Note: Descriptions are shown in the official language in which they were submitted.
I
IN SITU WELL COMPLETIONS AND METHODS FOR INJECTION AND
HYDROCARBON RECOVERY VIA SINGLE WELL
TECHNICAL FIELD
[001] The technical field generally relates to in situ hydrocarbon recovery
and,
more particularly, to a single-well assembly used for hydrocarbon recovery.
BACKGROUND
[002] According to single-well steam-assisted gravity-drainage (SW-SAGD)
techniques, an injection conduit and a production conduit can be located
within a
single well to simplify and downsize equipment. A single-well configuration
can
also have certain economic advantages, since the drilling, maintenance and
operational costs can be reduced compared to a dual well SAGD configuration.
However, proximity of the injection conduit and the production conduit
presents
challenges, such as production of the injected gas phase via the production
conduit.
[003] Single well configurations and equipment used in single-well operations
present various drawbacks, some of which relate to fluid supply and injection,
hydrocarbon production, and operating the system with simultaneous injection
and
production.
[004] There is thus a need for a technology that overcomes at least some of
the
drawbacks of what is known in the field.
SUMMARY
[005] According to an aspect, a single-well assembly for mobilizing and
recovering
hydrocarbons from a single-wellbore located in a hydrocarbon-containing
reservoir
and including a horizontal wellbore section having a toe and a heel is
provided.
The single-well assembly includes at least one injection sub having an
injection
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channel including an injection fluid inlet located on a heel side of the
injection sub
for receiving injection fluid flowing in a toe direction, an injection fluid
outlet located
on a toe side of the injection sub and in fluid communication with the
injection fluid
inlet for releasing injection fluid flowing in the toe direction. The
injection sub further
including an injection port in fluid communication with the injection channel
and the
reservoir to inject the injection fluid into the reservoir, and a production
fluid
passageway allowing passage of production fluid through the injection sub. The
single-well assembly also includes at least one production sub having a
production
channel comprising a production fluid inlet located on a toe side of the
production
sub for receiving production fluid flowing in a heel direction, and a
production fluid
outlet on a heel side of the production sub and in fluid communication with
the
production fluid inlet for releasing the production fluid flowing in the heel
direction.
The production sub further including a production port in fluid communication
with
the reservoir and the production channel to receive production fluid
comprising
mobilized hydrocarbons from the reservoir, and an injection fluid passageway
allowing passage of injection fluid through the production sub. The single-
well
assembly further includes an injection fluid supply system defining a first
flow path
configured to transport the injection fluid flowing in the toe direction
through at least
one of the production and/or injection subs for injection into the reservoir
via the
corresponding injection port; and a production fluid recovery system defining
a
second flow path configured to transport the production fluid flowing in the
heel
direction through at least one of the production and/or injection subs for
recovery
of the production fluid at surface. The first and second flow paths being
independent from one another and configured to allow injection fluid and
production fluid to flow along the horizontal wellbore section simultaneously.
[006] According to a possible embodiment, the injection fluid supply system
includes injection conduits coupled to each injection sub for connecting with
corresponding adjacent production subs, the injection conduits comprising a
first
injection conduit coupled to the injection fluid inlet and a toe side of the
injection
fluid passageway of a first adjacent production sub for transporting the
injection
fluid therebetween; and a second injection conduit coupled to the injection
fluid
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outlet and a heel side of the injection fluid passageway of a second adjacent
production sub for transporting the injection fluid therebetween.
[007] According to another possible embodiment, the production fluid recovery
system includes production conduits coupled to each production subs for
connecting with corresponding adjacent injection subs, the production conduits
comprising a first production conduit coupled to the production fluid outlet
and a
toe side of the production fluid passageway of a first adjacent injection sub
for
transporting the production fluid therebetween; and a second production
conduit
coupled to the production fluid inlet and a heel side of the production fluid
passageway of a second adjacent injection sub for transporting the production
fluid
therebetween.
[008] According to another possible embodiment, the injection conduits of the
injection fluid supply system extend within the production conduits of the
production fluid recovery system.
[009] According to another possible embodiment, the first injection conduit
extends
within the second production conduit, and wherein the second injection conduit
extends within the first production conduit.
[0010] According to another possible embodiment, the injection fluid supply
system further includes at least one stabilizing conduit coupled between one
of the
injection conduits and the corresponding injection or production sub, the
stabilizing
conduit being configured to set the injection conduit within the production
conduit.
[0011] According to another possible embodiment, the stabilizing conduit
includes
stabilizing fins extending radially and outwardly therefrom, each stabilizing
fin
being adapted to engage an inner surface of the corresponding production
conduit.
[0012] According to another possible embodiment, the injection conduits
concentrically extend within the production conduits.
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[0013] According to another possible embodiment, the injection sub includes a
plurality of production fluid passageways disposed about the injection
channel, and
wherein the production sub comprises a plurality of production channels
disposed
about the injection fluid passageway, each production fluid passageway being
in
fluid communication with a corresponding one of the production channels via
the
production fluid recovery system.
[0014] According to another possible embodiment, each production conduit is
provided with an annular sealing element extending radially and outwardly
therefrom, each annular sealing element being in sealing engagement with an
inner surface of the horizontal wellbore section of the single wellbore.
[0015] According to another possible embodiment, the single-well assembly
further includes a liner extending along the inner surface of the horizontal
wellbore
section.
[0016] According to another possible embodiment, the injection port includes
at
least one injection pipe extending between the injection channel and reservoir
for
establishing fluid communication therebetween.
[0017] According to another possible embodiment, the injection pipe includes a
main injection pipe extending outwardly from the injection channel in a
substantially orthogonal manner.
[0018] According to another possible embodiment, the injection pipe further
includes one or more secondary injection pipes extending outwardly from the
main
injection pipe and being configured to inject injection fluid into the
reservoir at an
angle with respect to the horizontal wellbore section.
[0019] According to another possible embodiment, the secondary injection pipes
are evenly spaced about the main injection pipe.
[0020] According to another possible embodiment, the secondary injection pipes
include an inlet section extending from the main injection pipe, and an outlet
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section extending from the inlet section and being axially aligned therewith,
the
outlet section having a cross-sectional area greater than that of the inlet
section.
[0021] According to another possible embodiment, the injection port includes
nozzle inserts operatively connected within the inlet section of the secondary
injection pipe, each nozzle insert having an inner channel for allowing
passage of
injection fluid therethrough and being configured to create a pressure drop
for at
least partially flashing the injection fluid during injection into the
reservoir.
[0022] According to another possible embodiment, each of the nozzle inserts is
a
throttling valve.
[0023] According to another possible embodiment, each of the nozzle inserts is
made of tungsten carbide.
[0024] According to another possible embodiment, the injection sub includes a
plurality of injection ports radially spaced about the injection channel.
[0025] According to another possible embodiment, the production port is
substantially parallel to the production channel and is adapted to transfer
production fluid from the reservoir into the production fluid recovery system.
[0026] According to another possible embodiment, the production port includes
a
converging-diverging nozzle extending between a production port inlet and a
production port outlet.
[0027] According to another possible aspect, there is provided a single-well
assembly for mobilizing and recovering hydrocarbons from a single-wellbore
provided in a hydrocarbon-containing reservoir and comprising a horizontal
wellbore section having a toe and a heel, the single-well assembly comprising
multiple subs connectable together in end-to-end fashion along the horizontal
wellbore. The subs can comprise injection subs distributed along the
horizontal
wellbore in spaced-apart relation to each other and configured to allow
passage of
an injection fluid in a heel-to-toe direction and injection of a mobilizing
fluid at
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respective locations along the horizontal wellbore; and production subs
distributed
along the horizontal wellbore in a staggered relation with respect to the
injection
subs and configured to allow passage of production fluid received from the
reservoir in a toe-to-heel direction for production at surface. The multiple
subs can
each be configured to include injection fluid conduits and production fluid
conduits
that align when the subs are connected together in end-to-end fashion to
provide
fluid communication along the single-well assembly for flow of the production
fluid
and flow of the injection fluid. The single-well assembly allowing the flow of
production fluid and injection fluid simultaneously. Thus, the production
fluid
conduits of adjacent subs align with each other, and injection fluid conduits
of
adjacent subs align with each other.
[0028] According to one embodiment, the subs can further comprise blank subs
that enable neither injection into the reservoir nor production from the
reservoir.
The injection fluid conduits can be tubular and positioned along a
longitudinal
centerline of the single-well assembly.
[0029] According to an embodiment, the subs can also comprise stabilizers
configured to stabilize and support the injection fluid conduits.
[0030] According to an embodiment, the production fluid conduits can include
annular portions and tubular portions. The annular portions of the production
fluid
conduits can be located about the injection fluid conduits, and the tubular
portions
of the production fluid conduits can be located in the injection subs and pass
around corresponding injection ports that provide fluid communication from the
injection fluid conduits into the reservoir.
[0031] According to an embodiment, the assembly also comprises annular sealing
elements arranged in between production and injection locations to provide
isolation therebetween. The sealing elements can allow some amount of fluid
communication from the injection section into the production section via, for
example, a tubular channel.
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[0032] According to another aspect, there is provided a method for mobilizing
and
recovering hydrocarbons via a single well provided in a hydrocarbon-containing
reservoir using the single-well assembly as defined above or herein. The
method
includes injecting a mobilizing fluid via a plurality of the injection subs
into the
reservoir to cause mobilization of hydrocarbons in the reservoir; and
producing a
production fluid comprising mobilized hydrocarbons from the reservoir via a
plurality of the production subs.
[0033] In the method, the mobilization fluid can include or consist of steam,
or can
include or consists of solvent.
[0034] According to some embodiments, a plurality of the single wells is
provided
extending from a common well pad, the single wells being in horizontal spaced-
apart relation with respect to each other within the reservoir.
[0035] According to some embodiments, an electric submersible pump is used in
the single well to produce the production fluid to surface.
[0036] According to some embodiments, a gas lift system is used in the single
well
to produce the production fluid to surface.
[0037] According to some embodiments, a rod pump is used in the single well to
produce the production fluid to surface.
[0038] According to some embodiments, a progressive cavity pump is used in the
single well to produce the production fluid to surface.
[0039] According to some embodiments, the method comprises performing
heating of the reservoir surrounding to the single well using a heater. The
heater
can be used during start-up and/or during normal operations.
[0040] According to some embodiments, the mobilization fluid is provided in
the
single-well assembly in liquid phase and flashes upon injection into the
reservoir.
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[0041] According to another aspect, there is provided a method for mobilizing
and
recovering hydrocarbons via a single well provided in a hydrocarbon-containing
reservoir, the method comprising delivering a mobilizing fluid into a single-
well
assembly through injection conduits provided in a horizonal section of the
single
well and defining a first flow path, the single-well assembly including
multiple subs
connected together in end-to-end fashion and comprising injection subs and
production subs; injecting the mobilizing fluid via a plurality of injection
subs into
the reservoir to cause mobilization of hydrocarbons in the reservoir; and
recovering
a production fluid comprising mobilized hydrocarbons from the reservoir via a
plurality of the production subs; and producing the production fluid that
flows
through production conduits provided in the subs and defining a second flow
path
independent from the first flow path; and recovering the production fluid at
surface.
[0042] According to some embodiments, the mobilization fluid comprises steam
and/or solvent. Heating of the reservoir can include using a heater.
[0043] According to some embodiments, a plurality of the single wells is
provided
extending from a common well pad, the single wells being in horizontal spaced-
apart relation with respect to each other within the reservoir.
[0044] According to some embodiments, an electric submersible pump is used in
the single well to produce the production fluid to surface.
[0045] According to some embodiments, a gas lift system is used in the single
well
to produce the production fluid to surface.
[0046] According to some embodiments, a rod pump is used in the single well to
produce the production fluid to surface.
[0047] According to some embodiments, a progressive cavity pump is used in the
single well to produce the production fluid to surface.
[0048] According to some embodiments, the mobilization fluid is delivered into
the
single-well assembly in liquid phase and flashes upon injection into the
reservoir.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0049] Figure 1 is a transverse cut view of a single wellbore and a single-
well
assembly provided along a horizontal wellbore section.
[0050] Figure 2 is a transverse cut view of a section of the single-well
assembly.
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[0051] Figure 2A is a transverse cut view of a section of the single-well
assembly
shown in Figure 2, showing an injection sub and corresponding injection and
production conduits.
[0052] Figure 2B is a transverse cut view of a section of the single-well
assembly
shown in Figure 2, showing an annular sealing element provided about a
production conduit.
[0053] Figure 2C is a transverse cut view of a section of the single-well
assembly
shown in Figure 2, showing a production sub and corresponding injection and
production conduits.
[0054] Figure 3A is a cross-sectional view of an injection sub, showing
production
fluid passageways surrounding an injection channel.
[0055] Figure 3B is a sectional view of the injection sub taken along cross-
section
lines 3B-3B of Figure 3A, showing an injection port extending from the
injection
channel.
[0056] Figure 4A is a cross-sectional view of a production sub, showing
production
channels surrounding an injection fluid passageway.
[0057] Figure 4B is a sectional view of the production sub taken along cross-
section lines 4B-4B of Figure 4A, showing a production port extending from an
outer surface of the production sub.
[0058] Figure 5A is a cross-sectional view of a stabilizing conduit, showing
stabilizing fins surrounding an injection fluid passageway and extending
therefrom.
[0059] Figure 5B is a sectional view of the stabilizing conduit taken along
cross-
section lines 5B-5B of Figure 5A.
[0060] Figure 6 is a transverse cut view of a section of the single-well
assembly,
showing a liner surrounding the production conduit and an annular sealing
element
provided between the liner and production conduit.
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[0061] Figure 7 is a perspective view of a section of the single-well
assembly,
showing fluid passages provided in the annular sealing element to prevent
pressure build-ups.
[0062] Figure 8A is a transverse cut view of a nozzle insert, showing an inner
channel extending therethrough.
[0063] Figure 8B is a transverse cut view of a nozzle insert, showing an inner
channel extending therethrough having a tapered section.
[0064] Figure 9A is a cross-sectional view of a production sub, showing
production
channels surrounding an injection fluid passageway.
[0065] Figure 9B is a sectional view of the production sub taken along cross-
section lines 9B-9B of Figure 9A, showing a production port extending along
the
production port in a substantially parallel manner.
DETAILED DESCRIPTION
[0066] The present description describes single-well methods and assemblies as
well as structural features thereof used in relation with hydrocarbon recovery
operations. However, it should be understood that the techniques and features
described herein could be used in relation to various hydrocarbon recovery
methods including dual-well steam-assisted gravity drainage (SAGD), infill or
step-
out wells, cyclic steam stimulation (CSS) or other known recovery methods.
[0067] As will be described below in relation to various example
implementations,
a single-well assembly for mobilizing and recovering hydrocarbons from a
single-
wellbore provided in a hydrocarbon-containing reservoir is provided. The
single-
well assembly is configured to be installed within a horizontal wellbore
section and
includes at least one injection sub for injecting injection fluid into the
reservoir, and
at least one production sub for receiving production fluid comprising
mobilized
hydrocarbons from the reservoir. It should be understood that, in the context
of the
present disclosure, the expression "sub" refers to a division or part of an
ensemble
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or structure. For example, the injection sub refers to a subsection of the
single-well
assembly used for the injection of mobilizing fluid. In some implementations,
the
injection and production subs can be installed in an alternating configuration
along
the horizontal wellbore section and are fluidly connected to one another via
conduits extending therebetween. Each sub can include passageways and/or
channels for allowing passage of both injection and production fluids
therethrough
for ultimately allowing recovery of production fluids from the single wellbore
at
surface. For simplicity, each conduit, channel, passageway, pipe and/or other
similar components referred to in the following disclosure has a cross-section
that
is preferably circular, although it should be appreciated that other shapes
are also
possible.
[0068] In some implementations, hydrocarbons are recovered by injecting a
mobilizing fluid (which can also be referred to as injection fluid) within the
reservoir
via the injection sub. The injection fluid then transfers thermal energy to
the
hydrocarbons contained in the reservoir to effectively mobilize the
hydrocarbons
by reducing the viscosity thereof. Hot mobilizing fluids (e.g., steam) use
heat to
raise the temperature of the hydrocarbons to facilitates mobilization, while
other
mobilizing fluids (e.g., organic solvents) can reduce viscosity by dissolving
hydrocarbons into the solvent. Depending on the mobilizing fluid that is used,
different viscosity-reduction mechanisms will be favored.
[0069] Mobilized fluid comprising hydrocarbons and injection fluid drains into
the
horizontal wellbore section and can then be produced via the production sub
and
recovered to the surface. It should be noted that the single-well assembly can
be
adapted to mobilize hydrocarbons in a surrounding region of the reservoir for
ultimately producing the hydrocarbons via any suitable in situ recovery method
which can be implemented using other well assemblies and configurations.
[0070] With reference to Figure 1, an implementation of a single-well assembly
10
configured for installation within a single wellbore 12 provided in a
hydrocarbon-
containing reservoir (R) is illustrated. More specifically, the wellbore 12
can include
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a horizontal wellbore section 14 having a toe 15 and a heel 16 at respective
ends
thereof. It should be understood that, as used herein, the expression "toe"
refers
to the end point of the horizontal wellbore section, as illustrated in Figure
1.
Therefore, expressions such as "toe side'', "toe direction" and any other
similar
expressions should be understood as directional/orientational expressions
using
the toe 15 of the horizontal wellbore section 14 as reference. Similarly, the
expression "heel", as used herein, refers to the beginning of the horizontal
wellbore section 14, and traditionally follows the curved transition section
between
the horizontal and vertical sections of the wellbore 12. Therefore,
expressions such
as " heel side", "heel direction" and any other similar expressions should be
understood as directional/orientational expressions using the heel 16 of the
horizontal wellbore section 14 as reference.
[0071] Now referring to Figures 2 to 2C, in addition to Figure 1, the assembly
10
is illustratively installed within the single wellbore 12, along the
horizontal wellbore
section 14. As best seen in Figure 2A, the assembly 10 can include at least
one
injection sub 100 in fluid communication with the reservoir (R) for injecting
injection
fluid into the reservoir. As mentioned above, once within the reservoir, the
injection
fluid mobilizes the hydrocarbons to enable their production.
[0072] Now referring more specifically to Figure 2C, the assembly 10 can
further
include at least one production sub 200 in fluid communication with the
reservoir
(R) for receiving production fluids, which can include mobilized hydrocarbons
and
injection fluid. In some implementations, production and injections subs 100,
200
can be alternatively installed along the horizontal wellbore section 14 to
define
multiple injection and production points communicating with the reservoir
along the
horizontal wellbore. More specifically, a first production sub 200 can be
installed
proximate the heel 16 of the wellbore 12, followed by a first injection sub
100,
followed by a second production sub 200, and so on. However, it is appreciated
that other configurations are possible when installing the subs 100, 200 of
the
assembly 10. For example, the first production sub 200 can be followed by a
pair
of injection subs 100 prior to installing the second production sub 200.
Indeed,
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multiple injection subs can be provided beside each other, and multiple
production
subs can be provided beside each other along the horizontal wellbore.
[0073] Referring more specifically to Figures 3A and 3B, an exemplary
implementation of the injection sub 100 is shown. The injection sub 100 can
include
an injection channel 102 extending thereth rough to allow passage of injection
fluid
during an injection phase of the hydrocarbon recovery operations. It should
thus
be understood that the injection channel 102 includes an injection fluid inlet
102A
provided on a heel side 103 of the injection sub, and an injection fluid
outlet 102B
provided on a toe side 105 of the injection sub 100 (i.e., opposite the
injection fluid
inlet 102A) for respectively receiving and releasing injection fluid flowing
in a toe
direction. In the present implementation, the injection sub 100 further
includes an
injection port 104 fluidly connecting the injection channel 102 with the
reservoir to
allow injection of injection fluid into the reservoir in a manner that will be
described
further below. It should be understood that, as used herein, the expression
"port"
refers to a connection between two or more components. Furthermore, the
injection sub 100 can include a production fluid passageway 110 adapted to
allow
passage of production fluid, generally flowing in a heel direction, through
the
injection sub 100. It should be understood that the injection channel 102 and
production fluid passageway 110 are not in fluid communication with each
other,
and that the injection and production fluids therefore flow along the single-
well
assembly 10 via separate conduits, as will be explained further below.
[0074] In some implementations, the injection sub 100 includes a plurality of
production fluid passageways 110 provided about the injection channel 102 to
allow the flow of production fluid flowing through the injection sub 100. The
production fluid passageways 110 can be provided at regular intervals around
the
injection channel 102, or arranged in groups as illustrated in Figure 3A. The
groups
of production fluid passageways 110 are illustratively spaced from one another
to
allow the injection port 104 to extend therebetween so as to establish fluid
communication between the injection channel 102 and the reservoir. It is
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appreciated that the production fluid passageways 110 can have any suitable
shape, size and/or configuration extending through the injection sub 100.
[0075] Referring specifically to Figures 4A and 4B, an exemplary
implementation
of the production sub 200 is shown. The production sub 200 can include a
production channel 202 extending therethrough to allow passage of production
fluid for recovery thereof at surface. It should thus be understood that the
production channel 202 includes a production fluid inlet 202A provided on a
toe
side 203 of the production sub, and a production fluid outlet 202B provided on
a
heel side 205 of the production sub 200 (i.e., opposite the production fluid
inlet
202A) for respectively receiving and releasing production fluid flowing in a
heel
direction so as to ultimately be recovered at surface. The production sub 200
further includes a production port 204 fluidly connecting the production
channel
202 and the reservoir to allow production fluid to be received by the
production port
204 from the reservoir in a manner that will be described further below.
Furthermore, the production sub 200 can include an injection fluid passageway
210 adapted to allow passage of injection fluid, generally flowing in a toe
direction,
through the production sub 200. It should be understood that, in a similar
fashion
as the injection channel 102 and production fluid passageway 110, the
production
channel 202 and injection fluid passageway 210 are not in fluid communication
with one another.
[0076] Referring back to Figures 2 to 2C, in addition to Figure 3B, the single-
well
assembly 10 includes an injection fluid supply system 150 configured to
transport
injection fluid through the corresponding subs in order to inject injection
fluid into
the reservoir via the injection ports 104. In the present implementation, the
injection
fluid supply system 150 is configured to connect each adjacent sub 100, 200 to
one another to allow effective transport of injection fluid through each sub
via the
corresponding injection channel 102 and/or injection fluid passageways 210, as
previously described. In some implementations, the injection fluid supply
system
150 includes injection conduits 152 fluidly connecting each corresponding pair
of
adjacent subs for transporting injection fluid therebetween. In other words,
each
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sub (injection 100 or production 200) is respectively fluidly connected to an
adjacent sub via an injection conduit 152 to allow injection fluid to flow
therebetween.
[0077] In the illustrated implementation, the injection conduits 152 extend
between
the subs of the single-well assembly 10 in a manner such as a first injection
conduit
154 extends between a corresponding injection sub 100 and a first adjacent
production sub 200, and a second injection conduit 156 extends between the
injection sub 100 and a second adjacent production sub 200. It should be
understood that the first and second adjacent production subs 200 mentioned
correspond to the production subs 200 located on either side of the
corresponding
injection sub 100. More specifically, the first injection conduit 154 can be
coupled
to the injection fluid inlet 102A of the corresponding injection sub 100 and a
toe
side of the injection fluid passageway 210 of the first adjacent production
sub 200.
[0078] Furthermore, the second injection conduit 156 can be coupled to the
injection fluid outlet 102B of the injection sub 100 and a heel side of the
injection
fluid passageway 210 of the second adjacent production sub 200. In some
implementations, the injection conduits 152 can be coupled directly to the
corresponding subs for establishing fluid communication therebetween. However,
it is appreciated that the injection fluid supply system 150 can include one
or more
injection coupling conduits 158 configured to couple injection conduits 152
with an
adjacent sub, or couple a pair of injection conduits 152 to one another
between the
corresponding subs. Therefore, it should be understood that the injection
coupling
conduits 158 can include a respective injection fluid passageway 159 for
allowing
the flow of injection fluid therethrough. It should be noted that the first
and/or
second injection conduits 154, 156 can be made of multiple injection conduits
152
coupled to one another via injection coupling conduits 158 for transporting
injection
fluid between the subs of the assembly 10. It is appreciated that various
configurations of the injection conduits 152 (with or without injection
coupling
conduits) are possible for connecting two adjacent subs together.
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[0079] Still referring to Figures 2 to 2C, but also with reference to Figure
4B, the
assembly 10 further includes a production fluid recovery system 250 configured
to
transport production fluid flowing in the heel direction so as to allow
production and
recovery of the production fluid at surface. It should be understood that the
production fluid recovery system 250 is configured to connect each adjacent
sub
to effectively transport production fluid produced from the reservoir (R) via
the
corresponding production channel 202 and production fluid passageways 110. In
some implementations, the production fluid recovery system 250 includes
production conduits 252 fluidly connecting each corresponding pair of adjacent
subs for transporting production fluid therebetween.
[0080] In the present implementation, the production conduits 252 extend
between
the subs of the single-well assembly 10 in a manner such as a first production
conduit 254 extends between a corresponding production sub 200 and a first
adjacent injection sub 100, and a second production conduit 256 extends
between
the production sub 200 and a second adjacent injection sub 100. It should be
understood that the first and second adjacent injection subs mentioned above
correspond to the injection subs located on either side of a corresponding
production sub 200. More specifically, the first production conduit 254 can be
coupled to the production fluid inlet 202A of the corresponding production sub
200
and a toe side of the production fluid passageway 110 of the first adjacent
injection
sub 100.
[0081] Furthermore, the second production conduit 256 can be coupled to the
production fluid outlet 202B of the production sub 200 and a heel side of the
production fluid passageway 110 of the second adjacent injection sub 100. In
some
implementations, the production conduits 252 can be coupled directly to the
corresponding subs for establishing fluid communication therebetween. However,
it is appreciated that the production fluid recovery system 250 can include
one or
more production coupling conduits 258 configured to couple production conduits
252 with a corresponding adjacent sub, or couple a pair of production conduits
252
to one another between the corresponding subs. Therefore, it should be
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understood that the production coupling conduits 258 can include production
fluid
passageways 259 for allowing the flow of production fluid therethrough. It is
noted
that the first and/or second production conduits 254, 256 can be made of
multiple
production conduits 252 coupled to one another via production coupling
conduits
258 for transporting production fluid between the subs of the assembly 10. It
is
appreciated that various configurations of the production conduits 252 (with
or
without production coupling conduits) are possible for connecting two adjacent
subs together.
[0082] As illustrated in Figures 1 to 20, and as mentioned above, the single-
well
assembly 10 is configured in a manner to have the injection conduits 152
extend
within the production conduits 252 along the horizontal wellbore section 14.
More
specifically, in the present implementation, the first injection conduit 154
extends
within the second production conduit 256, and the second injection conduit 156
extends within the first production conduit 254. Therefore, the production
fluid can
flow along the single-well assembly 10 in an annulus defined between the
injection
and production conduits 152, 252. In some implementations, the injection fluid
is
heated prior to being injected into the reservoir, as such the injection
conduits 152
can be provided with an insulated layer to mitigate heat exchange and/or heat
loss
with the surrounding environment. Additionally, the injection conduits 152 can
be
concentrically positioned within the corresponding production conduit 252,
although other configurations are possible. In some implementations, the
injection
fluid supply system 150 includes one or more stabilizing conduits 160 (Figure
2A)
to effectively stabilize the injection conduits 152 within the corresponding
production conduits 252. In other words, the stabilizing conduit 160 is
configured
to set the position of the injection conduit 152 it is connected to within the
surrounding production conduit 252. Therefore, in the illustrated
implementation,
the stabilizing conduit 160 is configured to set the injection conduit 152
concentrically within the corresponding production conduit 252. The
stabilizing
conduit 160 can be coupled between adjacent injection conduits 152 and/or
between an injection conduit 152 and an adjacent sub. As such, it should be
CA 3022711 2018-10-31
18
understood that the stabilizing conduit 160 can function as an injection
coupling
conduit 158.
[0083] With reference to Figures 5A and 5B, and with continued reference to
Figure 2, the stabilizing conduit 160 includes an injection fluid passageway
161 for
allowing the flow of injection fluid therethrough. Additionally, the
stabilizing conduit
160 includes one or more stabilizers, or stabilizing elements 162, configured
to set
the stabilizing conduit 160 and the components coupled therewith
concentrically
within the corresponding production conduit 252. In some implementations, the
stabilizing elements 162 include stabilizing fins 163 extending outwardly and
radially from an outer surface of the stabilizing conduit 160 for engaging an
inner
surface of the surrounding production conduit 252. The stabilizing conduit 160
can
include multiple stabilizing fins 163 positioned at regular intervals about
the
stabilizing conduit 160, although it is appreciated that other configurations
are
possible. For example, and as illustrated in the implementation of Figure 5A,
the
stabilizing conduit 160 can include three or more stabilizing fins 163 spaced
by
about 120 degrees or less around the injection fluid passageway 161. In some
implementations, the stabilizing fins 163 can have a substantially trapezoidal
shape so as to define an elongated contact surface with the inner surface of
the
surrounding production conduit 252. However, it is appreciated that the
stabilizing
fins 163 can have any suitable number, shape and/or size configured to engage
the inner surface in any suitable manner.
[0084] In an alternative implementation, another stabilizing structure can be
used,
such as a stabilizing ring for example, having stabilizing fins 163 extending
therefrom. The stabilizing ring can be configured to be connected about a
corresponding injection conduit 152 in a manner such that the stabilizing fins
163
extend and engage the inner surface of the surrounding production conduit 252,
while allowing production fluid to flow along the conduits, between the
stabilizing
fins 163.
CA 3022711 2018-10-31
19
[0085] Referring to Figures 1 and 6, well completion of the single wellbore 12
can
include a liner 18 extending along an inner surface of the horizontal wellbore
section 14. The liner 18 can extend along the full length of the horizontal
wellbore
section 14 (i.e., from heel 16 to toe 15) or along one or more sections
thereof. The
subs and conduits of the single-well assembly 10 are therefore adapted to be
installed within the liner 18, in a generally concentric manner, although
other
configurations are possible. It is appreciated that the liner 18 can be
slotted or
include other types of apertures along a length thereof for allowing injection
and/or
production fluids to flow into and from the reservoir. In some
implementations, the
liner 18 is spaced from the production conduits 252 and/or subs 100, 200
extending
therein so as to define an annular region (A) therebetween in which injection
and/or
production fluids can flow prior to being injected in the reservoir or
recovered at
surface. More specifically, injection fluid can be injected into the annular
region via
the injection port 104 prior to infiltrating the reservoir through the liner
18, while
production fluid can infiltrate the annular region from the reservoir prior to
being
recovered via the production port 204. It should thus be appreciated that the
single-
well assembly 10 can be configured to create three independent flow paths for
transporting fluids along the horizontal wellbore section 14. A first flow
path (F1) is
defined within the injection conduits 152, a second flow path (F2) is defined
in the
annulus between the injection and production conduits 152, 252, and a third
flow
path (F3) is defined in the annular region (A) between the production conduits
252
and the liner 18 or inner surface of the horizontal wellbore section 14.
[0086] With reference to Figure 7, and with continued reference to Figure 6,
the
single-well assembly 10 can include annular sealing elements 20 configured for
effectively sealing the annular region (A) described above along a section of
the
single-well assembly 10. In the present implementation, the annular sealing
element 20 extends radially and outwardly from a corresponding production
conduit 252 and engages the inner surface of the horizontal wellbore section
14
(e.g., the liner 18). Furthermore, each annular sealing element 20 extends
along a
section of a corresponding production conduit 252 extending between two
adjacent
subs. Therefore, the annular sealing element 20 can define corresponding
injection
CA 3022711 2018-10-31
20
22 and production 24 sections on either side thereof. More specifically, a
pair of
annular sealing elements 20 provided about production conduits 252 extending
on
either side of an injection sub 100 defines an injection section 22
therebetween.
As such, a pair of annular sealing elements 20 provided about production
conduits
252 extending on either side of a production sub 200 defines a production
section
24 therebetween. It should be understood that, as used herein, the injection
section
22 refers to the section of the single-well assembly 10 along which injection
fluid
is injected into the reservoir (R). Similarly, the production section 24
refers to the
section of the single-well assembly 10 along which production fluid is
recovered
from the reservoir (R). Furthermore, it should be noted that two or more
sealing
elements can be provided in series between injection and/or production subs.
[0087] In the present implementation, injection fluid is injected within the
annular
region (A) in the injection section 22 via the injection sub 100, prior to
infiltrating
into the reservoir (R). In a similar fashion, production fluid infiltrates the
annular
region (A) in the production section 24 prior to being recovered via the
production
port 204 and production fluid recovery system. It should be noted that each
annular
sealing element 20 effectively prevents fluid communication between injection
and
production fluids within a corresponding annular region (A) (i.e., along the
third flow
path (F3)). Additionally, and as best seen in Figure 7, the annular sealing
element
20 can include at least one tubular fluid passage 21 extending therethrough
for
allowing fluids to flow from one side of the annular sealing element 20 to the
other.
In the present implementation, the annular sealing element 20 includes a
plurality
of tubular fluid passages 21 provided about the production conduit 252 and
extending axially across the annular sealing element 20, allowing fluids to
flow from
the injection section 22 to the production section 24, or vice-versa. It will
be
understood that the direction of the flow substantially depends on the
pressure
differential between the sections 22, 24 defined on either side of the annular
sealing element 20. In some implementations, the tubular fluid passages 21 can
be provided with a control valve to control fluid flowing from one side to the
other
in response to the pressure differential therebetween. The control valve can
be
configured to selectively open or close the tubing to avoid pressure build-ups
within
CA 3022711 2018-10-31
21
the single-well assembly 10 for example. It should be noted that other uses
and
configurations of the tubular fluid passages are possible, such as the ones
described in Applicant's co-pending application titled PACKING MODULE AND
RELATED METHODS FOR RECOVERING HYDROCARBONS VIA A SINGLE
WELL D, filed on October 31st, 2018.
[0088] Referring back to exemplary implementations of Figures 3A and 3B, in
addition to Figure 6, in some implementations, the injection port 104 includes
one
or more injection pipes 106 extending between the reservoir and the injection
channel 102 to establish fluid communication therebetween. More specifically,
the
injection pipes 106 are adapted to establish fluid communication between the
injection channel 102 and the annular region (A) surrounding the injection sub
100
and within the corresponding injection section 22. In the illustrated
implementation,
the injection pipes 106 include a main injection pipe 107 outwardly and
radially
extending from the injection channel 102 and one or more secondary injection
pipes 108 extending from the main injection pipe 107 and communicating with
the
annular region (A) to allow injection of injection fluid therein and
ultimately within
the reservoir (R). The secondary injection pipes 108 are adapted to inject
injection
fluid within the annular region (A) at an angle with respect to the horizontal
wellbore
section 14, and thus with respect to the liner 18.
[0089] In some implementations, the injection fluid is injected within the
annular
region under pressure, therefore the injection is done at an angle to prevent
and/or
reduce potential damage done to surrounding components, such as the
aforementioned liner 18 surrounding the injection sub 100. It should be
understood
that the main injection pipe 107 can also be adapted to inject injection fluid
within
the annular region, although in order to prevent injection fluids to flow
directly on
the liner 18, which can cause damages, the main injection pipe 107 is blocked
and/or plugged to prevent any injection of fluids within the annular region.
It should
be understood that the main injection pipe 107 initially extends between the
injection channel 102 and the annular region (A) simply to facilitate
manufacturing
thereof. Once formed within the injection sub 100, the main injection pipe 107
is
CA 3022711 2018-10-31
22
plugged, as previously mentioned, to direct the flow of injection fluid from
the
injection channel 102 into the secondary injection pipes 108. However, it is
appreciated that the main injection pipe 107 can remain open, thus providing
an
injection pipe 106 providing a radial flow within the reservoir.
[0090] In some implementations, the injection sub 100 includes multiple
injection
ports 104 in order to increase injection rate of the injection fluid. In the
present
implementation, each injection sub 100 includes three injection ports 104,
each
having a main injection pipe 107 extending from the injection channel 102. The
main injection pipes 107 can be provided at regular intervals about the
injection
channel 102 (e.g., spaced by about 120 degrees around the injection channel
102),
although it is appreciated that other configurations are possible.
[0091] In the present implementation, the injection pipes 106 include a
plurality of
secondary injection pipes 108 provided about the main injection pipe 107 and
extending outwardly therefrom. The secondary injection pipes 108 can be
provided
at regular intervals about the main injection pipe 107, although it is
appreciated
that other configurations are possible. In some implementations, each
secondary
injection pipe 108 can include an inlet section 112 and an outlet section 114
axially
aligned along a length thereof between the main injection pipe 107 and the
annular
region (A). The inlet and outlet sections 112, 114 can have a cross-sectional
area
which differs from the other in order to create a pressure differential during
injection
of injection fluid. In other words, the cross-sectional area of the inlet
section 112
can be smaller than the cross-sectional area of the outlet section 114, or
vice-
versa. In the present implementation, the cross-sectional area of the
secondary
injection pipes 108 is smaller along the inlet section 112 than along the
outlet
section 114. Therefore, pressure along the outlet section 114 is lower than
the
pressure along the inlet section 112 which can cause the injection fluid to
evaporate at least partially into gaseous state (e.g., flash-evaporation) so
as to
facilitate infiltration within the reservoir and bitumen mobilization. In some
implementations, the injection port 104 can be provided with nozzle inserts
120
CA 3022711 2018-10-31
23
connected within the secondary injection pipes 108 to further increase the
pressure
differentiation between the inlet and outlet sections 112, 114.
[0092] With reference to Figures 8A and BB, and with continued reference to
Figure 313, various implementations of the nozzle insert 120 are shown. The
nozzle
inserts 120 can have a substantially cylindrical insert body 121 configured to
be
inserted within the secondary injection pipes 108 in order to at least
partially restrict
the flow of fluids therethrough. More specifically, the insert body 121 can
include a
threaded section 122 complementary to a threaded section located within the
secondary injection pipes 108, allowing the nozzle inserts 120 to be fastened
within
the corresponding pipes 108. However, it is appreciated that other methods of
connecting the nozzle inserts 120 within the secondary injection pipes 108 are
possible. For example, the nozzle inserts 120 can be inserted in the
corresponding
pipe via compression or interference fit, or can be machined as one piece from
the
same base material.
[0093] In some implementations, each nozzle insert 120 includes an inner
channel
124 extending between an inner channel inlet 125 and an inner channel outlet
126
for allowing injection fluid to flow therethrough and into the reservoir. As
seen in
the implementation of Figure 8A, the inner channel outlet 126 can be shaped
and
sized to allow insertion of a tool or tool head which can be used to screw the
insert
nozzle 120 within the secondary injection pipe 108. In the present
implementation,
the inner channel outlet 126 has a substantially hexagonal shape adapted to
receive hexagonally shaped tools such as hexagonal keys or specialized
screwdrivers for example. It is appreciated that the hexagonal opening can
have
any suitable length along the insert nozzle 120. For example, the insert
nozzle 120
can simply have a hexagonal-shaped outer-flange proximate the channel outlet
126 for allowing removal, installation and/or replacement of the insert nozzle
120
using a socket-type tool.
[0094] In addition, the inner channel 124 can be configured to create a
pressure
differential as the injection fluid flows through the nozzle insert 120. More
CA 3022711 2018-10-31
24
specifically, the inner channel inlet 125 can have a smaller cross-sectional
area
than that of the inner channel outlet 126, causing a pressure-drop through the
nozzle insert 120. Therefore, the pressure differential caused by the nozzle
inserts
120 can contribute in flashing the injection fluid in order to facilitate
infiltration into
the reservoir. It is appreciated that the inner channel inlet and outlet 125,
126 can
respectively have a substantially fixed cross-sectional area (Figure 8A) or
have a
varying (e.g., tapered) cross-sectional area (Figure 8B). In some
implementations,
the nozzle inserts 120 are made from hardened steel or carbide tungsten for
example to withstand the high pressures as injection fluid flows therethrough.
It
should be readily understood that the nozzle inserts 120 can be throttling
valves
configured to reduce the pressure as the injection fluid is injected into the
reservoir
from the injection port 104.
[0095] Referring back to exemplary implementations of Figures 4A and 4B, in
addition to Figure 6, in some implementations, the production port 204
includes a
production pipe 206 extending between the reservoir and the production channel
202 in order to establish fluid communication therebetween. More specifically,
the
production pipe 206 is configured to establish fluid communication between the
annular region (A) surrounding the production sub 200 (i.e., within the
production
section 24) and the production channel 202. In the illustrated implementation,
the
production pipe 206 extends along a length between an inlet 208 and an outlet
209, with the inlet 208 communicating with the annular region (A) and the
outlet
209 communicating with the production fluid inlet 202A of the production sub
200.
The cross-sectional area of the production pipe 206 can vary between the inlet
208
and outlet 209 thereof in order to create a pressure differential during
recovery of
production fluids. In the present embodiment, the cross-sectional area of the
production pipe 206 proximate the inlet 208 is greater than that proximate the
outlet
209. In some implementations, and as illustrated in Figure 4B, the production
pipe
206 can be angled with respect to the horizontal wellbore section 14 in order
to
facilitate entry of production fluids in the inlet 208 of the production pipe
206.
However, the angled production pipe 206 can cause production fluids to exit
the
outlet 209 and flow directly towards the injection conduit connected to the
CA 3022711 2018-10-31
25
production fluid inlet 202A of the production sub 200. When pressurized, or
when
containing elements such as sand, dirt or rocks, the production fluid flowing
onto
the injection conduit 152 can increase wear and/or cause damages thereto.
[0096] In some implementations, and with reference to Figures 9A and 9B, in
addition to Figure 4B, it is appreciated that the production pipe 206 can be
substantially parallel to the horizontal wellbore section, and thus to the
conduits of
the single-well assembly 10. Therefore, the flow of production fluids exiting
the
outlet 209 is directed within the production conduit 252 away from the
injection
conduit 152, thus reducing and/or preventing damages. It is thus appreciated
that,
in the present implementation, the inlet 208 includes a recess 208A extending
into
the production sub 200 to allow communication with the production pipe 206. In
some implementations, the production port 204 can further include a port
insert
218 insertable within the production pipe 206 along a section thereof to
increase
the pressure differential created between the inlet 208 and outlet 209. In the
present implementation, the port insert 218 includes a converging-diverging
nozzle
for creating the pressure differential. However, it is appreciated that other
mechanisms and/or methods are possible for creating a variation in pressure
along
the production pipe 206. In the present implementation, the port insert 218 is
introduced within the production pipe 206 mechanically via press-fit
connection,
although other methods of connection are possible. Furthermore, in some
implementations, the production sub 200 can include multiple production ports
204, and thus more than one production pipe 206 extending therethrough,
effectively increasing overall production rate of production fluids. Each
production
sub 200 can include three production ports 204 for example, provided at
regular
intervals around the injection fluid passageway 210. However, it is
appreciated that
other configurations are possible.
[0097] In some implementations, the production sub 200 includes a single
injection
fluid passageway 210 and a plurality of production channels 202 provided about
the injection fluid passageway 210 for increasing the flow of production fluid
flowing
through the production sub 200. The production channels 202 can be provided at
CA 3022711 2018-10-31
26
regular intervals around the injection fluid passageway 210, or arranged in
groups
as illustrated in Figures 4A and 9A. The groups of production channels 202 are
illustratively spaced from one another to allow the production pipe(s) 206 to
extend
therebetween so as to establish fluid communication between the production
channels 202 and the annular region (A). It is appreciated that the production
channels 202 can have any suitable shape, size and/or configuration extending
through the injection sub 100. It should be understood from the description
above
that the production channels 202 of each production sub 200 are in fluid
communication with the production fluid passageways 110 of each injection sub
100, and that the injection channel 102 of each injection sub 100 is in fluid
communication with the injection fluid passageway of each production sub 200.
[0098] It will be understood from the foregoing disclosure that various
implementations of a single-well assembly adapted to enable both injection and
production phases of bitumen recovery operations is provided. The single-well
assembly is configured to create three independent flow paths therealong, with
any
two of said flow paths being able to communicate. Therefore, the single-well
assembly advantageously allows for greater flow areas within a single well
installation while allowing multiple flow paths which can be made to
communicate
with one another.
CA 3022711 2018-10-31
