reduced in concentration. It may be desirable to transport a
heavy oil product
that contains the heavy end components, including asphaltenes. It may be
desirable to include
17
CA 02856460 2014-07-10
a solvent with the heavy oil product to reduce a viscosity of the heavy oil
product to a level
suitable for transport of the heavy oil product by pipeline.
[0070] The mixture of the solvent (i.e., first solvent) and heavy oil may
be treated in two
alternative ways, i.e. for partial or complete asphaltene removal or for heavy
end component
retention.
[0071] The present disclosure may include methods and apparatus for
obtaining a heavy
oil product from a mixture of a first solvent and heavy oil recovered/produced
from a
subterranean reservoir. Figs. 4 and 6 illustrate exemplary apparatuses 400 and
600. Figs. 7 and
8 illustrate exemplary flow diagrams of methods.
[0072] The mixture may comprise a first solvent and heavy oil. The mixture
may be, for
example, a mixture of a first solvent and heavy oil as produced as a result of
a solvent-based
recovery process, such as those previously discussed. The mixture may have a
relatively high
concentration of the first solvent to heavy oil, such as, for example, at
least 30 weight (wt.)% of
the first solvent or more. The weight percent may include any number bounded
by or included
within the aforementioned range. The first solvent may be a solvent injected
into the
subterranean reservoir to reduce a viscosity of the heavy oil to enable the
heavy oil to be
produced/recovered from the subterranean reservoir.
[0073] The first solvent may be a single hydrocarbon having greater than
or equal to
three carbon atoms (C3). For example, the first solvent may be a mixture of at
least two, and
more usually, at least three, hydrocarbons having a number of carbon atoms
from the range of
Cl to C30+. There may be at least hydrocarbons in the range of C3 to C12 or
higher in various
amounts in the first solvent. The first solvent may contain light hydrocarbons
having a low
number of carbon atoms, such as Cl to C3. The light hydrocarbons have low
molecular weights
and are generally the most volatile of the hydrocarbons in the mixture. The
amount of carbon
atoms within the first solvent may include any number bounded by or included
within the
preceding range.
[0074] Cl and C2 hydrocarbons may not always be present in the first
solvent. Heavier
hydrocarbons may be absent or present in only small amounts in the first
solvent. Heaver
hydrocarbons may include any amount of carbon atoms that are greater than or
equal to 30.
18
CA 02856460 2014-07-10
Hydrocarbons having any number of carbon atoms greater than 2 or less than 30,
such as but
not limited to C3 to C15 compounds and C3 to C12 compounds, may often be
present in the
first solvent. This range of carbon atoms may include any number within or
bounded by the
preceding range. The first solvent may include but is not limited to normal
alkanes, iso-alkanes,
naphthenic hydrocarbons, aromatic hydrocarbons, or olefin hydrocarbons. The
normal alkanes
have the highest tendency of causing heavy end component separation with a
decreasing
tendency in heavy end component separation from iso-alkanes to naphthenic
hydrocarbons to
aromatic hydrocarbons. Aromatic hydrocarbons (e.g., benzene, toluene and
xylene) may be
good solvents for mixture with heavy oil containing asphaltenes. The first
solvent may be a first
alkane having a carbon atom number in a range of C3 to C12.
[0075] Hydrocarbon mixtures used for producing solvents, such as first
solvents, may be
obtained, for example, from petroleum and natural gas products by distillation
(e.g., as gas
plant condensates), petroleum associate gases, or as crude refinery
distillates (e.g., raw
naphtha fraction) from an refinery crude distillation units, catalytic
reforming units, catalytic
cracking units, thermal cracking units, steam cracking units, hydrocracking
units, cokers, or from
petrochemical plants (e.g., from olefin units, aromatic solvent units, etc.)
[0076] The heavy oil product and the mixture may have different amounts of
first
solvent. The heavy oil product may have less of the first solvent than is
present in the mixture.
The heavy oil product may contain the first solvent and a second solvent.
There may be some
loss of the heavy end components from the mixture during the removal of some
of the first
solvent from the mixture. As such, the heavy oil product may contain a
slightly reduced
amount of heavy end components compared to the mixture. The heavy oil product
may retain
as much of the heavy end components as possible to achieve benefits, such as
those previously
described.
[0077] FIG. 2 is an illustration of asphaltene precipitation from mixtures
of Athabasca
heavy oil and solvent according to temperature and solvent concentration. The
solvent used in
Fig. 2 is n-heptane. From Fig. 2, it may be seen that the asphaltene
precipitation increases with
increased solvent concentration and decreased temperature. The asphaltene
precipitation
varies with solvent type, as shown in FIG. 3, which shows asphaltene and heavy
end
19
CA 02856460 2014-07-10
precipitation for the solvents, propane (C3), n-butane (C4), n-pentane (C5), n-
hexane (C6) and
n-heptane (C7) under the same conditions of temperature (for different
temperatures) and at a
certain solvent concentration.
[0078] The solubility of heavy end components, particularly asphaltenes,
in mixtures of
heavy oil and solvents may be affected in the following ways:
(I) temperature adjustment ¨ lower temperatures may result in
precipitation/separation;
(II) solvent concentration ¨ higher concentrations may result in
precipitation/separation;
(III) solvent type ¨ some solvents are more likely to result in
precipitation/separation
than others;
(IV) molecular weight of solvent ¨for solvents of a particular type, solvents
of lower
molecular weight may be more likely to result in precipitation/separation.
[0079] Regarding temperature adjustment, mixtures of heavy oil and
solvents produced
by solvent-based recovery processes may be delivered to a surface of a
subterranean reservoir
at temperatures higher (e.g., close to an operating temperature of the solvent-
based recovery
process) than both a naturally occurring temperature in the subterranean
reservoir (e.g., 5 to
12 Celsius ( C)) and an ambient temperature at a surface of the subterranean
reservoir. The
higher temperatures may maintain the heavy end components in solution or
suspension in the
mixture so that the heavy end components do not remain in the subterranean
reservoir.
Cooling of the mixture at the surface of the subterranean reservoir may result
in precipitation
of the heavy end components, such as asphaltenes.
[0080] Regarding solvent concentration, as shown in FIG. 2 for a solvent
that is an
alkane, the use of higher concentrations of solvent in the mixture of heavy
oil and solvent may
result in precipitation of asphaltenes at higher temperatures. It is a feature
of many solvent-
based recovery processes that the mixtures of heavy oil and solvent having
high concentrations
of solvent (e.g., greater than or equal to 30 wt.%) are produced, so that
asphaltene
precipitation is often likely on cooling of the mixture at the surface of the
subterranean
CA 02856460 2014-07-10
reservoir. The high concentration of solvent may include any number included
within or
bounded by the preceding range.
[0081] Regarding solvent type, solvents that may be employed for solvent-
based
recovery processes include, but are not limited to:
= normal (linear) alkanes;
= iso-alkanes (branched);
= cyclic alkanes (naphthenic, saturated)
= aromatic (cyclic, unsaturated) hydrocarbons; and
= alkenes or olefins (unsaturated).
[0082] The solvent used may depend on factors such as overall suitability
for solvent-
based recovery processes (which may depend, for example, on the boiling point
of the solvent),
relative cost and availability compared to other solvents, etc. Alkane based
solvents, also
referred to as paraffinic solvents, are often used in solvent-based recovery
processes because
of their relatively low cost, generally suitable boiling range, and their
ready availability at
production sites (e.g., in the form of gas plant condensates.) The solvents
may be single
compounds or mixtures of two or more compounds that may be of the same type or
of
different types. The above discussion of solvent type may apply to all
solvents used, including
the first solvent and the second solvent.
[0083] Regarding molecular weight of the solvent, lighter solvents (e.g.,
C3 and C4) can
cause higher asphaltene precipitation of both asphaltenes and other heavy end
components.
Heavier solvents (e.g., C5 and heavier) generally only cause precipitation of
asphaltenes. For
example, Fig. 3 illustrates the change in asphaltene and heavy end components
separation for
different solvents at different temperatures.
[0084] Substantial precipitation of heavy end components from the mixture
may be, for
example, removing no more than 5 wt.% asphaltenes (of the total weight of the
heavy oil)
where the heavy oil contains 15-20 wt.% asphaltenes and possibly 50 wt.% heavy
end
components. The weight percent of asphaltenes and heavy oil components in the
heavy oil
may include any number within or bounded by the respective preceding ranges.
21
CA 02856460 2014-07-10
[0085] The method of obtaining the heavy oil product may comprise forming
a treated
mixture. The treated mixture may be formed by treating the mixture to prevent
substantial
precipitation of heavy end components of the heavy oil from the mixture, 702
(Figure 7). The
mixture of the first solvent and heavy oil may be treated by heating the
mixture to above a
precipitation temperature of the mixture, reducing a concentration of the
solvent to below a
precipitation concentration, or adding a second solvent to the mixture.
[0086] The method of obtaining the heavy oil product may comprise
producing a
recovered solvent and the heavy oil product by separating a portion of the
first solvent from
the treated mixture, 704 (Figure 7). The heavy oil product may be a heavy oil
product that
retains all or at least substantially most of the heavy end components of the
heavy oil from the
mixture. The separation of the portion of the first solvent from the treated
mixture may be a
partial separation in which an amount of the first solvent is left in the
heavy oil product to
enable transportation of the heavy oil product by pipeline. The separation of
the portion of the
first solvent from the treated mixture may be a complete separation of the
first solvent from
the treated mixture to produce the heavy oil product. If the treated mixture
contains the
second solvent, then a portion of the second solvent may or may not be
separated when the
portion of the first solvent is separated.
[0087] The treated mixture may be separated into the heavy oil product,
the recovered
solvent and an aqueous phase consisting mainly of water carried from the
subterranean
reservoir by the mixture of the first solvent and heavy oil.
[0088] Virtually all of the first solvent may be removed from the treated
mixture as
solvent vapor or only part of the first solvent may be removed. If only part
of the first solvent is
removed, the non-vaporized portion of the first solvent that remains in the
heavy oil product
may reduce the viscosity of the heavy oil product to a level suitable for
pipelining. The removal
of some or all of the first solvent makes the heavy end components of the
heavy oil less likely to
precipitate or separate out, especially when the first solvent is alkane
based, so that the heavy
oil product may be allowed to cool to ambient temperature with a reduced risk
of the heavy
end components precipitating/separating from the heavy oil product. The
portion of the first
solvent removed as solvent vapor may be cooled, and then separated into a
light gas such as
22
CA 02856460 2014-07-10
methane and/or carbon dioxide (which may have originated within the
subterranean reservoir),
a recovered solvent, and an aqueous phase. The recovered solvent may be
supplemented with
fresh solvent heated and re-injected into the subterranean reservoir (e.g.,
via an injection well,)
for further operation of the solvent-based recovery process. Recycling of the
first solvent may
reduce an overall cost of the solvent-based recovery process. The heavy oil
product may
contain heavy end components. The heavy oil product may contain a lower amount
of the first
solvent than the mixture. The heavy oil product may be transported by pipeline
to a refinery or
other treatment plant.
[0089] The mixture may be treated by heating the mixture to a temperature
above a
precipitation temperature of the mixture at which the heavy end components
will precipitate
from the mixture. The mixture may be heated to a temperature above a heavy end
component
precipitation/separation temperature for a first solvent present in the
mixture. The mixture
may be heated to a temperature above a heavy end component
precipitation/separation
temperature for the first solvent employed for the solvent-based recovery
process that
produced the mixture. The temperature may vary according to the type of the
first solvent in
the mixture and a concentration of the first solvent in the mixture. Heating
of the mixture of
the first solvent and heavy oil may be used to avoid, or at least reduce,
separation of the heavy
end components, particularly asphaltenes.
[0090] The mixture may not be heated when treated if the temperature of
the mixture is
unlikely to fall below the temperature at which precipitation/separation
begins before the first
solvent is separated from the mixture. For example, the mixture may not be
heated if the
mixture is one having a fairly low temperature at which
precipitation/separation begins upon
cooling, or if a distance to be travelled by the mixture before separation of
the first solvent is
fairly short thereby allowing little time for cooling, especially if insulated
piping is employed for
the transfer from the production well to a fractionation facility.
[0091] The mixture may be treated by reducing a concentration of the first
solvent to
below a precipitation concentration at which the heavy end components
precipitate from the
mixture. Reducing the concentration of the first solvent may comprise one of:
(a) partially
evaporating the first solvent from the mixture to form the treated mixture,
(b) passing the
23
CA 02856460 2014-07-10
mixture through a membrane that is configured to allow only flow through of
the first solvent,
wherein the treated mixture comprises a portion of the mixture that does not
pass through the
membrane, and (c) introducing an extracting agent into the mixture that
dissolves a part of the
first solvent in the mixture to form a solution including the first solvent
and the extracting
agent, and separating the solution from the mixture to form the treated
mixture.
[0092] FIG. 5 shows a solvent/asphaltene precipitation phase boundary as
an example
for describing a solvent and asphaltene precipitation. The dashed line 500
shows the
precipitation boundary. Above this line in region 502, asphaltenes are
precipitated, but below
the line in region 504 there is no asphaltene precipitation. The mixture could
be heated from a
temperature at point "A" to a temperature at point 131" shown in FIG. 5, thus
moving the
mixture from the precipitation region 502 across the precipitation boundary to
the non-
precipitation region 504. The concentration of the solvent could be reduced to
point "Cl", i.e.
from about 68 wt.% to about 10 wt.%, which would drive the mixture into the
non-precipitation
region 504 which would reduce the risk of heavy end component
precipitation/separation
within the heavy oil product.
[0093] The first solvent may be partially evaporated from the mixture to
form the
treated mixture. The first solvent may be partially evaporated using one of a
single-stage flash
unit, a multi-stage flash unit and a distillation apparatus. If the first
solvent is volatile (e.g., a C3
to C5 alkane), passing the treated mixture through a single-stage flash unit
employing heat to
vaporize and remove some of the first solvent may result in greater solvent
reduction than if
the first solvent is of lower volatility, or if the first solvent contains
compounds of lower
volatility (e.g., C6+). If a higher degree of reduction is desired, and the
first solvent in the
mixture is of lower volatility, a multi-stage flash unit or a distillation
apparatus may be used to
partially evaporate the first solvent.
[0094] The mixture may be passed through the membrane that is configured
to allow
only flow through of the first solvent. The membrane may be a permeable
membrane or a
semi-permeable membrane. Passing the first solvent through the membrane may
reduce the
concentration of the first solvent. The membrane may contain pores large
enough to allow
molecules of the first solvent to pass through. The pores may be too small to
allow molecules
24
CA 02856460 2014-07-10
of the heavy oil and heavy end components to pass through. The first solvent
may pass through
the membrane under gravity or through an application of pressure against the
mixture to push
the first solvent through the membrane. The first solvent is thus separated
from the mixture.
The mixture may be passed through the membrane with portions of the mixture
that are
withheld from passage (i.e., the mixture that does not pass) through the
membrane forming
the treated mixture.
[0095] The extracting agent may be introduced into the mixture to dissolve
a part of the
first solvent. The introduction of the extracting agent may help reduce the
concentration of the
first solvent. The extracting agent may be introduced to mixture in an
extraction apparatus.
The extracting agent may be introduced into the mixture to selectively
dissolve either a part of
the first solvent or the heavy oil within itself, leaving the other component
of the mixture
(heavy oil or solvent, respectively) unextracted. The extracting agent and
either dissolved
solvent or dissolved heavy oil may then be separated from each other in a
further column or
vessel and re-used. The extracting agent may be a liquid that is an extraction
solvent for one of
the heavy oil and the first solvent of the mixture but that is immiscible with
other
component(s). The extracting agent may dissolve part of the first solvent to
form the solution
of the first solvent and the extracting agent. The solution may be separated
from the mixture
to form the treated mixture. For example, the solution may be separated from
the mixture
using distillation.
[0096] The mixture may be treated by adding a second solvent to the
mixture. The
heavy end components may be more soluble in the second solvent than in the
first solvent.
Adding the second solvent may help prevent precipitation/separation of heavy
end
components. The second solvent may be less likely to cause precipitation of
heavy end
components at temperatures that may be encountered at the surface of the
subterranean
reservoir than the first solvent.
[0097] The second solvent may be any suitable solvent. Alkane-based
solvents, such as
n-butane, n-pentane, n-hexane, or n-heptane, are often used for solvent-based
recovery
processes in which the first solvent is injected into the subterranean
reservoir as a vapor.
Alkane-based solvents have a tendency to allow the heavy end components to
CA 02856460 2014-07-10
precipitate/separate out at the surface of the subterranean reservoir. The
second solvent may
be a different type (e.g., benzene, toluene or xylene) or of a different
molecular weight (e.g., n-
decane) than the first solvent. The second solvent may be a single hydrocarbon
or a mixture of
different hydrocarbons. For example, the second solvent may be similar to the
first solvent but
with hydrocarbon components having a different molecular weight from the
hydrocarbons
components of the first solvent. For example, the second solvent may have a
higher molecular
weight than the molecular weight of the first solvent. The second solvent may
comprise a
second solvent compound that is a homologue of a first solvent compound of the
first solvent.
The first solvent may comprise a first alkane and the second solvent may
comprise a second
alkane. The second alkane may have a higher carbon atom number than a carbon
atom
number of the first alkane. For example, the carbon atom number of the first
alkane may be in
a range of C3 to C12, for example. The carbon atom number of the second
solvent may be
greater than or equal to C6 or any number included or bounded by this range.
The second
solvent may be any solvent that improves the solubility of asphaltene (e.g.,
gas oil, heavy gas
oil, synthetic crude oil, deasphalted bitumen, etc.). The second solvent may
comprise a second
solvent compound that is non-homologous to a first solvent compound of the
first solvent. The
first solvent may comprise a normal alkane. The second solvent may comprise at
least one of
normal alkanes, iso-alkanes, napthenic hydrocarbons, aromatic hydrocarbons and
olefin
hydrocarbons.
[0098] Once the second solvent has been added to the mixture, the
likelihood of
precipitation/separation of heavy end components may be reduced. The second
solvent in the
heavy oil product may reduce a viscosity of the heavy oil product so that the
heavy oil product
is more suitable for transport by pipeline despite containing heavy end
components.
[0099] Separating the portion of the first solvent from the treated
mixture may comprise
one of: (i) evaporating the portion of the first solvent from the treated
mixture to form the
heavy oil product, (ii) passing the mixture through a membrane that is
configured to allow only
flow through of the first solvent, where the heavy oil product comprises a
portion of the
treated mixture that does not pass through the membrane; and (iii) introducing
an extracting
agent into the treated mixture that dissolves a part of the first solvent in
the treated mixture to
26
CA 02856460 2014-07-10
form a solution including the first solvent and the extracting agent, and
separating the solution
from the treated mixture to form the heavy oil product. The solvent that is
separated from the
treated mixture may be only the first solvent or, if a second solvent was used
in treating the
mixture, then either the first solvent or the second solvent or both may be
separated from the
treated mixture. Separating the portion of the first solvent from the treated
mixture is
separate from treating the mixture by reducing a concentration of the first
solvent. Separating
the portion of the first solvent and reducing the concentration of the first
solvent may include
many of the same processes. Separating the portion of the first solvent may
attempt to remove
a larger portion of the first solvent than reducing the concentration of the
first solvent. If a
second solvent is added, then separating the portion of the first solvent may
or may not
remove a portion of the second solvent with the removal of the first solvent.
The second
solvent may not be in the mixture during reducing the concentration of the
first solvent.
[00100] The portion of the first solvent may be separated from the treated
mixture by
evaporation in one of a single-stage flash unit, a multi-stage flash unit and
a distillation
apparatus. A larger amount of solvent will be separated from the treated
mixture using a
single-stage flash unit when the first solvent is volatile (e.g., a C3 to C5
alkane) than when the
first solvent is of lower volatility. Removal of only a portion of the first
solvent may be suitable
if a sufficient amount of solvent is to remain in the heavy oil product to
reduce a viscosity of the
heavy oil product and enable transportation of the heavy oil product by
pipeline. The sufficient
amount of solvent in the heavy oil product to enable transportation of the
heavy oil product by
pipeline may be generally, for example, no more than 30 wt. % of the heavy oil
product being
solvent. If a higher degree of separation of the portion of the first solvent
is desired, and the
first solvent in the mixture is of lower volatility, a multi-stage flash unit
or a distillation
apparatus may be used. Evaporation to separate the portion of the first
solvent may use a
similar process to evaporation to reduce the concentration of the first
solvent but may use
different parameters, for example, time, etc.
[00101] When separating the portion of the first solvent, passing the
treated mixture
through the membrane may be a membrane as discussed above in connection with
reducing a
concentration of the first solvent in the mixture. Separating using the
membrane may allow
27
CA 02856460 2014-07-10
passage of more of the first solvent than when the mixture was treated. For
example,
separating using the membrane may differ from reducing the concentration of
the first solvent
by, for example, using a different membrane or different parameters such as a
time of the
separating process or a pressure that may be applied against the treated
mixture
[00102] The extracting agent may be introduced to the treated mixture to
separate the
portion of the first solvent. The extracting agent may dissolve either the
first solvent or the
heavy oil leaving the other components (heavy oil or first solvent,
respectively) unextracted.
The extracting agent and either the dissolved heavy oil or the dissolved first
solvent may be
separated from each other. The extracting agent may be the same as and/or
different from the
extracting agent discussed above in connection with reducing the concentration
of the first
solvent.
[00103] The portion of the solvent separated from the treated mixture may
be treated
and recycled to form recovered solvent. Treatment of separated solvent, may
include, for
example, treatment by a single stage flashing unit, a multi stage flashing
unit or a distillation
apparatus. The treatment of the separated solvent may, for example, involve
separation of by-
products such as light and heavy unwanted compounds, adjusting the composition
of the
solvent mixture, and possibly an aqueous phase from the separated solvent to
provide the
recovered solvent.
[00104] The method described above may be employed when it is desired to
retain all or
most of the heavy end components of the heavy oil in the heavy oil product.
[00105] The present disclosure may include an apparatus 400 for obtaining
a heavy oil
product from a mixture of a first solvent and heavy oil recovered from a
subterranean reservoir.
The apparatus 400 may be employed in conjunction with the above method in
which the heavy
oil product retains most or all of the heavy end components of the heavy oil
in the heavy oil
product.
[00106] The apparatus 400 may comprise a treating apparatus configured to
receive and
treat the mixture 472 to prevent substantial precipitation of heavy end
compounds of the
heavy oil from the mixture 472. The treating apparatus in Figure 4 may
comprise a heater 476.
The treating apparatus may or may not comprise a solvent separation apparatus,
such as but
28
CA 02856460 2014-07-10
not limited to the solvent separation apparatus 478 in Figure 4. The treating
apparatus 476
may be a separate and distinct apparatus from the solvent separation apparatus
478. A
production well 470 in a subterranean reservoir produces the mixture 472 of
the first solvent
and heavy oil as a product stream that is passed through the treating
apparatus. The treating
apparatus may comprise the heater 476. The heater 476 may heat the mixture to
prevent
substantial precipitation of heavy end components of the heavy oil from the
mixture 472. The
heater 476 may raise the temperature of the mixture 472 above a
precipitation/separation
temperature of the mixture 472 by heat exchange with a heating fluid to form
the treated
mixture 420. The treating apparatus may comprise a reduction apparatus to
reduce a
concentration of the first solvent in the mixture. The treating apparatus may
comprise, a
single-stage flashing unit, a multi-stage flashing unit, and a distillation
apparatus, each of which
may be the reduction apparatus. The treating apparatus may comprise a membrane
as
previously discussed for the reduction apparatus. The treating apparatus may
comprise an
extracting agent apparatus (not shown) in which an extracting agent, as
discussed above, may
be introduced to the mixture to reduce a concentration of the first solvent in
the mixture. The
treating apparatus may comprise an apparatus to add a second solvent to the
mixture 472. The
treating apparatus may output a treated mixture.
[00107] The apparatus 400 may comprise a solvent separation apparatus 478
in fluid
communication with the treating apparatus. The solvent separation apparatus
478 may be
configured to separate out a portion of the first solvent to produce a
separated first solvent
480, a heavy oil product 482, and a water product 484. When the solvent
separation apparatus
is not part of the treating apparatus, the solvent separation apparatus may
receive the treated
mixture from the treating apparatus.
[00108] The solvent separation apparatus 478 may separate a mixture (i.e.,
the mixture or
the treated mixture) into the separated first solvent 480, the heavy oil
product 482 and a water
product 484. The water product 484 may consist entirely or mainly of water.
The solvent
separation apparatus 478 may comprise at least one of a single-stage flashing
unit, a multi-
stage flashing unit, and a distillation apparatus. The solvent separation
apparatus 478 may
comprise a membrane as previously discussed for separating out the portion of
the first
29
CA 02856460 2016-02-12
solvent. The solvent separation apparatus 478 may comprise an extracting agent
apparatus in
which an extracting agent, as discussed above, may be introduced to the
treated mixture 420.
The extracting agent apparatus (not shown) may be a single stage extraction
vessel, multistage
extraction vessels, or an extractive column into which the extracting agent
can be introduced to
the treated mixture 420.
[00109] A solvent treating apparatus 422 may be in fluid communication with
the solvent
separation apparatus 478. The solvent treating apparatus 422 may be configured
to receive the
separated first solvent and separate the separated first solvent into a
recovered solvent 492
and by-products 494, 496. The solvent treating apparatus 422 is shown in Fig.
4 as a cooler 486
and a gas separator 490. The cooler 486 and the gas separator 490 may be
replaced by a
single-stage flashing unit, a multi-stage flashing unit or a distillation
apparatus. The solvent
treating apparatus 422 cleans up separated solvent for re-use while the
solvent separation
apparatus 478 separates solvent from the treated mixture.
[00110] The separated first solvent 480 may be combined with casing gas 488
issuing
from a well casing of the production well 470. The combined flows of the
separated first
solvent 480 and the casing gas 488 are passed through a cooler 486 that,
through heat
exchange with a cool fluid, cool the separated first solvent 480 and the
casing gas 488. The
casing gas and separated first solvent may then be fed to a gas separator 490
that separates the
casing gas and separated first solvent into the recovered solvent 496 and by-
products. The by-
products may include, for example, a light gas 492 (mainly methane and carbon
dioxide from
the subterranean reservoir) which may be removed from the apparatus 400 as a
valuable by-
product, and a water product 494. The water product 484 from the solvent
separation
apparatus 478 and the water product 494 from the gas separator 490 may be
combined and
removed for possible recycling or disposal.
[00111] The heavy oil product 482 from the solvent separation apparatus 478
may be
removed for possible transportation via a pipeline (not shown). The recovered
solvent 496
from the gas separator 490 may be mixed with fresh solvent 443 from a fresh-
solvent storage
structure 442 to make up for inevitable losses within the subterranean
reservoir and/or
amounts remaining in the heavy oil product 482. The mixed fresh solvent and
recovered
CA 02856460 2014-07-10
solvent may be fed to a vaporization assembly 450 for vaporization and
injection into an
injection well 430 via line 444.
[00112] The heavy oil product 482 may contain all of the heavy end
components from the
mixture of the heavy oil and the solvent with little or no solvent.
Alternatively, the heavy oil
product 482 may contain sufficient solvent to reduce a viscosity of the heavy
oil product 482 for
transportation by pipeline. The amount of solvent remaining in the heavy oil
product 482 may
be determined by the characteristics and conditions of operation of the
solvent separation
apparatus 478.
[00113] The heater 476 may keep the heavy end components in the mixture 472
in
solution or suspension at least until some or all of the first solvent can be
removed by the
solvent separation apparatus 478. The removal of some or all of the first
solvent may reduce
heavy end component precipitation, especially when the first solvent is one
that increases the
tendency of precipitation with increased concentration, e.g. lower alkanes
such as C3 to C7.
[00114] The apparatus 400 may remove most or all of the solvent from the
mixture 472
while producing a transportable heavy oil product containing the heavy end
components, with
a reduced risk of premature heavy end component precipitation.
[00115] Corresponding points "A", "E31" and "Cl from Fig. 5 are shown on
the apparatus
400 of FIG. 4.
[00116] Another method of the present disclosure may be a method of
obtaining a heavy
oil product from a mixture of a first solvent and heavy oil recovered from a
subterranean
reservoir. The heavy oil product obtained in this method may have a reduced
content of
asphaltenes. Details of the mixture of the first solvent and heavy oil may be
the same as those
previously described and may be produced by the previously described solvent-
based
recovered processes. The method may be employed when it is desired to remove a
portion of
the asphaltenes from the heavy oil in the heavy oil product. The first solvent
may be a solvent
as previously described that is injected into the subterranean reservoir to
reduce a viscosity of
the heavy oil to enable the heavy oil to be produced from the subterranean
reservoir during a
solvent-based recovery process as previously described. The heavy oil product
and the mixture
of the first solvent and heavy oil may differ in concentrations of the
solvent, the solvents
31
CA 02856460 2014-07-10
contained in the mixture versus the heavy oil product and/or the amount of
asphaltenes
contained in the mixture versus in the heavy oil product.
[00117] A treated mixture containing asphaltene precipitates may be formed
by treating
the mixture of the first solvent and heavy oil, 802 (Figure 8). Treating the
mixture may
comprise precipitating at least some asphaltenes in the heavy oil from the
mixture. The
mixture may be treated, for example, by cooling the mixture to below a
precipitation
temperature, such as is illustrated in Fig. 5 by points "A" to "B2", or adding
a second solvent to
the mixture so that a concentration of the first solvent and the second
solvent in the mixture is
above a precipitation concentration. The extent of precipitation may depend,
for example, on a
concentration of the first solvent and the second solvent.
[00118] Separated asphaltenes and a separated treated mixture may be
provided by
separating the asphaltene precipitates from the treated mixture, 804 (Figure
8).
[00119] A recovered solvent and the heavy oil product may be produced by
separating a
portion of the first solvent from the separated treated mixture, 806 (Figure
8). The separation
of the portion of the first solvent from the separated treated mixture may be
a partial
separation in which a sufficient amount of the first solvent is left in the
heavy oil product to
enable transportation of the heavy oil product by pipeline. The separation of
the portion of the
first solvent from the separated treated mixture may be a complete separation
of the first
solvent from the separated treated mixture to produce the heavy oil product.
[00120] The removal of some or all of the asphaltenes from the mixture and
then the
removal of some or all of the first solvent may reduce further precipitation
of the asphaltenes
within the heavy oil product. The removal of some or all of the asphaltenes
provides a heavy oil
product that may be more desirable to heavy oil refiners and/or may be a lower
viscosity than a
heavy oil containing all of the light end components and the heavy end
components. The heavy
oil product having the reduced content of asphaltenes may be suitable for
transport by pipeline
with little or no solvent remaining in the heavy oil product
[00121] An illustration of this method is also provided by the graph of
FIG. 5. The mixture
shown at point "A" is moved to point "B2" by the initial
precipitation/separation of the
asphaltenes, i.e. the mixture is moved further into the asphaltene
precipitation region 502. The
32
CA 02856460 2014-07-10
removal of the precipitated/separated asphaltenes and subsequent removal of
some or all of
the solvent by heating moves the heavy oil product to point "C2", i.e., into
the non-asphaltene
precipitation region 504 so that further asphaltene precipitation may no
longer be a concern.
[00122] The mixture may be treated by one of: (i) cooling the mixture to a
temperature
below a precipitation temperature at which asphaltenes begin to precipitate
from the mixture;
and (ii) adding a second solvent to the mixture so that a concentration of the
first solvent and
the second solvent together in the mixture is above a precipitation
concentration at which
asphaltenes precipitate from the mixture.
[00123] Higher concentrations of solvent may increase the tendency of the
asphaltenes to
precipitate/separate, especially when an alkane is used as the first solvent.
The second solvent
may be the same as the first solvent used for the solvent-based recovery
process and therefore
already present in the mixture. The second solvent may be a different solvent
from the first
solvent. If the second solvent is a different solvent, the second solvent may
be a solvent of the
same type or of a different type from the first solvent. If the first solvent
and the second
solvent are of the same type (e.g., different members of the group alkanes),
the second solvent
may be a solvent of lower molecular weight since solvents of lower molecular
weight have an
increased tendency to cause asphaltene precipitation. Thus, for example, if
the first solvent in
the mixture is n-heptane, the second solvent added at the surface of the
subterranean reservoir
may be n-hexane or n-pentane. If the second solvent is of a different type,
the second solvent
may be one having an increased tendency to cause asphaltene
precipitation/separation versus
the first solvent in the mixture. For example, if the first solvent in the
mixture is an iso-alkane
(branched alkane), the second solvent may be an n-alkane (linear alkane) of
the same number
of carbon atoms or fewer.
[00124] The second solvent may comprise a second solvent compound that is a
homologue of a first solvent compound of the first solvent. The second solvent
and the first
solvent may comprise at least one compound selected from the group consisting
of a normal
alkane, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and
olefin
hydrocarbons. The first solvent may comprise a first alkane and the second
solvent may
comprise a second alkane. The second alkane may have a lower carbon atom
number than a
33
CA 02856460 2014-07-10
carbon atom number of the first alkane. For example, the carbon atom number of
the first
alkane and the second alkane may be in a range of C2 to C12 inclusive. This
range of carbon
atoms may include any number within or bounded by the preceding range.
Alternatively, the
second solvent may comprise a second solvent compound that is non-homologous
to a first
solvent compound of the first solvent. The first solvent may comprise at least
one of iso-
alkanes, napthenic hydrocarbons, aromatic hydrocarbons and olefin
hydrocarbons. The second
solvent may comprise a normal alkane.
[00125] The asphaltene precipitates may be separated from the treated
mixture by
settling the asphaltene precipitates from the mixture by an action of gravity
and removing the
treated mixture from the settled precipitates. For example, the treated
mixture may be placed
in a vessel where the precipitates can settle under the action of the gravity
to the bottom of the
vessel. Water may be present in the mixture. The water may form a layer below
the treated
mixture that is removed from the treated mixture together with the asphaltene
precipitates.
[00126] The portion of the first solvent that is separated from the
separated treated
mixture may be separated by one of: (i) evaporating the portion of the first
solvent from the
separated treated mixture to form the heavy oil product, (ii) passing the
mixture through a
membrane that is configured to allow only flow through of the first solvent,
wherein the heavy
oil product comprises a portion of the separated treated mixture that does not
pass through
the membrane; and (iii) introducing an extracting agent into the separated
treated mixture that
dissolves a part of the first solvent in the separated treated mixture to form
a solution including
the first solvent and the extracting agent, and separating the solution from
the separated
treated mixture to form the heavy oil product. Separation of the portion of
the first solvent
from the separated treated mixture may be performed by the same process as
separating of
the portion of the first solvent from the treated mixture as previously
described.
[00127] The first solvent that has been separated from the separated
treated mixture,
806 (Figure 8) may be treated and recycled to form recovered solvent.
Treatment of separated
first solvent, which is the first solvent that has been separated from the
separated treated
mixture while separating the portion of the first solvent, may include, for
example, treating by a
single stage flashing unit, a multi stage flashing unit or a distillation
apparatus. The treatment
34
CA 02856460 2016-02-12
- of the separated solvent may, for example, involve separation of by-
products such as light gas
and heavy unwanted compounds, adjusting the composition of the solvent
mixture, and
possibly an aqueous phase from the separated solvent to provide the recovered
solvent.
[00128] The present disclosure may include an apparatus for
obtaining a heavy oil product
from a mixture of a first solvent and heavy oil recovered from a subterranean
reservoir. The
heavy oil product obtained by this apparatus may have a lower content of
asphaltenes. This
apparatus may be employed in conjunction with the method in which the heavy
oil product
having a lower content of asphaltenes is employed.
[00129] An apparatus 600 (Figure 6) for obtaining the heavy oil
product may comprise a
treating apparatus 624 configured to receive and treat the mixture 672 to
cause precipitation of
at least some asphaltenes of the heavy oil from the mixture to form a treated
mixture
containing asphaltene precipitates. The treating apparatus may comprise a
combiner 620 for
combining the mixture 672 with a second solvent 674 and/or a cooler 675. One
or both of the
combiner 620 and the cooler 675 may be present in the treating apparatus 624.
[00130] A production well 670 produces a mixture 672 of the first
solvent and heavy oil as
a product stream that may be mixed with a second solvent 674. The second
solvent 674 may
be in excess of solvent required to cause precipitation of asphaltenes from
the mixture. The
mixture 672 with the added second solvent 674 is passed through a cooler 675
where cooling is
effected by heat exchange with a cooler fluid. The cooler 675 producing the
treated mixture
622. As shown in Fig. 5, cooling the mixture moves the mixture from "A" to
132", which is
beyond the precipitation boundary. As can be seen in Fig. 5, an increase in
concentration of the
solvent (not shown) would also move the mixture to well above the
precipitation boundary
where precipitation of the asphaltenes would occur above the precipitation
boundary.
[00131] The apparatus 600 may comprise an asphaltene separation
apparatus 677 in fluid
communication with the treating apparatus 624 to receive the treated mixture
622. The
asphaltene separation apparatus 677 may be configured to separate the
asphaltene
precipitates from the treated mixture 622 to provide separated asphaltenes 679
and a
separated treated mixture 681.
CA 02856460 2016-02-12
. [00132] The treated mixture 622 may be transferred to the asphaltene
separation
apparatus 677. Asphaltene precipitates may settle from the treated mixture 622
while in the
asphaltene separation apparatus 677. The settled asphaltene precipitates may
be removed in
an asphaltene mixture 679 together with a water product containing mainly
water produced
from the subterranean reservoir. The treated mixture from which the asphaltene
mixture 679
may have been separated may form a separated treated mixture (or a lower
asphaltene
content heavy oil and solvent mixture) 681.
[00133] The asphaltene mixture 679 may be delivered to an asphalt
separation unit 683.
The asphalt separation unit 683 may separate the asphaltene mixture 679 into a
water product
684 and asphalt 685. The asphalt 685 may be removed from the apparatus 600.
The asphalt
685 may be used as a saleable product, e.g. for road construction.
[00134] The apparatus 600 may comprise a solvent separation
apparatus 628 in fluid
communication with the asphaltene separation apparatus 677 to receive the
separated treated
mixture. The solvent separation apparatus 628 may be configured to separate a
portion of the
first solvent from the separated treated mixture 681 to produce a separated
first solvent 680
and the heavy oil product 682 having the lower content of asphaltenes. The
solvent separation
apparatus 628 may include a solvent separator 678 possibly with a heater 676.
The solvent
separator 678 may comprise at least one of a single-stage flashing unit, a
multi-stage flashing
unit, a distillation apparatus, the membrane as previously described, and an
extracting agent
apparatus in which an extracting agent may be introduced to the treated
mixture, the
extracting agent dissolving a part of the solvent in the treated mixture.
[00135] The separated treated mixture 681 remaining after the
asphaltene separation is
passed from the asphaltene separator 677 to a heater 676, where the separated
treated
mixture 681 may be heated by heat exchange with a heated fluid. The heated
separated
treated mixture may be passed to a solvent separator 678 that separates the
heated separated
treated mixture into a separated first solvent 680 and a heavy oil product 682
which may
consequently contain little or no solvent. The heavy oil product 682 may have
a lower amount
of solvent according to the type of apparatus used for the solvent separator
678 and the
conditions employed for the separation. The heavy oil product 682 may be
transported via
36
CA 02856460 2016-02-12
= pipeline with a reduced risk of further precipitation of asphaltenes or
other heavy end
components of the heavy oil from the heavy oil product.
[00136] The apparatus 600 for obtaining the heavy oil product may
comprise a solvent
treating apparatus 630 in fluid communication with the solvent separation
apparatus 628 to
receive the separated first solvent for separating the separated first solvent
680 into a
recovered solvent 696 and by-products 692, 694. The solvent treating apparatus
630, shown as
a cooler 686 and a gas/solvent separator 690 may be replaced by at least one
of a single-stage
flashing unit, a multi-stage flashing unit, and a distillation apparatus.
[00137] The separated first solvent 680 from the solvent separator
678 may be mixed
with casing gas 688 (e.g., mainly methane and carbon dioxide) from a casing of
the production
well 670. The mixed solvent vapor and casing gas may be passed through a
cooler 686 before
being delivered to a gas/solvent separator 690. The gas/solvent separator 690
separates the
mixed solvent vapor and casing gas from the cooler 686 into a recovered
solvent 696 and by-
products such as a light gas component 692, and a water product 694. The light
gas component
692 is a potentially valuable product that may be removed from the apparatus
600 and used as
a fuel or sold. The aqueous component 694 may be mixed with the water product
684 from the
asphalt separation unit 683 and removed from the apparatus 600 for recycling
or disposal. The
recovered solvent 696 from the gas separator 690 may be mixed with fresh
solvent 643 added
from a storage structure 642 to make up for inevitable losses within the
reservoir and/or
amounts remaining in the heavy oil product 682. The recovered and fresh
solvent mixture is
delivered to a vaporization assembly 650 to convert it to a vapor for
injection into an injection
well 631 for further operation of the solvent-based recovery process within
the subterranean
reservoir.
[00138] FIG. 6 shows points "A", "B2" and "C2" corresponding to
those shown on FIG. 5.
[00139] While detailed information has been provided above, it will
be understood that
numerous changes, modifications, and alternatives to the preceding description
can be made
and the scope of the claims should not be limited to the preferred and
exemplified
embodiments set forth. The scope of the claims should be given the broadest
interpretation
consistent with the description as a whole. It is also contemplated that
structures and features
37
CA 02856460 2016-02-12
in the present examples can be altered, rearranged, substituted, deleted,
duplicated,
combined, or added to each other in any effective manner.
38
