Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
PACKING ASSEMBLY AND RELATED METHODS FOR RECOVERING
HYDROCARBONS VIA A SINGLE WELL
TECHNICAL FIELD
[001] The technical field generally relates to equipment for recovering
hydrocarbons via
a single well completion, and more particularly to a semi-permeable packing
assembly
and elements thereof, including a gas-limiting device preventing gas axial
fluid
communication between sections of the single well through the packing
assembly.
BACKGROUND
[001] According to single-well steam-assisted gravity-drainage (SW-SAG D)
techniques, an injection conduit and a production conduit can be located
within a single
well to simplify and downsize equipment compared to conventional SAGD that
employs
a vertically spaced-apart well pair. 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 to the production conduit can present challenges, such as
the risk of
undesirable production of the injected vapour-phase mobilizing fluid via the
production
conduit.
[002] There is thus a need for a technology that overcomes at least some of
the
drawbacks of what is known in the field.
SUMMARY
[002] In one aspect, there is provided packing assembly operable in a single
wellbore
in which an injection conduit extends within a production conduit along an
axial direction
for recovering mobilized hydrocarbons from a hydrocarbon-containing reservoir
via a
mobilizing fluid, the packing assembly comprising: an annular sealing element
engaged
in an annular space defined between an outer surface of the production conduit
and an
inner surface of the single wellbore, the sealing element axially separating
an injection
section of the annular space from a production section of said annular space,
the
mobilizing fluid being provided to the hydrocarbon-containing reservoir via
the injection
section and the mobilized hydrocarbons being produced via the production
section; and
at least one tubular fluid passage axially extending across the sealing
element, the at
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least one fluid passage being configured to allow condensed mobilizing fluid
to flow from
the injection section to the production section in response to an axial
pressure
differential therebetween.
[003] In some implementations, the injection conduit can be concentric with
respect to
the production conduit.
[004] In some implementations, the at least one tubular fluid passage can
include a
plurality of tubular fluid passages. The packing assembly can include from 1
to 30
tubular fluid passages. The plurality of tubular fluid passages can be
distributed radially
with respect to the production conduit and are evenly spaced apart from one
another.
The tubular fluid passages can include pairs of the fluid passages which are
symmetrical
about the axial direction.
[005] In some implementations, the tubular fluid passages can include at least
three
fluid passages being interconnected to enable the condensed mobilizing fluid
to flow
from one fluid passage to another fluid passage before being released into the
production section.
[006] In some implementations, the at least one tubular fluid passage can
extend
across an intermediate part of the sealing element spaced away from both the
inner
wellbore surface and the outer production conduit surface. Optionally, a cross-
section of
the tubular fluid passage in a direction perpendicular to the axial direction
can be of
circular, elliptical, trapezoidal, rectangular or star shape.
[007] In some implementations, the at least one tubular fluid passage can be
defined
by a tube. The tube can have variable inner cross-sectional dimensions along
the axial
direction. The tube can also have an upstream portion in fluid communication
with the
injection section, a downstream portion in fluid communication with the
production
section, and a restriction joining the upstream portion and the downstream
portion, the
restriction being sized to provide a pressure drop sufficient to condense a
portion of the
mobilizing fluid into the condensed mobilizing fluid upon flowing down the
tubular fluid
passage into the production section.
[008] In some implementations, the downstream portion of each tubular fluid
passage
can have a cross-sectional diameter which is greater than the upstream portion
at a
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defined ratio. The cross-sectional diameter of the upstream portion of each
tubular fluid
passage can be between 1.5 and 4 times smaller than the cross-sectional
diameter of
the downstream portion.
[009] In some implementations, the tube can include a valve which is actuable
to open
or close the fluid passage in accordance with an injection pressure in the
injection
section.
[010] In some implementations, the tube can be linear or curvilinear. The tube
can
have an inner cross-sectional diameter between 0.5 and 30 mm. The tube can
also have
a length between 20 mm and 1000 mm.
[011] In some implementations, the annular sealing element can be an
expandable
element which expands in response to a stimuli to seal the annular space which
axially
separates the injection section from the production section. Optionally, the
stimuli can
include swelling conditions, axial compression, pressure in the injection
conduit or a
combination thereof.
[012] In some implementations, the expandable element can be a swellable
element
comprising an elastomeric material which swells in the presence of
hydrocarbons and/or
water.
[013] In some implementations, the expandable element can be a flexible sleeve
having at least a portion which outwardly deflects to seal the annular space
upon being
pressurized by the mobilizing fluid flowing in the injection conduit.
[014] In some implementations, the annular sealing element can include a
sealing
mechanism which is a hydraulic, mechanical or interference setting mechanism.
[015] In some implementations, the annular sealing element is a single or
multiple-cup
sealing element.
[016] In some implementations, the packing assembly can further include a gas-
limiting
intake operatively connected to an inlet region of the at least one tubular
fluid passage,
the gas-limiting intake impeding gas flow upstream of the at least one tubular
fluid
= passage to prevent uncondensed mobilizing fluid from flowing to the
production section.
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[017] In some implementations, the gas-limiting intake can include at least
one inlet
port positioned at a bottom area of the injection section of the annular space
where
condensed mobilizing fluid accumulates; and an annular 'Chamber surrounding
the
production conduit and positioned in the injection section of the annular
space, the
annular chamber receiving the condensed mobilizing fluid via the at least one
inlet port,
and the annular liquid chamber being in fluid communication with the inlet
region of the
at least one tubular fluid passage to further communicate the condensed
mobilizing fluid
from the annular chamber to the at least one tubular fluid passage in response
to the
axial pressure differential.
[018] In some implementations, the gas-limiting intake can be rotatable with
respect to
the production conduit to position the at least one inlet port in the bottom
area of the
injection section. Optionally, at least a portion of a wall of the annular
chamber can
include a weighted portion, and the at least one inlet port can be located on
or adjacent
to the weighted portion, the weighted portion being configured to cause
rotation of the
gas-limiting intake so that the at least one inlet port is positioned at the
bottom area of
the injection section.
[019] In some implementations, the annular chamber can fully occupy the
annular
space adjacent to the annular sealing element. Optionally, the annular chamber
can be
mounted to the annular sealing element.
[020] In some implementations, the at least one inlet port can include an
aperture; or
the at least one inlet port can include a nozzle, a choke, a valve, an
Inflow/Flow Control
Device (ICDs/FCDs), or an Autonomous Inflow Control Devices (AICDs) limiting
or
preventing gas inflow.
[021] In some implementations, the gas-limiting intake can further include a
floating
valve located within the annular chamber, the floating valve being movable,
under the
action of buoyancy, between:
[022] a closed position in which the floating valve impedes fluid flow via the
at least one
inlet port, when the condensed mobilizing fluid is absent from the annular
chamber; and
[023] an open position in which the floating valve is lifted away from the at
least one
inlet port, when the condensed mobilizing fluid accumulates in the annular
chamber,
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thereby allowing the condensed mobilizing fluid to flow into at least one
tubular fluid
passage.
[024] In some implementations, the at least one inlet port can be a plurality
of inlet ports,
and the gas-limiting intake can include a plurality of floating valves, each
floating valve
cooperating with a corresponding one of the inlet ports of the annular
chamber.
[025] In some implementations, the mobilizing fluid includes steam, an organic
solvent,
a surfactant or a combination thereof. The mobilizing fluid can include or
consist
essentially of the organic solvent that is a Cl -05 alkane solvent.
Optionally, the alkane
solvent can include propane, butane or a mixture thereof. The mobilizing fluid
can be
steam, or the mobilizing fluid can be a mixture of steam and ammonia.
[026] In another aspect, there is provided a packing assembly operable in a
single
wellbore in which an injection conduit and a production conduit extend along
an axial
direction for recovering mobilized hydrocarbons from a hydrocarbon-containing
reservoir
via a mobilizing fluid, the packing assembly comprising: a sealing element
axially
separating an injection section of the wellbore from a production section of
the wellbore
and providing a seal therebetween, the mobilizing fluid being provided to the
hydrocarbon-
containing reservoir via the injection section and the mobilized hydrocarbons
being
produced via the production section; and at least one fluid passage having an
inlet in fluid
communication with the injection section and an outlet in fluid communication
with the
production section, to allow a portion of the mobilizing fluid to flow from
the injection
section into the production section in response to an axial pressure
differential
therebetween.
[027] In some implementations, the packing assembly can further include a gas-
limiting
intake positioned in the injection section and impeding gas flow upstream of
the at least
one fluid passage to prevent uncondensed mobilizing fluid from flowing to the
production
section.
[028] In some implementations, the gas-limiting intake can include at least
one inlet port
positioned at a bottom area of the injection section where liquid accumulates,
the liquid
comprising condensed mobilizing fluid; and a chamber positioned in the
injection section
to receive the liquid via the at least one inlet port, the chamber being in
fluid
communication with an inlet region of the at least one fluid passage to
further communicate
Date Recue/Date Received 2021-04-21
the liquid from the chamber to the at least one fluid passage in response to
the axial
pressure differential.
[029] In some implementations, the injection conduit can extend within the
production
conduit and the gas-limiting intake can be rotatable with respect to the
production conduit
to position the at least one inlet port in the bottom area of the injection
section. Optionally,
at least a portion of a wall of the chamber can include a weighted portion,
and the at least
one inlet port is located on or adjacent to the weighted portion, the weighted
portion being
configured to cause rotation of the gas-limiting intake so that the at least
one inlet port is
positioned at the bottom area of the injection section.
[030] In some implementations, the chamber can be an annular chamber
surrounding
the production conduit. Optionally, the annular chamber can fully occupy an
annular space
between the production conduit and inner walls of the single wellbore. Further
optionally,
the chamber can be mounted to the sealing element.
[031] In some implementations, the at least one inlet port can include an
aperture; or the
at least one inlet port can include a nozzle, a choke, a valve, an Inflow/Flow
Control Device
(ICDs/FCDs), or an Autonomous Inflow Control Devices (AICDs) limiting or
preventing gas
inflow.
[032] In some implementations, the gas-limiting intake can further include a
floating valve
located within the chamber, the floating valve being movable, under the action
of
buoyancy, between:
[033] a closed position in which the floating valve impedes fluid flow via the
at least one
inlet port, when liquid is absent from the chamber; and
[034] an open position in which the floating valve is lifted away from the at
least one inlet
port, when liquid accumulates in the chamber, thereby allowing the condensed
mobilizing
fluid to flow into the at least one fluid passage.
[035] In some implementations, the at least one fluid passage can be at least
one tubular
fluid passage being defined either by a tube or by the sealing element.
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[036] In some implementations, the at least one fluid passage can be an
annular fluid
passage defined between the sealing element and an inner surface of the single
wellbore,
the annular fluid passage being created upon unsealing the sealing element
from the inner
surface of the single wellbore.
[037] In some implementations, the sealing element can be a flexible single or
multiple-
cup sealing element which includes at least one notch or channel which defines
the at
least one tubular fluid passage.
[038] In some implementations, the sealing element can be an expandable
element
having at least a portion which outwardly deflects to seal the annular space
upon being
pressurized by the mobilizing fluid flowing in the injection conduit.
[039] In some implementations, the sealing element can be a flexible single or
multiple-
cup sealing element which, when unsealed from the inner surface of the single
wellbore
in response to the axial pressure differential, defines the annular fluid
passage.
[040] In some implementations, the at least one tubular fluid passage can be
configured
to favor condensed mobilizing fluid flowing down the tubular fluid passage
from the
injection section into the production section.
[041] In some implementations, a cross-section of the tubular fluid passage in
a direction
perpendicular to the axial direction can be of circular, elliptical,
trapezoidal, rectangular or
star shape. Optionally, the tubular fluid passage can have cross-sectional
dimensions
which vary along the axial direction.
[042] In some implementations, the at least one tubular fluid passage can have
an
upstream portion in fluid communication with the injection section, a
downstream portion
in fluid communication with the production section, and a restriction joining
the upstream
portion and the downstream, portion, the restriction being sized to provide a
pressure drop
sufficient to induce vapour to liquid phase transition of the portion of the
mobilizing fluid
upon flowing down the tubular fluid passage into the production section.
[043] In some implementations, the downstream portion of the at least one
tubular fluid
passage has a cross-sectional diameter which is greater than the upstream
portion at a
defined ratio. Optionally, the cross-sectional diameter of the upstream
portion of the at
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least one tubular fluid passage can be between 1.5 and 4 times smaller than
the cross-
sectional diameter of the downstream portion.
[044] In some implementations, the at least one tubular fluid passage can be
defined
by a tube. The tube can extend along the axial direction of the wellbore and
across the
sealing element. The tube can extend across an intermediate part of the
sealing element
spaced away from both the inner wellbore surface and the outer production
conduit
=
surface.
[045] In some implementations, the tube can be linear or curvilinear. The tube
can
have an inner cross-sectional diameter between 0.5 mm and 30 mm. The tube can
have
a length between 20 mm and 1000 mm.
[046] In some implementations, the tube can have a central portion extending
along
the axial direction of the wellbore and bypassing the sealing element.
Optionally, the
tube can have an inlet portion and an outlet portion extending radially with
respect to the
wellbore, the central portion joining the inlet portion to the outlet portion.
[047] In some implementations, the tube can include a valve which is actuable
to open
or close the tubular fluid passage in accordance with an injection pressure in
the
injection section.
[048] In some implementations, the at least one tubular fluid passage
comprises a
plurality of tubular fluid passages distributed radially within the single
wellbore. The
tubular fluid passages can be evenly spaced apart from one another.
Optionally, pairs of
fluid passages can be symmetric about the axial direction.
[049] In some implementations, the tubular fluid passages can include at least
three
tubular fluid passages being interconnected to enable the portion of the
mobilizing fluid
to flow from one tubular fluid passage to another tubular fluid passage before
being
released into the production section.
[050] In some implementations, the sealing element can be an expandable
element
which expands in response to a stimuli to seal the annular space which axially
separates
the injection section from the production section, the stimuli comprising
swelling
= conditions, axial compression, pressure in the injection conduit or a
combination thereof.
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Optionally, the expandable element can be a swellable element comprising an
elastomeric material which swells in presence of hydrocarbons and/or water.
[051] In some implementations, the expandable element can be a flexible sleeve
having at least a portion which outwardly deflects to seal the annular space
upon being
pressurized by the mobilizing fluid flowing in the injection conduit.
[052] In some implementations, the annular sealing element can include a
sealing
mechanism which is a hydraulic, mechanical or interference setting mechanism.
[053] In some implementations, the injection conduit can extend within the
production
conduit along the axial direction. Optionally, the injection conduit can be
concentric with
respect to the production conduit.
[054] In some implementations, the mobilizing fluid can include steam, an
organic
solvent, a surfactant or a combination thereof. The mobilizing fluid can
include or consist
essentially of the organic solvent that is a Cl-05 alkane solvent. The alkane
solvent can
include propane, butane or a mixture thereof. The mobilizing fluid can be
steam or the
mobilizing fluid can be a mixture of steam and ammonia.
[055] In some implementations, the packing assembly can include a gas-limiting
discharge positioned in the production section and impeding gas flow
downstream of the
at least one fluid passage to prevent uncondensed mobilizing fluid from
flowing to the
production section. Optionally, the gas-limiting discharge can include:
[056] a discharge chamber in fluid communication with an outlet region of the
at least
one fluid passage and receiving liquid flowing via the at least one fluid
passage towards
the production section, the liquid comprising condensed mobilizing fluid;
[057] at least one outlet port configured to discharge the liquid contained in
the
discharge chamber into the production section in response to the axial
pressure
differential.
[058] In some implementations, the injection conduit can extend within the
production
conduit and the gas-limiting discharge can be rotatable with respect to the
production
conduit to position the at least one outlet port in a bottom area of the
production section.
Optionally, at least a portion of a wall of the discharge chamber can be a
weighted
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portion, and the at least one outlet port can be located on the weighted
portion to rotate
the at least one outlet port towards the bottom area of the production section
under the
action of the weighted portion.
[059] In some implementations, the discharge chamber' can be an annular
discharge
chamber surrounding the production conduit. Optionally, the annular discharge
chamber
can fully occupy an annular space between the production conduit and inner
walls of the
single wellbore.
[060] In some implementations, the discharge chamber can be mounted to the
sealing
element.
[061] In some implementations, the at least one outlet port can include a
nozzle, a
choke, a valve, an Inflow/Flow Control Device (ICDs/FCDs), or can include an
Autonomous Inflow Control Devices (AICDs) limiting or preventing gas inflow to
the
production section.
[062] In some implementations, the gas-limiting discharge can further include
a floating
valve located within the discharge chamber, the floating valve being movable,
under the
action of buoyancy, between:
=
[063] a closed position in which the floating valve impedes fluid flow via the
at least one
outlet port, when liquid is absent from the chamber; and
[064] an open position in which the floating valve is lifted away from the at
least one
outlet port, when liquid accumulates in the discharge chamber, thereby
allowing the
liquid to flow into the production section.
[065] In another aspect, there is provided a packing assembly operable in a
single
wellbore in which an injection conduit and a production conduit extend along
an axial
direction for recovering mobilized hydrocarbons from a hydrocarbon-containing
reservoir
via a mobilizing fluid, the packing assembly including:
[066] a sealing element axially separating an injection section of the
wellbore from a
production section of the wellbore and providing a seal therebetween, the
mobilizing fluid
being provided to the hydrocarbon-containing reservoir via the injection
section and the
mobilized hydrocarbons being produced via the production section;
CA 3060778 2019-10-31
[067] at least one fluid passage having an inlet in fluid communication with
the injection
section and an outlet in fluid communication with the production section, to
allow a
portion of the mobilizing fluid to flow from the injection section into the
production section
in response to an axial pressure differential therebetween; and
[068] a gas-limiting device operatively connected to the at least one fluid
passage and
configured to prevent uncondensed fluids from being communicated from the
injection
section to the production section via the at least one fluid passage.
[069] In some implementations, the gas-limiting device can be the gas-limiting
intake
as defined herein or the gas-limiting discharge as defined herein.
[070] In some implementations, the at least one fluid passage can be at least
one
tubular fluid passage being walled either by a tube or by the sealing element.
Optionally,
the at least one tubular fluid passage can be configured to favor condensed
mobilizing
fluid flowing down the tubular fluid passage from the injection section into
the production
section.
[071] In some implementations, the at least one fluid passage can be an
annular fluid
passage created when the sealing element is unsealed from an inner surface of
the
wellbore in response to the axial pressure differential.
[072] In another aspect, there is provided a system for producing hydrocarbons
from a
hydrocarbon-containing reservoir via a single wellbore extending through the
hydrocarbon-containing reservoir in an axial direction, the system comprising:
an injection conduit in fluid communication with an injection section of the
wellbore, the injection conduit axially extending within the wellbore to
conduct
and deliver a mobilizing fluid within the injection section;
a production conduit in fluid communication with a production section of the
wellbore, the production conduit axially extending within the wellbore to
receive
and produce mobilized fluids containing hydrocarbons back to surface; and
a packing assembly comprising:
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a sealing element axially separating the injection section from the
production section and providing a seal therebetween, and
at least one fluid passage having an inlet in fluid communication with the
injection section and an outlet in fluid communication with the production
section, allowing a portion of the mobilizing fluid to flow from the injection
section into the production section in response to an axial pressure
differential therebetween.
[073] In some implementations, the packing assembly can include at least one
of the
characteristics as defined herein.
[074] In some implementations, the packing assembly can further include a gas-
limiting
device operatively connected to the at least one fluid passage, the gas-
limiting device
being configured to prevent uncondensed mobilizing fluid from being
communicated from
the injection section to the production section via the packing assembly.
[075] In some implementations, the gas-limiting device can be the gas-limiting
intake as
defined herein or the gas-limiting discharge as defined herein.
[076] In some implementations, the at least one fluid passage can be at least
one tubular
fluid passage being walled either by a tube or by the sealing element.
[077] In some implementations, the at least one tubular fluid passage can be
configured
to favor condensed mobilizing fluid flowing down the tubular fluid passage
from the
injection section into the production section.
[078] In some implementations, the at least one fluid passage can be an
annular fluid
passage created when the sealing element is unsealed from an inner surface of
the
wellbore in response to the axial pressure differential.
[079] In some implementations, the injection conduit can include a tubular
injection line
having a diameter between 20 mm and 300 mm. The diameter of the tubular
injection line
can be between 50 mm and 150 mm. The production conduit can include a tubular
production line that has a diameter between 60 mm and 300 mm. The diameter of
the
tubular production line can be between 100 mm and 150 mm. A wellbore section
can have
a diameter between 100 mm and 300 mm.
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Date Recue/Date Received 2021-04-21
[080] In some implementations, the injection conduit can axially extend within
the
production conduit, the injection conduit being concentric with respect to the
production
conduit.
[081] In another aspect, there is provide a process for recovering
hydrocarbons from a
reservoir via a single wellbore comprising an injection section and an
adjacent production
section which are in fluid communication via at least one fluid passage, the
process
comprising:
discharging a pressurized mobilizing fluid into the injection section of the
wellbore
via at least one injection port, wherein a pressure differential between the
injection
port and the injection section induces liquid to vapour phase transition of at
least a
portion of the mobilizing fluid upon discharge thereof, the vapour phase of
the
mobilizing fluid flowing from the injection section into the reservoir to
mobilize the
hydrocarbons and form mobilized hydrocarbons;
applying an axial pressure differential between the injection section and the
production section of the wellbore to stimulate drainage of the mobilized
hydrocarbons into the production section and convey condensed mobilizing fluid
via the at least one fluid passage from the injection section into the
production
section in response to the axial pressure differential therebetween; and
producing a production fluid comprising the mobilized hydrocarbons and the
condensed mobilizing fluid via the production conduit.
[082] In some implementations, the mobilizing fluid can be pressurized between
2000
kPa and 17000 kPa at a temperature between 100 C and 350 C within the
injection
conduit.
[083] In some implementations, discharging the pressurized mobilizing fluid
can include
providing sonic choked flow upon discharge of the mobilizing fluid via the at
least one
injection port.
[084] In some implementations, the process can include regulating the axial
pressure
differential between the injection section and the production section by
selectively allowing
or preventing axial fluid communication via the at least one fluid passage
within the
wellbore between the injection section and the production section.
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[085] In some implementations, applying the axial pressure differential can
include
placing a sealing element in sealing engagement with an inner surface of the
wellbore to
axially separate the injection section from the adjacent production section.
[086] In some implementations, the at least one fluid passage can be an
annular fluid
passage, and the process includes unsealing the sealing element from an inner
surface
of the wellbore to form the annular fluid passage between the sealing element
and the
inner surface of the wellbore, thereby regulating the axial pressure
differential.
[087] In some implementations, the at least one fluid passage can be at least
one tubular
fluid passage defined either by a channel across and within the sealing
element or by a
tube.
[088] In some implementations, the at least one tubular fluid passage can be
defined by
the tube axially which extends across and within the sealing element.
[089] In some implementations, the at least one tubular fluid passage can be
defined by
the tube bypassing the sealing element, the tube having a circular,
elliptical, trapezoidal,
rectangular or star shaped inner cross-section.
[090] In some implementations, the process can include monitoring a pressure
into the
injection section and compare the pressure to an upper threshold value.
[091] In some implementations, the process can include limiting uncondensed
mobilizing
fluid flowing down the at least one fluid passage from the injection section
into the
production section.
[091a] In another aspect, there is provided a packing assembly operable in a
single
wellbore in which an injection conduit and a production conduit extend along
an axial
direction for recovering mobilized hydrocarbons from a hydrocarbon-containing
reservoir
via a mobilizing fluid, the packing assembly comprising:
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Date Recue/Date Received 2021-04-21
a sealing element axially separating an injection section of the wellbore
from a production section of the wellbore and providing a seal
therebetween, the mobilizing fluid being provided to the hydrocarbon-
containing reservoir via the injection section and the mobilized
hydrocarbons being produced via the production section;
at least one fluid passage having an inlet in fluid communication with the
injection section and an outlet in fluid communication with the production
section, to allow a portion of the mobilizing fluid to flow from the injection
section into the production section in response to an axial pressure
differential therebetween; and
a gas-limiting device operatively connected to the at least one fluid passage
and configured to prevent uncondensed fluids from being communicated
from the injection section to the production section via the at least one
fluid
passage.
[092] In some implementations, the process can include impeding an inlet
region of the
at least one fluid passage with a gas-limiting intake having an inlet
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Date Recue/Date Received 2021-04-21
port oriented towards a bottom area of the injection section where a liquid
pool
accumulates, the inlet port being in liquid communication with the injection
section.
[093] In some implementations, the process can include impeding an outlet
region of the
at least one fluid passage with a gas-limiting discharge having an outlet port
in liquid
communication with the production section.
[094] In some implementations, the injection conduit can extend concentrically
within the
production conduit.
[095] In another aspect, there is provided a packing assembly operable in a
single
wellbore in which an injection conduit extends within a production conduit
along an axial
direction for recovering mobilized hydrocarbon form a hydrocarbon-containing
reservoir
via a mobilizing fluid, the packing assembly comprising:
an inner injection tube in fluid communication with the injection conduit for
transmitting the mobilizing fluid into the reservoir;
an outer production tube concentric with the inner injection tube and defining
therebetween an annular space, the outer production tube being in fluid
communication with the production conduit;
at least one fluid channel in fluid communication with the inner injection
tube and
radially extending from the inner injection tube and through the outer
production
tube;
a flexible sleeve surrounding a portion of the outer production tube, the
flexible
sleeve having an intermediate section freely movable with respect to the outer
production tube and having distal ends attached to the outer production tube
to
define:
a fluid chamber in fluid communication with the at least one dluid channel
to receive the mobilizing fluid therein, and
at least one injection port in fluid communication with the fluid chamber to
deliver the mobilizing fluid into an injection section of the wellbore;
wherein the flexible sleeve is reversibly deformable between:
Date Recue/Date Received 2021-04-21
a sealing position in which an outer surface of the intermediate section is
in sealing contact with an inner surface of the wellbore to isolate the
injection section from an adjacent production section of the wellbore; and
an open position in which the intermediate section is spaced away from
the inner surface of the wellbore, thereby forming a fluid passage between
the inner surface of the wellbore and the flexible sleeve to allow a portion
of the mobilizing fluid to flow from the injection section into the production
section in response to an axial pressure differential therebetween.
[096] In some implementations, the packing assembly can include at least one
injection
port in fluid communication with the inner injection tube via the at least one
fluid channel,
an least one production port in fluid communication with the outer production
tube, or a
combination thereof.
[097] In some implementations, the flexible sleeve can be made of a material
comprising a metallic element. The flexible sleeve can be made of a material
comprising
Teflon TM, glass filled Teflon TM, an elastomeric material or a combination
thereof.
[098] In another aspect, there is provided a method for producing hydrocarbons
from a
hydrocarbon-containing reservoir via a single wellbore extending through the
hydrocarbon-containing reservoir in an axial direction, the wellbore
comprising an
injection section and an adjacent production section being isolated from one
another,
and the method comprising:
delivering a mobilizing fluid at an injection flow rate into the injection
section of
the wellbore, the mobilizing fluid flowing from the injection section into the
reservoir at an injection pressure to mobilize the hydrocarbons;
regulating an axial pressure differential between the injection section and
the
production section by selectively allowing or preventing axial fluid
communication
via at least one fluid passage within the wellbore between the injection
section
and the production section; and
producing the hydrocarbons from the reservoir from the production section of
the
wellbore at a production flow rate.
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CA 3060778 2019-10-31
[099] In some implementations, allowing axial fluid communication between the
.
injection section and the production section of the wellbore can include
conveying
condensed mobilizing fluid through the at least one fluid passage from the
injection
section into the production section of the wellbore.
[100] In some implementations, the process can include decreasing the
production
pressure within the production, section to activate the flow of condensed
mobilizing fluid
through the at least one fluid passage when the injection pressure within the
injection
section reaches an upper threshold value. Optionally, decreasing the
production
pressure within the production section can include increasing the production
flow rate.
[101] In some implementations, the process can include increasing the
production
pressure within the production section to deactivate the flow of condensed
mobilizing
fluid through the at least one fluid passage when the injection pressure
within the
injection section reaches a lower threshold value. Optionally, increasing the
production
pressure within the production section can include decreasing the production
flow rate.
[102] In some implementations, the process can include decreasing the
injection flow
rate when the injection pressure within the injection section reaches a
maximum
operating value.
[103] In some implementations, the process can include monitoring the
injection
pressure within the injection section.
[104] In some implementations, the process can include producing the condensed
mobilizing fluid conveyed from the injection section into the production
section.
[106] In some implementations, the process can include using a packing
assembly as
defined herein.
[106] In another aspect, there is provided a start-up method to stimulate
mobilization of
hydrocarbons in a reservoir via a single well completion, the method
comprising
alternating injection of a mobilizing fluid and production of mobilized fluids
over time,
wherein the injection of the mobilizing fluid is performed into discrete
injection sections
axially distributed along the single well completion, and wherein the
production of the
mobilized fluids is performed from discrete production sections which are
staggered with
respect to the injection sections and separated therefrom via respective
packing
17
CA 3060778 2019-10-31
assemblies allowing axial fluid communication between each adjacent pair of
production
and injection sections, each production section producing an emulsion of
mobilized
hydrocarbons from the reservoir and condensed mobilizing fluid from the
adjacent
injection sections.
[107] In some implementations, the method can include increasing a quantity of
the
mobilizing fluid to be injected at each injection section over time until
continuous
operation is achieved.
[108] In some implementations, the method can include simultaneously
performing
injection and production once the continuous operation is achieved.
[109] In some implementations, the injection of the mobilizing fluid can be
performed at
a temperature below saturation conditions to maintain the mobilizing fluid in
condensed
phase upon injection into the injection sections.
[110] In some implementations, the method can include monitoring a presence of
hydrocarbons in the mobilized fluids that flow via the production sections.
[111] In some implementations, the method can include healing the mobilizing
fluid in
correlation with the monitored hydrocarbons to gradually increase the
temperature of the
mobilizing fluid until initiating downhole boiling of the mobilizing fluid
upon injection.
[112] In some implementations, the method can include injecting a solvent or a
diluent
into the injection sections prior to injection of the mobilizing fluid, the
injected solvent or
diluent being left to soak to increase injectivity of the reservoir.
[113] In some implementations, the method can include heating the solvent or
diluent
prior to being supplied into the injection sections.
[114] In some implementations, the method can include the solvent ,or diluent
after
soaking.
[115] In another aspect, there is provided another start-up method to
stimulate
mobilization of hydrocarbons from a reservoir via a single well completion,
the method
comprising:
18
CA 3060778 2019-10-31
injecting a mobilizing fluid into discrete injection sections axially
distributed along
the single well completion, at a temperature below saturation conditions to
maintain the mobilizing fluid in condensed phase upon injection thereof; and
producing mobilized fluids from discrete production sections which are
staggered
with respect to the injection sections and separated therefrom via
corresponding
packing assemblies which allows axial fluid communication between
corresponding adjacent pairs of production and injection sections, each
production section producing an emulsion of mobilized hydrocarbons from the
reservoir and condensed mobilizing fluid from the adjacent injection section.
[116] In some implementations, the method can include alternating the
injection of the
mobilizing fluid and the production of the mobilized fluids in time.
[117] In some implementations, the method can include increasing a quantity of
the
mobilizing fluid to be injected at each injection section over time until
continuous
operation is achieved.
[118] In some implementations, the method can include comprising
simultaneously
performing injection and production once the continuous operation is achieved.
[119] In some implementations, the method can include monitoring a presence of
hydrocarbons in the mobilized fluids.
[120] In some implementations, the method can include heating the mobilizing
fluid in
accordance with the monitored hydrocarbons to gradually increase the
temperature of
the mobilizing fluid until initiating downhole boiling of the mobilizing fluid
upon injection.
[121] In some implementations, the method can include injecting a solvent or
diluent
into the injection sections prior to injection of the mobilizing fluid, the
injected solvent or
diluent being left to soak to increase injectivity of the reservoir.
[122] In some implementations, the method can include heating the solvent or
diluent
prior to being injected into the injection sections.
[123] In some implementations, the method can include producing the solvent or
diluent after soaking.
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CA 3060778 2019-10-31
[124] In another aspect, there is provided another start-up method to
stimulate
mobilization of hydrocarbons in a reservoir via a single well completion, the
method
comprising:
injecting a solvent or diluent via discrete injection sections axially
distributed
along the single well completion, the injected solvent or diluent being left
to soak
to increase injectivity of the reservoir; and
producing mobilized fluids from discrete production sections which are
staggered
with respect to the injection sections and separated therefrom via
corresponding
packing assemblies allowing axial fluid communication between pairs of
adjacent
production and injection sections, the mobilized fluids including the solvent
or
diluent and mobilized hydrocarbons.
[125] In some implementations, the method can include heating the solvent or
diluent
prior to being injected via the injection sections.
[126] In some implementations, the method can include injecting a mobilizing
fluid into
the discrete injection sections, and producing from each production section an
emulsion
of the mobilized hydrocarbons from the reservoir and mobilizing fluid from the
adjacent
injection sections.
[127] In some implementations, the method can include alternating injection of
the
mobilizing fluid and production of mobilized fluids over time.
[128] In some implementations, the method can include increasing a quantity of
the
mobilizing fluid to be injected at each injection section over time until
continuous
operation is achieved.
[129] In some implementations, the method can include simultaneously
performing
injection and production once the continuous operation is achieved.
= [130] In some implementations, the injection of the mobilizing fluid can
be performed at
a temperature below saturation conditions to maintain the mobilizing fluid in
condensed
phase upon injection into the injection sections.
7n
CA 3060778 2019-10-31
[131] In some implementations, the method can include monitoring a presence of
'
hydrocarbons in the mobilized fluids.
[132] In some implementations, the method can include heating the mobilizing
fluid in
correlation with the monitored hydrocarbons to gradually increase the
temperature of the
mobilizing fluid until initiating downhole boiling of the mobilizing fluid
upon injection.
[133] In some implementations, the solvent or diluent can be injected and left
to soak in
liquid phase during start-up.
[134] While present techniques will be described in conjunction with example
embodiments, features and implementations, it will be understood that it is
not intended
to limit the scope of the techniques to such embodiments or implementations.
On the
contrary, it is intended to cover all alternatives, modifications and
equivalents as can be
included as defined by the present description.
[135] Advantages and other features of the present techniques will become more
apparent and be better understood upon reading of the following non-
restrictive
description, given with reference to the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[136] Figure 1 is a schematic cross-sectional view of a single well completion
showing
an injection conduit and a production conduit extending in parallel to one
another in an
axial direction of the well.
[137] Figure 2 is a schematic cross-sectional view of a single well completion
showing
an injection conduit and a production conduit extending concentrically with
each other in
an axial direction of the well.
[138] Figure 3 is a perspective view of an experimental set up including a
packing
assembly separating an injection section from a production section of the
annulus of a
single wellbore.
[139] Figure 4 is a schematic cross-sectional view of a single well completion
along a
direction perpendicular to the axial direction of the well, showing an
injection conduit and
21
CA 3060778 2019-10-31
a production conduit extending concentrically with each other and through a
packing
assembly in an axial direction of the well.
[140] Figure 5 is a schematic cross-sectional view of a single well completion
showing
an injection conduit and a production conduit extending in parallel to one
another and
through a packing assembly in an axial direction of the well.
[141] Figure 6 is an upper view of a wellbore surrounded by a liner and
including tubing
circumferentially distributed around the wellbore.
[142] Figure 7 is a cross-sectional view along line B-B showing the different
elements
of a packing assembly which are located inside or outside of the wellbore.
[143] Figure 8 is a semi-transparent side view of a single wellbore showing a
packing .
assembly cooperating with concentric injection and production conduits.
[144] Figure 9 is a schematic cross-sectional view of a fluid passage of a
packing
assembly including a flow control device.
[145] Figure 10 is another schematic cross-sectional view of a fluid passage
of a
packing assembly including a flow control device.
[146] Figure 11 is a cross-sectional side view of a single wellbore showing a
packing
assembly separating an injection section and a production section of the well,
and
circulation of a mobilizing fluid and mobilized fluids with operational
conditions.
[147] Figure 12 is a schematic cross-sectional view of a packing assembly
separating
an injection section and a production section of a single well, and including
a sealing
element in an expanded state.
[148] Figure 13 is a schematic cross-sectional view of a packing assembly
separating
an injection section and a production section of a single well, and including
a sealing
element in a deactivated state.
[149] Figure 14 is a semi-transparent perspective side view of a packing
assembly
separating an injection section from a production section of the annulus of a
single
wellbore, and including a gas-limiting intake in the injection section.
22
CA 3060778 2019-10-31
[150] Figures 15 and 16 are schematic cross-sectional views of a packing
assembly
separating an injection section and a production section of a single well, the
packing
assembly including a gas-limiting intake, for two different liquid levels in
the injection
section.
[151] Figures 17 and 18 are schematic cross-sectional views of a packing
assembly
separating an injection section and a production section of a single well, the
packing
assembly including a gas-limiting discharge, for two different liquid levels
in the injection
section.
[152] Figure 19 is a semi-transparent perspective side view of a packing
assembly
separating an injection section from a production section of the annulus of a
single
wellbore, and including a single-cup sealing element and a tubular fluid
passage.
[153] Figure 20 is a semi-transparent perspective side view of a packing
assembly
separating an injection section from a production section of the annulus of a
single
wellbore, and including a single-cup sealing element in an unsealed position
and an
annular fluid passage.
[154] Regarding the figures, the following list of numerical references is
provided to
facilitate reference to the various components that are illustrated:
- reservoir (1)
- packing assembly (2, 20)
- liner (4)
- mobilizing fluid (5)
- mobilizing fluid portions (5a, 6b)
- well, wellbore, well completion (6)
- production fluid (7)
- injection conduit (8)
o injection port (80)
o injection sub (81)
o injection chamber (82)
=
o injection outlet (84)
- production conduit (10)
o production port (100)
23
CA 3060778 2019-10-31
o production sub (101)
o production conduit segment (102)
- sealing element (12)
- fluid passage (including tubular fluid passage and annular fluid passage)
(14)
o tube, tubing (140)
o instrumentation line (142)
o inlet portion of the tube (144)
o outlet portion of the tube (146)
o main portion of the tube (148)
o control valve (150)
o flow control device (152)
o FCD tube (153)
o restriction portion (155)
o first and upstream portion (157)
o second and downstream portion (159)
- annular space, annulus (16)
o injection section (160)
o production section (162)
- flexible sleeve (18)
o intermediate section (180)
o distal ends (182)
o fluid chamber (184)
- inner injection tube (22)
- outer production tube (24)
- fluid channel (26)
- fluid passage (28)
- gas-limiting intake (19)
o inlet port(s) (190)
o chamber (liquid chamber, annular chamber) (192)
o weighted portion (194)
o floating valve (196)
- gas-limiting discharge (21)
o outlet port(s) (198)
24
CA 3060778 2019-10-31
o discharge chamber (liquid discharge chamber, annular discharge
chamber) (210)
CA 3060778 2019-10-31
DETAILED DESCRIPTION
[155] The present description relates to enhanced single-well steam-assisted
gravity-
drainage (SW-SAGD) techniques, and more particularly to a packing assembly for
use in
a well completion. The packing assembly separates adjacent production and
injection
sections of the well to avoid or limit short circuiting where injection fluid
would flow into
the production section, while enabling a controlled passage of condensed
injection fluid
from the injection section into the production section.
Introduction regarding SW-SAGD operations
[156] The SW-SAGD operation can be deployed in a reservoir containing heavy
hydrocarbons. Heavy hydrocarbons can be contained in porous or fractured rock
formations having a certain porosity, and the rock matrix combined with the
properties of
the heavy hydrocarbons keep the viscous hydrocarbons immobile under natural
reservoir conditions. In the present description, heavy hydrocarbons can be
referred to
or understood as oil (e.g., heavy oil) or bitumen. The reservoir that is to be
exploited can
be, for example, a heavy oil reservoir (where the oil is initially mobile), an
oil sands
reservoir, or any bituminous sands reservoir (where the oil is initially
immobile), where
the reservoir has an exploitable pay zone. It is also noted that techniques
described
herein can also be used in connection with reservoirs containing other types
of
hydrocarbons.
[157] Typically, a wellbore is drilled into a pay zone of the reservoir and
the wellbore is
then completed prior to operating the well for hydrocarbon recovery. The
wellbore can
include a vertical portion extending from a well pad at the surface, a
transition portion,
and then a horizontal portion extending from the transition portion along the
pay zone.
The vertical and horizontal portions can have various degrees of inclination
and can also
deviate along their respective trajectories, if desired, depending on the
geology of the
reservoir and the drilling techniques that are used. The completion of the
well can
include equipment that is deployed and installed down the wellbore. The
packing
assembly described herein can form part of the well completion.
[158] During the production phase of a SW-SAGD process, hydrocarbons are
recovered by injecting a mobilizing fluid (e.g., a heated fluid such as steam)
into the
reservoir at certain points along the length of the horizontal well portion to
mobilize
26
CA 3060778 2019-10-31
hydrocarbons contained in the reservoir. Mobilization can be achieved by
heating the
hydrocarbons (e.g., by transferring thermal energy from the injected
mobilizing fluid to
the hydrocarbons) and by dissolution (e.g., by solubilizing part of the
hydrocarbons into
the injected mobilizing fluid, for instance when a solvent is used), thereby
producing
mobilized fluids. The mobilized fluids, which include hydrocarbons and
condensed
mobilizing fluid, drain down from the reservoir and into the well, where they
are produced
as a= production fluid: The production fluid is recovered to the surface for
further
processing. The production fluid can enter the well at various spaced-apart
locations
along the horizontal portion of the well, and then can enter and flow through
a production
conduit of the horizontal well. The injection points and the production points
provided
along the length of the horizonal portion of the well can be offset from each
other.
= [159] In the example implementation illustrated in Figure 1, injection
(8) and production
(10) conduits are substantially parallel to one another and extend axially
within the single
well (6). It should be noted that the axial direction refers herein to the
direction of the
well. An annular-like region (16) can therefore be defined as the region of
the well (6)
which is in between the reservoir (1) (or liner when the well is lined) and
the external
surface of both injection (8) and production (10) conduits. In this case, this
annular-like
region (16) can be referred to as an annulus for the purposes of describing
certain
components and functions of the technology. In the example implementation
illustrated
in Figure 2, the injection conduit (8) is disposed within the production
conduit (10), e.g.,
concentrically, and both conduits extend axially within the horizonal portion
of the single
well (6). The annulus (16) can in this case be defined as the region of the
well (6)
between the reservoir (1) (or liner when the well is lined) and the external
surface of the
production conduit (10).
[160] It should be noted that a production section of the well refers to a
portion of the
annulus where mobilized fluids are received from the reservoir and are
produced. An
injection section of the well refers to another portion of the annulus where
the mobilizing
fluid is injected from the injection conduit, the mobilizing fluid flow being
able to flow from
the injection section into the reservoir. In the case of a single-well
completion, a same
well includes at least one injection section and at least one adjacent
production section.
More commonly, a same well includes a plurality of injection sections and
production
sections distributed along the single horizontal well in an alternating
configuration. The
mobilizing fluid is fed to the injection section via an injection conduit that
can be also
27
CA 3060778 2019-10-31
referred to herein to an injection tube or injection line. The mobilized
fluids are produced
from the production section via a production conduit that can be also referred
to herein
to a production tube or production line. An injection section can be fed with
mobilizing
fluid via one or more axially distributed injection ports provided at discrete
locations of
the injection conduit, the injected mobilizing fluid being conducted from the
injection
section into the reservoir and optionally through a liner. A production
section receives
mobilized fluids from the reservoir through the liner and can be produced via
one or
more axially distributed production ports provided at discrete locations of
the production
conduit.
[161] In one example, to mobilize the hydrocarbons, a heated and pressurized
mobilizing fluid is injected via the injection conduit into the injection
section of the well.
The mobilizing fluid in liquid phase under the injection conduit conditions
vaporizes upon
exiting the injection conduit under the reservoir conditions. A mobilized
chamber (which
can also be called a steam chamber when steam is used as the mobilizing fluid)
is
thereby created and expands upwardly and outwardly within the reservoir. It
should be
noted that the vapour chamber can have different characteristics depending on
the stage
of the recovery operation (e.g., start-up, ramp up, plateau, wind-down), the
reservoir
properties, and the mobilizing fluid that is injected. For example, when the
mobilizing =
fluid is injected as steam, the vapour chamber can be referred to as a steam
chamber.
Within the vapour chamber, higher vapour-phase saturation will be at the
center while at
the boundaries of the vapour chamber there will be liquids including mobilized
liquid
hydrocarbons and condensed mobilizing fluid. Liquids are mobilized at the
boundaries of
the chamber. Heat from the vapour chamber is transmitted to the hydrocarbons,
which
lowers their viscosity to enable drainage. It should be noted that, in the
case where a
solvent is used as a pressurized mobilizing fluid, hydrocarbon viscosity can
be reduced
when the solvent dissolves in the in-place hydrocarbons (as opposed to simply
heating
the hydrocarbons). For soluble solvents, the hydrocarbons can be mobilized
from
increased temperature and/or dilution effects. An emulsion of the condensed or
dissolved vapour phase of the mobilizing fluid and mobilized hydrocarbons flow
down
and is then produced, and can be referred to as the production fluid or
mobilized fluids.
The force due to gravity will cause the production fluid to move downward
along draining
edges of the vapour chamber and into the production sections of the well, to
be further
produced via the production conduit.
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CA 3060778 2019-10-31
[162] In a single well, alternating in time between production and injection
modes can
be performed but it can reduce the efficiency of the production. When
injecting and
producing simultaneously, one method to reduce producing uncondensed
mobilizing
fluid could include using a conventional packer to isolate injection and
production
sections of the single well. However, the use of such packers could lead to
concerns
regarding maximum operating pressure (MOP) within the well and caprock
integrity of
the reservoir, as well as how to warm up and initiate production.
[163] Optionally, the injection conduit can be provided concentrically with
respect to the
production conduit. Alternatively, the injection conduit can extend parallel
to the
production conduit in spaced-apart relationship. In some implementations, the
injection
conduit can have an outer diameter between 20 mm and 300 mm, optionally
between 30
mm and 200 mm, further optionally between 60 mm and 115 mm. The production
conduit can have a diameter between 60 mm and 200 mm, or between 100 mm to
150 mm, for example. Further optionally, the diameter of a horizontal section
of the well
in which the production and injection conduits are located can be between 100
mm and
300 mm.
[164] Optionally, steam can be injected via the injection conduit as the
mobilizing fluid.
Further optionally, pressurized hot water can be provided down the injection
conduit so
that it partially flashes to steam as it exits the injection conduit and
enters the reservoir.
Even if steam is generally used in gravity drainage operations, it should be
understood
that the mobilizing fluid described herein can include any fluid able to
mobilize
hydrocarbons. Said mobilizing fluid can include water, a solvent, a
surfactant, or a
combination thereof. Optionally, the mobilizing fluid can include or consist
essentially of
an organic solvent that is a C1-05 alkane solvent. Further optionally, the
alkane solvent .
can include propane, butane or a mixture thereof. Further optionally, the
mobilizing fluid
can include a mixture of steam and surfactant, e.g. a mixture of ammonia and
steam.
[165] Some ways to reduce production of uncondensed injected mobilizing fluid
in the
SW-SAGD completion includes staggering injection and production ports,
elevating the
toe (end point of the horizontal wellbore section) to provide an elevation-
based pressure
differential or using a conventional packer between each injection section and
production
section to provide isolation therebetween. However, certain drawbacks can
relate to the
use of such fully isolating packers separating two adjacent sections of the
well. For
29
CA 3060778 2019-10-31
example, the isolated well sections can become over-pressurized in certain
areas where
the reservoir has a lower injectivity (e.g., due to lower permeability for the
injected
mobilizing fluid), thereby potentially reaching a Maximum Operating Pressure
(MOP)
which can hinder caprock integrity of the reservoir.
Packing assembly implementations
[166] Techniques described herein relate to a device including at least one
fluid
passage allowing fluids to flow from one side to another side of the device in
response to
an axial pressure differential therebetween. More particularly, techniques
described
herein relate to a packing assembly providing a designed and selective fluid
flow,
optionally liquid flow, from an injection section to an adjacent production
section of the
annulus of the single well in response to an axial injection-production
pressure
differential.
[0001] In one aspect, there is provided a semi-permeable packing assembly for
selectively controlling fluid flow between axially separated injection and
production
sections of an annulus of a single wellbore. Referring to Figure 3; the
packing assembly
(2) is connected to concentric inner conduit (8) and outer conduit (10)
axially extending
along and within the wellbore (6). The axial direction refers herein to the
direction of the
length of the wellbore or the relevant wellbore section in which the packing
assembly is
located. The radial direction refers herein to the direction of the width (or
radius) of the
wellbore. An annulus (16) is defined by the available space between walls of
the
wellbore (6) and the outer conduit (10). One skilled in the art will readily
understand that,
when the wellbore is lined or cased, the annulus would be defined by the
available
space between the liner or casing (4) and the outer conduit (10). The packing
assembly
can therefore provide controlled pressurization of both injection and
production sections.
It should be noted that the terms "assembly", "module", "device", "apparatus",
"unit", and
"packer" can be used interchangeably within the context of the present
description.
[167] Depending on the location of injection and production ports or subs
along the
annulus, the first section can be referred to as the injection section and the
second
section can be referred to as the production section, or vice-versa. Figures
3, 4 and 11
to 20 provided herein illustrate examples of a packing assembly adapted to a
concentric
= configuration where the inner conduit is the injection conduit, the outer
conduit is the
CA 3060778 2019-10-31
production conduit, the first section of the annulus is the injection section
(due to the
presence of an injection sub in this section of the wellbore), and the second
section of
the annulus is the production section. However, it should be noted that the
features of
the packing assembly described in relation to these Figures can be adapted to
other
configurations or arrangements of injection conduit, production conduit,
injection section
and production section (e.g., depending on the position of injection and
production
subs), to enable selective fluid communication between two wellbore sections
via the
annulus.
[168] The axial injection-production pressure differential is to be understood
as a
difference of pressure between an injection section and a production section
of the
annulus along a fluid path and across the packing assembly. This axial
injection-
production pressure differential is to be distinguished from a production
pressure
differential which can be viewed as a difference between an average reservoir
pressure
and the pressure at which the mobilized fluids are produced from the
production section,
and from an injection pressure differential which is a difference between the
pressure at
which the mobilizing fluid is injected in the injection section and the
average reservoir
pressure.
[169] The expression "semi-permeable" is used to qualify the packing assembly,
as
such assembly includes elements (e.g., sealing element) preventing fluid
communication
between opposed sides of the assembly, and other elements (e.g., at least one
fluid
passage) allowing some fluid communication between the opposed sides of the
assembly. The expressions "selective" or "gas-limiting" are used in relation
to elements
of the packing assembly (e.g., gas-limiting device or flow control device)
selectively
allowing a liquid phase (i.e., as opposed to a gas/vapor phase) to be
communicated from
one side of the assembly to the other.
[170] In the context of steam and/or solvent-assisted operations for bitumen
recovery,
which may be gravity drainage operations, the expressions "liquid", "liquid
state" or
"liquid phase" refers to the state of a fluid that can be condensed mobilizing
fluid
resulting from condensation of the mobilizing fluid (e.g., steam and/or
solvent vapor),
drained mobilized fluids from the reservoir (including mobilized
hydrocarbons), or
injected mobilizing liquid (e.g., water and/or solvent in ,liquid phase). The
expressions
"vapor", "gas", "gas state" or "gas phase" refer to the state of a fluid that
can be
CA 3060778 2019-10-31
uncondensed mobilizing fluid (e.g., such as steam, or solvent vapor) or a non-
condensable gas.
[171] During injection of the mobilizing fluid, a portion of the mobilizing
fluid can remain
as liquid-phase mobilizing fluid (e.g., condensed back from vapour phase or
remaining in
liquid phase) in the injection section, instead of being conducted as
substantially vapour-
phase mobilizing fluid through the liner and into the reservoir to mobilize
hydrocarbons.
For example, when injecting low-quality steam as the mobilizing fluid, the
portion of
saturated water (moisture) included in the steam remains higher and notable
amounts of
water are therefore produced back to the surface.
[172] In response to such drawback, the packing assembly as described herein
offers
an escape flow path to the liquid that can accumulate in a bottom area of a
corresponding injection section along the wellbore.
[173] In the implementation shown in Figure 3, the packing assembly is used as
a part
of a single-well assembly (60) configured to be installed within the
horizontal wellbore
section (6) to mobilize hydrocarbons in the surrounding region of the
reservoir. The
single-well assembly (60) also includes a production conduit segment (102) and
an
injection conduit segment (not seen in Figure 3). The packing assembly (2) is
provided in
a section of an annular space (16) surrounding a portion of said injection and
production
conduit segments so as to provide sealing of such annular space section. The
single-
well assembly (60) can further include at least one injection sub (81) for
injecting the
mobilizing fluid into the reservoir, and at least one production sub (101) for
receiving the
mobilized fluids comprising the 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 or structure. The injection sub (81) is
operatively
connected to a proximal end of both injection and production conduit segments,
and the
production sub (101) is operatively connected to a distal end of both
injection and
production conduit segments. One skilled in the art will readily understand
that the
single-well assembly can include additional elements serving to join the subs
to the
conduit segments so as to ensure alignment and fluid communication
therebetween.
32
CA 3060778 2019-10-31
[174] It should be understood that some sections of the annulus can be
provided with a
packing assembly at each end thereof, said sections being exempt of any
injection and
production ports.
[175] Referring to the implementation illustrated in. Figure 14, the packing
assembly (2)
includes a sealing element (12) that can be in sealing engagement with the
liner (4) of
the single well (6) and an outer conduit (10), thereby axially separating a
first section
(160) of the annulus from a second section (162) of the annulus (16). The
sealing
element (12) can include a plurality of fluid passages (14) axially extending
across and
within the sealing element (12) to put the first section (160) of the annulus
(16) in fluid
communication with the adjacent second section (162) of the annulus (16) in
response to
an axial pressure differential. The packing assembly (2) can further include a
gas-limiting
device (19) controlling a liquid flow path from the first section (160) of the
annulus (16) to
the second section (162) of the annulus via the fluid passages (14). Various
aspects and
features in the design of the sealing element, fluid passage and gas-limiting
device are
presented as follows.
Sealing element
[176] Depending on the geometry of the well and completion components, the
sealing
element can take various forms to provide adequate isolation of an injection
section with
respect to an adjacent production section.
[177] Referring to Figures 1 to 5 and 14 to 18, the sealing element can be an
annular
sealing element (12) extending radially and outwardly from the production
conduit (10) to
axially isolate the injection section (160) with respect to the production
section (162) of
the annulus (16).
[178] In the implementation shown in Figures 3 and 4, the injection conduit
(8) is
provided within the production conduit (10) and the annular sealing element
(12) is a
sleeve-like body which is shaped to define an opening for the production
conduit (10).
The annular sealing element (12) thereby creates a seal between an inner
surface of the
liner (4) and an outer surface of the production conduit (10).
[179] In other implementations, the annular sealing element can be in sealing
engagement directly with an inner surface of the wellbore when the latter is
not lined.
33
CA 3060778 2019-10-31
[180] Referring to Figure 3, the annular sealing element (12) extends along a
portion of
the production conduit (10) axially separating the production section (162)
from the
injection section (160) of the annulus (16). The annular sealing element (12)
can include
an expandable element which forms a seal when in expanded state. For example,
the
expandable element can be a swellable element which expands when submitted to
swelling conditions. The swellable element can be an elastomeric element,
which is
responsive to hydrocarbons or water, thereby expanding when immersed in
certain oil or
water-containing fluids.
= [181] In other implementations, such as the implementation illustrated in
Figure 8, the
annular sealing element (12) can include a pair of opposed sealing rings (120)
having
circumferences that enable the sealing rings (s) to be sealed against the
liner (4) of the
wellbore (6), thereby defining an annular sealing space therebetween. Other
types of
mechanisms can be used to ensure sealing of the annulus by the sealing element
between an injection section and a production section of the single well. Such
mechanisms include hydraulic, mechanical and interference setting mechanisms.
For
example, the sealing element can include a spring member ensuring engagement
with
the wellbore and other components of the well to provide the sealing
engagement.
[182] Alternatively, the sealing element can be a fluid-activated sealing
component
such as employed in hydraulic packers where hydraulic Pressure is used to
activate the
sealing of the annulus. In other implementations, the sealing element can also
be made
to expand in response to other stimuli, such as axial compression or pressure
in the
injection conduit as will be described further below.
[183] For example, a single, double or multiple-cup sealing element can be
used to
provide sealing of the annulus by the packing assembly. Referring to Figure
19, the
sealing element (12) can be a flexible single-cup sealing element that is
positioned to
axially separate the first section (160) from the second section (162) of the
annulus (16).
For example, the single or multiple-cup sealing element can be made of glass-
filled
Teflon . In the illustrated implementation of Figure 19, the first section
(160) is an
injection section and the second section (162) is a production section. When
the
operating pressure Pi in the injection section (160) is superior to the
operation pressure
P2 in the production section (162), a proximal end (or wide end) of the
flexible single-cup
sealing element (12) is pushed against and seals the inner walls of the
wellbore (6).
34
CA 3060778 2019-10-31
[184] Alternatively, and referring to Figure 20, the same or similar flexible
single-cup
sealing element (12) can be used in another wellbore configuration, wherein a
tapered or
narrow end of the sealing element (12) is oriented towards the injection
section (160). In
this configuration, when the operating pressure Pi in the injection section
(160) is
superior to the operation pressure P2 in the production section (162), the
wide end of the
flexible single-cup sealing element (12) is pushed away and unseals from the
inner walls
of the wellbore (6).
[186] In some implementations, cup members of a same multiple-cup sealing
element
can be positioned in a row. The cup members of a same multiple-cup sealing
element or
from separate multiple-cup sealing elements can be oriented in same or
opposite
directions along the wellbore, to allow for various designed axial pressure
differentials as
well as sealing effects in response to the pressure differentials.
[186] It should be noted that Figure 3 only shows a portion of the well
completion and
that a plurality of sealing elements can be axially distributed along the
production
conduit, spaced-apart from one another, so as to define alternate injection
sections and
production sections. Additionally, each injection section can receive
mobilizing fluid
injected via one or more injection sub(s) and each production section can
receive
mobilized hydrocarbons to be produced via one or more production sub(s). More
specifically, a pair of sealing elements provided respectively about
injection/production
conduit portions extending on either side of one injection sub can define an
injection
section therebetween. As such, a pair of sealing elements provided
respectively about
injection/production conduit portions extending on either side of one
production sub can
define a production section therebetween.
[187] To confer semi-permeability to the packing assembly, fluid communication
is
allowed to some extent between the first and second sections of the annulus of
the
wellbore. This fluid communication can be allowed by providing one or more
fluid
passages across the packing assembly. As will be further detailed below, the
at least
one fluid passage can be created in various ways, e.g., by enabling the
sealing element
to unseal from the liner or wellbore under certain conditions, thereby
creating an annular
=
fluid passage. The fluid passage can also be created by providing at least one
elongated
channel across the sealing element, these elongated channels being walled by
the
sealing element itself or by tubing. Other configurations and designs can also
be
35 =
CA 3060778 2019-10-31
provided in order to enable the desired some fluid communication between the
first and
second sections.
Fluid passage
[188] In some implementations, the packing assembly can include at least one
fluid
passage extending across the sealing element to put the injection section of
the annulus
in fluid communication with the adjacent production section of the annulus in
response to
an axial pressure differential. The fluid passage is generally located within
the wellbore,
has an inlet in fluid communication with the injection section of the annulus
and an outlet
in fluid communication with the adjacent production section of the annulus, so
as to
confer semi-permeability to the packing assembly. More particularly, the
packing
assembly can include a plurality of fluid passages. The condensed mobilizing
fluid can
therefore be conducted through the at least one fluid passage from the
injection section
= into the production section. The condensed mobilizing fluid can then be
produced via a
corresponding production port of the production conduit located in the
production
section, thereby reducing formation of a liquid pool in the injection section.
The flowrate
of the condensed mobilizing fluid through the fluid passage depends on the
axial
pressure differential across the packing assembly (between the injection
section and the
= production section) as well as other properties such as the fluid
properties and the
geometry of the fluid passages.
[189] Various sealing elements as described above can be used in combination
with at
least one fluid passage as also described herein. Particular implementations
of at least
one tubular or annular fluid passage are described herein. It should
nevertheless be
noted that, in some implementations, the at least one fluid passage of the
packing
assembly can be configured in other ways, e.g., particulate material with a
permeability
that allows passage of the fluid. For example, any fluid passage could be used
in
combination with a gas-limiting device as described herein, e.g. the gas-
limiting intake
and/or the gas-limiting discharge.
Tubular fluid passage
[190] In one implementation, the packing assembly includes a sealing element
as
described herein and at least one tubular fluid passage allowing fluid
communication
between two adjacent sections of the wellbore and across the packing assembly.
CA 3060778 2019-10-31
[191] For example, referring to Figures 3 to 5 and 14 to 19, the tubular fluid
passage
(14) can be provided as elongated channel across and within the sealing
element (12).
In these examples, the tubular fluid passages can be defined by walls that are
part of the
material of the sealing element, and can thus be provided as bores through the
sealing
element itself. Alternatively, one could provide bores through the sealing
element and
additional tubular members could be inserted therein to define the fluid
passages. In
addition, one could also use separate tubing to define the channel or channels
serving
as the tubular fluid passage ensuring fluid communication between adjacent
sections of
the annulus. In another example, the tubular fluid passage can be defined by
at least
one tube or pipe. As seen in Figure 8, tubing (140) can be provided through an
annular
sealing space (12) between the two sealing rings (120). As seen in Figures 6
and 7 ,
tubing (14) can be provided to bypass the sealing element (12). In the
implementation
where the tubing bypasses the sealing element, one skilled in the art would
readily
understand that tubing can generally be within the completion and outside the
sealing
element by extending along the liner or casing, within the liner or casing, or
within the
reservoir itself (e.g., in open-hole completion). Thus, there are various
constructions and
configurations that are possible for providing the fluid passages.
[192] A tubular fluid passage refers herein to an elongated and hollow passage
having
generally continuous surfaces defining its side walls. The tubular fluid
passage can be
referred to as a walled channel and can have various cross-sections that
change along
its length. The tubular fluid passage can be generally cylindrical or can have
cylindrical
portions; and/or it can also have tapered portions having an elongated conical
shape, for
example. However, the tubular fluid passage is not limited to having a
substantially
circular cross-section, and can have other cross-sections such as elliptical,
trapezoidal,
rectangular, star-shaped, etc. The tubular passage can be straight, bent,
curved, or can
follow other trajectories. The tubular fluid passages and annular fluid
passage can thus
be distinguished from the type of fluid passages that can be formed by the
interstices
and pores of a particulate solid material.
[193] Referring to Figures 3 and 4, a plurality of tubular fluid passages (14)
having a
substantially circular cross-section defined by tubes extend axially across
the annular
sealing element (12) and are distributed circumferentially around the
concentric conduits
(8, 10), such that the inlet of each tubular fluid passage (14) is in fluid
communication
with an injection section (8), and the outlet of each tubular fluid passage
(14) is in fluid
37
CA 3060778 2019-10-31
communication with a production section (10). The mobilizing fluid (not
illustrated) is only
able to flow via the tubular fluid passages (14) as the annular sealing
element (12) seals
the annular space (16) located between the liner (4) and the production
conduit (10). It
should be noted that "across" is used to define that the tube axially extends
within the
annular sealing element from the injection section to the production section.
Optionally,
the tubular fluid passage extends across an intermediate part of the annular
sealing
element spaced away from both the inner wellbore surface and the outer
production
conduit surface. It can be seen in Figure 4 that at least one tubular fluid
passage (14)
can be used as a feed-through passage for an instrumentation line (142) to
measure
properties of the fluids downhole.
[194] In some implementations, the packing assembly can include at least three
tubular
fluid passages which are interconnected so as to form an extended tubular
fluid
passage. More particularly, a distal end of a first tubular passage can be
joined to the
proximal end of a second tubular fluid passage, the distal end of the second
tubular fluid
passage being also joined to the proximal end of a third tubular fluid
passage, such that
fluid communication is ensured between the three tubular fluid passages,
thereby
allowing the mobilizing fluid to flow forwardly and backwardly, from the
injection section
to the production section via the extended tubular fluid passage.
[195] Figures 6 and 7 also illustrate a configuration of the packing assembly
(2)
including a plurality of tubular fluid passages (14) distributed
circumferentially with
respect to concentric injection and production conduits (8, 10). However,
differently from
Figures 3 and 4, the tubular fluid passages (14) include tubing (140) arranged
to bypass
the annular sealing element (12) and put an injection section (160) in fluid
communication with an adjacent production section (162). Each tube (140) can
include
an inlet portion (144) extending outwardly and radially from the injection
section (160) of
the annulus (16) and through the liner (4), and an outlet portion (146)
extending
outwardly and radially from a production section (162) of the annulus (16) and
through
the liner (4). Each tube can further include a main portion (148) extending
outside of the
sealing element and within the wellbore to join the inlet portion (144) and
the outlet
portion (146) to ensure fluid communication therebetween, thereby providing a
bypassing fluid path from the injection section (160) into the production
section (162).
38
CA 3060778 2019-10-31
[196] Figure 5 shows an example implementation of a packing assembly (2) in
sealing
engagement with the liner (4) of a single well (6) and cooperating with an
injection
conduit (8) and a production conduit (10) which are arranged in a spaced-apart
and
parallel configuration. Tubular fluid passages (14) can be generally
distributed radially
around the injection conduit (8) and the production conduit (10) within the
annular
sealing element (12). However, the tubular fluid passages could be provided in
other
arrangements through the sealing element. The tubular fluid passages could be
arranged at different distances from the edge or middle of the sealing
element, in various
patterns that are regular or irregular, and/or passages having a same or
different cross-
section or shape at given axial positions, for example.
[197] The configuration of the fluid passage can differ from the one
illustrated in Figure
and, for example, a plurality of passages can be provided below the production
conduit
in a lower portion of the sealing element, such that the fluid passages are
positioned
near a liquid pool that could form in the injection section of the wellbore.
As illustrated in
Figure 19, a fluid passage (14) can be provided in the lower portion of the
single-cup
sealing element (12) by creating a notch or channel within a circumference
thereof, to
allow the accumulated liquid to flow via the fluid passage (14) to the
production section
(162) in response to the axial pressure differential (Pi - P2).
[198] In an implementation wherein a plurality of packing assemblies are
axially
provided along the well, the total open cross-sectional area of the packing
assembly,
which is defined by the fluid passages, may vary from one packing assembly to
another
to modulate the flow rate of the mobilizing fluid communicated from one
injection section
to the adjacent production section. For example, to reduce the residence time
of
condensed mobilizing fluid within an injection section, the number of fluid
passages may
be increased, optionally doubled, from a first packing assembly located near
a.distal end
of the well (toe) to a last packing assembly located near a proximal end of
the well
(heel). One skilled in the art will readily understand that the total open
cross-sectional
area of the packing assembly may be modified by varying the number of fluid
passages
or the cross-section of each fluid passage, for example.
[199] In the implementation illustrated in Figure 8, the plurality of tubular
fluid passages
(14) is defined by corresponding tubes (140), distributed circumferentially
around the
outer conduit (production, 10). The tubes (140) axially extend, within the
annular sealing
39
CA 3060778 2019-10-31
space (122) and are held in place via the opposed sealing rings (120), such
that the inlet
of each fluid passage (14) is in fluid communication with the injection
section (160), and
the outlet of each fluid passage (14) is in fluid communication with the
production section
(162). Each sealing ring (120) can thus have an aperture that receives a
corresponding
end of one of the tubes (140).
[200] It should be noted that the packing assembly configurations illustrated
in Figures
3, 6, 7 and 8 could also be used as an experimental set up in order to test
certain
operational requirements (dimensions, diameters of the openings, pressures,
temperatures, flowrate, etc.) before operation at a commercial scale.
Annular fluid passage
[201] In another implementation, the packing assembly can include a sealing
element
as described herein and a substantially annular fluid passage that can be
defined
between the liner of the wellbore (or inner surface of the wellbore) and an
outer surface
of the sealing element, allowing fluid communication between two adjacent
sections of
the wellbore and across the packing assembly.
[202] As seen in Figures 13 and 20, an annular fluid passage (14) can be
created by
allowing the sealing element (12) to unseal from the liner or casing (4) under
certain
operating conditions, such that some fluid contained in the annulus (16) can
leak via the
annular fluid passage (14) between the injection section and the production
section in
response to an axial pressure differential.
[203] In another example as illustrated in Figure 20, the single-cup sealing
element
(12) can be installed within the wellbore (6) such that its circumference is
not fully sealed
against the liner (4). In this implementation, the cup-style sealing element
(12) can be
made of flexible material allowing some fluid communication via the annulus
under
certain pressure conditions. More particularly, the annular fluid passage can
be created
between the liner (4) and the circumference of the sealing element (12) when
the axial
pressure differential between Pi and P2 reaches a threshold. For example, when
P1 ¨ P2
is superior to 300 kPa, the single-cup sealing element (12) can be deformed
and unseal
from the liner (4) such that a portion of the fluids contained in the first
section (160) of
the annulus (16) could flow into the second section (162) via the created
annular fluid
passage (14) to be further produced and regulate the axial pressure
differential. Thus,
CA 3060778 2019-10-31
_
the cup-style sealing element (12) can be arranged and configured such that it
assumes
a first position at a lower pressure differential between first and second
sections in order
to provide a full or substantial seal, and moves to a second position in
response to
higher pressure differentials such that it unseals and enables a leak between
the two
sections. Such first and second positions could also be referred to as sealed
and leaky
positions, respectively.
[204] In another example, the sealing element can be reversibly energized for
expansion thereof. Referring to Figures 12 and 13, a flexible sleeve (18)
acting as the
sealing element can seal the annulus (16) between the injection section (160)
and the
production section (162). The flexible sleeve (18) can be reversibly deformed
between a
sealing position and an open position. Referring to Figure 12, upon
energization, the
flexible sleeve (18) is deformed into the sealing position in which an
intermediate section
(180) of the flexible sleeve (18) is in sealing engagement with the liner (4)
(or an inner
surface of the wellbore), thereby closing the annulus (16) between the
injection section
(160) and the production section (162) of the well. Fluid communication
between the
injection section (160) and the production section (162) is therefore
prevented. Referring
to Figure 13, the flexible sleeve (18) can be de-energized into the open
position to
unseal the annulus (16). The intermediate section (180) thus moves away from
the liner
(4), to form an annular fluid passage (28) therebetween. A portion of the
fluids present in
the injection section (160) can therefore flow via the fluid passage (28) of
the wellbore
into the production section (162) in response to the axial pressure
differential. More
details will be provided further below with respect to the embodiment of the
packing
assembly illustrated in Figures 12 and 13.
[205] Many configurations and variations can be envisioned by one skilled in
the art to
provide the fluid communication between injection and production sections of
the well,
as long as a desired fluid communication between adjacent sections of the
annulus is
enabled.
=
Gas-limiting features
[206] The packing assembly can include one or more gas-limiting devices for
preventing or limiting uncondensed fluids, including uncondensed mobilizing
fluid, to be
communicated from the first section of the annulus to the second section of
the annulus
41
CA 3060778 2019-10-31
via the packing assembly. Such gas-limiting devices can be provided at various
locations
of the packing assembly, such as at the inlet of the fluid passages, the
outlet of the fluid
passages, and/or within the fluid passages. More specifically, the packing
assembly can
include at least one of a gas-limiting intake, a gas-limiting discharge, a
control valve, and
a flow control device, cooperating with the fluid passages of the packing
assembly to
encourage liquid passage while preventing or limiting gas passage between the
adjacent
sections. For instance, the gas-limiting device can allow liquid accumulating
in a bottom
area of the annulus to be communicated to another section of the annulus for
production
thereof, while limiting or preventing any uncondensed fluids to follow the
same path.
Gas-limiting intake
[207] In one implementation, the packing assembly includes a sealing element
as
described herein, at least one fluid passage as described herein and a gas-
limiting
intake configured for preventing gas (i.e., any uncondensed fluids), which is
contained in
a first section of the wellbore, from entering the at least one fluid passage
of the packing
assembly. More specifically, the gas-limiting intake provides a selective flow
path to
liquids accumulating in the first section for further communication to the at
least one fluid
passage. The gas-limiting intake cooperates with one side of the sealing
element, such
that the inlet of the at least one fluid passage is impeded by the gas-
limiting intake when
gas is present and would otherwise flow into the fluid passage.
[208] Referring to Figure 14, the packing assembly (2) includes a gas-limiting
intake
(19) (e.g., bearing-type) concealing an inlet region to the plurality of fluid
passages (14)
distributed circumferentially with respect to concentric injection and
production conduits
(8, 10). When liquid is accumulating in the bottom area of the injection
section (160),
pressure is rising in the injection section (160) and the liquid can enter an
annular
chamber (192) via an inlet port (190) of the gas-limiting intake (19). Each of
the fluid
passages (14) has a corresponding inlet in fluid communication with the
annular
chamber (192) of the gas-limiting intake (19), such that only liquid
accumulating within
the chamber (192) can flow towards the production section (162) via the fluid
passages
(14) in response to axial pressure differential. As the inlet port (190) of
the gas-limiting
intake (19) is positioned below a liquid level in the injection section (160),
uncondensed
fluid (i.e., gas) is prevented or inhibited from being communicated to the
fluid passages
(14) and production section (162). It is noted that the gas-limiting intake
(19) can be
42
CA 3060778 2019-10-31
configured to prevent gas flow into the fluid passages, or at least generally
limit such gas
flow to a relatively small quantity.
[209] As can be readily understood by one skilled in the art, the amount of
liquid
transmitted to the chamber (192) will depend on a difference of pressure
between the
chamber (192) and the injection section (160) as well as other factors. In
addition, as the
liquid level rises in the chamber (192), pressure in the liquid chamber (192)
can also rise
and liquid flows into the fluid passages in response to the axial pressure
differential
between the liquid chamber (192) and the production section (162). Therefore,
various
sizes and geometries of the chamber can be provided to comply with the fluid
passages'
configuration. Optionally, the chamber of the gas-limiting intake can have
walls that are
made of steel (e.g., mild, hardened or stainless), aluminum, titanium,
fibreglass,
polymers, or suitable composite materials.
[210] In some implementations, the gas-limiting intake includes a plurality of
inlet ports.
The inlet ports can be spaced apart from one another to define various
patterns as could
be readily chosen by one skilled in the art depending on the wellbore
configuration and
the other components of the packing assembly. For example, the inlet ports can
be
grouped in multiples of two or more in a bottom portion of a wall of the
chamber.
Different means can be used to ensure that uncondensed fluids are not
communicated
within the chamber of the gas-limiting intake via the inlet ports.
[211] In the implementation illustrated in Figure 14, the gas-limiting intake
(19) can
include a weighted portion (194) to orient inlet ports (190) of the gas-
limiting intake
towards a bottom area of the injection section (160), upon installation of the
packing
assembly (2) within the wellbore (6). Indeed, the gas-limiting intake can be
configured so
that it can rotate about a central longitudinal axis, and more particularly
rotate with
respect to the outer conduit onto which the intake is installed, under the
action of the
weighted portion (194). Optionally, the inlet ports (190) are located on or
within or close
to this weighted portion (194) for positioning thereof in the bottom area of
the annulus
= (16) where liquid can accumulate. The inlet ports (190) can thereby be
positioned below
a level of liquids accumulating in the bottom area of the injection section
(160). In this
example, the gas-limiting intake (19) can be sized to provide an amount of
play between
its outer surface and the inner surface of the wellbore or liner, such that it
can freely
43
CA 3060778 2019-10-31
rotate after or during installation so that the weighted portion (194) falls
to the bottom
and thus orients the gas-limiting intake (19) in the desired position.
[212] The inlet ports (190) can simply be apertures or orifices within the
walls of the
chamber of the intake, or can be equipped with various types of nozzles,
chokes, or
valves limiting or preventing gas flow. The inlet port (190) can also be any
device or can
be defined by any geometry known and used for limiting gas flow, including
Inflow/Flow
Control Devices (ICDs/FCDs) and Autonomous Inflow Control Devices (AICDs).
[213] In the implementation illustrated in Figures 15 to 17, the gas-limiting
intake (19)
can include a floating valve (196, ball-type) to prevent uncondensed fluids
from entering
the intake chamber (192) via the inlet port (190). The floating valve (196) is
located
within the chamber (192) and is able to move away from the inlet port (190),
under the
action of buoyancy, as the liquid level rises within the chamber (192). The
floating valve
can thus be sized and weighted accordingly for the given fluids and pressures
that may
be used in operation. Referring to Figure 15, a liquid pool can start to
accumulate in the
bottom are of the injection section (160) of the annulus (16). As long as the
liquid level of
the liquid pool does not reach a height of the inlet port (190) of the chamber
(192), the
floating valve (196) mates with the inlet port (190) and impedes fluid
communication via
the inlet port (190). Any uncondensed fluid located above the liquid pool in
the injection
section (160) is thereby prevented from entering the chamber (192) and the
fluid
passages (14) towards the production section (162). Referring to Figure 16, as
the liquid
level in the bottom area of the injection section (160) rises, the floating
valve (196) is
lifted by liquid entering the chamber (192) via the inlet port (190). Liquid
flow to the
chamber (192) is thereby allowed and liquid can start to accumulate within the
chamber
(192) until reaching a fluid passage (14), allowing communication of the
liquid towards
the adjacent production section (162) via the fluid passage (14). The floating
valve (196)
remains away from the inlet port (190) of the chamber (192) which only
receives liquid
inflow.
[214] It should be noted that the structure, size and shape of the "intake"
can be
tailored to the fluid passage configuration (e.g., through the annulus,
through the sealing
element, bypass via the reservoir, etc.). One skilled in the art will
understand that various
structures and configurations can be designed to allow the intake to impede
one or more
fluid passages of the packing assembly that would be otherwise exposed to
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uncondensed fluids in the injection sections, while allowing other fluid
passages that are
exposed to accumulated liquid to receive this liquid and transfer it into the
adjacent
production section on the other side of the packing assembly.
[215] It should be noted that, even if the gas-limiting intake is illustrated
in the Figures
installed in a single well including concentric injection and production
conduits, the gas-
limiting intake and elements thereof as described herein can be applied in the
context of
separate injection and production conduits, axially extending in parallel
relationship
within the single wellbore. It should be further noted that, even if the gas-
limiting intake is
illustrated in the Figures installed in a well that is used for single-well
SAGD operations,
and thus including an injection conduit and a production conduit within the
same
horizontal wellbore, the gas-limiting devices and elements thereof as
described herein
can be applied in the context of other wells when uncondensed fluids are to be
prevented from flowing from one section of the wellbore to another, while
allowing liquids
to flow.
= Gas-limiting discharge
[216] In another embodiment, the packing assembly includes a sealing element
as
described herein, at least one fluid passage as described herein and a gas-
limiting
discharge configured for preventing gas (i.e., uncondensed fluids), flowing
from one side
of the packing assembly, from being discharged to the other side of the
packing
assembly in the annulus of the wellbore. More specifically, the gas-limiting
discharge
= provides a selective flow path to any liquid, accumulating in a first
section of the
wellbore, across the packing assembly. The gas-limiting discharge cooperates
with one
side of the sealing element, such that the outlet of the at least one fluid
passage is
= impeded by the gas-limiting discharge when gas is present and would
otherwise flow
into the production section.
1217] Referring to Figure 17, the packing assembly (2) includes a gas-limiting
discharge (21) (e.g. bearing-type) concealing an outlet region to of the
plurality of fluid
passages (14) distributed circumferentially with respect to concentric
injection and
production conduits (8, 10). When liquid is accumulating in the bottom area of
the
injection section (160), pressure is rising in the injection section (160) and
fluids can flow
across the fluid passages (14) into an annular discharge chamber (210) of the
gas-
CA 3060778 2019-10-31
limiting discharge (21). Each of the fluid passages (14) has a corresponding
outlet in
fluid communication with the annular discharge chamber (210) of the gas-
limiting
discharge (21), such that fluids flowing through the fluid passages (14), in
response to
axial pressure differential, are contained within the chamber (21). The
chamber (21) of
the gas-limiting discharge (21) is further equipped with at least one outlet
port (198)
which is in fluid communication with a production section (162) of the annulus
(16). The
outlet port (198) can evacuate fluids contained in the discharge chamber into
the
production section in response to the axial pressure differential. The outlet
port (198)
can be configured to prevent uncondensed fluid (i.e., gas) from being
communicated to
the production section (162). It is noted that the gas-limiting discharge (21)
can be
configured to prevent gas flow into the production, or at least generally
limit such gas
flow to a relatively small quantity.
[218] As can be readily understood, the amount of liquid transmitted to the
discharge
chamber (210) will depend on a difference of pressure between the discharge
chamber
(210) and the production section (162), as well as other factors. In addition,
as the liquid
level rises in the discharge chamber (210), pressure in the liquid chamber
(210) can also
rise and liquid flows into the production section (162) in response to the
axial pressure
differential between the liquid chamber (192) and the production section
(162).
Therefore, various sizes and geometries of the discharge chamber can be
provided to
comply with the fluid passages' configuration. Optionally, the discharge
chamber of the
gas-limiting discharge have walls that are made of steel (e.g., mild, hardened
or
stainless), aluminum, titanium, fibreglass, polymers, or suitable composite
materials.
[219] In some implementations, the gas-limiting discharge includes a plurality
of outlet
ports. The outlet ports can be spaced apart from one another to define various
patterns
as could be readily chosen by one skilled in the art depending on the wellbore
configuration and the other components of the packing assembly. For example,
the
outlet ports can be grouped in multiples of two or more in a bottom portion of
a wall of
the discharge chamber. Different means can be used to ensure that uncondensed
fluids
are not communicated from the discharge chamber to the production section via
the
outlet ports.
[220] In some implementations, similarly to the features described in relation
to the
gas-limiting intake of Figure 14, the gas-limiting discharge can include a
weighted
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CA 3060778 2019-10-31
portion to orient outlet ports of the gas-limiting discharge towards a bottom
area of the
production section, upon installation of the packing assembly within the
wellbore.
Indeed, the gas-limiting discharge can be configured so that it can rotate
about a central
longitudinal axis, and more particularly rotate with respect to the outer
conduit onto
which the discharge is installed, under the action of the weighted portion.
Optionally, the
outlet ports can be located on or within or close to the weighted portion for
positioning
thereof in the bottom area of the annulus. In this example, the gas-limiting
discharge can
be sized to provide an amount of play between its outer surface and the inner
surface of
the wellbore or liner, such that it can freely rotate after or during
installation so that the
weighted portion falls to the bottom and thus orients the gas-limiting
discharge in the
desired position.
[221] The outlet ports (198) can simply be apertures or orifices within the
walls of the
discharge chamber of the gas-limiting discharge, or can be equipped with
various types
of nozzles, chokes, or valves limiting or preventing gas flow to the
production section.
The outlet ports (198) can also be any device or can be defined by any
geometry known
and used for limiting gas flow, including Inflow/Flow Control Devices
(ICDs/FCDs) and
Autonomous Inflow Control Devices (AICDs).
[222] In the implementation illustrated in Figures 17 and 18, the gas-limiting
discharge
(21) further includes a floating valve (196, ball-type) which is located in
the chamber (21)
and impedes fluid flow via the outlet port (198), in absence of liquid
accumulated in the
chamber (21). The floating valve (196) is able to move away from the outlet
port (198),
under the action of buoyancy, as the liquid level rises within the discharge
chamber
(210). The floating valve can thus be sized and weighted accordingly for the
given fluids
and pressures that may be used in operation. Referring to Figure 18, when
liquid,
flowing from at least one of the fluid passages (14) , accumulates within the
discharge
chamber (21), the floating valve (196) is lifted upon liquid level rising in
said chamber
(21).The outlet port (198) is thereby unblocked and liquid can flow into the
production
section (162) of the annulus (16). Any uncondensed fluids, including
uncondensed
mobilizing fluid, which are located above the liquid pool in the discharge
chamber, are
prevented from being communicated to the production section (162), which only
receives
liquid inflow from the packing assembly (2).
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CA 3060778 2019-10-31
[223] It should be noted that the structure, size and shape of the "discharge"
can be
tailored to the fluid passage configuration (e.g., through the annulus,
through the sealing
element, bypass via the reservoir, etc.). One skilled in the art will
understand that various
structures and configurations can be designed to allow the discharge to impede
one or
more fluid passages of the packing assembly that would otherwise discharge
uncondensed fluids in the production section in absence of additional gas-
limiting
means.
[224] It should be noted that, even if the gas-limiting discharge is
illustrated in the
Figures installed in a single well including concentric injection and
production conduits,
the gas-limiting discharge and elements thereof as described herein can be
applied in
the context of separate injection and production conduits. It should be
further noted that,
even if the gas-limiting discharge is illustrated in the Figures installed in
a well that is
used for single-well SAGD operations, and thus including an injection conduit
and a
production conduit within the same horizontal wellbore, the packing assembly
and
elements thereof as described herein can be applied in the context of other
wells when
uncondensed fluids are to be prevented from flowing from one section of the
annulus to
another, while allowing liquids to flow.
Other gas-limiting features and components
[225] Other means can be used to prevent any uncondensed fluids from being
communicated to a production section via the annulus and directly from an
injection
section.
[226] In implementations where the fluid passage is tubular, the tubular fluid
passage
can be further equipped with a control valve positioned across the tubing to
control a
flow of the fluid from one side to another side of the packing assembly in
response to the
axial pressure differential therebetween. The control valve can be configured
to
selectively open or close the tubing. Alternatively, a gradual opening of the
tubing can be
allowed by said control valve. In some implementations, the tubular fluid
passage can be
selective in allowing fluid to flow from a first side of the packing assembly
to a second
side, while resisting fluid flow from the second side of the packing assembly
to the first
side.
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CA 3060778 2019-10-31
[227] Referring to Figures 6 and 7, the control valve (150) can be located
proximate the
inlet portion (144) of the corresponding tubular fluid passage bypassing the
annular
sealing element (12). Referring to Figure 8, tubes (140) and associated
control valves
(150) can be located within the annular sealing space of the packing assembly
between
the injection section (160) and the production section (162). One skilled in
the art will
understand that the positioning of the valve along the tube is not limited to
the illustrated
implementations, and the valve can be positioned at various locations along
the tube
between an injection section and a production section..
[228] The control valve may be actuated when the corresponding well region
reaches a
critical axial injection-production pressure differential. Various techniques
can be used to
sense the injection-production pressure differential and actuate the valve
accordingly.
For example, a temperature and/or pressure sensor can be used. Optionally, the
sensor
and actuator can be combined such as in bimetallic strips where the
temperature/pressure change is converted into mechanical displacement that
could
actuate the valve for example.
[229] Further implementations of the tubular fluid passage can prevent
uncondensed
mobilizing fluid to flow down the passage. The tubular passage can be sized
and
configured to limit the flow of vapour phase relative to liquid phase, so that
the vapour
phase tends to condense before passing through the fluid passage, thereby
expelling
the mobilizing fluid in substantially liquid phase into the production section
via the
packing assembly. This configuration enables limiting vapour flow from the
injection side
to the production side of the packing assembly. Indeed, the thermal energy of
the
vapour-phase mobilizing fluid (e.g. steam) can damage equipment and hinder
proper
operations if produced. Producing vapour-phase mobilizing fluid can also be
undesirable
due to the corresponding waste of energy, which would not be used to mobilize
the
hydrocarbons within the reservoir.
[230] For example, the tubular fluid passage can be defined by a tube having
an inner
cross-sectional diameter which varies along the axial direction. Such tube can
be
referred to as a flow control device (FCD), for regulating the flow of fluid
from an injection
section to an adjacent production section of the well. The variation of the
inner cross-
sectional diameter is tailored to favor axial liquid flow with respect to
axial vapour flow.
49
CA 3060778 2019-10-31
[231] Two different implementations of the FCD (152) are schematically
illustrated in
Figures 9 and 10. An FCD tube (153) includes a restriction portion (155) being
positioned centrally in Figure 9 and near the outlet of the tube (153) in
Figure 10, which
results in a tubular fluid passage (14) having a varying inner cross-sectional
diameter.
The FCD (152) is configured to interfere with the vapour flow from an
injection section to
an adjacent production section via the packing assembly.
[232] Referring to Figure 10, the FCD tube (153) can include a first and
upstream
portion (157) having a first inner cross-sectional diameter, a second and
downstream
portion (159) having a second inner cross-sectional diameter, and the
restriction portion
(155) joining the upstream (157) and downstream (159) portions. The second
cross-
sectional diameter can be greater than the first cross-sectional diameter at a
defined
ratio. The restriction is sized to create a pressure drop and induce vapour to
liquid
transition of the mobilizing fluid when flowing down the tubular fluid passage
(14) of the
FCD (152). Such variation of inner cross-sectional diameter allows for
selective liquid
flow between an injection section and a production section of the annulus (not
illustrated
in Figure 10).
[233] It should be noted that different geometries can be used for the FCD,
such as
described in the US patent application published under No. 20170058655, to
prevent or
at least reduce uncondensed mobilizing fluid conveying from the injection
section into
the production section via the tubular fluid passage of an FCD.
It should be noted that other methods and mechanisms can be used to limit the
flow of
uncondensed fluids via each tubular fluid passage. For example, orientation of
the
tubular fluid passage can be chosen to place an inlet of the tubular fluid
passage
proximate to the bottom of the annulus. Multiple techniques available can be
used to
orient devices (top vs bottom) in a well.
[234] Although implementations illustrated in the Figures show a plurality of
fluid
passages, the packing assembly can include a single fluid passage which
location can
be strategically chosen to further favor passage of condensed mobilizing fluid
rather than
uncondensed mobilizing fluid.
[235] Although implementations illustrated in the Figures mainly show a
concentric
configuration where the injection conduit extends along and within the
production
sn
CA 3060778 2019-10-31
conduit, one skilled in the art will readily understand that other conduit
configurations can
be used to implement the packing assembly, including the production conduit
extending
along and within the injection conduit.
[236] In addition, implementations described in relation to a specific gas-
limiting feature
or component can be combined with another gas-limiting features or components
described herein. For example, the packing assembly can include a flow control
device
within one or more of the fluid passages and can further include a gas-
limiting discharge
on the production side of the sealing element, at the outlet of the fluid
passages, and/or
a gas-limiting intake on the upstream side. It should further be noted that
features
described in relation to the gas-limiting intake or discharge provided at one
side of the
sealing element, can be adapted to provide a gas-limiting intake or discharge
to a
specific portion of the fluid passages along and across the sealing element.
Related methods and operations
[237] Reservoir pressure changes as hydrocarbon-containing fluids (mobilized
fluids)
are produced from the reservoir. Techniques described herein further provide
methods
for controlling an axial pressure differential within the annulus of a single
well
completion, so as to enhance the process for the production of the hydrocarbon-
containing fluids.
[238] Referring to the implementation illustrated in Figure 11 and including
tubular fluid
passages, the mobilizing fluid (5) is injected via an injection port (80)
along the injection
conduit (8) into an injection section (160) of the annulus (16). A portion of
the injected
mobilizing fluid (5a) is conducted through the liner (4) into the reservoir
(1) and mobilizes
hydrocarbons from the reservoir (1). Mobilized fluids (7) drain by gravity
through the liner
(4) and into the production section (162) of the annulus (16). The packing
assembly (2)
extends along a portion of the production conduit (10) and isolates the
injection section
(160) from the production section (162) via the sealing element (12) which is
a pair of
sealing rings in Figure 11. The packing assembly (2) includes tubes (140),
each defining
a tubular fluid passage (14) extending in an annular sealing element (12). The
axial
pressure differential between an injection point along the injection section
(160) and a
production point along the production section (162) can be controlled such
that another
portion of the mobilizing fluid (5b) is conducted into the production section
(162) through
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CA 3060778 2019-10-31
each tubular fluid passage (14). Both the portion of mobilizing fluid (5b) and
the drained
mobilized fluids (7) can be produced via a production port (100) along the
production
conduit (10) as a production fluid (70).
[239] The method includes managing pressure in both injection section and
production
section of the well by controlling the production rate. In some
implementations, the
method can include depressurizing a production section to increase a
mobilizing fluid
flow rate across the packing assembly from an injection section into the
production
section. In other implementations, the method can include pressurizing a
production
section to decrease a mobilizing fluid flow rate across the packing assembly
from an
injection section into the production section. Preferably, the fluid flow is a
liquid flow to
reduce production of a gas/vapor phase of the mobilizing fluid.
[240] During steady-state operation of the single well, the method can include
injecting
the mobilizing fluid in the injection section of the annulus at an injection
flow rate which is
not impacted by downstream conditions, and which can therefore be kept
substantially
constant upon maintaining the upstream conditions. If the pressure in the
injection
section increases above an upper threshold value, the method includes
increasing a
production flow rate at which the mobilized fluids are produced to decrease
the pressure
in the adjacent production section of the annulus, thereby activating fluid
flow within the
tubular fluid passages of the packing assembly and relieving pressure in the
injection
section.
[241] As a consequence, the axial pressure differential is increased as the
production
section is depressurized, and fluid flow is thereby accelerated through the
tubular fluid
passages of the packing assembly from the injection side to the production
side. The
flow of mobilizing fluid from the injection section to the production section
enables relief
of the pressure in the injection section under the upper threshold value. One
skilled in
the art will readily understand that condensed mobilizing fluid can constantly
be flowing
via the tubular fluid passages with a flow rate which is in accordance with
the axial
pressure differential.
[242] It should be noted that the critical axial injection-production pressure
differential is
chosen according to the optimal conditions for production and can be below or
equal to
the MOP of the well. For example, one can optimize the pressure differential
to
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CA 3060778 2019-10-31
maximize injection while allowing sufficient pressure in the production
section to allow
efficient lift to surface.
[243] Injection pressure can increase for a number of reasons, including low
injectivity
of the reservoir above the corresponding well section, and slowing of the
production flow
rate. It should be understood that the method can include slowing the
injection flow rate
if activation/acceleration of the fluid flow across the packing assembly is
not sufficient to
relieve pressure build-up in an injection section. One skilled in the art will
readily
understand that the method can also include slowing the production flow rate
in case the
pressure in the injection section decreases below a lower threshold value.
[244] For example, the axial pressure differential can be controlled between
20 and
1000 kPa. For example, the axial pressure differential can be controlled at
300 kPa by
managing the production flow rate, so as to maintain the pressure in the
injection section
around 1500 kPa.
[245] In some implementations, the method can include pressurizing the
mobilizing
fluid downhole to maintain the mobilizing fluid in liquid phase in the
injection conduit and
to vaporize the mobilizing fluid during delivery within the injection section
according to
the pressure drop between the injection conduit and the injection section of
the annulus.
Optionally, the mobilizing fluid can be pressurized between 2000 kPa and 17000
kPa at
a temperature between 100 C and 350 C within the injection conduit.
[246] In some implementations, the method can include allowing condensed
mobilizing
fluid to be released into the production section via the tubular fluid
passages, while
limiting uncondensed mobilizing fluid to be released into the production
section. It should
be understood that any vapour phase can, in some aspects, be prevented from
being
released into the production section. However, depending on the axial pressure
differential and related flow rate within the tubular fluid passages, a
certain amount of
uncondensed mobilizing fluid can still be released into the production section
along with
a main flow of condensed mobilizing fluid.
= [247] It should be noted that method implementations described above with
respect to
a packing assembly including tubular fluid passages can be applied and adapted
to a
packing assembly including at least one fluid passage as described herein, and
more
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CA 3060778 2019-10-31
particularly to a packing assembly including an annular fluid passage between
the liner
(or walls of the wellbore) and the sealing element, or other types of fluid
passages.
Other packing assembly implementations
[248] The following section provides additional information regarding optional
features
and implementations for packing assemblies.
Reversibly deformable sealing element and integrated injection port
[249] In another implementation, another packing assembly configuration is
provided,
including a downhole sealing element which is reversibly energized for
expansion
thereof, to contain fluids and pressures in their respective sections of the
well. This
packing assembly can further optionally include at least one injection port in
fluid
communication with an injection conduit to distribute the mobilizing fluid
within the
reservoir. In some implementations, combining injection and packing equipment
can
advantageously reduce the number of elements needed for the well completion.
[250] Referring to Figures 12 and 13, the packing assembly (20) can be used in
a
single well completion (6) to isolate an injection section (160) from an
adjacent
production section (162) of the annulus (16). Optionally, the packing assembly
(20) can
cooperate with concentric injection and production conduits (8, 10). One
skilled in the art
will readily understand that the packing assembly (20) can also cooperate with
injection
and production subs as detailed above.
[251] Still referring to Figures 12 and 13, the packing assembly (20) includes
an inner
injection tube (22) and an outer production tube (24) concentric with said
inner injection
tube (22). The injection tube (22) and production tube (24) of the packing
assembly (20)
are configured to cooperate with respective injection and production conduits
(8, 10) to
ensure alignment and fluid communication between the injection tube (22) and
the
injection conduit (8), and between the production tube (24) and the production
conduit
(10). The inner injection tube (22) is in fluid communication with the
injection conduit (8)
for transmitting the mobilizing fluid into the reservoir. The packing assembly
(20) also
includes two opposed fluid channels (26) which are radially extending from the
inner
injection tube (22) and through the outer production tube (24) such that fluid
circulating
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CA 3060778 2019-10-31
in the inner injection tube (22) can flow into the fluid channels (26) without
being
communicated to the production tube (24).
[252] Still referring to Figures 12 and 13, the packing assembly (20) also
includes a
flexible sleeve (18) that can serve to seal the annulus (16) between the
injection section
(160) and the production section (162). The flexible sleeve (18) wraps around
at least a
portion of the outer production tube (24) and includes an intermediate section
(180)
which is freely movable with respect to the outer production tube (24) and
opposed distal
ends (182, 183) which are attached to the outer production conduit (24). An
inner
surface of the flexible sleeve thereby defines an injection chamber (184)
receiving the
Mobilizing fluid flowing from the fluid channels (26). The volume of the
injection chamber
can vary according to the pressure in the injection chamber (184), such that
an outer =
surface of the intermediate section (180) can contact the liner (4) of the
reservoir and
thereby prevent any fluid communication between the injection section (160)
and the
production section (162) of the annulus (16).
[253] Again, it should be noted that the design can differ from the
illustrated
implementation. For example, the outer surface of the intermediate section can
directly
contact the wellbore when no liner is provided.
[254] It should be further noted that securing the distal ends of the flexible
sleeve about
the outer surface of the outer production tube can be performed according to
various
techniques including welding, interference fitting, compression fitting, or
molding as a
one-piece structure with the production tube.
[255] Deformation of the flexible sleeve allows for fluid communication
between the
injection section and the production section of the wellbore. The flexible
sleeve can be
activated to selectively open or close the annulus of the well. Activation or
energization
can refer to a reversible deformation of the flexible sleeve into a sealing
position in which
the flexible sleeve is in sealing engagement with the liner or casing of the
well to close
the annulus. Opening of the annulus upon deactivation of the flexible sleeve
allows fluids
to be communicated from one side of the packing assembly to another side of
the
packing assembly.
[256] More particularly, the flexible sleeve can be reversibly deformed
between a
sealing position and an open position. Referring to Figure 12, upon
energization by the
CA 3060778 2019-10-31
pressure inside the injection chamber (184), the flexible sleeve (18) is
deformed into the
sealing position as the injection chamber (184) reaches a maximal size for
which the
intermediate section (180) of the flexible sleeve (18) is in sealing
engagement with the
liner (4) (or an inner surface of the wellbore), thereby closing the annulus
(16) between
an injection section (160) and a production section (162) of the well. Fluid
communication between the injection section (160) and the production section
(162) is
therefore prevented. Referring to Figure 13, the flexible sleeve (18) can be
de-energized
into the open position to unseal the annulus (16). De-energization of the
flexible sleeve
(18) can be performed by decreasing the flow rate or pressure at which the
mobilizing
fluid is delivered into the injection chamber (184). It should be noted that
when injection
is done at critical (choked) flow, reducing injection pressure will have
minimal effect on
injection flowrate, but can deactivate the flexible sleeve (18). The size of
the injection
chamber (184) can be reduced and the intermediate section (180) is thereby
spaced
away from the liner (4), to form a fluid passage (28) therebetween. A portion
of the fluids
present in the injection section (160) can therefore flow via the fluid
passage (28) of the
wellbore into the production section (162) in response to the axial pressure
differential.
[257] Figure 13 shows an implementation of the packing assembly (20) including
a
sleeve-shaped sealing element (18). The resulting fluid passage (28) can
therefore have
a generally annular cross-section, and can be referred to as an annular fluid
passage.
Other designs of sealing elements can be used as long as they enable to
reversibly seal
the annulus upon activation by fluid pressure. It is also noted that the
annular fluid
passage does not have to be formed as a complete or full annular space, but
can
include a section or part of an annulus defined between generally concentric
components.
[258] De-activation of the flexible sleeve (18) to open the annulus (16) can
be
performed if the pressure in the injection section (160) of the annulus
reaches an upper
threshold value. Opening of the annulus (16) allows depressurizing of the
injection
section (160) into the adjacent production section (162) located on the other
side of the
packing assembly (20).
[259] In some implementations, the flexible sleeve can be made of a metallic
material
which is able to deflect while resisting of high temperatures encountered in
oil sands
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CA 3060778 2019-10-31
mining operation. The flexible sleeve can include Teflon, an elastomeric
material or a
combination thereof.
[260] Still referring to Figures 12 and 13, the packing assembly (20) can
further
include, optionally, at least one injection port (80) to allow the mobilizing
fluid to flow
from the inner injection tube (22) into the injection section (160) of the
annulus. The
injection port (80) is defined by or provided at one distal portion (183) of
the flexible
sleeve (18), nearby the injection section (160).
[261] Optionally, the technique chosen to secure the distal ends of the
flexible sleeve
has to be adapted to the number and configuration of injection ports. Opposed
distal
ends of the flexible sleeve are attached to the outer production tube in a way
that allow
the at least one injection port to be defined or inserted therebetween. For
example, as
seen on Figures 12 and 13, one distal end (183) of the flexible sleeve (18)
can be
secured to the outer production tube (24) such that a section of the distal
end (183) is in
sealing engagement with the outer surface of the production tube (24) and a
remaining
section of the distal end (183) defines an outlet of the injection chamber
(184) serving as
the injection port (80).
[262] In an implementation not shown in Figures 12 and 13, multiple injection
ports can
be provided about one distal end of the flexible sleeve. For example, a
plurality of
injection nozzles can be radially distributed around the production tube, and
installed
between the outer production tube and one distal end of the flexible sleeve in
a
sandwich-like configuration. In other implementations, one could combine
injection,
production and packing equipment in a same packing assembly. For example, the
packing assembly can further include at least one production port in fluid
communication
with the production conduit, the production port being provided at a distal
end of the
flexible sleeve.
[263] Variations in the above described configuration can be performed to
adapt to
dual-well SAGD operations. For example, the flexible element can be configured
to wrap
around an injection string of a dual-well SAGD completion, the flexible
element being
deflected from the injection string to create an injection chamber that can
seal the
annulus between two adjacent injection sections from an injection well.
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[264] Although not shown in the Figures, implementations described in relation
to the
packing assembly (20) including the energizable sealing element (18) could be
combined with the implementations described in relation to the packing
assembly (2)
including the at least one tubular fluid passage (14). For example, a packing
assembly
as encompassed herein can include a sealing element that can be reversibly
activated
by the fluid pressure of the flowing mobilizing fluid, and at least one
tubular fluid passage
extending across such sealing element to allow fluid flow from the injection
section to the
production section in response to the axial pressure differential.
Related methods and operations
[265] In a related aspect, there is provided a method for controlling an axial
pressure
differential between an injection section and a production section of an
annulus of a
single well completion, a portion of the annulus being reversibly sealed by an
expandable packing assembly as above described and disposed between the
injection
section and the production section.
[266] The method includes injecting a mobilizing fluid into the injection
section via the
packing assembly at an injection flow rate, and managing the injection flow
rate to
control the expansion or deformation of the packing assembly within the
annulus. The
injection flow rate can be "controlled for example according to the pressure
imposed at
the well head.
[267] Controlling the expansion or deformation of the packing assembly enables
to
unseal the portion of the annulus between the injection section and the
production
section, and to allow fluid communication therebetween via the annulus. As
already
mentioned, fluid communication from the injection section into the production
section can
be desirable, for instance when the pressure in the injection section reaches
an upper
threshold value, as it allows depressurization of the opened injection section
via the
unsealed annulus.
[268] In some implementations, referring to Figure 12, the method can include
increasing an injection pressure of the mobilizing fluid to expand the
injection chamber
(184) of the packing assembly (20), when a pressure in the injection section
(160)
reaches a lower threshold value. As the intermediate section (180) of the
flexible sleeve
(18) contacts the liner (14), the injection section (160) is isolated from the
production
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=
section (162) and pressure in the injection section can further increase above
the lower
threshold value.
[269] In some implementations, referring to Figure 13, the method can further
include
decreasing the injection pressure of the mobilizing fluid to shrink the
injection chamber
(184), when the pressure in the injection section (160) reaches an upper
threshold value.
As the annulus (16) is unsealed, fluid communication between the injection
section (160)
and the production section (162) is allowed, thereby depressurizing the
injection section
(160) below the upper threshold value.
[270] It should be understood that shrinking of the sealing element of the
packing
assembly refers to a reduction of the volume of the injection chamber of the
packing
assembly. Any alternative means to vary the volume of the injection chamber
can be
used as long as they ensure reversible sealing of the annulus by direct
contact with the
sealing element.
[271] Packing assembly and method implementations described herein allow for
emergency depressurization of the annular space when operating pressures are
elevated, thereby ensuring that MOP is never exceeded.
[272] Implementations described in relation to the packing assembly including
at least
one tubular fluid passage can be combined with the implementations described
in
relation to the packing assembly including at least one injection port.
Indeed, the packing
assembly can include both tubular fluid passage and injection port. The
sealing element
can be activated upon expansion of the injection chamber with injection of the
mobilized
fluid via the injection port. In case of an excessive rise of pressure within
the injection
section of the annulus, the production rate can be reduced so as to increase
the axial
injection-production pressure differential, thereby allowing or accelerating
condensed
mobilizing fluids to flow through the tubing of the fluid passage of the
packing assembly.
The tubing can be embedded within the sealing element or can be provided
within the
annulus, such that the sealing element can be in sealing engagement with an
outer
surface of the tubing when in expanded state.
[273] It should be noted that the implementations illustrated in the Figures
include one
packing assembly separating an injection section from an adjacent production
section.
However, one skilled in the art will readily understand that the single well
completion can
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include a plurality of packing assemblies as herein described and claimed,
isolating
injection sections and production sections alternately disposed along the
single well.
[274] It should be noted that, as the mobilizing fluid flows across the
packing assembly
in accordance with the axial pressure differential, fluid can also be allowed
to flow from a
production section into an adjacent injection section. The packing assembly
described
herein is therefore not limited to allow fluid flowing only from one side of
the packer to
the other side of the packer, but rather allows for a reversible fluid flow
across the
packer. As the pressure in an injection section is superior to the pressure in
a production
section under typical SW-SAGD conditions, the mobilizing fluid is allowed to
flow from an
injection section into the adjacent production section and across the packing
assembly.
However, for example during start-up phase operations for pre-heating the
reservoir, it
could be desirable to let heated mobilized fluids flow from a production
section into an
adjacent injection section. In another example related to cyclic steam
injection
operations, one can readily understand that the fluid passages across the
packing
assembly could also be used to conduct drained mobilized fluids from an
injection
section into a production section of the annulus to benefit from drainage of
the mobilized
fluids via an injection section.
[275] While generally described in relation to single well completions, it
should further
be noted that certain implementations of the packing assembly can be used or
adapted
for other completions, such as dual-well SAGD, or highly-deviated production
or infill
wells.
[276] It should be noted that configurations of the packing assembly described
herein
can be used in experimental set-up including laboratory-scaled experiments,
pilot-scale
experiments, computer-simulated experiments, or a combination thereof, so as
to
evaluate optimal parameters for the hydrocarbons recovery operation.
CA 3060778 2019-10-31
Start-up methods
[277] Before reaching a steady-state production, recovery of hydrocarbons from
the
reservoir is generally stimulated during a period referred to as a start-up
period. Indeed,
initial injectivity in some reservoirs can be very low, making it difficult to
start the
mobilization of the hydrocarbons.
[278] In conventional dual-well SAGD, steam is initially circulated for
several weeks or
months to pre-heat the reservoir during the start-up period. Different ways of
stimulating
production during the start-up period have to be developed in order to cope
with single-
well SAGD operation challenges. For example, as above-described, packing
assemblies
and production subs of a single-well completion can include mechanisms, such
as flow
control devices, limiting production of uncondensed mobilizing fluid (e.g.
steam). Steam
circulation as performed in dual-well SAGD can therefore not be feasible.
[279] In a first implementation, there is provided a method to stimulate
mobilization of
hydrocarbons from a reservoir via a single well completion, the method
including
alternating injection of a mobilizing fluid and production of mobilized fluids
in time. The
mobilizing fluid is injected at discrete injection sections at a pressure and
temperature
that would be used in steady-state operation of the single well, such that a
pressurized
heated mobilizing fluid is released in the reservoir and expected to mobilize
hydrocarbons first near the injection sections. The mobilized hydrocarbons and
condensed mobilizing fluid emulsion is then produced at discrete production
sections.
Injection phase and production phase are alternately repeated as hydrocarbons
are "
removed from the reservoir, allowing an increasing quantity of mobilizing
fluid to be
injected in each subsequent cycle until continuous operation is achieved. In
some
implementations, cyclic injection and production can further be used during an
entire life
of the well.
[280] In a second implementation, there is provided a method to stimulate
mobilization
of hydrocarbons from a reservoir via a single well completion, the method
including
injection of a mobilizing fluid at a temperature below saturation conditions
of the fluid for
any pressure. The injected mobilizing fluid therefore remains completely in
liquid phase
and the method includes production of the mobilizing fluid in liquid phase.
The method
further includes gradually increasing a temperature of the mobilizing fluid
such that
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hydrocarbons are gradually heated and mobilized in a near-well region of the
reservoir
due to heat-transfer from the liquids. Optionally, the method can include
monitoring of
the presence of hydrocarbons in the produced liquids such that heating of the
mobilizing
fluid can be performed in correlation, until initiating downhole boiling of
the mobilizing
fluid upon injection. It should be noted that this gradual heating reduces
over-
pressurization risks in an early stage when reservoir injectivity is low, but
when the
packing assemblies and production string are configured to prevent sufficient
vapor/gas
phase to be produced to maintain an acceptable downhole pressure. In addition,
this
method is a gradual process which would reduce thermal stresses on the single-
well
completion equipment.
[281] In a third implementation, there is provided a method to stimulate
mobilization of
hydrocarbons from a reservoir via a single well completion, the method
including
injection of a solvent or diluent which is left to soak a near-well region of
the reservoir,
thereby increasing its injectivity. Optionally, the method can include heating
the solvent
or diluent prior to injection thereof. Further optionally, the method can
include producing
the solvent or diluent back to the surface.
[282] While implementations of the packing assembly have been described in
detail in
relation to a single well, it should be understood that the techniques
described herein
could be used in relation to other hydrocarbon recovery methods including
those that
utilize dual-well steam-assisted gravity-drainage (SAGD), infill or step-out
wells, cyclic
steam stimulation (CSS) wells, or other enhanced hydrocarbon recovery methods
or well
systems. The. packing assembly can be particularly useful in a well that is
capable of
simultaneous injection of a mobilizing fluid into the reservoir and production
of a
production fluid from the reservoir.
[283] As alternative implementations, as readily understood by one skilled in
the art,
closed-loop circulation method or heating method with electric cables can be
also used
to start mobilizing hydrocarbons within a near-well region of the reservoir.
[284] In the present description, an embodiment or implementation is an
example
= feature of the described packing assembly or related techniques.
Appearances of "one
embodiment," "an embodiment", "some embodiments", or "some implementations" do
not necessarily all refer to the same embodiments. Although various features
can be
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described in the context of a single embodiment, the features can also be
provided
separately or in any suitable combination. Conversely, although the packing
assembly
can be described herein in the context of separate embodiments for clarity,
various
features of the packing assembly can also be implemented in a single
embodiment.
[285] It should be noted that the same numerical references refer to similar
elements of
the packing assembly or single well completion. Furthermore, for the sake of
simplicity
and clarity, namely so as to not unduly burden the figures with several
references
numbers, not all figures contain references to all the components and
features, and
references to some components and features can be found in only one figure,
and
components and features of the present disclosure which are illustrated in
other figures
can be easily inferred therefrom. The embodiments, geometrical configurations,
materials mentioned and/or dimensions shown in the figures are optional, and
are given
for exemplification purposes only. Therefore, the descriptions, examples,
methods and
materials presented in the specification are not to be construed as limiting
but rather as
illustrative only.
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