Note: Descriptions are shown in the official language in which they were submitted.
SOLVENT-DRIVEN RECOVERY PROCESS WITH ABBREVIATED STEAM BOOST
TECHNICAL FIELD
[0001] The present disclosure generally relates to solvent-driven
processes for in-
situ hydrocarbon recovery. In particular, the present disclosure relates to
solvent-driven
processes in which hydrocarbon-production conditions are revitalized by a
shift in
injection/production protocols.
BACKGROUND
[0002] Viscous hydrocarbons can be extracted from some subterranean
reservoirs
using in-situ recovery processes. Some in-situ recovery processes are thermal
processes
wherein heat energy is introduced to a reservoir to lower the viscosity of
hydrocarbons in situ
such that they can be recovered from a production well. In some thermal
processes, heat
energy is introduced by injecting a heated fluid into the reservoir by way of
an injection well.
Steam-assisted gravity drainage (SAGD) is a representative thermal-recovery
process that
uses steam to mobilize hydrocarbons in situ.
[0003] Some thermal recovery processes employ injection fluids that include
solvent,
optionally in combination with steam, as for example disclosed in Canadian
Patent
Publication 2,956,771. Solvent-aided processes (SAP) are one such category. In
the context
of the present disclosure, SAP injection fluids comprise less than about 50 %
solvent and
greater than about 50% steam on a mass basis. Solvent-driven processes (SDP)
are another
.. such category. In the context of the present disclosure, SDP injection
fluids comprise greater
than about 50 % solvent and less than about 50 % steam on a mass basis.
Solvent-driven
processes are not widely employed on commercial scale but, when they are, they
are typically
employed as one phase in a broader recovery profile. For example, a well may
be transitioned
through: (i) a start-up phase during which hydraulic communication is
established between
an injection well and a production well; (ii) a SAGD phase during which a
production chamber
expands primarily in a vertical direction from the injection well and
mobilized hydrocarbons
are recovered from the production well along with condensed steam; (iii) a SDP
phase during
which the production chamber expands primarily in a horizontal and/or lateral
direction and
mobilized hydrocarbons are recovered along with condensed solvent; and (iv) a
blow-down
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Date Recue/Date Received 2020-12-18
phase during which non-condensable gas is injected to recover residual
hydrocarbons and
solvent.
[0004] Successfully executing the SDP phase of a recovery operation
is difficult and
may introduce economic risk. Heavy-hydrocarbon reservoirs are heterogeneous,
production-
chamber development is highly complex, reservoir conditions resulting from
preceding SAGD
phases are hard to predict, and solvent prices/availability are subject to
short-term volatility.
Accordingly, there is a need for alternative SDP strategies and, more
generally, for
hydrocarbon recovery processes that allow for a greater degree of flexibility
during SDP
implementation.
SUMMARY
[0005] Solvent-driven processes (SDP) pose unique challenges as
compared to
steam assisted gravity drainage (SAGD) and solvent-aided processes (SAP). In
particular,
the present disclosure contemplates that, after transitioning from a SAGD
phase or a SAP
phase, a typical SDP phase: (i) may result in declining rates of steam-
condensate drainage
towards the production well; and (ii) may result in declining reservoir
temperature/pressure
conditions. The first phenomena increases the potential for solvent
shortcutting ¨ the flow of
injected solvent from injection well to production well without substantially
participating in the
development of the production chamber ¨ because declining rates of steam
condensate
drainage may lead to lower fluid levels in proximity to the production well.
The second
phenomena may lead to declining rates of hydrocarbon drainage towards the
production well
due to the impact that reservoir pressure/temperature conditions have on
solvent
liquid/vapour phase equilibria.
[0006] In view of the foregoing, the present disclosure provides
methods for in-situ
hydrocarbon recovery that include an SDP phase that is punctuated by an
abbreviated steam
boost (ASB) ¨ a so-called "ASB-SDP" phase. The ASB involves temporarily
foregoing
solvent-driven injection in favour of steam injection to increase produced-
fluid levels (through
increased steam-condensate drainage) and to return the reservoir to a
desirable
temperature/pressure state. Importantly, as highlighted by the results of the
present
disclosure, the ASB does not require the high rates of steam injection
associated with SAGD
and/or SAP. For example, steam injection rates for ASB are generally between
about 1/4th
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Date Recue/Date Received 2020-12-18
and about 1/3rd typically associated with SAGD. Also importantly, ASB
parameters may be
configured to provide the enthalpic adjustment required to re-volatilize
condensed solvent for
further hydrocarbon mobilization. At the same time, ASB parameters may be
modulated to
mitigate solvent shortcutting.
[0007] Accordingly, in select embodiments, the present disclosure relates
to a
method of recovering hydrocarbons from a subterranean reservoir, comprising:
(i) selecting
a solvent that has a liquid phase that is delineated from a vapour phase by a
vapourization
curve under reservoir conditions; (ii) in a solvent-driven process (SDP) phase
of the method,
modulating production of mobilized fluids from the reservoir while injecting
the solvent into
the reservoir at a constant or variable SDP rate such that a SDP bottom-hole
pressure-
temperature condition transitions from a first regime to a second regime under
which the SDP
bottom-hole pressure-temperature condition lies above the vapourization curve
of the
solvent; and (iii) interrupting the SDP phase with an abbreviated steam boost
(ASB) phase
that comprises modulating production of mobilized fluids from the reservoir
while injecting
steam into the reservoir at a constant or variable ASB injection rate that is
sufficient to provide
a desired target increased ASB bottom-hole pressure-temperature condition. In
select
embodiments, the ASB bottom-hole pressure-temperature condition may be
selected so that
it that lies below the vapourization curve of the solvent but not sufficient
to increase the ASB
bottom-hole pressure to more than a threshold value, for example of about 105
%, about 110
%, about 115%, about 120%, or about 125% of the SDP bottom-hole pressure under
the
first regime.
[0008] As noted above, in the context of the present disclosure, SDP
injection fluids
comprise greater than about 50 % solvent and less than about 50 % steam on a
mass basis.
Those skilled in the art will appreciate that such processes may be
implemented in a variety
of ways and may be referred to by a variety of different names. In other
words, SDP
represents a plurality of more specific embodiments that share a common aspect
¨ employing
injection fluids comprising greater than about 50 % solvent and less than
about 50 % steam
on a mass basis. Accordingly, given that the methods of the present disclosure
feature an
SDP phase that is punctuated by an ASB phase, they may also be characterized
as
comprising a "principal phase" that is punctuated by an ASB phase, wherein the
principle
phase employs an injection fluid comprising greater than about 50 % solvent
and less than
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Date Recue/Date Received 2020-12-18
about 50 % steam on a mass basis, and wherein the term "principle phase" is
used to
describe one which is interrupted by an ASB phase. In this respect, for
example: (i) an SDP
injection rate may be characterized as a principle-phase injection rate, (ii)
an SDP bottom-
hole pressure-temperature condition may be characterized as a principle-phase
bottom-hole
pressure-temperature condition, (iii) an SDP bottom-hole pressure may be
characterized as
a principle-phase bottom-hole pressure, and (iv) an SDP bottom-hole
temperature may be
characterized as a principle-phase bottom-hole temperature.
[0009] Select embodiments of the present disclosure relate to a
method of recovering
hydrocarbons from a subterranean reservoir, comprising: selecting a solvent
that has a liquid
phase that is delineated from a vapour phase by a vapourization curve under
reservoir
conditions; in a principle phase of the method, modulating production of
mobilized fluids from
the reservoir while injecting an injection fluid comprising the solvent into
the reservoir at: (i) a
constant or variable principle-phase solvent concentration of at least about
50 wt. % of the
injection fluid, and (ii) a constant or variable principle-phase injection
rate, such that a
.. principle-phase bottom-hole pressure-temperature condition transitions from
a first regime to
a second regime under which the principle-phase bottom-hole pressure-
temperature
condition lies above the vapourization curve of the solvent; and interrupting
the principle
phase with an abbreviated steam boost (ASB) phase that comprises modulating
production
of mobilized fluids from the reservoir while injecting steam into the
reservoir at a constant or
variable ASB injection rate that is sufficient to provide a target increased
ASB bottom-hole
pressure-temperature condition.
[0010] In select embodiments of the present disclosure, the target
ASB bottom-hole
pressure-temperature condition lies below the vapourization curve of the
solvent but is not
sufficient to increase the ASB bottom-hole pressure to more than about 110 %
of the SDP
bottom-hole pressure under the first regime (i.e. 110 % of the principle-phase
bottom-hole
pressure under the first regime).
[0011] In select embodiments of the present disclosure, the ASB
bottom-hole
pressure-temperature condition comprises an ASB bottom-hole temperature of
between
about 75 C and about 250 C.
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Date Recue/Date Received 2020-12-18
[0012] In select embodiments of the present disclosure, the ASB
bottom-hole
temperature is between about 100 C and about 200 C.
[0013] In select embodiments of the present disclosure, the ASB
bottom-hole
pressure-temperature condition comprises an ASB bottom-hole pressure between
about
3000 kPa and about 3250 kPa.
[0014] In select embodiments of the present disclosure, the ASB
bottom-hole
pressure is between about 3100 kPa and about 3250 kPa.
[0015] In select embodiments of the present disclosure, ASB phase is
followed by an
additional SDP phase (i.e. an additional principle phase).
[0016] In select embodiments of the present disclosure, the ASB phase is
followed
by a blowdown phase.
[0017] In select embodiments of the present disclosure, the ASB phase
is executed
for a period of between about 1 weeks and about 25 weeks.
[0018] In select embodiments of the present disclosure, the steam
injected during the
ASB phase is substantially free of co-injected solvent.
[0019] In select embodiments of the present disclosure, the steam
injected during
ASB phase is a component of an injection fluid that further comprises between
about 3 %
and about 50 % of a solvent on a mass basis.
[0020] In select embodiments of the present disclosure, during the
ASB phase, the
production of the mobilized fluids comprises a production rate of between
about 5 T/d and
about 500 T/d.
[0021] In select embodiments of the present disclosure, during the
ASB phase, the
production of the mobilized fluids provides a produced fluid stream having a
water cut of
between about 10 % and about 40 % by mass.
[0022] In select embodiments of the present disclosure, the water cut is
between
about 15 % and about 35 % by mass.
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Date Recue/Date Received 2020-12-18
[0023] In select embodiments of the present disclosure, the ASB
injection rate is
variable within a range of about 20 T/d to about 100 T/d.
[0024] In select embodiments of the present disclosure, the ASB
injection rate is
constant and between about 20 T/d to and about 100 T/d.
[0025] In select embodiments of the present disclosure, the SDP bottom-hole
pressure-temperature condition comprises a SDP bottom-hole temperature between
about
75 C and about 250 C under the first regime (i.e. the principle-phase bottom-
hole pressure-
temperature condition comprises a principle-phase bottom-hole temperature
between about
75 C and about 250 C under the first regime).
[0026] In select embodiments of the present disclosure, the SDP bottom-hole
temperature is between about 100 C and about 150 C under the first regime
(i.e. the
principle-phase bottom-hole temperature is between about 100 C and about 150
C under
the first regime).
[0027] In select embodiments of the present disclosure, the SDP
bottom-hole
pressure-temperature condition comprises a SDP bottom-hole temperature between
about
75 C and about 250 C under the second regime (i.e. the principle-phase
bottom-hole
pressure-temperature condition comprises a principle-phase bottom-hole
temperature
between about 75 C and about 250 C under the second regime).
[0028] In select embodiments of the present disclosure, the SDP
bottom-hole
temperature is between about 100 C and about 150 C under the second regime
(i.e. the
principle-phase bottom-hole temperature is between about 100 C and about 150
C under
the second regime).
[0029] In select embodiments of the present disclosure, the SDP
bottom-hole
pressure-temperature condition comprises a SDP bottom-hole pressure between
about 2500
kPa and about 3500 kPa under the first regime (i.e. the principle-phase bottom-
hole pressure-
temperature condition comprises a principle-phase bottom-hole pressure between
about
2500 kPa and about 3500 kPa under the first regime.).
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Date Recue/Date Received 2020-12-18
[0030] In select embodiments of the present disclosure, the SDP
bottom-hole
pressure is between about 3000 kPa and about 3300 kPa under the first regime
(i.e. the
principle phase bottom-hole pressure is between about 3000 kPa and about 3300
kPa under
the first regime).
[0031] In select embodiments of the present disclosure, the SDP bottom-hole
pressure-temperature condition comprises a SDP bottom-hole pressure between
about 2500
kPa and about 3500 kPa under the second regime (i.e. the principle-phase
bottom-hole
pressure-temperature condition comprises a principle-phase bottom-hole
pressure between
about 2500 kPa and about 3500 kPa under the second regime).
[0032] In select embodiments of the present disclosure, the SDP bottom-hole
pressure is between about 3000 kPa and about 3300 kPa under the second regime
(i.e. the
principle-phase bottom-hole pressure is between about 3000 kPa and about 3300
kPa under
the second regime).
[0033] In select embodiments of the present disclosure, the ASB
bottom-hole
pressure-temperature condition is sufficient to increase the ASB bottom-hole
pressure to
between 80 % and about 110 % of the SDP bottom-hole pressure under the first
regime (i.e.
the ASB bottom-hole pressure-temperature condition is sufficient to increase
the ASB
bottom-hole pressure to between 80 % and about 110 % of the principle-phase
bottom-hole
pressure under the first regime).
[0034] In select embodiments of the present disclosure, the ASB bottom-hole
pressure-temperature condition is sufficient to increase the ASB bottom-hole
pressure to
between about 90% and about 110% of the SDP bottom-hole pressure under the
first regime
(i.e the ASB bottom-hole pressure-temperature condition is sufficient to
increase the ASB
bottom-hole pressure to between about 90 % and about 110 % of the principle-
phase bottom-
hole pressure under the first regime).
[0035] In select embodiments of the present disclosure, the SDP phase
of the method
is preceded by a SAGD phase, a SAP phase, or a combination thereof (i.e. the
principal
phase of the method is preceded by a SAGD phase, a SAP phase, or a combination
thereof).
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Date Recue/Date Received 2020-12-18
[0036] In select embodiments of the present disclosure, solvent
comprises primarily
propane, butane, diluent, natural gas condensate, or a combination thereof.
[0037] In select embodiments of the present disclosure, the solvent
comprises
propane.
BRIEF DESCRIPTION OF THE DRAWINGS
[0038] These and other features of the present disclosure will become
more apparent
in the following detailed description in which reference is made to the
appended drawings.
The appended drawings illustrate one or more embodiments of the present
disclosure by way
of example only and are not to be construed as limiting the scope of the
present disclosure.
[0039] FIG. 1 provides a phase diagram for steam and a set of
archetypal solvents
under reservoir conditions. For each solvent, the phase diagram delineates
temperature/pressure conditions under which the solvent is substantially in
the vapour phase
from those under which the solvent is substantially in the liquid phase.
[0040] FIG. 2 provides a flow diagram of a broader hydrocarbon recovery
process
that includes a solvent driven process (SDP) phase that is punctuated by an
abbreviated
steam boost (ASB) phase.
[0041] FIG. 3 provides a schematic plot of propane production in
produced fluid as a
function time. The schematic differentiates an SDP process from an ASB-SDP
process.
DETAILED DESCRIPTION
[0042] Extensive modeling and trials indicate that, during a
prolonged period of
hydrocarbon recovery within a solvent driven process (SDP) phase of a broader
recovery
scheme, discontinuing solvent injection in favour of low-rate steam injection
(i.e. executing
an abbreviated steam boost (ASB) phase as defined herein) has the potential to
provide a
number of potential benefits and/or to mitigate a number of potential
problems. At a high-
level, the ASB strategies set out herein allow for hydrocarbon recovery under
SDP conditions
that would otherwise be associated with: (i) insufficient rates of steam-
condensate drainage
8
Date Recue/Date Received 2020-12-18
to maintain the liquid level at the production well without compromising
production rates, and
(ii) insufficient reservoir temperature/pressure conditions to maintain
solvent substantially in
the vapour phase.
[0043] With respect to (i), the emulsion-production rates associated
with some
implementations of SDP phases are only a fraction of those associated with
conventional
SAGD phases. For example, transitioning from a conventional SAGD phase to a
conventional
SDP phase may reduce the rate of emulsion production from about 20 m3/hr to
about 4 m3/hr.
This may result, at least in part, from a substantial reduction in the amount
of steam
condensate in the emulsion. For example, transitioning from a conventional
SAGD phase to
a conventional SDP phase may reduce the water cut of a produced emulsion
stream from
about 80 % to about 30 % on a mass basis. As the conventional SDP process
continues, the
operative level of liquid around the producer is reduced. This progression
creates a condition
where solvent short cutting is likely ¨ it becomes difficult to control the
rate of solvent
production in the gaseous phase without compromising the rate of hydrocarbon
production.
ASB-SDP is an alternative approach that provides flexibility in attending to
the rate of solvent
production in the gaseous phase and the rate of hydrocarbon production. For
example, in
ASB-SDP, the injection of steam at a low rate, such as about 80 T/d, may add
an additional
about 3.3 m3/hr to the conventional SDP emulsion-production rate of about 4
m3/hr. In this
way, ASB-SDP may allow for increasing emulsion accumulation around the
production well,
which may allow for better gaseous solvent production control.
[0044] With respect to (ii), during a conventional SDP phase the
temperature/pressure in the production chamber may decrease from a condition
that is
sufficient to maintain the solvent substantially in the vapour phase as it
migrates to the
chamber front, to one that is not. For example, during a conventional SDP
phase the
temperature of the production chamber may decrease from about 225 C to about
113 C
over about 450 days. Under typical reservoir conditions, solvents such as
propane and/or
butane exist substantially in the liquid phase at about 113 C, and they are
likely to pool in
proximity to the production well where their ability to further develop the
production chamber
is limited. The ASB phase requires relatively little steam, and yet it
provides a means to
revitalize the reservoir temperature/pressure profile in relatively short
order. For example,
The ASB phase may increase reservoir temperature back to about 225 C from
about 113 C
9
Date Recue/Date Received 2020-12-18
in as little as about 60 days at a steam injection rate of about 80 T/d.
Solvents such as
propane and/or butane exist substantially in the vapour phase under high-
reservoir
temperature conditions such as about 225 C, hence ASB provides a means to
increases
reservoir temperature/pressure conditions which may advance solvent gas
perpetuation,
bitumen mobilization, and/or chamber development.
[0045] Because ASB provides a means to mitigate: (i) insufficient
rates of steam-
condensate drainage to maintain the liquid level at the production well
without compromising
production rates; and (ii) insufficient reservoir temperature/pressure
conditions to maintain
solvent substantially in the vapour phase, it introduces a degree of
flexibility into SDP-based
hydrocarbon recovery methods that may be advantageous in a variety of
contexts. As a first
example, in select embodiments of the present disclosure, ASB-SDP may be well
suited for
hydrocarbon recovery during periods of solvent price volatility. As a second
example, in select
embodiments of the present disclosure, ASB-SDP may be well suited for
hydrocarbon
recovery when solvent supply to the recovery operation is tenuous. As a third
example, in
select embodiments of the present disclosure, ASB-SDP may be well suited for
hydrocarbon
recovery during periods where there is additional steam capacity due to lower
utilization from
the neighboring wells. As a fourth example, in select embodiments of the
present disclosure,
ASB-SDP may be useful for evaluating the steam and/or solvent requirement to
re-pressurize
a production chamber. As a fifth example, in select embodiments of the present
disclosure,
ASB-SDP may increase solvent efficacy within the recovery scheme. As a sixth
example, in
select embodiments of the present disclosure, ASB-SDP may be useful as a
regulation
technique for in situ upgrading. Moreover, in select embodiments of the
present disclosure,
ASB-SDP may be advantageous in more than one such contexts.
[0046] Select embodiments of the present disclosure will now be
described with
reference to FIG. 1 to FIG. 3 without limiting the scope of the present
disclosure.
[0047] In select embodiments, the present disclosure relates to a
method of
recovering hydrocarbons from a subterranean reservoir, comprising: (i)
selecting a solvent
that has a liquid phase that is delineated from a vapour phase by a
vapourization curve under
reservoir conditions; (ii) in a solvent-driven process (SDP) phase of the
method, modulating
production of mobilized fluids from the reservoir while injecting the solvent
into the reservoir
at a constant or variable SDP rate such that a SDP bottom-hole pressure-
temperature
Date Recue/Date Received 2020-12-18
condition transitions from a first regime to a second regime under which the
SDP bottom-hole
pressure-temperature condition lies above the vapourization curve of the
solvent; and (iii)
interrupting the SDP phase with an abbreviated steam boost (ASB) phase that
comprises
modulating production of mobilized fluids from the reservoir while injecting
steam into the
reservoir at a constant or variable ASB injection rate that is sufficient to
provide a target ASB
bottom-hole pressure-temperature condition. For example, the target ASB bottom-
hole
pressure-temperature condition may be selected so that it lies below the
vapourization curve
of the solvent but is not sufficient to increase the ASB bottom-hole pressure
to more than a
target SDP bottom-hole pressure, for example a target of about 110% of the SDP
bottom-
hole pressure under the first regime.
[0048] As noted above, in the context of the present disclosure, SDP
injection fluids
comprise greater than about 50 % solvent and less than about 50 % steam on a
mass basis.
Those skilled in the art will appreciate that such processes may be
implemented in a variety
of ways and may be referred to by a variety of different names. In other
words, SDP
represents a plurality of more specific embodiments that share a common aspect
¨ employing
injection fluids comprising greater than about 50 % solvent and less than
about 50 % steam
on a mass basis. Accordingly, given that the methods of the present disclosure
feature an
SDP phase that is punctuated by an ASB phase, they may also be characterized
as
comprising a "principal phase" that is punctuated by an ASB phase, wherein the
principle
phase employs an injection fluid comprising greater than about 50 % solvent
and less than
about 50 % steam on a mass basis, and wherein the term "principle phase" is
used to
describe one which is interrupted by an ASB phase. In this respect, for
example: (i) an SDP
injection rate may be characterized as a principle-phase injection rate, (ii)
an SDP bottom-
hole pressure-temperature condition may be characterized as a principle-phase
bottom-hole
pressure-temperature condition, (iii) an SDP bottom-hole pressure may be
characterized as
a principle-phase bottom-hole pressure, and (iv) an SDP bottom-hole
temperature may be
characterized as a principle-phase bottom-hole temperature.
[0049] Select embodiments of the present disclosure relate to a
method of recovering
hydrocarbons from a subterranean reservoir, comprising: selecting a solvent
that has a liquid
phase that is delineated from a vapour phase by a vapourization curve under
reservoir
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Date Recue/Date Received 2020-12-18
conditions; in a principle phase of the method, modulating production of
mobilized fluids from
the reservoir while injecting an injection fluid comprising the solvent into
the reservoir at: (i) a
constant or variable principle-phase solvent concentration of at least about
50 wt. % of the
injection fluid, and (ii) a constant or variable principle-phase injection
rate, such that a
principle-phase bottom-hole pressure-temperature condition transitions from a
first regime to
a second regime under which the principle-phase bottom-hole pressure-
temperature
condition lies above the vapourization curve of the solvent; and interrupting
the principle
phase with an abbreviated steam boost (ASB) phase that comprises modulating
production
of mobilized fluids from the reservoir while injecting steam into the
reservoir at a constant or
variable ASB injection rate that is sufficient to provide a target increased
ASB bottom-hole
pressure-temperature condition.
[0050] In the context of the present disclosure, the word
"hydrocarbon" is generally
used interchangeably with "petroleum" and/or "oil" to refer to mixtures of
widely varying
composition, as will be evident from the context in which the word is used. It
is common
practice to categorize hydrocarbon substances of high viscosity and density
into two
categories, "heavy oil" and "bitumen". For example, some sources define "heavy
oil" as a
hydrocarbon-containing mixture that has a mass density of greater than about
900 kg/m3.
Bitumen is sometimes described as that portion of a hydrocarbon-containing
mixture that
exists in the semi-solid or solid phase in natural deposits, with a mass
density greater than
about 1000 kg/m3 and a viscosity greater than about 10,000 centipoise (cP; or
10 Pa-s)
measured at original temperature in the deposit and atmospheric pressure, on a
gas-free
basis. Although these terms are in common use, references to heavy oil and
bitumen
represent categories of convenience, and there is a continuum of properties
between heavy
oil and bitumen. Accordingly, references to heavy oil and/or bitumen herein
include the
continuum of such substances, and do not imply the existence of some fixed and
universally
recognized boundary between the two substances. In particular, the term "heavy
oil" includes
within its scope all "bitumen" including hydrocarbons that are present in semi-
solid or solid
form.
[0051] In the context of the present disclosure, a "reservoir" or
"hydrocarbon-bearing
formation" is a subsurface formation containing one or more natural
accumulations of
moveable hydrocarbons, which are generally confined by relatively impermeable
rock. An "oil
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Date Recue/Date Received 2020-12-18
sand" reservoir is generally comprised of strata of sand or sandstone
containing viscous
hydrocarbons, such as bitumen. Viscous petroleum, such as bitumen, may also be
found in
reservoirs whose solid structure consists of carbonate material rather than
sand material.
Such reservoirs are sometimes referred to as "bituminous carbonates".
[0052] In the context of the present disclosure, SAP injection fluids
comprise less
than about 50 % solvent and greater than about 50 % steam on a mass basis. In
the context
of the present disclosure, SDP injection fluids comprise greater than about
50% solvent and
less than about 50 % steam on a mass basis. For example, an SDP injection
fluid may
comprise about 80 % solvent and about 20 % steam on a mass basis. Those
skilled in the
art will appreciate that SAGD, SAP, and SDP processes can each be implemented
in a
variety of ways, such that each of these categories comprise a plurality of
more specific
embodiments. For example, the terms "solvent assisted process" and "SAP"
incorporate
more specific embodiments that employ injection fluids comprising less than
about 50 %
solvent and greater than about 50 % steam on a mass basis, such as so called
"Expanding
solvent SAGD" or "ES-SAGD".
[0053] In the context of the present disclosure, "selecting a solvent
that has a liquid
phase that is delineated from a vapour phase by a vapourization curve under
reservoir
conditions" may be facilitated by considering a phase diagram. FIG. 1 provides
a phase
diagram 100 for a set of archetypal solvents, under example reservoir
conditions.
[0054] The phase diagram 100 plots comprises a vertical pressure axis and a
horizontal temperature axis. The phase diagram 100 comprises a propane
vapourization
curve 102 that delineates: (i) a region of reservoir temperature-pressure
conditions 104 under
which propane is substantially in the liquid phase, from (ii) a region of
reservoir
temperature/pressure conditions 106 under which propane is substantially in
the vapour
phase. Analogous vapourization curves for butane, pentane, hexane, heptane,
and octane
are indicated by reference numbers 110, 112, 114, 116, and 188, respectively.
The phase
diagram 100 also comprises a vapourization curve 108 for water. Considering a
solvent
vapourization curve in combination the water vapourization curve 108 provides
useful context
for reservoir behavior during a transition from a SAGD phase to a SDP phase.
For example,
steam injection at about 3000 kPa may provide a temperature of about 240 C in
proximity to
the injection well (curve 108 at a pressure of 3000 kPa). Maintaining this
pressure and
13
Date Recue/Date Received 2020-12-18
transitioning to a SDP phase equates to a shift along dashed line 120 towards
the
vapourization curve for propane 102. Continued SDP may provide a pressure-
temperature
condition into region 104, under which propane exists primarily in the liquid
phase. ASB-SDP
may be utilized to transition the reservoir to region 106 where propane exists
primarily in the
vapour phase as indicated in FIG. 1 by dashed arrow 122, for example.
[0055] Many solvents are characterized by a liquid phase that is
delineated from a
vapour phase by a vapourization curve under reservoir conditions. As will be
appreciated by
those skilled in the art who have benefitted from the teachings of the present
disclosure, the
solvent may be vapourizable at the operational pressure and temperature near
the injection
well and in a central region of the production chamber, so that the solvent
can enter the
reservoir in the vapour phase and can remain in the vapour phase until the
solvent vapour
reaches the production chamber front. The solvent may also be substantially
condensable at
the edges, margins, or boundaries of the production chamber, where the local
temperature
is significantly lower than the temperature in the central region of the
vapour chamber. The
condensed solvent may be capable of dissolving hydrocarbons such that the
condensed
solvent (i.e. liquid solvent) may reduce the viscosity of the hydrocarbons, or
increase the
mobility of the hydrocarbons, which may assist hydrocarbon drainage and may
improve the
rate of hydrocarbon production. There may be a number of underlying mechanisms
for
increasing mobility of hydrocarbons in the reservoir formation as will be
understood by those
skilled in the art. A suitable solvent may be selected to assist drainage of
hydrocarbons based
on any of these mechanisms or a combination of such mechanisms. For example, a
solvent
may be selected based on its ability to reduce the viscosity of hydrocarbons,
to dissolve in
the reservoir fluid, or to reduce surface and interfacial tension between
hydrocarbons and
sands or other solid or liquid materials present in the reservoir. The solvent
may also be
selected to act as a wetting agent or surfactant. When oil attachment to sand
or other
immobile solid materials in the reservoir is reduced, the oil mobility can be
increased. The
solvent may function as an emulsifier for forming hydrocarbon-water emulsions,
which may
help to improve oil mobility with water in the reservoir. In select
embodiments of the present
disclosure, the solvent may comprise propane, butane, pentane, diluent,
natural gas
condensate, or a combination thereof. In select embodiments of the present
disclosure, the
solvent is propane. In select embodiments of the present disclosure, the
solvent is butane.
Compositions comprising primarily methane, ethane, 02, CO2, N2, CO, H2S, H2,
NH3, flue
14
Date Recue/Date Received 2020-12-18
gas, or a combination thereof are typically not condensable under the majority
of reservoir
conditions contemplated in the present disclosure and, as such, these non-
condensable
gases may fall outside of the present definition of "solvent".
[0056] In the context of the present disclosure, modulating
production of mobilized
fluids from the reservoir while injecting the solvent into the reservoir at a
constant or variable
SDP rate such that a SDP bottom-hole pressure-temperature condition lies above
the
vapourization curve of the solvent" may involve manipulating: (i) production
pump rates; (ii)
injection rates; (iii) injection fluid composition; or (iv) a combination
thereof. In the context of
the present disclosure, such manipulations may result in a
temperature/pressure transition
from a first regime (such as one associated with a conventional SAGD or SAP
phase) to a
second regime (such as one associated with a conventional SDP phase). In
select
embodiments of the present disclosure, under the first regime, the SDP bottom-
hole
pressure-temperature condition comprises a SDP bottom-hole temperature between
about
75 C and about 300 C (such as between about 110 C and about 250 C). In
select
embodiments of the present disclosure, under the first regime, the SDP bottom-
hole
pressure-temperature condition comprises a SDP bottom-hole pressure between
about 2500
kPa and about 3500 kPa (such as between about 3000 kPa and about 3300 kPa or
between
about 3150 kPa and about 3250 kPa). In select embodiments of the present
disclosure, under
the second regime, the SDP bottom-hole pressure-temperature condition
comprises a SDP
bottom-hole temperature between about 100 C and about 300 C (such as between
about
110 C and about 250 C). In select embodiments of the present disclosure,
under the second
regime, the SDP bottom-hole pressure-temperature condition comprises a SDP
bottom-hole
pressure between about 2500 kPa and about 3500 kPa (such as between about 3000
kPa
and about 3300 kPa or between about 3150 kPa and about 3250 kPa).
[0057] During the SDP phase, the injected solvent may play the dominant
role in
further expansion, particularly lateral or horizontal expansion of the
production chamber. In
select embodiments of the present disclosure, the SDP phase is preceded by a
SAGD phase,
a SAP phase, or a combination thereof. While the production chamber may be
dominated by
steam from an earlier SAGD or SAP process, after a period of operation under
SDP
.. conditions, the solvent may become the dominant vapour in the production
chamber having
regard to the solvent-dominated composition of the injection fluid during the
SDP phase. This
Date Recue/Date Received 2020-12-18
transition may be associated with a reduction in reservoir pressure leading to
bottom-hole
pressure-temperature conditions that are not sufficiently energetic to re-
volatilize condensed
solvent from the pool in proximity to the production well. In selected
embodiments of the
present disclosure, during the SDP phase, the solvent may be co-injected with
a small
amount of steam. In such a case, the amount of the injected steam may be
sufficient to heat
and vapourize the injected solvent, and maintain the solvent in the vapour
phase in the
production chamber to allow the solvent to travel to the chamber front (i.e.
the edges or
margins of the production chamber). However, the weight ratio of co-injected
steam to co-
injected solvent is relatively small, such as less than about 20 wt.% or less
than about 30 wt.
%, so that steam plays only a minor role in further expansion the production
chamber and
does not provide a sufficient enthalpic boost to re-volatilize a substantial
amount of
condensed solvent in proximity to the production well.
[0058] In the context of the present disclosure, interrupting the SDP
phase with an
abbreviated steam boost (ASB) that comprises modulating production of
mobilized fluids from
the reservoir while injecting steam into the reservoir at a constant or
variable ASB injection
rate that is sufficient to provide an ASB bottom-hole pressure-temperature
condition that lies
below the vapourization curve of the solvent may involve manipulating: (i)
production pump
rates; (ii) injection rates; (iii) injection fluid composition; or (iv) a
combination thereof. In select
embodiments of the present disclosure, the ASB bottom-hole pressure-
temperature condition
.. comprises an ASB bottom-hole temperature of between about 75 C and about
300 C (such
as between about 11000 and about 250 C). In select embodiments of the present
disclosure,
the ASB bottom-hole pressure-temperature condition comprises an ASB bottom-
hole
pressure between about 2500 kPa and about 3500 kPa (such as between about 3000
kPa
and about 3300 kPa or between about 3150 kPa and about 3250 kPa). In select
embodiments
of the present disclosure, the ASB phase is executed for a period of between
about 1 day,
about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, or about
7 days and
about 2 weeks, about 3 weeks, about 4 weeks, about 5 weeks, or about 6 weeks.
[0059] Reservoir simulations indicate that, under SDP conditions, in
situ hydrocarbon
mobilization may be sensitive to relatively modest changes in solvent vapour
pressure. For
example, a reservoir at 3200 kPa producing an emulsion with a water cut of
about 30 % may
provide an emulsion rate of about 3.5 m3/hr at about 100 C and an emulsion
rate of about
16
Date Recue/Date Received 2020-12-18
4.2 m3/hr at about 115 C. An ASB phase as set out in the present disclosure
may be
employed to direct this change in order to improve solvent efficiencies (such
as cSOR and
iSOR).
[0060] In select embodiments of the present disclosure, the steam
injected during the
ASB phase may be a component of an injection fluid that further comprises
between about
50 % and about 90 % of a solvent on a mass basis. In select embodiments of the
present
disclosure, during the ASB phase, the production of the mobilized fluids
comprises a
production rate of between about 5 T/d and about 250 T/d. In select
embodiments of the
present disclosure, during the ASB phase, the production of the mobilized
fluids provides a
produced fluid stream having a water cut of between about 5 % and about 80 %
by mass. In
select embodiments of the present disclosure, the water cut is between about
10 % and about
80 % by mass.
[0061] In select embodiments of the present disclosure, the ASB
injection rate is
variable within a range of about 5 T/d to about 500 T/d. In select embodiments
of the present
disclosure, the ASB injection rate is constant and between about 5 T/d and
about 500 T/d.
[0062] In select embodiments of the present disclosure, the steam
injected during the
ASB phase is substantially free of co-injected solvent.
[0063] As noted above, in select embodiments of the present
disclosure, ASB-SDP
may provide one or more advantages in the context of in-situ hydrocarbon
recovery. As a
first example, ASB-SDP may be well suited for hydrocarbon recovery during
periods of
solvent price volatility. Solvent prices, such as propane prices and/or butane
prices, tend to
fluctuate in a volatile way based on a supply/demand curve and/or seasonality.
For example,
between January 2018 and January 2019, the price of butane varied from about
40 US$/bbl
to about 4 US$/bbl. During the same time period, the price of propane varied
between about
30 US$/bbl and about 10 US$/bbl. In select embodiments of the present
disclosure, ASB-
SDP may be used as a means to navigate economic conditions that make
conventional
solvent-driven processes untenable. For example, ASB-SDP could be executed
based on a
threshold violation of an economic parameter such as a price ratio between
Western Canada
Select (WCS) and solvent. In select embodiments of the present disclosure, the
threshold
may be a WCS-to-solvent ratio of between about 2.5:1 and about 4.0:1Ø
17
Date Recue/Date Received 2020-12-18
[0064] As a second example, ASB-SDP may be well suited for
hydrocarbon recovery
when solvent supply to the recovery operation is tenuous. For example, steam
injection at a
rate of between about 5 T/d and about 50 T/d for a period of about 1 week to
ab0ut25 weeks
may be adapted so as to maintain dormant conditions for between about 1 month
and about
6 months such that production via a conventional SDP phase may continue
thereafter.
[0065] As a third example, ASB-SDP may be well suited for hydrocarbon
recovery
during periods where there is additional steam capacity due to lower
utilization from the
neighboring wells. For example, if a neighboring well failed or transitioned
to an SDP well,
the spare steam could be used for the ASB-SDP phase.
[0066] As a fourth example, ASB-SDP may be useful for testing solvent
and/or steam
requirements to pressurize the production chamber. For example, an ASB phase
based on
about 80 T/d of steam injection rate could replace about 40 T/d of propane
injection and about
26 T/d of steam injection during SDP. When implementing the ASB, the process
may
comprise reducing the solvent injection rate from about 40 T/d to about 0 T/d
and monitoring
the bottom-hole pressure while injecting a sufficient volume of steam to
maintain the bottom-
hole pressure at about 3200 kPa. The volume of steam required may be constant,
or it may
vary over time. For example, the volume of steam required may be about 80 T/d,
or it may
be increased from about 40 T/d to about 80 T/d over a period of weeks, which
may result in
a more efficient recovery and better environmental performance.
[0067] As a fifth example, ASB-SDP may be useful for in-situ upgrading of
hydrocarbons resources during production. For example, pilot scale trials
suggest that
asphaltene particles may break apart during ASB-SDP. Production-chamber core
samples
indicate a significant deviation in asphaltene precipitation along the
vertical section of the
core. In one instance, an asphaltene content of about 26 % was observed at the
higher and
middle sections of the production chamber and lower content of about 18 % was
observed at
IHS zones and next to injection well. Without being bound to any particular
theory, this may
indicate that bitumen upgrading occurs due to the extraction of the heavier
particles from the
oleic phase as the solubility of the solvent increases and decreasing
temperature within the
production chamber. The ASB-SDP may act as a regulation technique to achieve
improved
upgrading performance while also improving production chamber development.
This may be
particularly effective after a prolonged SDP phase.
18
Date Recue/Date Received 2020-12-18
[0068] In select embodiments of the present disclosure, the ASB phase
may be
followed by an additional SDP phase. In select embodiments of the present
disclosure, the
ASB phase may be followed by a blowdown phase. More generally, select
embodiments of
the ASB-SDP of the present disclosure may be implemented as described with
reference to
FIG. 2, which provides an archetypal flow chart describing an in situ
hydrocarbon recovery
process that features ASP-SDP.
[0069] In FIG. 2, At 200, a reservoir is subjected to an initial
phase of a SAGD
process, referred to as the "start-up" phase or stage, in which fluid
communication between
an injection well and a production well is established. To permit drainage of
mobilized
hydrocarbons and condensate to the production well, fluid communication
between the
injection well and the production well must be established. Fluid
communication in this
context refers to fluid flow between the injection well and the production
well. Establishment
of such fluid communication typically involves mobilizing viscous hydrocarbons
in the
reservoir to form a mobilized reservoir fluid and removing the mobilized
reservoir fluid to
create a porous pathway between the wells. Viscous hydrocarbons may be
mobilized by
heating such as by injecting or circulating pressurized steam or hot water
through the injection
well or the production well. In some cases, steam may be injected into, or
circulated in, both
the injection well and the production well for faster start-up. A pressure
differential may be
applied between the injection well and the production well to promote
steam/hot water
penetration into the porous geological formation that lies between the wells
of the well pair.
The pressure differential promotes fluid flow and convective heat transfer to
facilitate
communication between the wells.
[0070] Additionally or alternatively, other techniques may be
employed during the
start-up phase 200. For example, to facilitate fluid communication, a solvent
may be injected
into the reservoir region around and between the injection well and the
production well. The
region may be soaked with a solvent before or after steam injection. An
example of start-up
using solvent injection is disclosed in CA 2,698,898. In further examples, the
start-up phase
200 may include one or more start-up processes or techniques disclosed in CA
2,886,934,
CA 2,757,125, or CA 2,831,928.
[0071] Once fluid communication between the injection well and the
production well
has been achieved, hydrocarbon production or recovery may commence during
phase 205.
19
Date Recue/Date Received 2020-12-18
As the hydrocarbon production rate is typically low initially and will
increase as the production
chamber develops, this early production phase is known as the "ramp-up" phase
or stage.
During the ramp-up phase 205, steam is typically injected continuously into
the injection well,
at constant or varying injection pressure and temperature. At the same time,
mobilized heavy
hydrocarbons and aqueous condensate are continuously removed from the
production well,
typically in the form of an emulsion having oleic and aqueous phases. During
the ramp-up
phase 205, the zone of communication between the injection well and the
production well
may continue to expand axially along the full length of the horizontal
portions thereof.
[0072] As injected steam heats up the reservoir, hydrocarbons in the
heated region
are softened, resulting in reduced viscosity. Further, as heat is transferred
from steam to the
reservoir, steam condenses. The aqueous condensate and mobilized hydrocarbons
will drain
downward due to gravity, in a gravity-dominated process. As a result of
depletion of the heavy
hydrocarbons, a porous region is formed in the reservoir, which is referred to
as a production
chamber. When the void space in a production chamber is filled with mainly
steam, it is
commonly referred to as a "steam chamber." The aqueous condensate and
hydrocarbons
drained towards the production well and collected in the production well are
then produced
(transferred to the surface, typically as an oil in water emulsion), such as
by gas lifting or
through pumping as is known to those skilled in the art.
[0073] As alluded to above, the production chamber is formed and
gradually expands
due to depletion of hydrocarbons and other in-situ materials from regions
within the reservoir,
generally above the injection well. Injected steam tends to rise up to reach
the top of the
production chamber before it condenses, and steam can also spread laterally as
it travels
upward. Therefore, during early stages of chamber development, the production
chamber
generally expands upwardly and laterally from the injection well. During the
ramp-up phase
205, the production chamber can grow vertically towards an overburden.
Depending on the
size of the reservoir (and the pay therein) and the distance between the
injection well and the
overburden, it can take a long time, such as many months and up to two years,
for the
production chamber to reach the overburden especially when the pay zone is
relative thick
as is typically found in some operating oil sands reservoirs. However, in a
thinner pay zone
the production chamber can reach the overburden sooner. The time to reach the
vertical
expansion limit can also be longer in cases where the pay zone is higher or
highly
Date Recue/Date Received 2020-12-18
heterogeneous, or the reservoir has complex overburden geologies such as with
inclined
heterolithic stratification, top water, top gas, or other stratigraphic
complexities.
[0074] In the next phase, the reservoir may be subject to a
conventional SAGD
production process 210, where the oil production rate is sufficiently high for
economic
recovery of hydrocarbons and the cumulative steam oil ratio continues to
decrease or remain
relatively stable. During the conventional SAGD production process 210 (or a
similar but
modified steam-driven recovery process), one or more chemical additives may be
added to
steam or co-injected with steam to enhance hydrocarbon recovery. For example,
a surfactant,
which lowers the surface tension of a liquid, the interfacial tension (IFT)
between two liquids,
or the IFT between a liquid and a solid, may be added. The surfactant may act,
for example,
as a detergent, a wetting agent, an emulsifier, a foaming agent, or a
dispersant to facilitate
the drainage of the softened hydrocarbons to the production well. An organic
solvent, such
as an alkane or alkene, may also be added to dilute the mobilized hydrocarbons
so as to
increase the mobility and flow of the diluted hydrocarbon fluid to the
production well for
improved recovery. Other materials in liquid or gas form may also be added to
enhance
recovery performance.
[0075] The start-up phase 200, the ramp-up phase 205, and the SAGD
production
process phase 210 described above are non-limiting examples, and there are
numerous
conventional and innovative techniques known to those skilled in the art that
result in the
formation of a production chamber. In alternative embodiments, rather than
using a well pair,
one or more single horizontal or vertical wells may be used for providing a
production
chamber. For example, CA 2,844,345 discloses a process that provides a
production
chamber using a single vertical or inclined well. The process may be preceded
by start-up
acceleration techniques to establish communication in the formation between an
injection
means and a production means within the single well.
[0076] When the vapour chamber grows vertically, oil production rates
normally
continue to increase, and the cumulative steam to oil ratio normally continues
to decrease.
Steam utilization during such chamber growth is relatively efficient. However,
when the top
front of the vapour chamber approaches or reaches an overburden, vertical
growth of the
vapour chamber will slow down and eventually stop. While the vapour chamber
may continue
to grow or expand laterally, which may be at a slower pace, steam utilization
during slow
21
Date Recue/Date Received 2020-12-18
lateral growth may be less efficient. As a result, oil production rate may
reach a peak value
or plateau, and then start to decline. The cumulative steam-to-oil ratio may
bottom out and
start to increase. Thus, such changes in chamber growth, oil production rate
and cumulative
steam-to-oil ratio may be used to define threshold violations to trigger a
transition to a solvent-
driven process (SDP) phase 215. To initiate conditions suitable for SDP, a
suitable solvent
and transition condition are selected (according to various factors and
considerations as set
out herein). As can be appreciated by those skilled in the art having
benefited from the
teachings of the present disclosure, the selection may be performed at any
time prior to
solvent injection, and may be performed in any order depending on the
particular situation
and application.
[0077] The SPD phase 215 involves injection of the selected solvent
into the
reservoir through the injection well. The solvent is generally injected into
the reservoir in a
vapour phase. Injection of the solvent in the vapour phase allows solvent
vapour to rise in
the production chamber and condense at a region away from the injection well.
Allowing
solvent to rise in the production chamber before condensing may achieve
beneficial effects.
For example, when solvent vapour is delivered to the production chamber and
then allowed
to condense and disperse near the edges of the vapour chamber, oil production
performance,
such as indicated by one or more of oil production rate, cumulative steam-to-
oil ratio, and
overall efficiency, may be improved. Injection of solvent in the gaseous
phase, rather than a
liquid phase, may allow vapour to rise in the production chamber before
condensing so that
condensation occurs away from the injection well. As will be appreciated by
those skilled in
the art who have benefitted from the teachings of the present disclosure,
injecting solvent
vapour into the vapour chamber does not necessarily require solvent be fed
into the injection
well in vapour form. For example, the solvent may be heated downhole and
vapourized in
the injection well.
[0078] In FIG. 2, the SDP phase 215 is interrupted by an abbreviated
steam boost
(ASB) phase 220. The ASB phase may be triggered by a variety of factors as set
out herein.
For example, the ASB phase may be triggered by a local pressure drop to a
pressure-
temperature condition under which the solvent is substantially in the liquid
phase. During the
ASB phase 220, solvent injection may be stopped or greatly decreased in favour
of low
injection rate steam injection. The steam injection rate could be at a
significantly reduced rate
22
Date Recue/Date Received 2020-12-18
as compared to a SAGD like rate (such as that used at 210). For example, steam
injection at
220 may be about 75 % less than that at 210. At the same time, steam injection
at 220 may
be about 300 % that used under SDP conditions (such as that used at 215). For
example,
220 may comprise steam injection rates of about 80 T/d, and 215 may employ a
steam
injection rate of about 26 T/d in combination with propane injection rate of
about 40 T/D. In
select embodiments of the present disclosure, the bottom-hole pressure may be
kept steady
during 220. Under such conditions, the temperature in the production chamber
is expected
to increase back to between about 200 C and about 21500 due to the higher
steam enthalpy
of about 2.6 MJ/kg despite the low injected steam rate in comparison to an SDP-
like enthalpy
of about 0.5 MJ/kg. The temperature increase in the production chamber may
results in a
benefit where condensed solvent is re-vapourized such that it may advance
chamber
development. At the same time, during the ASB phase 220, steam injection may
reheat the
solvent already in situ and utilize the condensed steam as a tool to control
gaseous solvent
production.
[0079] In FIG. 2, the ASB phase 220 is followed by a further phase 225,
which may
be an additional SDP phase, a blow down phase, a SAP phase, a SAGD phase, or a
combination thereof.
[0080] FIG. 3 provides a schematic plot 300 of propane production in
produced fluid
as a function time. Reference number 304 indicates a schematic plot of the SDP
process
.. under such conditions, and reference number 306 provides pilot-scale field
data for such a
process. In the schematic plot 300, reference number 308 indicates the timing
of a potential
shift to an ASB-SDP process. Reference number 310 indicates a schematic plot
of propane
production in produced fluid under such conditions. Comparing schematic plots
304 and 310
highlights how the ASB-SDP process drives re-vapourization of the propane
solvent from the
produced fluid.
[0081] In the present disclosure, all terms referred to in singular
form are meant to
encompass plural forms of the same. Likewise, all terms referred to in plural
form are meant
to encompass singular forms of the same. Unless defined otherwise, all
technical and
scientific terms used herein have the same meaning as commonly understood by
one of
ordinary skill in the art to which this disclosure pertains.
23
Date Recue/Date Received 2020-12-18
[0082] As used herein, the term "about" refers to an approximately +/-
10 % variation
from a given value. It is to be understood that such a variation is always
included in any given
value provided herein, whether or not it is specifically referred to.
[0083] It should be understood that the compositions and methods are
described in
terms of "comprising," "containing," or "including" various components or
steps, the
compositions and methods can also "consist essentially of or "consist of the
various
components and steps. Moreover, the indefinite articles "a" or "an," as used
in the claims,
are defined herein to mean one or more than one of the element that it
introduces.
[0084] For the sake of brevity, only certain ranges are explicitly
disclosed herein.
However, ranges from any lower limit may be combined with any upper limit to
recite a range
not explicitly recited, as well as, ranges from any lower limit may be
combined with any other
lower limit to recite a range not explicitly recited, in the same way, ranges
from any upper
limit may be combined with any other upper limit to recite a range not
explicitly recited.
Additionally, whenever a numerical range with a lower limit and an upper limit
is disclosed,
any number and any included range falling within the range are specifically
disclosed. In
particular, every range of values (of the form, "from about a to about b," or,
equivalently, "from
approximately a to b," or, equivalently, "from approximately a-b") disclosed
herein is to be
understood to set forth every number and range encompassed within the broader
range of
values even if not explicitly recited. Thus, every point or individual value
may serve as its own
lower or upper limit combined with any other point or individual value or any
other lower or
upper limit, to recite a range not explicitly recited.
[0085] Therefore, the present invention is well adapted to attain the
ends and
advantages mentioned as well as those that are inherent therein. The
particular embodiments
disclosed above are illustrative only, as the present invention may be
modified and practiced
in different but equivalent manners apparent to those skilled in the art
having the benefit of
the teachings herein. Although individual embodiments are dis-cussed, the
invention covers
all combinations of all those embodiments. Furthermore, no limitations are
intended to the
details of construction or design herein shown, other than as described in the
claims below.
Also, the terms in the claims have their plain, ordinary meaning unless
otherwise explicitly
and clearly defined by the patentee. It is therefore evident that the
particular illustrative
embodiments disclosed above may be altered or modified and all such variations
are
24
Date Recue/Date Received 2020-12-18
considered within the scope and spirit of the present invention. If there is
any conflict in the
usages of a word or term in this specification and one or more patent(s) or
other documents
that may be incorporated herein by reference, the definitions that are
consistent with this
specification should be adopted.
[0086] Many
obvious variations of the embodiments set out herein will suggest
themselves to those skilled in the art in light of the present disclosure.
Such obvious variations
are within the full intended scope of the appended claims.
Date Recue/Date Received 2020-12-18
