Note: Descriptions are shown in the official language in which they were submitted.
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REGULATION OF ASPHALTENE PRODUCTION IN A SOLVENT-BASED
RECOVERY PROCESS AND SELECTION OF A COMPOSITION OF A
HYDROCARBON SOLVENT MIXTURE
BACKGROUND
Field of Disclosure
[0001] The present disclosure relates to regulating asphaltene
production in a solvent-
based recovery process and selecting a composition of a hydrocarbon solvent
mixture.
Description of Related Art
[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. For
example, the heavy oil may be sufficiently viscous that economical production
of the heavy
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oil from a subterranean formation is precluded.
[0005] Several conventional recovery processes, such as but not limited
to thermal
recovery processes, have been utilized to decrease the viscosity of the heavy
oil. Decreasing
the viscosity of the heavy oil may decrease a resistance of the heavy oil to
flow and/or permit
production of the heavy oil from the subterranean formation by piping,
flowing, and/or
pumping the heavy oil from the subterranean formation. While each of these
recovery
processes may be effective under certain conditions, each possess inherent
limitations.
[0006] One of the conventional recovery processes utilizes steam
injection. The steam
injection may be utilized to heat the heavy oil to decrease the viscosity of
the heavy oil.
Water and/or steam may represent an effective heat transfer medium, but the
pressure
required to produce saturated steam at a desired temperature may limit the
applicability of
steam injection to high pressure operation and/or require a large amount of
energy to heat the
steam.
[0007] Another of the conventional recovery processes utilizes cold
and/or heated
solvents. Cold and/or heated solvents may be injected into a subterranean
formation as
liquids and/or vapors to decrease the viscosity of heavy oil present within
the subterranean
formation. Traditionally, pure (i.e., single-component), or at least
substantially pure, propane
is injected into the subterranean formation as the cold and/or heated solvent.
The injected
propane may dissolve the heavy oil, dilute the heavy oil, and/or transfer
thermal energy to the
heavy oil. Utilizing the cold and/or heated solvents may suffer from limited
injection
temperature and/or pressure operating ranges, and/or an inability to
effectively decrease the
viscosity of the heavy oil.
[0008] In general, the conventional recovery processes may not decrease
the viscosity of
the heavy oil present within the subterranean formation. For example, certain
heavy oil may
not be soluble within the solvents utilized in a conventional recovery
process; a substantial
fraction of the heavy oil present in a subterranean formation may comprise
asphaltenes.
Asphaltenes may not be soluble in the solvent used and thus the asphaltenes
may not be
produced from the subterranean formation. Under certain conditions, it may be
desirable to
produce at least a fraction of the asphaltenes from the subterranean
formation; it may be
desirable to regulate an asphaltene content of the heavy oil produced from the
subterranean
formation.
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[0009] A need exists for improved technology, including technology that
may address
one or more of the above described disadvantages. For example, a need exists
for regulating
asphaltene production in a solvent-based recovery processes; a need exists for
selecting a
composition of a hydrocarbon solvent mixture.
SUMMARY
[0010] It is an object of the present disclosure to provide systems and
methods for
regulation of asphaltene production in a solvent-based recovery process and
selecting a
hydrocarbon solvent mixture composition of a hydrocarbon solvent mixture.
[0011] A method of regulating asphaltene product in a solvent-based
recovery process
solvent-based recovery process may include determining a bituminous
hydrocarbon deposit
composition of a bituminous hydrocarbon deposit that includes asphaltenes and
is present
within a subterranean formation; selecting a hydrocarbon solvent mixture
composition of a
hydrocarbon solvent mixture based on the bituminous hydrocarbon deposit
composition,
wherein selecting comprises selecting such that a product hydrocarbon stream
that is
produced by combining the hydrocarbon solvent mixture and the bituminous
hydrocarbon
deposit within a solvent extraction chamber extending within the subterranean
formation, is
expected to have at least a threshold asphaltene content at a temperature and
pressure within
the solvent extraction chamber, and wherein the hydrocarbon solvent mixture
includes
hydrocarbon molecules that define an average molecular carbon content;
injecting the
hydrocarbon solvent mixture into the solvent extraction chamber; producing the
product
hydrocarbon stream from the subterranean formation; determining a product
hydrocarbon
stream asphaltene content of the product hydrocarbon stream; and comparing the
product
hydrocarbon stream asphaltene content to a target asphaltene content for the
product
hydrocarbon stream.
[0012] A method of selecting a hydrocarbon solvent mixture composition of a
hydrocarbon solvent mixture for injection into a subterranean formation at an
injection
pressure to produce a product hydrocarbon stream from the subterranean
formation via a
solvent-based recovery process, wherein the subterranean formation includes a
bituminous
hydrocarbon deposit that includes asphaltenes, and wherein the product
hydrocarbon stream
is generated via combination of the hydrocarbon solvent mixture and the
bituminous
hydrocarbon deposit within a solvent extraction chamber that extends within
the subterranean
formation, may comprise determining a threshold maximum pressure of the
subterranean
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formation; determining a stream temperature at which the hydrocarbon solvent
mixture is to
be injected into the subterranean formation; determining a target asphaltene
content for the
product hydrocarbon stream; and selecting the hydrocarbon solvent mixture
composition
based on the stream temperature, the threshold maximum pressure, and the
target asphaltene
content, wherein the hydrocarbon solvent mixture includes hydrocarbon
molecules that
define an average molecular carbon content.
[0013] 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
[0014] 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.
[0015] Fig. 1 is a schematic representation of examples of a hydrocarbon
production
system.
[0016] Fig. 2 is a schematic representation of a surface facility.
[0017] Fig. 3 is a bar graph illustrating heavy end component deposition
within a
subterranean formation for various single-component hydrocarbon solvents.
[0018] Fig. 4 is a table illustrating an average saturation temperature
for three different
hydrocarbon solvent mixtures.
[0019] Fig. 5 is a bar graph illustrating heavy end component deposition
within the
subterranean formation for the three different hydrocarbon solvent mixtures of
Fig. 4.
[0020] Fig. 6 is a flowchart depicting a method of regulating asphaltene
production in a
multicomponent solvent-based recovery process.
[0021] Fig. 7 is a flowchart depicting a method of selecting a composition
of a
hydrocarbon solvent mixture to be utilized in a multicomponent solvent-based
recovery
process.
DETAILED DESCRIPTION
[0022] For the purpose of promoting an understanding of the principles
of the disclosure,
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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.
[0023] 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.
[0024] 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
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.
[0025] "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);
wt.% aromatics (which can range from 15 wt.% - 50 wt.%, or higher);
30 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.%).
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[0025]
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.
[0026]
The term "heavy oil" includes bitumen, as well as lighter materials that may
be
found in a sand or carbonate reservoir. "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 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.
[0027]
"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.
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[0028] "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.
[0029] 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, and mixtures
of steam and
wet steam, any of which could possibly be used with a solvent and other
substances, and any
material in the vapor phase.
[0030] "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.
[0031] "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
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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.
[0032] A
"subterranean reservoir" is a subsurface rock or sand reservoir from which a
production fluid, or resource, can be harvested. A
subterranean reservoir may
interchangeably be referred to as a subterranean formation. The subterranean
formation may
include sand, granite, silica, carbonates, clays, and organic matter, such as
bitumen, heavy oil
(e.g., bitumen), oil, gas, 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.
[0033]
"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.
[0034]
"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-based extraction recovery
process (SEP),
thermal solvent-based extraction recovery processes (TSEP), and any other such
recovery
process employing solvents either alone or in combination with steam. A
solvent-based
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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.
[0035] 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.
[0036] "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).
[0037] "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.
[0038] A "solvent extraction chamber" is a region of a subterranean
reservoir containing
heavy oil that forms around a well that is injecting solvent into the
subterranean reservoir.
The solvent extraction chamber has a temperature and a pressure that is
generally at or close
to a temperature and pressure of the solvent injected into the subterranean
reservoir. The
solvent extraction chamber may form when heavy oil has, due to heat from the
solvent,
dissolution within the solvent, combination with the solvent, and/or the
action of gravity, at
least partially mobilized through the pore spaces of the reservoir matrix. The
mobilized
heavy oil may be at least partially replaced in the pore spaces by solvent,
thus forming the
solvent 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
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remainder possibly being heavy oil.
[0039] A "vapor chamber" is a solvent extraction chamber that includes a
vapor, or
vaporous solvent. Thus, when the solvent is injected into the subterranean
formation as a
vapor, a vapor chamber may be formed around the well.
[0040] A "compound that has five or more carbon atoms" may include any
suitable single
chemical species that may include five or more carbon atoms. A "compound that
has five or
more carbon atoms" also may include any suitable mixture of chemical species.
Each of the
chemical species in the mixture of chemical species may include five or more
carbon atoms
and each of the chemical species in the mixture of chemical species also may
include the
same number of carbon atoms as the other chemical species in the mixture of
chemical
species. For example, a compound that has five carbon atoms may include a
pentane, n-
pentane, a branched pentane, cyclopentane, a pentene, n-pentene, a branched
pentene,
cyclopentene, a pentyne, n-pentyne, a branched pentyne, cyclopentyne,
methylbutane,
dimethylpropane, ethylpropane, and/or any other hydrocarbon with five carbon
atoms. A
compound with six carbon atoms, seven carbon atoms, or eight carbon atoms may
include a
single chemical species with six carbon atoms, seven carbon atoms, or eight
carbon atoms,
respectively, and/or may include a mixture of chemical species that each
include six carbon
atoms, seven carbon atoms, or eight carbon atoms, respectively.
[0041] 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.
These terms when used in reference to a quantity or amount of a material, or a
specific
characteristic of the material, refer to an amount that is sufficient to
provide an effect that the
material or characteristic was intended to provide. The exact degree of
deviation allowable
may in some cases depend on the specific context.
100421 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.
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[0043] As used herein, the phrase "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 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.
[0044] As used herein, the term "and/or" placed between a first entity and
a second entity
means one of (1) the first entity, (2) the second entity, and (3) the first
entity and the second
entity. Multiple entities listed with "and/or" should be construed in the same
manner, i.e.,
"one or more" of the entities so conjoined. Other entities may optionally be
present other
than the entities specifically identified by the "and/or" clause, whether
related or unrelated to
those entities specifically identified. Thus, as a non-limiting example, a
reference to "A
and/or B," when used in conjunction with open-ended language such as
"comprising" may
refer to A only (optionally including entities other than B); to B only
(optionally including
entities other than A); to both A and B (optionally including other entities).
These entities
may refer to elements, actions, structures, steps, operations, values, and the
like.
[0045] As used herein the terms "adapted" and "configured" mean that the
element,
component, or other subject matter is designed and/or intended to perform a
given function.
Thus, the use of the terms "adapted" and "configured" should not be construed
to mean that a
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,
given element, component, or other subject matter is simply "capable of"
performing a given
function but that the element, component, and/or other subject matter is
specifically selected,
created, implemented, utilized, programmed, and/or designed for the purpose of
performing
the function. It is also within the scope of the present disclosure that
elements, components,
and/or other recited subject matter that is recited as being adapted to
perform a particular
function may additionally or alternatively be described as being configured to
perform that
function, and vice versa.
[0046] As used herein, the phrase, "for example," the phrase, "as
an example," and/or
simply the term "example," when used with reference to one or more components,
features,
details, structures, embodiments, and/or methods according to the present
disclosure, are
intended to convey that the described component, feature, detail, structure,
embodiment,
and/or method is an illustrative, non-exclusive example of components,
features, details,
structures, embodiments, and/or methods according to the present disclosure.
Thus, the
described component, feature, detail, structure, embodiment, and/or method is
not intended to
be limiting, required, or exclusive/exhaustive; and other components,
features, details,
structures, embodiments, and/or methods, including structurally and/or
functionally similar
and/or equivalent components, features, details, structures, embodiments,
and/or methods, are
also within the scope of the present disclosure.
[0047] Any of the ranges disclosed may include any number within
and/or bounded by
the range given.
[0048] Figs. 1-7 provide illustrative, non-exclusive examples of
systems 10 according to
the present disclosure, components of systems 10, data that may be utilized to
select a
composition of a hydrocarbon solvent mixture 32 that may be utilized with
systems 10,
and/or methods, according to the present disclosure, of operating and/or
utilizing systems 10.
The systems 10 may be referred to as hydrocarbon production systems 10.
Elements that
serve a similar, or at least substantially similar, purpose are labeled with
like numbers in each
of Figs. 1-7, and these elements may not be discussed in detail herein with
reference to each
of Figs. 1-7. Similarly, all elements may not be labeled in each of Figs. 1-7,
but associated
reference numerals may be utilized for consistency. Elements, components,
and/or features
that are discussed herein with reference to one or more of Figs. 1-7 may be
included in and/or
utilized with any of Figs. 1-7 without departing from the scope of the present
disclosure.
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[0049] In
general, elements that are likely to be included are illustrated in solid
lines,
while elements that are optional are illustrated in dashed lines. However,
elements that are
shown in solid lines may not be essential. Thus, an element shown in solid
lines may be
omitted without departing from the scope of the present disclosure.
[0050] Fig. 1 is a schematic representation of a hydrocarbon production
system 10 that
may be utilized with, may be included in, and/or may include the systems and
methods
according to the present disclosure. Hydrocarbon production system 10 may
include an
injection well 30 and a production well 70 that extend within a subterranean
formation 24
that is present within a subsurface region 22 and/or that extend between a
surface region 20
and the subterranean formation 24. Hydrocarbon production system 10 may
include a surface
facility 40. Surface facility 40 may be configured to receive a product
hydrocarbon stream 72
from production well 70. Product hydrocarbon stream 72 may be hydrocarbon
produced
from the subterranean formation 24. Surface facility 40 may be configured to
provide a
hydrocarbon solvent mixture 32 to injection well 30.
[0051] Hydrocarbon solvent mixture 32 may be, or may be referred to as, a
liquid
hydrocarbon solvent mixture 32.
When the hydrocarbon solvent mixture is liquid
hydrocarbon solvent mixture 32, the solvent-based recovery process may be
referred to as, or
may be, a liquid extraction process. An example of a liquid extraction process
is a cyclic
solvent process (CSP). Hydrocarbon solvent mixture 32 also may be, or may be
referred to
as, a vaporous hydrocarbon solvent mixture 32. When the hydrocarbon solvent
mixture is
vaporous hydrocarbon solvent mixture 32, the solvent-based recovery process
may be
referred to as, or may be, a vapor extraction process (VAPEX). Hydrocarbon
solvent mixture
32 also may be, or may be referred to as, a liquid-vapor hydrocarbon solvent
mixture 32 that
includes a liquid and a vapor.
[0052] When the solvent-based recovery process is performed using heated
solvent, the
solvent-based recovery process may be referred to as a high temperature
solvent (and/or
vapor) solvent-based recovery process. The heated solvent may be injected into
the
subterranean formation at an injection temperature and an injection pressure.
The injection
temperature may be at, or near, a saturation temperature for the heated
solvent at the injection
pressure. When more than one solvent is utilized, the extraction process may
be referred to
as a multi-solvent-based recovery process and/or a multi-component solvent-
based recovery
process, which, at elevated temperatures, may be referred to as a high
temperature multi-
13
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component solvent-based recovery process, which may be a high temperature
multi-
component vapor extraction process.
[0053] Once provided to subterranean formation 24, hydrocarbon solvent
mixture 32 may
combine with bituminous hydrocarbon deposit 25 within a solvent extraction
chamber 60,
may dissolve in bituminous hydrocarbon deposit 25, and/or may dissolve
bituminous
hydrocarbon deposit 25, thereby decreasing the viscosity of the bituminous
hydrocarbon
deposit. When hydrocarbon solvent mixture 32 is a vaporous hydrocarbon solvent
mixture,
solvent extraction chamber 60 may be referred to as a vapor chamber 60. The
vaporous
hydrocarbon solvent mixture may condense within vapor chamber 60. When
hydrocarbon
solvent mixture 32 condenses, the hydrocarbon solvent mixture may release
latent heat (or
latent heat of condensation), transfer thermal energy to the subterranean
formation, and/or
generate a condensate 34. Condensation of the hydrocarbon solvent mixture 32
may heat a
bituminous hydrocarbon deposit 25 that may be present within the subterranean
formation,
thereby decreasing a viscosity of the bituminous hydrocarbon deposit.
[0054] The bituminous hydrocarbon deposit 25 may include bitumen 26,
gaseous
hydrocarbons 27, asphaltenes 28, and/or water 29. Hydrocarbon solvent mixture
32 and/or
condensate 34 also may combine with, mix with, be dissolved in, dissolve,
and/or dilute
bituminous hydrocarbon deposit 25, further decreasing the viscosity of the
bituminous
hydrocarbon deposit.
[0055] The energy transfer between hydrocarbon solvent mixture 32 and
bituminous
hydrocarbon deposit 25 and/or the mixing of hydrocarbon solvent mixture 32
and/or
condensate 34 with bituminous hydrocarbon deposit 25 may generate reduced-
viscosity
hydrocarbons 74, which may flow to production well 70. After flowing to
production well
70, reduced-viscosity hydrocarbons 74 may be produced from the subterranean
formation as
product hydrocarbon stream 72. The reduced-viscosity hydrocarbons 74 may have
a lower
viscosity than the hydrocarbons within the subsurface formation 24 had before
the
hydrocarbon solvent mixture 32 was injected into the subterranean formation
24. The
product hydrocarbon stream 72 may comprise reduced-viscosity hydrocarbons 74,
asphaltenes 28, gaseous hydrocarbons 27, water 29, hydrocarbon solvent mixture
32, and/or
condensate 34 in any suitable ratio and/or relative proportion.
[0056] The systems and methods according to the present disclosure may
be utilized to
control and/or regulate a product hydrocarbon stream composition of the
product
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hydrocarbon stream 72. The systems and methods according to the present
disclosure may be
utilized to control and/or regulate a portion of the bituminous hydrocarbon
deposit 25 that is
produced from the subterranean formation 24. A hydrocarbon solvent mixture
composition
of the hydrocarbon solvent mixture may be controlled, regulated, and/or varied
such that a
first portion of the bituminous hydrocarbon deposit becomes reduced-viscosity
hydrocarbons
74 and/or is produced with product hydrocarbon stream 72. The hydrocarbon
solvent mixture
composition may be controlled, regulated, and/or varied such that a second
portion of the
bituminous hydrocarbon deposit remains within the subterranean formation, does
not become
reduced-viscosity hydrocarbons 74, and/or is not produced with product
hydrocarbon stream
72. The first portion of the bituminous hydrocarbon deposit may have a lower
asphaltene
content than the bituminous hydrocarbon deposit and may be referred to as an
upgraded
portion of the bituminous hydrocarbon deposit. The second portion of the
bituminous
hydrocarbon deposit may have a higher asphaltene content than the bituminous
hydrocarbon
deposit and also may be referred to as a retained portion of the bituminous
hydrocarbon
deposit. The first portion of the bituminous hydrocarbon deposit may be
different from the
second portion of the bituminous hydrocarbon deposit.
[0057] The systems and methods according to the present disclosure may be
discussed in
the context of determining, adjusting, and/or regulating the asphaltene
content of the product
hydrocarbon stream. It is to be understood that adjusting and/or regulating
the asphaltene
content of the product hydrocarbon stream may include regulating the
proportion of the
asphaltenes from the bituminous hydrocarbon deposit that are retained within
the
subterranean formation and/or that are not produced with the product
hydrocarbon stream.
[0058] Surface facility 40 may process product hydrocarbon stream 72
and/or may
separate product hydrocarbon stream 72 into one or more component streams
prior to the
product hydrocarbon stream being conveyed from the surface facility 40.
Surface facility 40
may separate product hydrocarbon stream 72 into a bitumen product stream 42, a
gaseous
hydrocarbon product stream 44, an asphaltene product stream 48, a separated
solvent stream
49, and/or a water product stream 46, which may include water 29. The bitumen
product
stream 42 may include bitumen 26 and/or asphaltenes 28. The gaseous
hydrocarbon product
stream 44 may include gaseous hydrocarbons 27. The asphaltene product stream
48 may
include asphaltenes 28. The separated solvent stream 49 may include a portion
of
hydrocarbon solvent mixture 32 that was produced with product hydrocarbon
stream 72.
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:
Separated solvent stream 49 may be referred to as a surplus solvent stream 49,
an undesired
solvent stream 49, an unwanted solvent stream 49, and/or an excess solvent
stream 49.
Separated solvent stream 49 may be generated as a result of adjustments to the
hydrocarbon
solvent mixture composition. Separated solved stream 49 may be generated as a
result of
removing some of the solvents in product hydrocarbon stream 72 that are not
wanted or
desired to be in the hydrocarbon solvent mixture 32.
[0059] Surface facility 40 may generate hydrocarbon solvent
mixture 32 from any
suitable source. Surface facility 40 may receive a supplemental solvent stream
31 and/or may
supply at least a portion of the solvent stream to injection well 30 as
hydrocarbon solvent
mixture 32. Surface facility 40 may separate at least a portion of gaseous
hydrocarbons 27,
hydrocarbon solvent mixture 32, and/or condensate 34 from product hydrocarbon
stream 72.
Surface facility 40 may recycle and/or re-inject the separated gaseous
hydrocarbons 27,
separated hydrocarbon solvent mixture 32, and/or separated condensate 34 into
injection well
30 as hydrocarbon solvent mixture 32.
[0060] Conventional recovery processes that utilize an injected vapor
stream to decrease
the viscosity of hydrocarbons may utilize a pure (i.e., single-component), or
at least
substantially pure, injected vapor stream that comprises a light hydrocarbon,
such as propane.
In contrast, the systems and methods according to the present disclosure may
utilize a
hydrocarbon solvent mixture 32. The hydrocarbon solvent mixture 32 may include
a heavy
hydrocarbon fraction that comprises, consists of, or consists essentially of
hydrocarbons with
five or more carbon atoms. The heavy hydrocarbon fraction may comprise greater
than 10
mole percent, greater than 20 mole percent, greater than 30 mole percent,
greater than 40
mole percent, greater than 50 mole percent, greater than 60 mole percent,
greater than 70
mole percent, or greater than 80 mole percent of hydrocarbon solvent mixture
32. The heavy
hydrocarbon fraction may comprise less than 99 mole percent, less than 95 mole
percent, less
than 90 mole percent, less than 80 mole percent, less than 70 mole percent,
less than 60 mole
percent, or less than 50 mole percent of hydrocarbon solvent mixture 32.
Suitable ranges
may include combinations of any upper and lower amount of mole percentage
listed above or
any number within the mole percentages listed above.
[0061] The heavy hydrocarbon fraction may include at least a first compound
that has
five or more carbon atoms and a second compound that has more carbon atoms
than the first
compound. The first compound and the second compound each may comprise at
least 10
16
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= mole percent of hydrocarbon solvent mixture 32. For example, the first
and/or second
compounds may comprise at least 20 mole percent, at least 30 mole percent, at
least 40 mole
percent, at least 50 mole percent, at least 60 mole percent, at least 70 mole
percent, or at least
80 mole percent of hydrocarbon solvent mixture 32. Suitable ranges of the
carbon atoms or
mole percent of the first compound and the second compound may include
combinations of
any upper and lower amount listed above or any number within or bounded by the
aforementioned ranges.
[0062] The heavy hydrocarbon fraction may comprise any suitable
hydrocarbon
molecules, materials, and/or compounds. For example, the heavy hydrocarbon
fraction may
comprise one or more of alkanes, n-alkanes, branched alkanes, alkenes, n-
alkenes, branched
alkenes, alkynes, n-alkynes, branched alkynes, aromatic hydrocarbons, and/or
cyclic
hydrocarbons.
[0063] The hydrocarbon solvent mixture 32 may include a light
hydrocarbon fraction that
may include hydrocarbons with fewer than five carbon atoms, such as
hydrocarbons with one
carbon atom, two carbon atoms, three carbon atoms, and/or four carbon atoms.
The light
hydrocarbon fraction (when present) may, but is not required to, comprise a
minority portion
of the hydrocarbon solvent mixture. For example, the light hydrocarbon
fraction may
comprise at least 5 mole percent, at least 10 mole percent, at least 15 mole
percent, at least 20
mole percent, at least 30 mole percent, at least 40 mole percent, at least 50
mole percent, or at
least 60 mole percent of the hydrocarbon solvent mixture. The light
hydrocarbon fraction
may comprise less than 70 mole percent, less than 60 mole percent, less than
50 mole
percent, less than 40 mole percent, less than 30 mole percent, less than 20
mole percent, less
than 15 mole percent, or less than 10 mole percent of the hydrocarbon solvent
mixture.
Suitable ranges may include combinations of any upper and lower amount of
hydrocarbon
fraction ranges listed above or any number within or bounded by the
hydrocarbon fraction
ranges listed above.
[0064] The hydrocarbon solvent mixture 32 may comprise any
suitable number of
compounds and/or chemical species. For example, the hydrocarbon solvent
mixture may
include a third compound that may include more carbon atoms than the second
compound.
When the hydrocarbon solvent mixture includes the third compound, the third
compound
may comprise any suitable portion, or fraction, of the hydrocarbon solvent
mixture. The third
compound may comprise at least 20 mole percent, at least 30 mole percent, at
least 40 mole
17
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percent, at least 50 mole percent, at least 60 mole percent, or at least 70
mole percent of the
hydrocarbon solvent mixture. The hydrocarbon solvent mixture 32 may include
alkanes, iso-
.
alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and/or olefin
hydrocarbons. In
general, normal alkanes may have a highest tendency of causing phase
separation of
asphaltenes, with a decreasing tendency for phase separation being observed
when moving
from iso-alkanes to naphthenic hydrocarbons to aromatic hydrocarbons.
[0065] Hydrocarbon solvent mixture 32 may be injected into
subterranean formation 24
at a stream temperature. A hydrocarbon solvent mixture composition of
hydrocarbon solvent
mixture 32 may be selected such that the vapor pressure of the hydrocarbon
solvent mixture
at the stream temperature is less than a threshold maximum pressure of the
subterranean
formation. This may prevent damage to the subterranean formation and/or escape
of
hydrocarbon solvent mixture 32 from the subterranean formation. The threshold
maximum
pressure may include, for example, a characteristic pressure of the
subterranean formation,
such as a fracture pressure of the subterranean formation, a hydrostatic
pressure within the
subterranean formation, a lithostatic pressure within the subterranean
formation, a gas cap
pressure for a gas cap that is present within the subterranean formation,
and/or an aquifer
pressure for an aquifer that is located above and/or under the subterranean
formation.
[0066] Pressures, such as the previously discussed pressures, may
be measured and/or
determined in any suitable manner. As examples, pressure may be measured with
a
downhole pressure sensor, calculated from any suitable property and/or
characteristic of the
subterranean formation, and/or estimated, such as via modeling the
subterranean formation.
The threshold maximum pressure may be selected to correspond in any suitable
or desired
manner to one or more of these measured or calculated characteristic
pressures. For example,
the disclosed threshold maximum pressure may be selected to be, to be greater
than, to be less
than, to be within a selected range of, to be a selected percentage of, to be
within a selected
constant of, etc. one or more of these measured or calculated characteristic
pressures. The
threshold maximum pressure may be a user-selected, or operator-selected, value
that does not
directly correspond to a measured or calculated pressure.
[0067] The threshold maximum pressure also may be related to
and/or based upon the
characteristic pressure of the subterranean formation. The threshold maximum
pressure may
be less than 95%, less than 90%, less than 85%, less than 80%, less than 75%,
less than 70%,
less than 65%, less than 60%, less than 55%, or less than 50% of the
characteristic pressure
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for the subterranean formation. The threshold maximum pressure may be at least
20%, at
least 25%, at least 30%, at least 35%, at least 40%, at least 45%, at least
50%, at least 55%, at
least 60%, at least 65%, at least 70%, at least 75%, or at least 80% of the
characteristic
pressure for the subterranean formation. Suitable ranges may include
combinations of any
upper and lower amount of percentage ranges listed above or any number within
or bounded
by the percentage ranges listed above.
[0068] Examples of vapor pressures for hydrocarbon solvent mixtures 32
include vapor
pressures that are greater than a lower threshold pressure of at least 0.2
megapascals (MPa),
at least 0.3 MPa, at least 0.4 MPa, at least 0.5 MPa, at least 0.6 MPa, at
least 0.7 MPa, at least
0.8 MPa, at least 0.9 MPa, at least 1 MPa, at least 1.1 MPa, at least 1.2 MPa,
at least 1.3 MPa,
at least 1.4 MPa, at least 1.5 MPa, at least 1.6 MPa, at least 1.7 MPa, at
least 1.8 MPa, at least
1.9 MPa, at least 2 MPa, at least 2.1 MPa, at least 2.2 MPa, at least 2.3 MPa,
at least 2.4 MPa,
and/or at least 2.5 MPa. The vapor pressure for the hydrocarbon solvent
mixture may be less
than an upper threshold pressure that is less than 3 MPa, less than 2.9 MPa,
less than
2.8 MPa, less than 2.7 MPa, less than 2.6 MPa, less than 2.5 MPa, less than
2.4 MPa, less
than 2.3 MPa, less than 2.2 MPa, less than 2.1 MPa, less than 2 MPa, less than
1.9 MPa, less
than 1.8 MPa, less than 1.7 MPa, less than 1.6 MPa, less than 1.5 MPa, less
than 1.4 MPa,
less than 1.3 MPa, less than 1.2 MPa, less than 1.1 MPa, less than 1 MPa, less
than 0.9 MPa,
less than 0.8 MPa, less than 0.7 MPa, less than 0.6 MPa, less than 0.5 MPa,
less than 0.4
MPa, and/or less than 0.3 MPa. Suitable ranges may include combinations of any
upper and
lower amount of pressure ranges listed above or any number within or bounded
by the
pressure ranges listed above.
[0069] Examples of stream temperatures of hydrocarbon solvent mixture 32
when it is
injected into injection well 30 include stream temperatures of at least 30
degrees ( ) Celsius
(C), at least 35 C, at least 40 C, at least 45 C, at least 50 C, at least
55 C, at least 60 C, at
least 65 C, at least 70 C, at least 75 C, at least 80 C, at least 85 C,
at least 90 C, at least
95 C, at least 100 C, at least 105 C, at least 110 C, at least 115 C, at
least 120 C, at least
125 C, at least 130 C, at least 135 C, at least 140 C, at least 145 C, at
least 150 C, at least
155 C, at least 160 C, at least 165 C, at least 170 C, at least 175 C, at
least 180 C, at least
185 C, at least 190 C, at least 195 C, at least 200 C, at least 205 C,
and/or at least 210 C.
Additionally or alternatively, the stream temperature also may be less than
250 C, less than
240 C, less than 230 C, less than 220 C, less than 210 C, less than 200
C, less than
19
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190 C, less than 180 C, less than 170 C, less than 160 C, less than 150
C, less than
140 C, less than 130 C, less than 120 C, less than 110 C, less than 100
C, less than 90 C,
less than 80 C, less than 70 C, less than 60 C, less than 50 C, and/or
less than 40 C.
Suitable ranges may include combinations of any upper and lower amount of
temperature
ranges listed above or any number within or bounded by the temperature ranges
listed above.
[0070] Injection well 30 may include any suitable structure that may
form a fluid conduit
to convey hydrocarbon solvent mixture 32 to, or into, subterranean formation
24 and/or to, or
into, solvent extraction chamber 60. Production well 70 may include any
suitable structure
that may form a fluid conduit to convey product hydrocarbon stream 72 from
subterranean
formation 24 to, toward, and/or proximal, surface region 20. As an example,
and as
illustrated in Fig. 1, injection well 30 may be spaced apart from production
well 70.
Production well 70 may extend at least partially below injection well 30, may
extend at least
partially vertically below injection well 30, and/or may define a greater
distance (or average
distance) from surface region 20 when compared to injection well 30. At least
a portion of
production well 70 may be parallel to, or at least substantially parallel to,
a corresponding
portion of injection well 30. At least a portion of injection well 30, and/or
of production well
70, may include a horizontal, or at least substantially horizontal, portion.
[0071] Bituminous hydrocarbon deposit 25 may include and/or be any
suitable
subterranean hydrocarbon deposit that may include bitumen 26 and/or
asphaltenes 28.
Bituminous hydrocarbon deposit 25 may be referred to as a viscous hydrocarbon
deposit 25,
a bitumen deposit 25, an oil sands deposit 25, and/or an asphaltene-containing
deposit 25. An
example of a bituminous hydrocarbon deposit 25 that may be included in and/or
utilized with
the systems and methods according to the present disclosure may include the
Athabasca
bitumen deposit in Alberta, Canada.
[0072] Bituminous hydrocarbon deposit 25 may include a wide range of
hydrocarbon
molecules that may possess a correspondingly wide range of molecular carbon
contents,
molecular weights, viscosities, densities, chemical functionalities, and/or
solvent solubilities.
Bituminous hydrocarbon deposit 25 may include hydrocarbon molecules with
eleven (i.e.,
C11) or more carbon atoms. The composition of the bituminous hydrocarbon
deposit may be
characterized into two different fractions. The first fraction, which may be
referred to as the
light fraction, the light end, the light end fraction, and/or the light end
components, may
include hydrocarbon molecules with eleven to thirty carbon atoms (i.e., C11-
C30). The
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second fraction, which may be referred to as the heavy fraction, the heavy
end, the heavy end
fraction, and/or the heavy end components, may include hydrocarbon molecules
with greater
than thirty carbon atoms (i.e., C30+). The first fraction and the second
fraction often may
separate into two different liquid phases (i.e., a light liquid phase and a
heavy liquid phase) in
product hydrocarbon streams 72 that are formed from bituminous hydrocarbon
deposits 25.
Asphaltenes 28 are heavy end components and may be present in the heavy liquid
phase;
however, under certain conditions, a portion of the asphaltenes may
precipitate from the
heavy liquid phase, forming a separate solid, or semi-solid, phase.
[0073] The portion of the asphaltenes that precipitate from the heavy
liquid phase and/or
a fraction of the heavy liquid phase that may be produced with product
hydrocarbon stream
72 may depend upon the hydrocarbon solvent mixture composition. The
hydrocarbon solvent
mixture composition may be regulated to regulate the precipitation of the
asphaltenes and/or
the fraction of the heavy liquid phase that is produced with the product
hydrocarbon stream.
[0074] Bituminous hydrocarbon deposits 25 that may be included in and/or
utilized with
the systems and methods according to the present disclosure may include any
suitable
portion, proportion, or fraction of the light end components, the heavy end
components,
and/or asphaltenes 28. Prior to being produced from the subterranean
formation, such as by
utilizing the systems and methods that are disclosed in the present
disclosure, the light end
components, the heavy end components, and the asphaltenes may form a
(heterogeneous
and/or homogeneous) multicomponent mixture that defines bituminous hydrocarbon
deposit
25. The light end components, the heavy end components, and the asphaltenes
may be (at
least substantially) indistinguishable within bituminous hydrocarbon deposit
25. During
and/or subsequent to being combined with hydrocarbon solvent mixture 32, the
light end
components, the heavy end components, and/or the asphaltenes may separate from
one
another and/or may become separate, or distinct, phases within the
subterranean formation
and/or within the product hydrocarbon stream.
[0075] The light end components may comprise at least 10 weight percent,
at least 15
weight percent, at least 20 weight percent, at least 25 weight percent, or at
least 30 weight
percent of the bituminous hydrocarbon deposit. The light end components also
may comprise
less than 50 weight percent, less than 45 weight percent, less than 40 weight
percent, less
than 35 weight percent, or less than 30 weight percent of the bituminous
hydrocarbon deposit.
Suitable ranges may include combinations of any upper and lower amount of
weight percent
21
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ranges listed above or any number within or bounded by the weight percent
ranges listed
above.
[0076] The heavy end components may comprise at least 50 weight percent,
at least 55
weight percent, at least 60 weight percent, at least 65 weight percent, or at
least 70 weight
percent of the bituminous hydrocarbon deposit. The heavy end components also
may
comprise less than 90 weight percent, less than 85 weight percent, less than
80 weight
percent, less than 75 weight percent, or less than 70 weight percent of the
bituminous
hydrocarbon deposit. Suitable ranges may include combinations of any upper and
lower
amount of weight percent ranges listed above or any number within or bounded
by the weight
percent ranges listed above.
[0077] The asphaltenes may comprise at least 1 weight percent, at least
2.5 weight
percent, at least 5 weight percent, at least 7.5 weight percent, at least 10
weight percent, at
least 12 weight percent, at least 14 weight percent, at least 16 weight
percent, or at least 18
weight percent of the bituminous hydrocarbon deposit. The asphaltenes also may
comprise
less than 24 weight percent, less than 22 weight percent, less than 20 weight
percent, or less
than 18 weight percent of the bituminous hydrocarbon deposit. Suitable ranges
may include
combinations of any upper and lower amount of weight percent ranges listed
above or any
number within or bounded by the weight percent ranges listed above.
[0078] The disclosed systems and methods may utilize the variable
solubility of
asphaltenes 28 in different hydrocarbon solvent mixtures 32 to control,
regulate, and/or vary
the asphaltene content of product hydrocarbon stream 72 and/or to control,
regulate, and/or
vary a proportion of the asphaltenes that are present within bituminous
hydrocarbon deposit
that is produced with product hydrocarbon stream 72.
[0079] Fig. 2 is a schematic representation of a surface facility 40
that may include and/or
25 be utilized with the systems and methods according to the present
disclosure. Fig. 2 may be a
more detailed view of surface facility 40 of Fig. 1 and any of the structures,
features, and/or
functions that are described with reference to surface facility 40 of Fig. 2
may be included in
and/or utilized with surface facility 40 of Fig. 1. Any of the structures,
features, and/or
functions that are described with reference to surface facility 40 of Fig. 1
also may be
included in and/or utilized with surface facility 40 of Fig. 2.
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[0080] Surface facility 40 may receive product hydrocarbon stream 72
from production
well 70. Product hydrocarbon stream 72 may include hydrocarbon solvent mixture
32,
condensate 34, and/or reduced-viscosity hydrocarbons 74, including bitumen,
gaseous
hydrocarbons 27, and/or asphaltenes. Product hydrocarbon stream 72 also may
include water
29.
[0081] Product hydrocarbon stream 72 may be provided to a separation
unit 52.
Separation unit 52 may separate product hydrocarbon stream 72 into one or more
constituent
streams. The constituent streams ¨ interchangeably referred to as component
streams ¨ may
include a bitumen product stream 42, a gaseous hydrocarbon product stream 44,
a water
product stream 46, an asphaltene product stream 48, a separated solvent stream
49, and/or a
recovered solvent stream 55. Bitumen product stream 42, gaseous hydrocarbon
product
stream 44, water product stream 46, asphaltene product stream 48, and/or
separated solvent
stream 49 may be discharged from surface facility 40 and/or utilized in any
suitable process
that may be downstream from surface facility 40. Separated solvent stream 49
may be
combined, or mixed, with bitumen product stream 42 to reduce a viscosity of
the bitumen
product stream. Such a viscosity reduction may decrease a resistance to flow
of the bitumen
product stream within a pipeline. Gaseous hydrocarbon product stream 44 may be
utilized as
a fuel, such as to provide heat for vaporization of hydrocarbon solvent
mixture 32.
Asphaltene product stream 48 may be utilized as a feedstock for a gasification
process to
generate a synthetic gas.
[0082] Recovered solvent stream 55 may be provided to a solvent
treatment unit 53,
which may be utilized to regulate, adjust, and/or control the composition of
an adjusted
solvent stream 56 that may be produced by the solvent treatment unit. Solvent
treatment unit
53 may combine recovered solvent stream 55 with a supplemental solvent stream
31. Solvent
treatment unit 53 may separate a separated solvent stream 49 from recovered
solvent stream
55 (or from a combined stream that includes recovered solvent stream 55 and
supplemental
solvent stream 31) to generate adjusted solvent stream 56. Separated solvent
stream 49 may
include a portion of hydrocarbon solvent mixture 32 and/or condensate 34 that
was produced
with product hydrocarbon stream 72.
[0083] Adjusted solvent stream 56 may be provided to a solvent injection
unit 58. The
solvent injection unit may generate hydrocarbon solvent mixture 32 from
adjusted solvent
stream 56. The solvent injection unit 58 may provide the hydrocarbon solvent
mixture to an
23
CA 02857329 2014-07-21
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injection well 30 for injection into a subterranean formation.
[0084] Separation unit 52 may include any suitable structure that may be
utilized to
separate product hydrocarbon stream 72 into one or more of the illustrated
component
streams. Separation unit 52 may include a separating unit, a phase separator,
a liquid-gas
separator, a liquid-liquid separator, a liquid-liquid-gas separator, an
extraction unit, a
distillation column, an extractive distillation column, an adsorption column,
an absorption
column, and/or any other separating unit or any combination of the above-
listed structures
that may be combined in a complex separation unit that includes more than one
suitable
separation structure.
[0085] Solvent treatment unit 53 may include any suitable structure that
may be
configured to receive recovered solvent stream 55 and/or supplemental solvent
stream 31 and
to generate adjusted solvent stream 56 and/or separated solvent stream 49 from
the solvent
treatment unit 53. Solvent treatment unit 53 may include a mixing unit, a
separation unit, a
phase separator, a liquid-gas separator, a liquid-liquid separator, a liquid-
liquid-gas separator,
an extraction unit, a distillation column, an extractive distillation column,
an adsorption
column, an absorption column, and/or any other separating unit or any
combination of the
above-listed structures that may be combined in a complex separation unit that
includes more
than one suitable separation structure.
[0086] Solvent injection unit 58 may include any suitable structure that
may be
configured to generate hydrocarbon solvent mixture 32 from adjusted solvent
stream 56.
Solvent injection unit 58 may include a vaporization assembly that may be
configured to
vaporize adjusted solvent stream 56 to generate hydrocarbon solvent mixture
32. Solvent
injection unit 58 may include a pressurization assembly that may be configured
to pressurize
adjusted solvent stream 56 to generate hydrocarbon solvent mixture 32.
[0087] Referring more generally to Figs. 1-2, the systems and methods
according to the
present disclosure may include controlling, regulating, and/or varying a
hydrocarbon solvent
mixture composition that is injected into injection well 30. This control,
regulation, and/or
variation in the hydrocarbon solvent mixture composition is discussed in more
detail with
reference to methods 100 and 200 of Figs. 6-7, respectively, and may be
utilized to control,
regulate, and/or vary a composition of product hydrocarbon stream 72.
24
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;-=
[0088] For example, the hydrocarbon solvent mixture composition
may be varied (i.e.,
increased or decreased) to maintain at least a threshold asphaltene content
within product
hydrocarbon stream 72. The hydrocarbon solvent mixture composition may be
varied to
maintain the asphaltene content within product hydrocarbon stream 72 at, or
near, a target
asphaltene content. The target asphaltene content may be different from (or
greater than) the
threshold asphaltene content.
[0089] The hydrocarbon solvent mixture composition may be varied
based upon a desired
stream temperature at which the hydrocarbon solvent mixture is injected into
injection well
30 and/or based upon a desired temperature within solvent extraction chamber
60. The
desired temperature may impact the viscosity of bituminous hydrocarbon deposit
25 and/or
the solubility of bituminous hydrocarbon deposit 25 within hydrocarbon solvent
mixture 32.
[0090] The hydrocarbon solvent mixture composition may be varied
based upon a desired
pressure at which the hydrocarbon solvent mixture is injected into injection
well 30 and/or
based upon a desired pressure within solvent extraction chamber 60. The
desired pressure
may impact the average saturation temperature of injected solvent and
consequently the
viscosity of bituminous hydrocarbon deposit 25, the solubility of bituminous
hydrocarbon
deposit 25 within hydrocarbon solvent mixture 32, and/or a production rate of
product
hydrocarbon stream 72. The hydrocarbon solvent mixture composition of may be
varied in
any suitable manner. The hydrocarbon solvent mixture 32 may include a
plurality of
hydrocarbon molecules that defines, or has, an average molecular carbon
content; the
hydrocarbon solvent mixture composition may be varied by varying the average
molecular
carbon content. The phrase "average molecular carbon content" may refer to an
average
number of carbon atoms that may be present in hydrocarbon molecules that
comprise
hydrocarbon solvent mixture 32.
[0091] The hydrocarbon solvent mixture 32 might comprise 25 mole percent
propane
(which includes three carbon atoms), 25 mole percent butane (which includes
four carbon
atoms), 25 mole percent pentane (which includes five carbon atoms), and 25
mole percent
hexane (which includes six carbon atoms). For such a hydrocarbon solvent
mixture 32, the
average molecular carbon content would be (0.25*3+0.25*4+0.25*5+0.25*6), which
yields
an average molecular carbon content of 4.5. The hydrocarbon solvent mixture 32
might
comprise 50 mole percent propane and 50 mole percent pentane. For such a
hydrocarbon
solvent mixture 32, the average molecular carbon content would be
(0.5*3+0.5*5), which
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yields an average molecular carbon content of 4Ø
[0092] The systems and methods according to the present disclosure are
described in the
context of the average molecular carbon content of hydrocarbon solvent mixture
32.
However, it is to be understood that changes in the average molecular carbon
content may
produce a proportionate change in an average molecular weight of hydrocarbon
solvent
mixture 32. Changing the average molecular carbon content may be referred to
as changing
the average molecular weight. Increasing the average molecular carbon content
also may be
referred to as increasing the average molecular weight. Decreasing the average
molecular
carbon content may be referred to as decreasing the average molecular weight.
[0093] Changes in the chemical structure of hydrocarbon solvent mixture 32
may change
the asphaltene content of product hydrocarbon stream 72. For a molecule with a
given
number of carbon atoms, normal alkanes generally will produce a lower
asphaltene content
than iso-alkanes. Iso-alkanes generally will produce a lower asphaltene
content than
naphthenic hydrocarbons. Naphthenic hydrocarbons generally will produce a
lower
asphaltene content than aromatic hydrocarbons. The systems and methods
according to the
present disclosure may utilize this variation in asphaltene content with
chemical structure of
hydrocarbon solvent mixture 32 to change, or vary, the asphaltene content of
product
hydrocarbon stream 72.
[0094] The systems and methods according to the present disclosure may
include
increasing a proportion of hydrocarbon solvent mixture 32 that comprises
chemical structures
that provide a (relatively) higher asphaltene content in product hydrocarbon
stream 72, such
as naphthenic hydrocarbons and/or aromatic hydrocarbons, to increase the
asphaltene content
of the product hydrocarbon stream. The systems and methods according to the
present
disclosure also may include increasing a proportion of hydrocarbon solvent
mixture 32 that
comprises chemical structures that provide a (relatively) lower asphaltene
content in product
hydrocarbon stream 72, such as normal alkanes and/or iso-alkanes, to decrease
the asphaltene
content of the product hydrocarbon stream.
[0095] The control, regulation, and/or variation in the hydrocarbon
solvent mixture
composition may be accomplished in any suitable manner. For example, a
supplemental
solvent stream composition of supplemental solvent stream 31 may be varied to
control,
regulate, and/or vary the hydrocarbon solvent mixture composition. The
operation of surface
facility 40 may be varied to vary the hydrocarbon solvent mixture composition.
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[0096] With reference to Fig. 2, the operation of separation unit 52 may
be varied to vary
the composition, or average molecular carbon content, of recovered solvent
stream 55. The
operation of solvent treatment unit 53 may be varied to vary the composition,
or average
molecular carbon content, of adjusted solvent stream 56. The variation in the
operation of
separation unit 52 and/or of solvent treatment unit 53 may include varying
respective
operating temperatures, varying respective operating pressures, and/or varying
a composition
of streams 42, 44, 46, 48, and/or 49.
[0097] Fig. 3 is a bar graph illustrating heavy end component deposition
within a
subterranean formation for various single-component hydrocarbon solvents at
two different
temperatures. Stated another way, Fig. 3 illustrates a fraction, proportion,
or percentage of
heavy end components that initially may be present within a bituminous
hydrocarbon deposit
and that remain in a subterranean formation that may include the bituminous
hydrocarbon
deposit subsequent to solvent extraction of bituminous hydrocarbon deposit at
the given
temperatures by the given solvents.
[0098] As may be seen in Fig. 3, increasing the carbon content of the
single-component
hydrocarbon solvents decreases the fraction of the heavy end components that
may remain
within the subterranean formation subsequent to the solvent-based recovery
process. Stated
another way, increasing the carbon content of the single-component hydrocarbon
solvents
increases the fraction of the heavy end components that may be produced from
the
subterranean formation via the solvent-based recovery process.
[0099] Fig. 3 illustrates that increasing the temperature of the solvent-
based recovery
process decreases the fraction of the heavy end components that may remain
within the
subterranean formation. Thus, Fig. 3 illustrates that both the carbon content
and the
temperature of the single-component hydrocarbon solvents may have a
significant impact on
the production of heavy end components from a subterranean formation that may
include a
bituminous hydrocarbon deposit. However, single-component hydrocarbon solvents
generally exhibit specific and/or well-defined vapor pressures at a given
temperature, which
may significantly limit the temperature and/or pressure of solvent-based
recovery processes
that may be performed utilizing the single-component hydrocarbon solvents.
[0100] The systems and methods according to the present disclosure may
utilize a
multicomponent hydrocarbon solvent, such as hydrocarbon solvent mixture 32 of
Figs. 1-2.
Performing solvent-based recovery processes with multicomponent hydrocarbon
solvent
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mixtures may permit independent (or at least quasi-independent) selection of
the temperature
of the solvent-based recovery process, the pressure of the solvent-based
recovery process, and
the proportion of the heavy end components that may be produced during the
solvent-based
recovery process.
[0101] The ability of the systems and methods according to the present
disclosure to
independently select the temperature of the solvent-based recovery process,
the pressure of
the solvent-based recovery process, and the proportion of the heavy end
components that may
be produced during the solvent-based recovery process is illustrated in Figs.
4-5. Fig. 4 is a
table illustrating an average saturation temperature for three different
hydrocarbon solvent
mixtures at a pressure of 0.5 megapascals. The three different hydrocarbon
solvent mixtures
are designated Mix 1, Mix2, and Mix3, and have average molecular carbon
contents of 5.65,
5.05, and 4.25, respectively. Fig. 5 is a bar graph illustrating heavy end
component
deposition, which may include asphaltene deposition, within a subterranean
formation for the
three different hydrocarbon solvent mixtures of Fig. 4.
[0102] As may be seen in Figs. 4-5, decreasing the average molecular carbon
content of
the hydrocarbon solvent mixture decreases the average saturation temperature
of the
hydrocarbon solvent mixture at 0.5 megapascals. Decreasing the average
molecular carbon
content also increases the fraction of the heavy end components that remains
in the
subterranean formation after performing the solvent-based recovery process.
[0103] The data in Figs. 4-5 are presented as examples to illustrate how
the systems and
methods according to the present disclosure may vary the composition of a
hydrocarbon
solvent mixture to vary the temperature, pressure, heavy end component, and/or
asphaltene
production of a solvent-based recovery process that utilizes the hydrocarbon
solvent mixture.
The specific hydrocarbon solvent mixtures and the pressure of 0.5 megapascals
are provide
for illustration purposes only. It is within the scope of the present
disclosure that other
hydrocarbon solvent mixtures that produce different average saturation
temperatures at 0.5
megapascals may be utilized in the disclosed systems and methods. The
disclosed systems
and methods also may operate at pressures greater than and/or less than 0.5
megapascals.
[0104] Figs. 3-5 illustrate the properties of various hydrocarbon
solvent mixtures that
may be formed from normal alkanes and/or heavy end deposition for these
mixtures.
However, it is to be understood that hydrocarbon solvent mixtures according to
the present
disclosure may include other components in addition to normal alkanes. These
other
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components may include iso-alkanes, naphthenic hydrocarbons, olefin
hydrocarbons, and/or
aromatic hydrocarbons. In addition, the hydrocarbon solvent mixture initially
may be
obtained from any suitable source. As examples, the hydrocarbon solvent
mixtures may
include, or be, a gas plant condensate and/or crude oil refinery naphtha
products.
[0105] Fig. 6 is a flowchart depicting methods 100, according to the
present disclosure, of
regulating asphaltene production in a multicomponent solvent-based recovery
process.
Methods 100 include determining a composition of a bituminous hydrocarbon
deposit at 110,
selecting a hydrocarbon solvent mixture composition at 120, injecting the
hydrocarbon
solvent mixture at 130, and producing a product hydrocarbon stream at 140.
Methods 100
may include separating a hydrocarbon solvent fraction of the product
hydrocarbon stream
from a bituminous hydrocarbon fraction of the product hydrocarbon stream at
150. Methods
100 may include determining an asphaltene content of the product hydrocarbon
stream at 160
and comparing the asphaltene content to a target asphaltene content at 170.
Methods 100
may include adjusting the composition of the hydrocarbon solvent mixture at
180, and/or
repeating the methods at 190.
[0106] Determining the bituminous hydrocarbon deposit composition of the
bituminous
hydrocarbon deposit at 110 may include determining the bituminous hydrocarbon
deposit
composition of any suitable bituminous hydrocarbon deposit that may include
asphaltenes
and that may be present within a subterranean formation. The bituminous
hydrocarbon
deposit composition may be determined in any suitable manner.
[0107] The determining at 110 may include measuring the bituminous
hydrocarbon
deposit composition and/or measuring the composition of a sample of the
bituminous
hydrocarbon deposit. The determining at 110 may include performing a crude
assay on the
sample, obtaining a gas chromatograph of the sample, and/or performing a
standard ASTM
asphaltene test. Examples of standard ASTM asphaltene tests include ASTM test
numbers
D6560, D3279, and D7061.
[0108] The determining at 110 may include obtaining the bituminous
hydrocarbon
deposit composition. The determining at 110 may include utilizing a tabulated
composition
of the bituminous hydrocarbon deposit. The tabulated composition may be
obtained from
any suitable source, such as a suitable book, publication, and/or database of
bituminous
hydrocarbon deposit compositions.
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[0109] Selecting the hydrocarbon solvent mixture composition at 120 may
include
selecting based, at least in part, on the determined bituminous hydrocarbon
deposit
composition. The selecting at may include selecting the hydrocarbon solvent
mixture
composition such that the product hydrocarbon stream is expected to have at
least a threshold
asphaltene content at a temperature and pressure of, or within, the solvent
extraction
chamber. Thus, when the hydrocarbon solvent mixture is combined with the
bituminous
hydrocarbon deposit within the solvent extraction chamber, the product
hydrocarbon stream
with at least the threshold asphaltene content may be produced. The selecting
at 120 may
include performing methods 200 of Fig. 7.
[0110] The hydrocarbon solvent mixture may include a plurality of
hydrocarbon
molecules that defines an average molecular carbon content. The selecting at
120 may
include selecting such that the average molecular carbon content has a
threshold value.
Examples of the threshold value of the average molecular carbon content
include average
molecular carbon contents of at least 2, at least 2.25, at least 2.5, at least
2.75, at least 3, at
least 3.25, at least 3.5, at least 3.75, at least 4, at least 4.25, at least
4.5, at least 4.75 at least 5,
at least 5.25, at least 5.5, at least 5.75, at least 6, at least 6.25, at
least 6.5, at least 6.75, or at
least 7. Additional examples of the threshold value of the average molecular
carbon content
include average molecular carbon contents of less than 12, less than 11.5,
less than 11, less
than 10.5, less than 10, less than 9.5, less than 9, less than 8.5, less than
8, less than 7.5, less
than 7, less than 6.5, less than 6, less than 5.5, or less than 5. Suitable
ranges may include
combinations of any upper and lower amount of average molecular carbon content
ranges
listed above or any number within or bounded by the average molecular carbon
content
ranges listed above.
[0111] The selecting at 120 also may include selecting such that the
hydrocarbon solvent
mixture may include a first fraction that comprises a first compound with at
least five carbon
atoms and a second fraction that comprises a second compound with at least six
carbon
atoms. The first compound and the second compound each may comprise at least
10 mole
percent, at least 20 mole percent, at least 30 mole percent, at least 40 mole
percent, at least 50
mole percent, at least 60 mole percent, at least 70 mole percent, or at least
80 mole percent of
the hydrocarbon solvent mixture. Suitable ranges may include combinations of
any upper
and lower amount of mole percent ranges listed above or any number within or
bounded by
the mole percent ranges listed above.
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_
[0112] As discussed with reference to Figs. 4-5, the hydrocarbon
solvent mixture
composition may directly impact the average saturation temperature and/or the
vapor
pressure of the hydrocarbon solvent mixture. The selecting at 120 may include
selecting the
hydrocarbon solvent mixture composition based, at least in part, on a desired
temperature
within the solvent extraction chamber and/or based upon a desired pressure
within the solvent
extraction chamber.
[0113] The production rate of the product hydrocarbon stream that
is produced during the
producing at 140 may be impacted by the temperature within the solvent
extraction chamber,
with higher temperatures yielding higher production rates. The desired
temperature within
the solvent extraction chamber may be based, at least in part, on a desired
production rate of
the product hydrocarbon stream. The pressure within the solvent extraction
chamber may be
limited to a threshold maximum pressure of the subterranean formation. The
desired pressure
within the solvent extraction chamber may be based, at least in part, on the
threshold
maximum pressure of the subterranean formation. The threshold maximum pressure
is
discussed with respect to Fig. 1.
[0114] As illustrated in Fig. 6 at 122, the selecting at 120 may
include increasing the
average molecular carbon content of the hydrocarbon solvent mixture. The
average
molecular carbon content may be increased to increase the temperature (or
based upon an
increase in the desired temperature) within the subterranean formation. The
average
molecular carbon content may be increased to decrease the pressure (or based
upon a
decrease in the desired pressure) within the subterranean formation.
[0115] As illustrated in Fig. 6 at 124, the selecting at 120 also
may include decreasing the
average molecular carbon content of the hydrocarbon solvent mixture. The
average
molecular carbon content may be decreased to decrease the temperature (or
based upon a
decrease in the desired temperature) within the subterranean formation. The
average
molecular carbon content may be decreased to increase the pressure (or based
upon an
increase in the desired pressure) within the subterranean formation.
[0116] As illustrated in Fig. 6 at 126, the selecting at 120 may
include selecting a
chemical structure of the hydrocarbon solvent mixture. The hydrocarbon solvent
mixture
may include hydrocarbon molecules that have different chemical structures. The
selecting at
126 may include selecting the chemical structures and/or a relative proportion
of the chemical
structures such that the product hydrocarbon stream has at least the threshold
asphaltene
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content. The selecting at 126 may include increasing a proportion of the
hydrocarbon solvent
mixture that comprises chemical structures that provide a (relatively) higher
asphaltene
content in the product hydrocarbon stream, such as naphthenic hydrocarbons
and/or aromatic
hydrocarbons, to increase the asphaltene content of the product hydrocarbon
stream. The
selecting at 126 may include increasing a proportion of the hydrocarbon
solvent mixture that
comprises chemical structures that provide a (relatively) lower asphaltene
content in the
product hydrocarbon stream, such as normal alkanes and/or iso-alkanes, to
decrease the
asphaltene content of the product hydrocarbon stream. The selecting at 126 may
include
decreasing the normal alkane content of the hydrocarbon solvent mixture to
increase the
asphaltene content of the product hydrocarbon stream.
[0117] Injecting the hydrocarbon solvent mixture at 130 may include
injecting the
hydrocarbon solvent mixture into the solvent extraction chamber. The injecting
at 130 may
include injecting the hydrocarbon solvent mixture into an injection well. The
injection well
may extend within the subterranean formation, may extend within the solvent
extraction
chamber, may extend proximal the solvent extraction chamber, may extend
between a surface
region and the subterranean formation, and/or may extend between the surface
region and the
solvent extraction chamber.
[0118] Injecting the hydrocarbon solvent mixture at 130 may include
injecting at an
injection temperature and/or at an injection pressure. Injecting the
hydrocarbon solvent
mixture at 130 may include injecting such that the hydrocarbon solvent mixture
is a liquid
hydrocarbon solvent mixture at the injection temperature and the injection
pressure. Injecting
the hydrocarbon solvent mixture at 130 may include injecting such that the
hydrocarbon
solvent mixture is a vaporous hydrocarbon solvent mixture at the injection
temperature and
the injection pressure. Injecting the hydrocarbon solvent mixture at 130 may
include
injecting such that the hydrocarbon solvent mixture is a liquid-vapor
hydrocarbon solvent
mixture that includes both a liquid and a vapor at the injection temperature
and the injection
pressure. When the hydrocarbon solvent mixture is the vaporous hydrocarbon
solvent
mixture, the injection temperature may be at, or near, a saturation
temperature for the
vaporous hydrocarbon solvent mixture at the injection pressure.
[0119] Producing the product hydrocarbon stream at 140 may include
producing the
product hydrocarbon stream from the subterranean formation, producing the
product
hydrocarbon stream from the solvent extraction chamber, and/or producing the
product
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hydrocarbon stream to the surface region. The producing at 140 may include
producing the
product hydrocarbon stream from a production well. The production well may
extend within
=
the subterranean formation, may extend within the solvent extraction chamber,
may extend
proximal the solvent extraction chamber, may extend between a surface region
and the
subterranean formation, and/or may extend between the surface region and the
solvent
extraction chamber. The production well may be spaced apart from the injection
well. The
production well may be located below the injection well and/or may be located
vertically
deeper within the subterranean formation than the injection well.
[0120] Separating the hydrocarbon solvent fraction of the product
hydrocarbon stream
from the bituminous hydrocarbon fraction of the product hydrocarbon stream at
150 may
include separating in any suitable manner. The separating at 150 may include
separating in,
or utilizing, a surface facility, such as surface facility 40 of Figs. 1-2.
[0121] When methods 100 include the separating at 150, the
injecting at 130 may include
injecting at least a portion of the hydrocarbon solvent fraction as the
hydrocarbon solvent
mixture. When methods 100 include the separating at 150, methods 100 may
include
regulating the separating at 150 to regulate the composition of the
hydrocarbon solvent
fraction. Regulation of the composition of the hydrocarbon solvent fraction
may be utilized
during, or to accomplish, the adjusting at 180.
[0122] Determining the asphaltene content of the product
hydrocarbon stream at 160 may
include determining the asphaltene content in any suitable manner. For
example, the
determining at 160 may include indirectly determining the asphaltene content
of the product
hydrocarbon stream. The indirectly determining may include measuring a density
of the
product hydrocarbon stream and/or measuring a viscosity of the product
hydrocarbon stream.
[0123] The determining at 160 may include performing a crude
assay on a sample from
the product hydrocarbon stream. The determining at 160 may include obtaining a
gas
chromatograph of the sample from the product hydrocarbon stream. The
determining at 160
may include performing a standard ASTM asphaltene test. Examples of standard
ASTM
asphaltene tests include ASTM test numbers D6560, D3279, and D7061.
[0124] The determining at 160 may include determining the
asphaltene content of any
suitable portion of the product hydrocarbon stream. When methods 100 include
the
separating at 150, the determining at 160 may include determining an
asphaltene content of
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the bituminous hydrocarbon fraction.
[0125] Comparing the asphaltene content to the target asphaltene content
at 170 may
include comparing the asphaltene content of the product hydrocarbon stream to
any suitable
target, desired, and/or predetermined asphaltene content for the product
hydrocarbon stream.
For example, and prior to the producing at 140, the bituminous hydrocarbon
deposit may
define an initial hydrocarbon mass. The target asphaltene content may be
based, at least in
part, on a desired fraction of the initial hydrocarbon mass to be produced
from the
subterranean formation. The desired fraction of the initial hydrocarbon mass
may be based,
at least in part, on a market value of the product hydrocarbon stream as a
function of the
asphaltene content of the product hydrocarbon stream.
[0126] Adjusting the composition of the hydrocarbon solvent mixture at
180 may include
adjusting based, at least in part, on the comparing at 170. The target
asphaltene content may
be a target asphaltene content range, and the adjusting at 180 may include
adjusting to
maintain the asphaltene content of the product hydrocarbon stream within the
target
asphaltene content range. The product hydrocarbon stream may include a
hydrocarbon
solvent fraction and a bituminous hydrocarbon fraction. The hydrocarbon
solvent fraction
may include, comprise, or be formed from the hydrocarbon solvent mixture that
was injected
during the injecting at 130. The bituminous hydrocarbon fraction may include,
comprise, or
be formed from the bituminous hydrocarbon deposit. Examples of lower limits
for the target
asphaltene content range include lower limits of at least 1 weight percent, at
least 2 weight
percent, at least 3 weight percent, at least 4 weight percent, at least 5
weight percent, at least
6 weight percent, at least 8 weight percent, at least 10 weight percent, at
least 12 weight
percent, at least 14 weight percent, or at least 16 weight percent of the
bituminous
hydrocarbon fraction. Examples of upper limits for the target asphaltene
content range
include upper limits of less than 30 weight percent, less than 28 weight
percent, less than 26
weight percent, less than 24 weight percent, less than 22 weight percent, less
than 20 weight
percent, less than 18 weight percent, less than 16 weight percent, less than
14 weight percent,
less than 12 weight percent, less than 10 weight percent, or less than 5
weight percent of the
bituminous hydrocarbon fraction. Suitable ranges may include combinations of
any upper
and lower amount of weight percentage ranges listed above or any number within
or bounded
by the weight percentage ranges listed above.
[0127] The adjusting at 180 also may include adjusting to maintain the
asphaltene content
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of the product hydrocarbon stream above the threshold asphaltene content.
Examples of the
threshold asphaltene content include threshold asphaltene contents of at least
1 weight
percent, at least 2 weight percent, at least 3 weight percent, at least 4
weight percent, at least
weight percent, at least 6 weight percent, at least 8 weight percent, at least
10 weight
5 percent, at least 12 weight percent, at least 14 weight percent, or at
least 16 weight percent of
the bituminous hydrocarbon fraction. Suitable ranges may include combinations
of any
upper and lower amount of weight percentage ranges listed above or any number
within or
bounded by the weight percentage ranges listed above.
[0128] The subterranean formation may have a fluid permeability, and
deposition of
asphaltenes within the subterranean formation may impact, or decrease the
fluid permeability.
The adjusting at 180 may include adjusting to maintain at least a threshold
fluid permeability
within the subterranean formation. The threshold fluid permeability may be
determined
based upon one or more characteristics of the subterranean formation and/or
based upon a
desired production rate of the product hydrocarbon stream from the
subterranean formation.
[0129] The product hydrocarbon stream may include one or more contaminants
that may
be present within and/or be generated from the bituminous hydrocarbon deposit.
These
contaminants may negatively impact the operation of equipment that may receive
and/or
process the product hydrocarbon stream. The adjusting at 180 may include
adjusting to
maintain a concentration of the one or more contaminants below a threshold
contaminant
level. The threshold contaminant level may be selected such that the one or
more
contaminants do not have a negative impact on the operation of the equipment
that may
receive and/or process the product hydrocarbon stream. Examples of
contaminants that may
be present within the product hydrocarbon stream include heavy metals,
vanadium, nickel,
nitrogen, and/or sulfur heteroatoms and others.
[0130] The adjusting at 180 may include adjusting to maintain one or more
material
properties of the product hydrocarbon stream and/or of the bituminous
hydrocarbon fraction
of the product hydrocarbon stream within a desired range. The adjusting at 180
may include
adjusting to maintain the pipelineability of the product hydrocarbon stream.
As another
example, the product hydrocarbon stream may have a density at a given
temperature (such as
5 degrees Celsius). The adjusting at 180 may include adjusting the viscosity
to maintain the
density within a target density range. The product hydrocarbon stream may have
a viscosity
at the given temperature. The adjusting at 180 may include adjusting to
maintain the
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viscosity within a target viscosity range. The adjusting at 180 may include
adjusting to
produce a target weight percent of the asphaltenes from the bituminous
hydrocarbon deposit.
The adjusting at 180 may include adjusting to produce at least 1, at least 2,
at least 5, at least
10, at least 15, at least 20, or at least 25 weight percent of the asphaltenes
from the
bituminous hydrocarbon deposit. The adjusting at 180 also may include
adjusting to produce
less than 99, less than 98, less than 95, less than 90, less than 85, less
than 80, or less than 75
weight percent of the asphaltenes from the bituminous hydrocarbon deposit.
Suitable ranges
may include combinations of any upper and lower amount of weight percentage
ranges listed
above or any number within or bounded by the weight percentage ranges listed
above.
[0131] The adjusting at 180 may include adjusting to deposit a target
weight percent of
the asphaltenes within the subterranean formation during the producing at 140.
The adjusting
at 180 may include adjusting to deposit at least 1, at least 2, at least 5, at
least 10, at least 15,
at least 20, or at least 25 weight percent of the asphaltenes within the
subterranean formation.
The adjusting at 180 may include adjusting to deposit less than 99, less than
98, less than 95,
less than 90, less than 85, less than 80, or less than 75 weight percent of
the asphaltenes
within the subterranean formation. Suitable ranges may include combinations of
any upper
and lower amount of weight percentage ranges listed above or any number within
or bounded
by the weight percentage ranges listed above.
[0132] As illustrated in Fig. 6 at 182, the adjusting at 180 may include
increasing the
average molecular carbon content of the hydrocarbon solvent mixture. The
average
molecular carbon content may be increased to increase the asphaltene content
of the product
hydrocarbon stream. The average molecular carbon content may be increased to
decrease
deposition of asphaltenes within the subterranean formation, which may
increase the fluid
permeability of the subterranean formation. Contaminants may be bound to
and/or produced
with asphaltenes, and the average molecular carbon content may be increased to
increase the
concentration of contaminants within the product hydrocarbon stream. The
average
molecular carbon content may be increased to increase the viscosity of the
product
hydrocarbon stream. The average molecular carbon content may be increased to
increase the
density of the product hydrocarbon stream.
[0133] As illustrated in Fig. 6 at 184, the adjusting at 180 may include
decreasing the
average molecular carbon content of the hydrocarbon solvent mixture. The
average
molecular carbon content may be decreased to decrease the asphaltene content
of the product
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hydrocarbon stream. The average molecular carbon content may be decreased to
increase
deposition of asphaltenes within the subterranean formation, which may
decrease the fluid
permeability of the subterranean formation. Contaminants may be bound to
and/or produced
with asphaltenes, and the average molecular carbon content may be decreased to
decrease the
concentration of contaminants within the product hydrocarbon stream. The
average
molecular carbon content may be decreased to decrease the viscosity of the
product
hydrocarbon stream. The average molecular carbon content may be decreased to
decrease the
density of the product hydrocarbon stream.
[0134] As illustrated in Fig. 6 at 186, the adjusting at 186 also may
include adjusting a
chemical structure of the hydrocarbon solvent mixture. The hydrocarbon solvent
mixture
may include a plurality of hydrocarbon molecules that have different chemical
structures.
The adjusting at 186 may include adjusting the chemical structures and/or a
relative
proportion of the chemical structures such that the product hydrocarbon stream
has the target
asphaltene content. The adjusting at 186 may include increasing a proportion
of the
hydrocarbon solvent mixture that comprises chemical structures that provide a
(relatively)
higher asphaltene content in the product hydrocarbon stream, such as
naphthenic
hydrocarbons and/or aromatic hydrocarbons, to increase the asphaltene content
of the product
hydrocarbon stream. The adjusting at 186 also may include increasing a
proportion of the
hydrocarbon solvent mixture that comprises chemical structures that provide a
(relatively)
lower asphaltene content in the product hydrocarbon stream, such as normal
alkanes and/or
iso-alkanes, to decrease the asphaltene content of the product hydrocarbon
stream. The
adjusting at 186 may include decreasing the normal alkane content of the
hydrocarbon
solvent mixture to increase the asphaltene content of the product hydrocarbon
stream.
[0135] Repeating the methods at 190 may include repeating any suitable
portion of
methods 100. For example, the repeating at 190 may include repeating at least
the injecting
at 130, the producing at 140, the determining at 150, the comparing at 160,
and the adjusting
at 170. The producing at 140 may include at least substantially continuously
producing the
product hydrocarbon stream during a production interval, or time. The
repeating at 190 may
include periodically repeating during the production interval to maintain the
asphaltene
content of the product hydrocarbon stream at, or near, the target asphaltene
content or at, or
within, the target asphaltene content range.
[0136] Fig. 7 is a flowchart depicting methods 200, according to the
present disclosure, of
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selecting a composition of a hydrocarbon solvent mixture to be utilized in a
multicomponent
solvent-based recovery process. The hydrocarbon solvent mixture may be
injected into a
subterranean formation at an injection pressure to produce a hydrocarbon
product stream
from the subterranean formation via a solvent-based recovery process. The
subterranean
formation may include a bituminous hydrocarbon deposit that may include
asphaltenes. The
product hydrocarbon stream may be generated via combination of the hydrocarbon
solvent
mixture with the bituminous hydrocarbon deposit within a solvent extraction
chamber that
extends within the subterranean formation.
[0137] Methods 200 include determining a threshold maximum pressure of
the
subterranean formation at 210, determining a stream temperature for the
hydrocarbon solvent
mixture at 220, determining a target asphaltene content for the product
hydrocarbon stream
at 230, and selecting a composition of the hydrocarbon solvent mixture at 240.
Methods 200
further may include injecting the hydrocarbon solvent mixture at 245,
producing the product
hydrocarbon stream at 250, separating a hydrocarbon solvent fraction of the
product
hydrocarbon stream from a bituminous hydrocarbon fraction of the product
hydrocarbon
stream at 255, determining the asphaltene content of the product hydrocarbon
stream at 260,
comparing the asphaltene content to the target asphaltene content at 265,
adjusting the
composition of the hydrocarbon solvent mixture at 270, and/or repeating the
methods at 275.
[0138] Determining the threshold maximum pressure of the subterranean
formation at
210 may include determining any suitable threshold maximum pressure of the
subterranean
formation. Examples of the threshold maximum pressure of the subterranean
formation are
discussed with reference to Fig. 1. The determining at 210 may include
determining in any
suitable manner. The threshold maximum pressure of the subterranean formation
may be
measured. The threshold maximum pressure of the subterranean formation may be
calculated. The threshold maximum pressure of the subterranean formation may
be obtained
from a tabulation and/or from a database of threshold maximum pressures for
subterranean
formations.
[0139] Determining the stream temperature for the hydrocarbon solvent
mixture at 220
may include determining and/or establishing any suitable stream temperature at
which the
hydrocarbon solvent mixture is to be injected into the subterranean formation.
The
determining at 220 may include determining in any suitable manner. The
determining at 220
may include determining based upon a desired temperature within the solvent
extraction
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chamber. The determining at 220 may include determining based upon a desired
production
rate of the product hydrocarbon stream from the subterranean formation. The
determining at
220 may include determining based upon a desired heat loss to the subterranean
formation
and/or to maintain less than a threshold heat loss to the subterranean
formation.
[0140] Determining the target asphaltene content for the product
hydrocarbon stream at
230 may include determining any suitable target asphaltene content for the
product
hydrocarbon stream. The determining at 230 may include determining based upon
an
asphaltene content of the bituminous hydrocarbon deposit. The determining at
230 may
include determining based upon a target, or desired, fluid permeability for
the subterranean
formation. The determining at 230 may include determining based upon a target,
or desired,
contaminant concentration within the product hydrocarbon stream. The
determining at 230
may include determining based upon a desired density of the product
hydrocarbon stream
and/or of a bituminous hydrocarbon fraction of the product hydrocarbon stream.
The
determining at 230 may include determining based upon a desired viscosity of
the product
hydrocarbon stream and/or of the bituminous hydrocarbon fraction.
[0141] Selecting the composition of the hydrocarbon solvent mixture at
240 may include
selecting based, at least in part, on the threshold maximum pressure.
Selecting the
composition of the hydrocarbon solvent mixture at 240 may include selecting
based, at least
in part, on the stream temperature. Selecting the composition of the
hydrocarbon solvent
mixture at 240 may include selecting based, at least in part on the target
asphaltene content
for the product hydrocarbon stream.
[0142] The hydrocarbon solvent mixture may include a plurality of
hydrocarbon
molecules that defines an average molecular carbon content. The selecting at
240 may
include selecting such that the average molecular carbon content has a
threshold value and/or
is within a threshold range. Examples of threshold values and/or threshold
ranges of the
average molecular carbon content are discussed with reference to the selecting
at 120 of
methods 100.
[0143] As illustrated in Fig. 7 at 241, the selecting at 240 may include
increasing the
average molecular carbon content of the hydrocarbon solvent mixture. The
increasing at 241
may include increasing to increase the stream temperature and/or based upon an
increase in a
desired stream temperature. The increasing at 241 may include increasing to
decrease the
injection pressure and/or based upon a decrease in a desired injection
pressure. The
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increasing at 241 may include increasing to increase the asphaltene content
for the product
hydrocarbon stream and/or based upon an increase in the target asphaltene
content for the
product hydrocarbon stream.
[0144] As illustrated in Fig. 7 at 242, the selecting at 240 also may
include decreasing the
average molecular carbon content of the hydrocarbon solvent mixture. The
decreasing at 242
may include decreasing to decrease the stream temperature and/or based upon a
decrease in
the desired stream temperature. The decreasing at 242 may include decreasing
to increase the
injection pressure and/or based upon an increase in the desired injection
pressure. The
decreasing at 242 may include decreasing to decrease the asphaltene content
for the product
hydrocarbon stream and/or based upon a decrease in the target asphaltene
content for the
product hydrocarbon stream.
[0145] As illustrated in Fig. 7 at 243, the selecting at 240 also may
include selecting a
chemical structure of the hydrocarbon solvent mixture. The hydrocarbon solvent
mixture
may include a plurality of hydrocarbon molecules that have different chemical
structures.
The selecting at 243 may include selecting the chemical structures and/or a
relative
proportion of the chemical structures such that the product hydrocarbon stream
has at least
the threshold asphaltene content. The selecting at 243 may include increasing
a proportion of
the hydrocarbon solvent mixture that comprises chemical structures that
provide a (relatively)
higher asphaltene content in the product hydrocarbon stream, such as
naphthenic
hydrocarbons and/or aromatic hydrocarbons, to increase the asphaltene content
of the product
hydrocarbon stream. The selecting at 243 also may include increasing a
proportion of the
hydrocarbon solvent mixture that comprises chemical structures that provide a
(relatively)
lower asphaltene content in the product hydrocarbon stream, such as normal
alkanes and/or
iso-alkanes, to decrease the asphaltene content of the product hydrocarbon
stream. The
selecting at 243 may include decreasing the normal alkane content of the
hydrocarbon solvent
mixture to increase the asphaltene content of the product hydrocarbon stream.
[0146] Injecting the hydrocarbon solvent mixture at 245 may be at least
substantially
similar to the injecting at 130 of methods 100 of Fig. 6. Producing the
product hydrocarbon
stream at 250 may be at least substantially similar to the producing at 140 of
methods 100 of
Fig. 6. Separating the hydrocarbon solvent fraction of the product hydrocarbon
stream from
the bituminous hydrocarbon fraction of the product hydrocarbon stream at 255
may be at
least substantially similar to the separating at 150 of methods 100 of Fig. 6.
Determining the
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asphaltene content of the product hydrocarbon stream at 260 may be at least
substantially
similar to the determining at 160 of methods 100 of Fig. 6. Comparing the
asphaltene content
to the target asphaltene content at 265 may be at least substantially similar
to the comparing
at 170 of methods 100 of Fig. 6. Adjusting the hydrocarbon solvent mixture
composition at
270 may be at least substantially similar to the adjusting at 180 of methods
100 of Fig. 6.
The adjusting the hydrocarbon solvent mixture composition at 270 may include
increasing or
decreasing the average molecular carbon content of the hydrocarbon solvent
mixture.
Repeating the methods at 275 may be at least substantially similar to the
repeating at 190 of
methods 100 of Fig. 6.
[0147] The disclosed systems and methods may refer to producing certain
proportions,
fractions, and/or percentages of heavy end components, such as asphaltenes,
that may be
present within a bituminous hydrocarbon deposit. The systems and methods also
may refer
to depositing, or retaining, certain proportions, fractions, and/or
percentages of the heavy end
components in a subterranean formation that may include the bituminous
hydrocarbon
deposit.
[0148] The disclosed systems and methods may not be utilized over, or to
produce, an
entire bituminous hydrocarbon deposit. It may be uneconomical, or even
impossible, to
perform the disclosed systems and methods within certain regions of the
bituminous
hydrocarbon deposit. The disclosed systems and methods may be performed over a
period of
several years. Other recovery processes may be utilized within certain
portions of a given
bituminous hydrocarbon deposit. Thus, the described proportions, fractions,
and/or
percentages may refer to proportions, fractions, and/or percentages of a
produced portion (or
fraction) of the bituminous hydrocarbon deposit and not to proportions,
fractions, and/or
percentages of the entire bituminous hydrocarbon deposit. The produced portion
may include
a portion of the bituminous hydrocarbon deposit that is produced utilizing the
disclosed
systems and methods and/or a portion of the bituminous hydrocarbon deposit
that is produced
at a given point in time (or over a given period of time) utilizing the
disclosed systems and
methods.
[0149] In the present disclosure, several examples have been discussed
and/or presented
in the context of flow diagrams, or flow charts, in which the methods are
shown and
described as a series of blocks, or steps. Unless specifically set forth in
the accompanying
description, the order of the blocks may vary from the illustrated order in
the flow diagram,
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including with two or more of the blocks (or steps) occurring in a different
order and/or
concurrently.
Industrial Applicability
[0151]
The systems and methods disclosed in the present disclosure are applicable to
the
oil and gas industry.
[0152]
It is believed that the following claims particularly point out certain
combinations
and subcombinations that are novel and non-obvious.
Other combinations and
subcombinations of features, functions, elements and/or properties may be
claimed through
amendment of the present claims or presentation of new claims in this or a
related application.
Such amended or new claims, whether different, broader, narrower, or equal in
scope to the
original claims, are also regarded as included within the subject matter of
the present
disclosure.
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