CA3060778C

CA3060778C - Packing assembly and related methods for recovering hydrocarbons via a single well

Info

Publication number: CA3060778C
Application number: CA3060778A
Authority: CA
Inventors: Martin Lastiwka; Alan Watt
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2018-10-31
Filing date: 2019-10-31
Publication date: 2022-06-14
Anticipated expiration: 2039-10-31
Also published as: CA3060778A1; CA3022710A1

Abstract

There are provided implementations of a packing assembly, related hydrocarbon recovery processes and start-up recovery methods, wherein the packing assembly is 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. A sealing element axially separates 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 has 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.

Description

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 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 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.

[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, 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.

Date Recue/Date Received 2021-04-21

[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 Date Recue/Date Received 2021-04-21 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.

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 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;

[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:

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.

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 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.

Date Recue/Date Received 2021-04-21

[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:

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 14a 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.

[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 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:

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.

[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 [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 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.

[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) 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) o discharge chamber (liquid discharge chamber, annular discharge chamber) (210) 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 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 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.

[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 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 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 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.

[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.

[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).

[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 =

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.

[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 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).

[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 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, _ 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 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 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 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 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-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 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).

[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.

[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.

[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 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 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 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 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 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 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 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.

[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 =
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 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.

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 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 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.

Claims

1. 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 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 least one tubular 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.

2. The packing assembly of claim 1, wherein the injection conduit is concentric with respect to the production conduit.

3. The packing assembly of claim 1 or 2, wherein the at least one tubular fluid passage includes a plurality of tubular fluid passages.

4. The packing assembly of claim 3, wherein the plurality of tubular fluid passages are distributed radially with respect to the production conduit and are evenly spaced apart from one another.

5. The packing assembly of claim 3 or 4, wherein the tubular fluid passages comprise pairs of the fluid passages which are symmetrical about the axial direction.

6. The packing assembly of claim 3 or 4, wherein the tubular fluid passages 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.

7. The packing assembly of any one of claims 1 to 5, wherein the at least one tubular Date Recue/Date Received 2021-08-10 fluid passage extends across an intermediate part of the sealing element spaced away from both the inner wellbore surface and the outer production conduit surface.

8. The packing assembly of any one of claims 1 to 7, comprising from 1 to 30 tubular fluid passages.

9. The packing assembly of any one of claims 1 to 8, wherein a cross-section of the tubular fluid passage in a direction perpendicular to the axial direction is of circular, elliptical, trapezoidal, rectangular or star shape.

10. The packing assembly of any one of claims 1 to 9, wherein the at least one tubular fluid passage is defined by a tube.

11. The packing assembly of claim 10, wherein the tube has variable inner cross-sectional dimensions along the axial direction.

12. The packing assembly of claim 10 or 11, wherein the tube has 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.

13. The packing assembly of claim 12, wherein the downstream portion of each tubular fluid passage has a cross-sectional diameter which is greater than the upstream portion at a defined ratio.

14. The packing assembly of claim 13, wherein the cross-sectional diameter of the upstream portion of each tubular fluid passage is between 1.5 and 4 times smaller than the cross-sectional diameter of the downstream portion.

15. The packing assembly of any one of claims 10 to 14, wherein the tube comprises a valve which is actuable to open or close the fluid passage in accordance with an injection pressure in the injection section.

16. The packing assembly of any one of claims 10 to 15, wherein the tube is linear or curvilinear.

17. The packing assembly of any one of claims 10 to 16, wherein the tube has an inner Date Recue/Date Received 2021-08-10 cross-sectional diameter between 0.5 and 30 mm.

18. The packing assembly of any one of claims 10 to 17, wherein the tube has a length between 20 mm and 1000 mm.

19. The packing assembly of any one of claims 1 to 18, wherein the annular sealing element is 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.

20. The packing assembly of claim 19, wherein the stimuli comprises swelling conditions, axial compression, pressure in the injection conduit or a combination thereof.

21. The packing assembly of claim 20, wherein the expandable element is a swellable element comprising an elastomeric material which swells in the presence of hydrocarbons and/or water.

22. The packing assembly of claim 20, wherein the expandable element is 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.

23. The packing assembly of any one of claims 1 to 19, wherein the annular sealing element comprises a sealing mechanism which is a hydraulic, mechanical or interference setting mechanism.

24. The packing assembly of any one of claim 1 to 19, wherein the annular sealing element is a single or multiple-cup sealing element.

25. The packing assembly of any one of claims 1 to 24, further comprising a gas-limiting intake operatively connected to an inlet 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.

26. The packing assembly of claim 25, wherein the gas-limiting intake comprises:
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 Date Recue/Date Received 2021-08-10 the condensed mobilizing fluid via the at least one inlet port, and the annular liquid chamber being in fluid communication with the inlet 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.

27. The packing assembly of claim 26, wherein the gas-limiting intake is rotatable with respect to the production conduit to position the at least one inlet port in the bottom area of the injection section.

28. The packing assembly of claim 27, wherein at least a portion of a wall of the annular chamber comprises 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.

29. The packing assembly of any one of claims 26 to 28, wherein the annular chamber fully occupies the annular space adjacent to the annular sealing element.

30. The packing assembly of any one of claims 26 to 29, wherein the annular chamber is mounted to the annular sealing element.

31. The packing assembly of any one of claims 26 to 30, wherein the at least one inlet port comprises an aperture; or wherein the at least one inlet port comprises 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.

32. The packing assembly of any one of claims 25 to 31, wherein the gas-limiting intake further includes a floating valve located within the annular chamber, the floating valve being movable, under the action of buoyancy, between:
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 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, thereby allowing the condensed mobilizing fluid to flow into at least one tubular fluid passage.

Date Recue/Date Received 2021-08-10

33. The packing assembly of claim 31, wherein the at least one inlet port is a plurality of inlet ports, and the gas-limiting intake includes a plurality of floating valves, each floating valve cooperating with a corresponding one of the inlet ports of the annular chamber.

34. The packing assembly of any one of claims 1 to 33, wherein the mobilizing fluid includes steam, an organic solvent, a surfactant or a combination thereof.

35. The packing assembly of claim 34, wherein the mobilizing fluid includes or consists essentially of the organic solvent that is a C1-05 alkane solvent.

36. The packing assembly of claim 35, wherein the alkane solvent comprises propane, butane or a mixture thereof.

37. The packing assembly of claim 33, wherein the mobilizing fluid is steam.

38. The packing assembly of claim 33, wherein the mobilizing fluid is a mixture of steam and ammonia.

39. 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.

40. The packing assembly of claim 39, further comprising 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.

Date Recue/Date Received 2021-08-10

41. The packing assembly of claim 40, wherein the gas-limiting intake comprises:
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 of the at least one fluid passage to further communicate the liquid from the chamber to the at least one fluid passage in response to the axial pressure differential.

42. The packing assembly of claim 41, wherein the injection conduit extends within the production conduit and the gas-limiting intake is rotatable with respect to the production conduit to position the at least one inlet port in the bottom area of the injection section.

43. The packing assembly of claim 42, wherein at least a portion of a wall of the chamber comprises 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.

44. The packing assembly of any one of claims 41 to 43, wherein the chamber is an annular chamber surrounding the production conduit.

45. The packing assembly of claim 44, wherein the annular chamber fully occupies an annular space between the production conduit and inner walls of the single wellbore.

46. The packing assembly of any one of claims 41 to 44, wherein the chamber is mounted to the sealing element.

47. The packing assembly of any one of claims 41 to 46, wherein the at least one inlet port comprises an aperture; or wherein the at least one inlet port comprises 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.

48. The packing assembly of any one of claims 41 to 47, wherein the gas-limiting intake further includes a floating valve located within the chamber, the floating Date Recue/Date Received 2021-08-10 valve being movable, under the action of buoyancy, between:
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 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 at least one fluid passage.

49. The packing assembly of any one of claims 39 to 48, wherein the at least one fluid passage puts the injection section in direct fluid communication with the injection section.

50. The packing assembly of any one of claims 39 to 49, wherein the at least one fluid passage is an elongated channel.

51. The packing assembly of any one of claims 39 to 50, wherein the at least one fluid passage is at least one walled fluid passage.

52. The packing assembly of any one of claims 39 to 51, wherein the at least one fluid passage has a straight portion.

53. The packing assembly of any one of claims 39 to 52, wherein the at least one fluid passage has a bent or curved portion.

54. The packing assembly of any one of claims 39 to 53, wherein the at least one fluid passage has cross-sectional dimensions which vary along the axial direction.

55. The packing assembly of any one of claims 39 to 54, wherein the at least one fluid passage is provided in the wellbore to put the inlet of the at least one fluid passage in fluid communication with a lower portion of the injection section.

56. The packing assembly of any one of claims 39 to 55, wherein the at least one fluid passage extends across the packing assembly.

57. The packing assembly of any one of claims 39 to 56, wherein the at least one fluid passage extends across the sealing element.

58. The packing assembly of any one of claims 39 to 56, wherein the at least one fluid passage extends between the sealing element and an inner surface of the wellbore.

59. The packing assembly of any one of claims 39 to 58, wherein the at least one fluid Date Recue/Date Received 2021-08-10 passage is a single fluid passage.

60. The packing assembly of any one of claims 39 to 58, wherein the at least one fluid passage comprises a plurality of fluid passages distributed radially within the wellbore.

61. The packing assembly of any one of claims 39 to 60, wherein the at least one fluid passage is configured to favor condensed mobilizing fluid flowing down the tubular fluid passage from the injection section into the production section.

62. The packing assembly of any one of claims 39 to 61, wherein the at least one fluid passage is at least one tubular fluid passage being defined either by a tube or by the sealing element.

63. The packing assembly of any one of claims 39 to 61, wherein the at least one fluid passage is 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.

64. The packing assembly of claim 62, wherein the sealing element is 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.

65. The packing assembly of claim 63, wherein the sealing element is 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.

66. The packing assembly of claim 63, wherein the sealing element is 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.

67. The packing assembly of any one of claims 39 to 63, wherein the sealing element is 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.

68. The packing assembly of claim 67, wherein the expandable element is a swellable Date Recue/Date Received 2021-08-10 element comprising an elastomeric material which swells in presence of hydrocarbons and/or water.

69. The packing assembly of any one of claims 39 to 63, wherein the sealing element comprises a sealing mechanism which is a hydraulic, mechanical or interference setting mechanism.

70. The packing assembly of claim 62, wherein the at least one tubular fluid passage is configured to favor condensed mobilizing fluid flowing down the tubular fluid passage from the injection section into the production section.

71. The packing assembly of claim 62 or 70, wherein a cross-section of the tubular fluid passage in a direction perpendicular to the axial direction is of circular, elliptical, trapezoidal, rectangular or star shape.

72. The packing assembly of any one of claims 62 and 70 to 71, wherein the tubular fluid passage has cross-sectional dimensions which vary along the axial direction.

73. The packing assembly of any one of claims 62 and 70 to 72, wherein the at least one tubular fluid passage has 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.

74. The packing assembly of claim 73, wherein the downstream portion of the at least one fluid passage has a cross-sectional diameter which is greater than the upstream portion at a defined ratio.

75. The packing assembly of claim 74, wherein the cross-sectional diameter of the upstream portion of the at least one tubular fluid passage is between 1.5 and times smaller than the cross-sectional diameter of the downstream portion.

76. The packing assembly of any one of claims 62 and 70 to 75, wherein the at least one tubular fluid passage is defined by a tube.

77. The packing assembly of claim 76, wherein the tube extends along the axial direction of the wellbore and across the sealing element.

78. The packing assembly of claim 77, wherein the tube extends across an Date Recue/Date Received 2021-08-10 intermediate part of the sealing element spaced away from both the inner wellbore surface and the outer production conduit surface.

79. The packing assembly of claim 77 or 78, wherein the tube is linear or curvilinear.

80. The packing assembly of claim 76, wherein the tube has a central portion extending along the axial direction of the wellbore and bypassing the sealing element.

81. The packing assembly of claim 80, wherein the tube has 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.

82. The packing assembly of any one of claims 76 to 81, wherein the tube comprises a valve which is actuable to open or close the tubular fluid passage in accordance with an injection pressure in the injection section.

83. The packing assembly of any one of claims 76 to 82, wherein the tube has an inner cross-sectional diameter between 0.5 mm and 30 mm.

84. The packing assembly of any one of claims 76 to 83, wherein the tube has a length between 20 mm and 1000 mm.

85. The packing assembly of any one of claims 49 and 70 to 84, wherein the at least one tubular fluid passage comprises a plurality of tubular fluid passages distributed radially within the single wellbore.

86. The packing assembly of claim 85, wherein the tubular fluid passages are evenly spaced apart from one another.

87. The packing assembly of claim 85 or 86, wherein pairs of fluid passages are symmetric about the axial direction.

88. The packing assembly of any one of claims 62 and 70 to 86, wherein the tubular fluid passages comprise 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.

89. The packing assembly of any one of claims 39 to 88, wherein the injection conduit extends within the production conduit along the axial direction.

90. The packing assembly of claim 89, wherein the injection conduit is concentric with Date Recue/Date Received 2021-08-10 respect to the production conduit.

91. The packing assembly of any one of claims 39 to 90, wherein the mobilizing fluid includes steam, an organic solvent, a surfactant or a combination thereof.

92. The packing assembly of claim 91, wherein the mobilizing fluid includes or consists essentially of the organic solvent that is a C1-05 alkane solvent.

93. The packing assembly of claim 92, wherein the alkane solvent comprises propane, butane or a mixture thereof.

94. The packing assembly of claim 91, wherein the mobilizing fluid is steam.

95. The packing assembly of claim 91, wherein the mobilizing fluid is a mixture of steam and ammonia.

96. 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:
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.

97. The system of claim 96, wherein the packing assembly further includes a gas-limiting device operatively connected to the at least one fluid passage, the gas-Date Recue/Date Received 2021-08-10 limiting device being configured to prevent uncondensed mobilizing fluid from being communicated from the injection section to the production section via the packing assembly.

98. The system of claim 97, wherein the gas-limiting device is the gas-limiting intake as defined in any one of claims 40 to 48.

99. The system of any one of claims 96 to 98, wherein the at least one fluid passage is at least one tubular fluid passage being walled either by a tube or by the sealing element.

100. The system of claim 99, wherein the at least one tubular fluid passage is configured to favor condensed mobilizing fluid flowing down the tubular fluid passage from the injection section into the production section.

101. The system of any one of claims 96 to 98, wherein the at least one fluid passage is 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.

102. The system of claim 96, wherein the packing assembly comprises at least one of the characteristics as defined in any one of claims 39 to 95.

103. The system of any one of claims 96 to 102, wherein the injection conduit includes a tubular injection line having a diameter between 20 mm and 300 mm.

104. The system of claim 103, wherein the diameter of the tubular injection line is between 50 mm and 150 mm.

105. The system of any one of claims 96 to 104, wherein the production conduit includes a tubular production line that has a diameter between 60 mm and 300 mm.

106. The system of claim 105, wherein the diameter of the tubular production line is between 100 mm and 150 mm.

107. The system of any one of claims 96 to 106, wherein a wellbore section has a diameter between 100 mm and 300 mm.

108. The system of any one of claims 96 to 107, wherein the injection conduit axially extends within the production conduit, the injection conduit being concentric with respect to the production conduit.
Date Recue/Date Received 2021-08-10

109. The system of any one of claims 96 to 108, wherein the packing assembly is a first packing assembly located near a distal end of the wellbore, and the system further comprises a second packing assembly located near a proximal end of the wellbore.

110. The system of claim 109, wherein a number of fluid passages in the first packing assembly differs from the number of fluid passages in the second packing assembly.

111. 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.

112. The process of claim 111, wherein the mobilizing fluid is pressurized between 2000 kPa and 17000 kPa at a temperature between 100 C and 350 C
within the injection conduit.

113. The process of claim 111 or 112, wherein discharging the pressurized mobilizing fluid comprises providing sonic choked flow upon discharge of the mobilizing fluid via the at least one injection port.

Date Recue/Date Received 2021-08-10

114. The process of any one of claims 111 to 113, comprising 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.

115. The process of any one of claims 111 to 114, wherein applying the axial pressure differential comprises 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.

116. The process of claim 115, wherein the at least one fluid passage puts the injection section in direct fluid communication with the injection section.

117. The process of claim 115 or 116, wherein the at least one fluid passage is an elongated channel.

118. The process of any one of claims 115 to 117, wherein the at least one fluid passage is at least one walled fluid passage.

119. The process of any one of claims 115 to 118, wherein the at least one fluid passage has a straight portion.

120. The process of any one of claims 115 to 119, wherein the at least one fluid passage has a bent or curved portion.

121. The process of any one of claims 115 to 120, wherein the at least one fluid passage has cross-sectional dimensions which vary along the axial direction.

122. The process of any one of claims 115 to 121, wherein the at least one fluid passage is provided in the wellbore to put the inlet of the at least one fluid passage in fluid communication with a lower portion of the injection section.

123. The process of any one of claims 115 to 122, wherein the at least one fluid passage extends across the packing assembly.

124. The process of any one of claims 115 to 123, wherein the at least one fluid passage extends across the sealing element.

125. The process of any one of claims 115 to 123, wherein the at least one fluid passage extends between the sealing element and an inner surface of the wellbore.

Date Recue/Date Received 2021-08-10

126. The process of any one of claims 115 to 125, wherein the at least one fluid passage is a single fluid passage.

127. The process of claim 126, wherein the at least one fluid passage is an annular fluid passage, and the process comprises 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.

128. The process of any one of claims 115 to 125, wherein the at least one fluid passage comprises a plurality of fluid passages distributed radially within the wellbore.

129. The process of any one of claims 115 to 126 and 128, wherein the at least one fluid passage is at least one tubular fluid passage defined either by a channel across and within the sealing element or by a tube.

130. The process of claim 129, wherein the at least one tubular fluid passage is defined by the tube axially extending across and within the sealing element.

131. The process of claim 129, wherein the at least one tubular fluid passage is defined by a tube bypassing the sealing element, the tube having a circular, elliptical, trapezoidal, rectangular or star shaped inner cross-section.

132. The process of any one of claims 111 to 131, comprising monitoring a pressure into the injection section and compare the pressure to an upper threshold value.

133. The process of any one of claims 111 to 132, comprising limiting uncondensed mobilizing fluid flowing down the at least one fluid passage from the injection section into the production section.

134. The process of claim 133, comprising impeding an inlet region of the at least one fluid passage with a gas-limiting intake having an inlet 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.

135. The process of claim 133, comprising 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.

Date Recue/Date Received 2021-08-10

136. The process of any one of claims 111 to 135, wherein the injection conduit extends concentrically within the production conduit.

137. 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 hydrocarbons from 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 fluid 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:
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 Date Recue/Date Received 2021-08-10 in response to an axial pressure differential therebetween.

138. The packing assembly of claim 137, further comprising 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.

139. The packing assembly of claim 137 or 138, wherein the flexible sleeve is made of a material comprising a metallic element.

140. The packing assembly of any one of claims 137 to 139, wherein the flexible sleeve is made of a material comprising TeflonTm, glass filled TeflonTm, an elastomeric material or a combination thereof.

141. 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.

142. The method of claim 141, wherein allowing axial fluid communication between the injection section and the production section of the wellbore comprises conveying condensed mobilizing fluid through the at least one fluid passage from the injection section into the production section of the wellbore.

143. The method of claim 142, comprising decreasing the production pressure within the production section to activate the flow of the condensed mobilizing fluid through the at least one fluid passage when the injection pressure within the Date Recue/Date Received 2021-08-10 injection section reaches an upper threshold value.

144. The method of claim 143, wherein decreasing the production pressure within the production section comprises increasing the production flow rate.

145. The method of any one of claims 142 to 144, comprising 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.

146. The method of claim 145, wherein increasing the production pressure within the production section comprises decreasing the production flow rate.

147. The method of any one of claims 141 to 146, comprising decreasing the injection flow rate when the injection pressure within the injection section reaches a maximum operating value.

148. The method of any one of claims 141 to 147, comprising monitoring the injection pressure within the injection section.

149. The method of any one of claims 141 to 148, comprising producing the condensed mobilizing fluid conveyed from the injection section into the production section.

150. The method of claim 141, comprising using a packing assembly as defined in any one of claims 1 to 95, and 137 to 140.

151. The packing assembly of any one of claims 39 and 49 to 95, further comprising 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.

152. The packing assembly of claim 151, wherein the gas-limiting discharge comprises:
a discharge chamber in fluid communication with the outlet 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;
at least one outlet port configured to discharge the liquid contained in the discharge chamber into the production section in response to the axial Date Recue/Date Received 2021-08-10 pressure differential.

153. The packing assembly of claim 152, wherein the injection conduit extends within the production conduit and the gas-limiting discharge is rotatable with respect to the production conduit to position the at least one outlet port in a bottom area of the production section.

154. The packing assembly of claim 153, wherein at least a portion of a wall of the discharge chamber is a weighted portion, and the at least one outlet port is 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.

155. The packing assembly of any one of claims 153 or 154, wherein the discharge chamber is an annular discharge chamber surrounding the production conduit.

156. The packing assembly of claim 155, wherein the annular discharge chamber fully occupies an annular space between the production conduit and inner walls of the single wellbore.

157. The packing assembly of any one of claims 152 to 156, wherein the discharge chamber is mounted to the sealing element.

158. The packing assembly of any one of claims 152 to 157, wherein the at least one outlet port is 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 to the production section.

159. The packing assembly of any one of claims 152 to 158, wherein the gas-limiting discharge further includes a floating valve located within the discharge chamber, the floating valve being movable, under the action of buoyancy, between:
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 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.

160. A packing assembly operable in a single wellbore in which an injection conduit and a production conduit extend along an axial direction for recovering Date Recue/Date Received 2021-08-10 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;
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.

161. The packing assembly of claim 160, wherein the gas-limiting device is the gas-limiting intake as defined in any one of claims 40 to 48 or the gas-limiting discharge as defined in any one of claims 151 to 159.

162. The packing assembly of claim 160 or 161, wherein the at least one fluid passage puts the injection section in direct fluid communication with the injection section.

163. The packing assembly of any one of claims 160 to 162, wherein the at least one fluid passage is an elongated channel.

164. The packing assembly of any one of claims 160 to 163, wherein the at least one fluid passage is at least one walled fluid passage.

165. The packing assembly of any one of claims 160 to 164, wherein the at least one fluid passage has a straight portion.

166. The packing assembly of any one of claims 160 to 165, wherein the at least one fluid passage has a bent or curved portion.

167. The packing assembly of any one of claims 160 to 166, wherein the at least Date Recue/Date Received 2021-08-10 one fluid passage has cross-sectional dimensions which vary along the axial direction.

168. The packing assembly of any one of claims 160 to 167, wherein the at least one fluid passage is provided in the wellbore to put the inlet of the at least one fluid passage in fluid communication with a lower portion of the injection section.

169. The packing assembly of any one of claims 160 to 168, wherein the at least one fluid passage extends across the packing assembly.

170. The packing assembly of any one of claims 160 to 169, wherein the at least one fluid passage extends across the sealing element.

171. The packing assembly of any one of claims 160 to 169, wherein the at least one fluid passage extends between the sealing element and an inner surface of the wellbore.

172. The packing assembly of any one of claims 160 to 171, wherein the at least one fluid passage is a single fluid passage.

173. The packing assembly of any one of claims 160 to 171, wherein the at least one fluid passage comprises a plurality of fluid passages distributed radially within the wellbore.

174. The packing assembly of any one of claims 160 to 173, wherein the at least one fluid passage is at least one tubular fluid passage being walled either by a tube or by the sealing element.

175. The packing assembly of claim 174, wherein the at least one tubular fluid passage is configured to favor condensed mobilizing fluid flowing down the tubular fluid passage from the injection section into the production section.

176. The packing assembly of any one of claims 160 to 172, wherein the at least one fluid passage is 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.

177. The system of claim 97, wherein the gas-limiting device is the gas-limiting discharge as defined in any one of claims 151 to 159.

178. The system of claim 96, wherein the packing assembly comprises at least one of the characteristics as defined in any one of claims 151 to 159.

Date Recue/Date Received 2021-08-10

179. The method of claim 141, comprising using a packing assembly as defined in any one of claims 151 to 176.
Date Recue/Date Received 2021-08-10