Note: Descriptions are shown in the official language in which they were submitted.
FORCED SOLVENT CYCLING IN OIL RECOVERY
TECHNICAL FIELD
[0001] The present disclosure relates to in situ methods for recovering
hydrocarbons from
subterranean reservoirs. In particular, the present disclosure relates to
solvent-aided or solvent
driven processes that ameliorate the unproductive short circuiting of injected
solvent between
an injection well and a production well, thereby driving a productive solvent
cycling process.
BACKGROUND
[0002] Hydrocarbons in some subterranean deposits of viscous hydrocarbons,
can be
extracted in situ by lowering the viscosity of the hydrocarbons to mobilize
them so that they can
be moved to, and recovered from, a production well. Reservoirs of such
deposits may be referred
to as reservoirs of heavy hydrocarbons, heavy oil, bitumen, or oil sands. In
situ processes for
recovering oil from oil sands typically involve the use of multiple wells
drilled into the reservoir,
.. and are assisted or aided by thermal and/or solvent based recovery
techniques, such as injecting
a heated fluid, typically steam, solvent or a combination thereof, into the
reservoir from an injection
well. Steam-assisted gravity drainage (SAGD) and cyclic steam stimulation
(CSS) are
representative thermal-recovery processes that use steam to mobilize
hydrocarbons in situ.
Solvent-aided processes (SAP) and solvent-driven processes (SDP) are
representative thermal-
.. recovery processes that use both steam and solvent to mobilize hydrocarbons
in situ.
[0003] Atypical SAGD process is disclosed in Canadian Patent No.
1,130,201 issued on 24
August 1982, in which the functional unit involves two wells that are drilled
into the deposit, one
for injection of steam and one for production of oil and water. Steam is
injected via the injection
well to heat the formation. The steam condenses and gives up its latent heat
to the formation,
heating a layer of viscous hydrocarbons. The viscous hydrocarbons are thereby
mobilized, and
drain by gravity toward the production well with an aqueous condensate. In
this way, the
injected steam initially mobilizes the in-place hydrocarbons to create a steam
or production
chamber in the reservoir around and above the horizontal segment of the
injection and
production wells.
[0004] Some thermal recovery processes employ injection fluids that include
solvent,
optionally in combination with steam, as for example disclosed in Canadian
Patent Publication
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Date Recue/Date Received 2020-12-18
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. 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 aided 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".
[0005] 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 phase during which non-condensable gas is injected to recover
residual
hydrocarbons and solvent.
[0006] The terms "steam chamber" or "production chamber" or "recovery
chamber"
accordingly refer to the volume of the reservoir which is saturated with
injected fluids and from
which mobilized oil has at least partially drained. Mobilized viscous
hydrocarbons are typically
recovered continuously through one or more production wells. The conditions of
mobilizing fluid
injection and of hydrocarbon production may be modulated to control the growth
of the
production chamber, for example to maximize oil production at the production
well. There are,
however, circumstances in which maximum oil production may not be the
paramount
commercial operational imperative.
SUMMARY
[0007] Methods are disclosed for operating a well pair in a heavy oil
reservoir to facilitate
recovery of hydrocarbons, where the production well includes one or more
segments that are
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spaced apart from corresponding segments of the injection well by interwell
zones that include
mobile fluids. In this circumstance, there is a risk of an injection fluid
short circuiting from the
injection well to the production well. This is particularly problematic when
the injection fluids
include a volatile solvent, because it is difficult or impossible to determine
whether any solvent
produced through the production well, typically as a casing gas, is the result
of solvent short
circuiting or, more productively, merely the production of solvent that had
dissolved in, and
hence mobilized, the heavy oil that is being produced, before being released
as a gas from the
production fluids.
[0008] In view of the foregoing challenge, the present methods provide a
system in which
the risk of short circuiting solvent is ameliorated. This is accomplished by
taking steps to
segregate the injection of solvent from the production of solvent-derived
casing gas. This
segregation is implemented by adopting distinct phases of operation, a
"solvent-filling" phase
and a "bitumen-draining" phase. In the solvent-filling phase, solvent is
injected, for example so
as to raise a bottom hole pressure (BHP) in the recovery chamber to a solvent-
filling-phase
upper BHP threshold value, but production of solvent-derived casing gas is
minimized. In
contrast, in the bitumen-draining phase, injection of solvent is minimized and
production of
solvent-derived casing gas is permitted, for example up to a bitumen-draining-
phase maximum
casing gas production threshold.
[0009] In the solvent-filling phase, the production of fluids is
throttled-down, for example by
adjusting the speed of a production pump, so as to minimize production of
gaseous solvent.
This approach to production fluid management guards against the short
circuiting of the injected
solvent through the interwell mobile fluid zone directly to the production
well. In the bitumen-
draining phase, the production of fluids may be throttled-up, with the
attendant production of an
operationally acceptable amount of gaseous solvent, but because the injection
of solvent is
reduced during the bitumen-draining phase, the produced casing gas is
necessarily attributable
to solvent entrained in the mobilized bitumen, and cannot be attributable to
solvent short
circuiting through the interwell zone.
[0010] The well pair in the subterranean heavy oil reservoir is emplaced
so as to service a
recovery chamber. In a typical well pattern, analogous to a SAGD well pair, a
production well
accessing the heavy oil reservoir is provided, typically comprising a
production well surface
facility in fluid communication with a generally horizontal longitudinal
production well segment
within a heavy oil zone in the reservoir. The production well may include a
fluid-permeable
production well casing, through which production fluids are collected. The
fluid-permeable
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Date Recue/Date Received 2020-12-18
collection segments of the production well may be spaced apart from one or
more
corresponding segments of an injection well, with an interwell zone between
these segments of
the production and injection wells. This interwell zone provides an avenue for
fluid flow that
potentially permits solvent short circuiting.
[0011] The injection well accessing the heavy oil reservoir may similarly
comprise an
injection well surface facility in fluid communication with a generally
horizontal longitudinal
injection well segment within the heavy oil zone in the reservoir. The
longitudinal injection well
segment typically being generally parallel to and vertically spaced apart
above the longitudinal
production well segment.
[0012] In the solvent-filling phase, a mobilizing fluid that includes a
solvent is injected into
the recovery chamber through the injection. This may for example take place at
a constant or
variable solvent-filling-phase injection rate, so as to increase a bottom hole
pressure (BHP) in
the recovery chamber. In conjunction with injection of mobilizing fluids, the
production of
mobilized fluids from the production well may be modulated, for example so as
to limit the
amount of production well casing gas production below a solvent-filling-phase
maximum casing
gas production threshold. In this way, an increase the BHP may be achieved,
for example to a
solvent-filling-phase upper BHP threshold value.
[0013] In the bitumen-draining phase, decreasing the solvent injection
rate, for example to
below an average, or minimum, of the solvent-filling-phase injection rates,
may be implemented
so as to decrease the BHP in the recovery chamber. In conjunction with this,
the production of
mobilized fluids from the production well may be modulated so as to permit the
amount of
casing gas produced to rise, for example to a bitumen-draining-phase maximum
casing gas
production threshold.
[0014] The transition between solvent-filling and bitumen-draining
phases may be triggered
by select operating parameters. For example, when the bitumen-draining-phase
maximum
casing gas production threshold is reached, operations may be returned to the
solvent-filling
phase. In typical implementations, the solvent-filling-phase maximum casing
gas production
threshold is much less than the value of the bitumen-draining-phase maximum
casing gas
production threshold, for example at or less than about 50%, about 40%, about
30%, about
20%, about 10%, about 5%, or about 1% of the bitumen-draining-phase maximum
casing gas
production threshold. This reflects the fact that casing gas production may be
permitted in the
bitumen-draining phase, when solvent injection is reduced, because the
produced casing gas is
derived in large part from solvent that has previously dissolved in the
mobilized bitumen,
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Date Recue/Date Received 2020-12-18
representing the intended productive use of the solvent rather than an
unproductive short
circuiting of solvent.
[0015] In select embodiments, the present disclosure relates to a method
of recovering
hydrocarbons from a subterranean heavy oil reservoir, comprising:
providing a well pair servicing a recovery chamber, the well pair comprising:
a production
well accessing the heavy oil reservoir; and, spaced apart from the production
well by an
interwell zone, an injection well accessing the heavy oil reservoir;
in a solvent-filling phase, injecting a mobilizing fluid comprising a solvent
through the
injection well at a constant or variable solvent-filling-phase injection rate
so as to
increase a bottom hole pressure (BHP) in the recovery chamber while modulating
production of mobilized fluids from the production well so as to limit the
amount of
production well casing gas production below a solvent-filling-phase maximum
casing gas
production threshold, so as to increase the BHP to a solvent-filling-phase
upper BHP
threshold value;
in a bitumen-draining phase, decreasing the solvent injection rate, so as to
decrease the
BHP in the recovery chamber while modulating production of mobilized fluids
from the
production well so as to permit the amount of casing gas produced to rise to a
bitumen-
draining phase maximum casing gas production threshold; and,
when the bitumen-draining-phase maximum casing gas production threshold is
reached,
returning to the solvent-filling phase, wherein the solvent-filling-phase
maximum casing
gas production threshold is at or less than 50% of the value of the bitumen-
draining-
phase maximum casing gas production threshold.
[0016] In select embodiments of the present disclosure, the bitumen-
draining-phase
maximum casing gas production threshold is at least about 10 T/d, about 11
T/d, about 12 T/d,
about 13 T/d, about 14 T/d, about 15 T/d, about 16 T/d, about 17 T/d, about 18
T/d, about 19
T/d or about 20 T/d; or, is an at least about 10%, about 20%, about 30%, about
40%, about
50%, about 60% about 70%, about 80%, about 90%, about 100%, about 110%, about
120%,
about 130%, about 140%, about 150%, about 160%, about 170%, about 180%, about
190%, or
about 200% increase of casing gas production rate within a bitumen-draining-
phase maximum
casing gas monitoring period of from about 1 hour to about 1 week.
[0017] In select embodiments of the present disclosure, the solvent-
filling-phase maximum
casing gas production threshold is between about 0 T/d and about 10 T/d; or,
is an at least
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Date Recue/Date Received 2020-12-18
about 10%, about 20%, about 30%, about 40%, about 50%, about 60% about 70%,
about 80%,
about 90%, about 100%, about 110%, about 120%, about 130%, about 140%, about
150%,
about 160%, about 170%, about 180%, about 190%, or about 200% increase of
casing gas
production rate within a solvent-filling-phase maximum casing gas monitoring
period of from
about 1 hour to about 1 week.
[0018] In select embodiments of the present disclosure, the solvent-
filling-phase maximum
casing gas production threshold is at or less than about 40%, about 30%, about
20%, about
10%, about 5% or about 1% of the value of the bitumen-draining-phase maximum
casing gas
production threshold.
[0019] In select embodiments of the present disclosure, the solvent-filling-
phase upper BHP
threshold value is at least about 3175 kPa, about 3200 kPa, about 3225 kPa or
3250 kPa.
[0020] In select embodiments of the present disclosure, the BHP is
generally maintained
within a BHP constraint range at or below the solvent-filling-phase upper BHP
threshold value
and at or above a minimum BHP constraint value.
[0021] In select embodiments of the present disclosure, in the bitumen-
draining phase, the
solvent injection rate is decreased to below an average of the solvent-filling-
phase injection
rates, so as to decrease the BHP in the recovery chamber.
[0022] In select embodiments of the present disclosure, in the bitumen-
draining phase, the
solvent injection rate is decreased to below a minimum value of the solvent-
filling-phase
.. injection rates, so as to decrease the BHP in the recovery chamber.
[0023] In select embodiments of the present disclosure, the solvent-
filling phase and the
bitumen-draining phase are repeated in a plurality of cycles, and in the
plurality of cycles one or
more of the following parameters changes from one cycle to another cycle: the
bitumen-
draining-phase maximum casing gas production threshold; the solvent-filling-
phase maximum
casing gas production threshold; and/or, the solvent-filling-phase upper BHP
threshold value.
[0024] In select embodiments of the present disclosure, the solvent
comprises C2 to C10
linear, branched, or cyclic alkanes, alkenes, or alkynes, substituted or
unsubstituted.
[0025] In select embodiments of the present disclosure, the solvent
predominantly
comprises one or more n-alkane.
[0026] In select embodiments of the present disclosure, the n-alkane is
propane, butane or
pentane.
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Date Recue/Date Received 2020-12-18
[0027] In select embodiments of the present disclosure, the solvent
comprises propane
and/or butane.
[0028] In select embodiments of the present disclosure, the mobilizing
fluid comprises
steam.
[0029] In select embodiments of the present disclosure, the mobilizing
fluid comprises at
least about 50%, about 60%, about 70%, about 80% or 90% solvent.
[0030] In select embodiments of the present disclosure, the production
well accessing the
heavy oil reservoir comprises a production well surface facility in fluid
communication with a
generally horizontal longitudinal production well segment within a heavy oil
zone in the
reservoir, the production well comprising a fluid-permeable production well
casing.
[0031] In select embodiments of the present disclosure, the injection
well accessing the
heavy oil reservoir comprises an injection well surface facility in fluid
communication with a
generally horizontal longitudinal injection well segment within the heavy oil
zone in the reservoir,
the longitudinal injection well segment being generally parallel to and
vertically spaced apart
above the longitudinal production well segment.
[0032] In select embodiments of the present disclosure, the method
further comprises a
transition period between: (i) the solvent-filling phase and the bitumen-
draining phase; and/or (ii)
the bitumen-draining phase and the solvent-filling phase.
BRIEF DESCRIPTION OF THE DRAWINGS
[0033] Figure 1 includes two graphs, schematically illustrating the
synchronous adjustment
of the BHP and the fluid production rate in alternating "solvent-filling" and
"bitumen-draining"
phases of a heavy oil production process.
DETAILED DESCRIPTION
[0034] Cyclic processes are disclosed for managing the efficient use of
solvent in the
recovery of mobilized hydrocarbons from heavy oil reservoirs, including
process that involve the
co-injection of steam and solvent, particularly solvent-aided (SAP) or solvent-
driven processes
(SDP). These cyclic processes include conditionally recurrent steps of
increasing and
decreasing the injection rate of a mobilizing injection fluid and the
production rate of a mobilized
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Date Recue/Date Received 2020-12-18
production fluid, in alternating phases. Specifically, each cycle has two
phases, which may be
referred to as a "solvent-filling" phase and "bitumen-draining" phase.
[0035] In the solvent-filling phase, an injection fluid, typically a
mixture of solvent and steam
is injected into the formation, typically at a relatively high injection rate,
so that the bottom hole
pressure (BHP) in the recovery chamber increases. During this phase, the
production rate is
typically maintained at a relatively low, or minimum, production rate, which
is selected so as to
minimize or prevent casing gas flow. This phase is a "filling" phase, in the
sense that in this
phase: (i) the recovery chamber is being filled with injected mobilizing
fluid, typically steam and
solvent, and (ii) the bottom portion of the recovery chamber fills with
drained mobilized
hydrocarbon liquids, so the mobilized liquid level above the production well
rises (the injection
rate is high and production rate is low). Operating conditions may accordingly
be arranged so
that little or no solvent gas is produced through the production casing in
this solvent-filling
phase, so that there can inherently be little or no short circuiting of
solvent from the injection well
directly to the production well through the interwell zone.
[0036] In select implementations, the solvent-filling phase ends, and the
process transitions
to the bitumen-draining phase, when the BHP reaches a preselected maximum
value. In the
transition period, the injection rate may be relatively quickly decreased, for
example so as to
decrease the BHP to a preselected minimum. In conjunction with this, the
production rate may
be increased. Then, for example when the minimum BHP pressure is reached, the
injection rate
is maintained at a relatively low level, for example so as to maintain the BHP
at the selected
minimum BHP, and the production rate is correspondingly increased, for example
up to a
maximum production rate. In this bitumen-draining phase, casing gas is
produced and some
solvent may be produced through the casing gas. The solvent produced in the
casing gas,
however, is not attributable to short circuiting because the solvent injection
rate has been
throttled-down. This phase is a "draining" phase in the sense that in this
phase, the liquid level
above the production well will be lowered due to the reduced injection rate
and increased
production rate, and the amount of steam/solvent in the chamber also
decreases.
[0037] As the mobilized liquid level above the production well falls
during the bitumen-
draining phase, the casing gas flow rate will generally increase. The casing
gas flow rate may
accordingly be monitored, and when the casing gas flow rate reaches a
preselected maximum
threshold value or rate (for example when there is a sharp increase in the
casing gas production
rate), the bitumen-draining phase may be concluded, and the process can be
made to transition
back to a solvent-filling phase to initiate the next cycle. In this way,
productive solvent cycling in
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Date Recue/Date Received 2020-12-18
the recovery chamber is prioritized over unproductive short circuiting of
solvent. The process
accordingly cyclically alternates between the solvent-filling phase and the
bitumen-draining
phase, and the triggering condition for transitioning from the solvent-filling
phase to the bitumen-
draining phase is the attainment of a maximum BHP, while the triggering
condition for
transitioning from the bitumen-draining phase to the solvent-filling phase is
the onset of a
maximum casing gas threshold, being a maximum casing gas flow rate or a
maximum rate-
change increase.
[0038] In select implementations, the methods of the present disclosure
may comprise a
transition period between: (i) the solvent-filling phase and the bitumen-
draining phase; and/or (ii)
the bitumen-draining phase and the solvent-filling phase. The duration and
operations
associated with the transition period may be modulated to achieve particular
production and/or
reservoir parameters as will be appreciated by those skilled in the art who
have benefitted from
the teachings of the present disclosure,
[0039] The processes disclosed herein overcome the challenge that it is
difficult or
impossible to tell whether a solvent present in produced casing gas is short
circuiting
unproductively, or if it is productively migrating to the casing via the
liquid drained next to the
producer. In addition, in a typical SAGD process, relatively large quantities
of emulsion are
produced, and in the emulsion effectively forms a physical buffer around the
production well.
However, in a recovery process involving the use of significant amounts of
solvent, where water
is limited (as there is less steam), the mobilized oil is thicker, and larger
quantities of gas are
typically produced in the absence of a similar physical buffer around the
production well. These
characteristics of solvent-based recovery processes exacerbate the challenges
associated with
short circuiting of solvent. The present processes are accordingly
particularly advantageous in a
high-gas, low-water recovery environment, conditions typical of SAP and SDP
processes.
[0040] In effect, the present processes provide methods for adjusting
solvent production in
a hydrocarbon recovery process, typically where steam and solvent are co-
injected. The
mobilizing fluid is injected at an injection rate into the reservoir, so as to
assist hydrocarbon
production, and a reservoir fluid comprising hydrocarbons is produced at a
production rate. The
methods involve conditionally recurrent transitioning between a solvent-
filling phase and a
bitumen-draining. In the solvent-filling phase, the injection rate and the
production rate are
adjusted to increase a bottom hole pressure in the reservoir, and the
production rate is set at a
reduced production rate selected so as to reduce production of the solvent in
the gas phase
from the reservoir. In the bitumen-draining phase, the injection rate and the
production rate are
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Date Recue/Date Received 2020-12-18
adjusted to maintain the bottom hole pressure in the recovery chamber, for
example at a
preselected minimum pressure, and the production rate is increased, for
example to a maximum
production rate, to increase production of the solvent in the gas phase at an
increased gas
production rate. The triggering condition for transitioning from the solvent-
filling phase to the
bitumen-draining phase is the attainment of a preselected maximum BHP; and the
triggering
condition for transitioning from the bitumen-draining phase to the solvent-
filling phase is the
onset of a gas production rate, or rate change, that reaches a maximum value.
[0041] The present processes are accordingly cyclic processes, imposing
forced solvent
cycling, for managing production of solvent in a process of recovering
oil/petroleum/hydrocarbons from a reservoir/formation containing bitumen/heavy
oil/heavy
hydrocarbons, for example by co-injection of steam and solvent. The cyclic
process includes
conditionally recurrent steps of increasing and decreasing of the production
rate and the
injection rate of fluids, and the cycling of the bottom hole pressure between
a maximum and a
minimum. The synchronized adjustment of the bottom hole pressure and the
production rate is
arranged such that the production rate is low while the bottom hole pressure
is increasing or
high, and the production rate is high while the bottom hole pressure is
decreasing or low. The
synchronized adjustment of the injection rate and production rate is arranged
such that the
production rate is low while the injection rate is high, and the production
rate is high while the
injection rate is low. The process may involve monitoring casing gas flow
during production, and
triggering transition from a "bitumen-draining" phase (low injection/high
production) to a
"solvent-filling" phase (high injection/low production) when the casing gas
flow rate, or change in
casing gas flow rate, reaches a selected maximum threshold.
[0042] In the context of the present application, various terms are used
in accordance with
what is understood to be the ordinary meaning of those terms. For example,
"petroleum" is a
naturally occurring mixture consisting predominantly of hydrocarbons in the
gaseous, liquid or
solid phase. In the context of the present application, the words "petroleum"
and "hydrocarbon"
are used to refer to mixtures of widely varying composition. The production of
petroleum from a
reservoir necessarily involves the production of hydrocarbons, but is not
limited to hydrocarbon
production and may include, for example, trace quantities of metals (e.g. Fe,
Ni, Cu, V).
Similarly, processes that produce hydrocarbons from a well will generally also
produce
petroleum fluids that are not hydrocarbons. In accordance with this usage, a
process for
producing petroleum or hydrocarbons is not necessarily a process that produces
exclusively
petroleum or hydrocarbons, respectively. "Fluids", such as petroleum fluids,
include both liquids
Date Recue/Date Received 2020-12-18
and gases. Natural gas is the portion of petroleum that exists either in the
gaseous phase or in
solution in crude oil in natural underground reservoirs, and which is gaseous
at atmospheric
conditions of pressure and temperature. Natural gas may include amounts of non-
hydrocarbons.
The abbreviation POIP stands for "producible oil in place" and in the context
of the methods
disclosed herein is generally defined as the exploitable or producible oil
located above the
production well elevation.
[0043] It is common practice to segregate petroleum substances of high
viscosity and
density into two categories, "heavy oil" and "bitumen". For example, some
sources define
"heavy oil" as a petroleum that has a mass density of greater than about 900
kg/m3. Bitumen is
sometimes described as that portion of petroleum that exists in the semi-solid
or solid phase in
natural deposits, with a mass density greater than about 1,000 kg/m3 and a
viscosity greater
than 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.
[0044] A "reservoir" is a subsurface formation containing one or more
natural accumulations
of moveable petroleum, which are generally confined by relatively impermeable
rock. An "oil
sand" or "oil sands" reservoir is generally comprised of strata of sand or
sandstone containing
petroleum. A "zone" in a reservoir is an arbitrarily defined volume of the
reservoir, typically
characterized by some distinctive property. Zones may exist in a reservoir
within or across
strata or facies, and may extend into adjoining strata or facies. In some
cases, reservoirs
containing zones having a preponderance of heavy oil are associated with zones
containing a
preponderance of natural gas. This "associated gas" is gas that is in pressure
communication
with the heavy oil within the reservoir, either directly or indirectly, for
example through a
connecting water zone. A pay zone is a reservoir volume having hydrocarbons
that can be
recovered economically.
[0045] "Thermal recovery" or "thermal stimulation" refers to enhanced
oil recovery
techniques that involve delivering thermal energy to a petroleum resource, for
example to a
heavy oil reservoir. There are a significant number of thermal recovery
techniques other than
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Date Recue/Date Received 2020-12-18
SAGD, such as cyclic steam stimulation (CSS), in-situ combustion, hot water
flooding, steam
flooding, and electrical heating. In general, thermal energy is provided to
reduce the viscosity of
the petroleum to facilitate production.
[0046] A "chamber" within a reservoir or formation is a region that is
in fluid/pressure
communication with a particular well or wells, such as an injection or
production well. For
example, in a SAGD process, a steam chamber is the region of the reservoir in
fluid
communication with a steam injection well, which is also the region that is
subject to depletion of
hydrocarbons, often by gravity drainage, into a production well.
[0047] As used herein, the term "about", in the context of a numerically
definable parameter,
refers to an approximately +/-10% variation from a given value. Where
numerical values are
recited herein and these values are necessarily an approximation, for example
to a given
decimal point, it is to be understood that the recital of the values imputes
the exercise of
approximation.
[0048] A wide variety of alternative configurations of injection and
production wells may be
adapted for alternative implementations of forced solvent cycling processes,
for example
involving production wells that are infill wells, which may in turn be
wedgewells, and where
steam or production chambers served by particular injection and/or production
wells are distinct
or have merged.
[0049] Reservoirs containing heavy hydrocarbons are typically below an
overburden, which
may also be referred to as a cap layer or cap rock. The overburden may be
formed of a layer of
impermeable material such as clay or shale. Under natural conditions (e.g.
prior to the
application of a recovery process), the reservoir is typically at a relatively
low temperature, such
as about 12 C, and the formation pressure may be from about 0.1 to about 4
MPa (1 MPa =
1,000 Pa), depending on the location and other characteristics of the
reservoir. A pair of wells,
including an injection well and a production well, are drilled into and extend
substantially
horizontally in the reservoir for producing hydrocarbons from the reservoir.
The well pair is
typically positioned away from the top of the reservoir, which is defined by
the lower edge of the
overburden, and positioned near the bottom of a pay zone or geological stratum
in the reservoir.
[0050] As is typical of such well pair configurations, the injection
well may be vertically
spaced from the production well, such as at a distance between about 1 m to
about 15 m, and
more typically of about 5 m. The distance between the injection well and the
production well in a
well pair may vary and may be selected to optimize forced solvent cycling
operations. In select
12
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embodiments, the horizontal sections of the injection well and the production
well may be
between about 800 m and about 2000 m in length. In other embodiments, these
lengths may be
varied and the overall pattern of well pairs may vary widely. The injection
well and the
production well may each be configured and completed according to a wide
variety of suitable
techniques available in the art. The injection well and the production well
may also be referred
to as the "injector" and "producer", respectively.
[0051] The injection well and the production well are typically
connected to respective
corresponding surface facilities, which typically include an injection surface
facility and a
production surface facility. The injection surface facility may be configured
and operated to
supply injection fluids, such as steam, solvent or combinations thereof into
the injection well.
The production surface facility is configured and operated to produce fluids
collected in the
production well to the surface. In select embodiments, co-injected fluids or
materials may be
pre-mixed before injection. In other embodiments, co-injected fluids may be
separately supplied
into the injection well. In particular, the injection surface facility may be
used to supply steam
into the injection well in a first phase, and a mixture of steam and solvent
into the injection well
in a second phase. In the second phase, the solvent may be pre-mixed with
steam at surface
before co-injection. Alternatively, the solvent and steam may be separately
fed into the injection
well for injection into the reservoir. Optionally, the injection surface
facility may include a heating
facility (not separately shown) for pre-heating the solvent before injection.
[0052] The injection well typically has an injector casing and the
production well has a
production casing. An injector tubing is typically positioned in the injector
casing. The injector
casing may include a slotted liner along the horizontal section of well for
injecting fluids into the
reservoir. Production casing may also be completed with a slotted liner, a
wire wrap or a precise
punched slot screen (PPS), along the horizontal section of well for collecting
fluids drained from
the reservoir by gravity (i.e. in a gravity-dominated process). In select
embodiments, the
production well may be configured and completed similarly to the injection
well. In select
embodiments, each of the injection well and the production well may be
configured and
completed for both injection and production.
[0053] The reservoir may be subjected to an initial phase, for example
as part of a SAGD
process, referred to as the "start-up" phase or stage. Typically, start-up
involves establishing
fluid communication between the injection well and the production well. 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 in the
interwell zone. Fluid
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Date Recue/Date Received 2020-12-18
communication in this context refers to fluid flow between the injection and
production wells.
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.
[0054] Additionally or alternatively, other techniques may be employed
during the start-up
stage. 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 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.
[0055] Once fluid communication between the injection well and the
production well has
been achieved, oil production or recovery may commence, employing one or more
iterations of
forced solvent cycling. As a result of depletion of the heavy hydrocarbons, a
porous region is
formed in the reservoir, which is referred to as a vapor or production or
recovery chamber. The
mobilized hydrocarbons drained towards the production well and collected in
the production well
are then produced (transferred to the surface), such as by gas lifting or
through pumping.
[0056] The solvent for use in the present processes may be selected based
on a number of
considerations and factors, for example as set out in CA2,956,771. The solvent
may be
injectable as a vapor, and may be selected on the basis of being suitable for
dissolving at least
one of the heavy hydrocarbons to be recovered from the reservoir. The solvent
may be a
viscosity-reducing solvent, which reduces the viscosity of the heavy
hydrocarbons in the
reservoir. Suitable solvents may include C2 to C10 linear, branched, or cyclic
alkanes, alkenes,
or alkynes, in substituted or unsubstituted form, or other aliphatic or
aromatic compounds.
Select embodiments may for example use an n-alkane as the dominant solvent,
for example
propane, butane, pentane or mixtures thereof. For a given selected solvent,
the corresponding
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Date Recue/Date Received 2020-12-18
operating parameters during co-injection of the solvent with steam may also be
selected or
determined in view the properties and characteristics of the selected solvent.
The mass fraction
of the solvent may for example be greater than 20% and enough steam may be
added to
ensure that the injected solvent is substantially in the vapor phase. In a
given application, the
solvent may be selected based on its volatility and solubility in the
reservoir fluid.
[0057] The solvent may be heated to vaporize the solvent. For example,
when the solvent is
propane, it may be heated with hot water at a selected temperature such as,
for example, about
100 C. Additionally or alternatively, solvent may be mixed or co-injected
with steam to heat the
solvent to vaporize it and to maintain the solvent in vapor phase. Depending
on whether the
solvent is pre-heated at surface, the weight ratio of steam in the injection
stream should be high
enough to provide sufficient heat to the co-injected solvent to maintain the
injected solvent in the
vapor phase. If the feed solvent from surface is in the liquid phase, more
steam may be required
to both vaporize the solvent and maintain the solvent in the vapor phase as
the solvent travels
through the vapor chamber 260. For example, where the selected solvent is
propane, a solvent-
steam mixture containing about 90% propane and about 10% steam on a mass basis
may be
injected at a suitable temperature, such as about 75 C to about 100 C. For
example, the
enthalpy per unit mass of the aforementioned steam-propane mixture may be
about 557 kJ/kg.
[0058] In the context of the present disclosure, at various times, the
produced-fluid stream
may have an oil:water ratio of from about 60:40 to about 90:10, or for example
alternatively
about 75:25 to about 90:10, depending on the amount of solvent injected. The
use of solvent
accordingly gives rise to a bitumen-concentrating effect in the mobilized
fluid zone at the bottom
of the production chamber, compared to thermal recovery mediated by steam
alone.
[0059] Although various embodiments of the invention are disclosed
herein, many
adaptations and modifications may be made within the scope of the invention in
accordance
with the common general knowledge of those skilled in this art. Such
modifications include the
substitution of known equivalents for any aspect of the invention in order to
achieve the same
result in substantially the same way. Terms such as "exemplary" or
"exemplified" are used
herein to mean "serving as an example, instance, or illustration." Any
implementation described
herein as "exemplary" or "exemplified" is accordingly not to be construed as
necessarily
preferred or advantageous over other implementations, all such implementations
being
independent embodiments. Unless otherwise stated, numeric ranges are inclusive
of the
numbers defining the range, and numbers are necessarily approximations to the
given decimal.
The word "comprising" is used herein as an open-ended term, substantially
equivalent to the
Date Recue/Date Received 2020-12-18
phrase "including, but not limited to", and the word "comprises" has a
corresponding meaning.
As used herein, the singular forms "a", "an" and "the" include plural
referents unless the context
clearly dictates otherwise. Thus, for example, reference to "a thing" includes
more than one
such thing. Citation of references herein is not an admission that such
references are prior art to
the present invention. Any priority document(s) and all publications,
including but not limited to
patents and patent applications, cited in this specification, and all
documents cited in such
documents and publications, are hereby incorporated herein by reference as if
each individual
publication were specifically and individually indicated to be incorporated by
reference herein
and as though fully set forth herein. The invention includes all embodiments
and variations
substantially as hereinbefore described and with reference to the examples and
drawings.
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Date Recue/Date Received 2020-12-18
