CA3022710A1

CA3022710A1 - Packing module and related methods for recovering hydrocarbons via a single well

Info

Publication number: CA3022710A1
Application number: CA3022710A
Authority: CA
Inventors: Martin Lastiwka; Alan Watt
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2018-10-31
Filing date: 2018-10-31
Publication date: 2020-04-30
Also published as: CA3060778C; CA3060778A1

Abstract

There are provided implementations of a packing module, related hydrocarbon recovery processes and start-up recovery methods, wherein the packing module 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 tubular 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 MODULE AND RELATED METHODS FOR RECOVERING
HYDROCARBONS VIA A SINGLE WELL
TECHNICAL FIELD
[001] The technical field relates to techniques for recovering hydrocarbons using a single well that can be operated for simultaneous injection and production, and more particularly to a semi-permeable packing module located between an injection section and a production section of the well.
BACKGROUND

[002] According to single-well steam-assisted gravity-drainage (SW-SAGD) techniques, an injection conduit and a production conduit can be located within a single well to simplify and downsize equipment 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.

[003] There is thus a need for a technology that overcomes at least some of the drawbacks of what is known in the field.
SUMMARY

[004] In one aspect, there is provided packing module 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 module 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.

[005] In some implementations, the injection conduit can be concentric with respect to the production conduit.

[006] In some implementations, the at least one tubular fluid passage can include a plurality of tubular fluid passages. 8. The packing module 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.

[007] 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.

[008] 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.

[009] 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.

[010] 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.

[011] 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.

[012] 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.

[013] 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.

[014] 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.

[015] 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.

[016] In some implementations, the annular sealing element can include a sealing mechanism which is a hydraulic, mechanical or interference setting mechanism.

[017] 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 C1-05 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.

[018] In another aspect, there is provided a packing module 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 module 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 tubular 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.

[019] 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.

[020] In some implementations, across-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.

[021] 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.

[022] In some implementations, 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. Optionally, the cross-sectional diameter of the upstream portion of the at least one tubular fluid passage can be between 1.5 and 4 times smaller than the cross-sectional diameter of the downstream portion.

[023] 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.

[024] 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.

[025] 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.

[026] 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.

[027] 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.

[028] 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.

[029] 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.

[030] 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.

[031] In some implementations, the annular sealing element can include a sealing mechanism which is a hydraulic, mechanical or interference setting mechanism.

[032] 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.

[033] 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 01-05 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.

[034] 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 module comprising:
a sealing element axially separating the injection section from the production section and providing a seal therebetween, and at least one tubular 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.

[035] In some implementations, the packing module can include at least one of the characteristics as defined herein.

[036] 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.

[037] In some implementations, the injection conduit can axially extend within the production conduit, the injection conduit being concentric with respect to the production conduit.

[038] 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 tubular 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 tubular 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.

[039] 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.

[040] 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.

[041] 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.

[042] In some implementations, the at least one tubular fluid passage can be defined by a tube axially extending across sealing element.

[043] In some implementations, the at least one tubular fluid passage can be defined by a tube bypassing the sealing element, the tube having a circular, elliptical, trapezoidal, rectangular or star shaped inner cross-section.

[044] In some implementations, the process can include monitoring a pressure into the injection section and compare the pressure to an upper threshold value.

[045] In some implementations, the process can include limiting uncondensed mobilizing fluid flowing down the at least one tubular fluid from the injection section into the production section.

[046] In some implementations, the injection conduit can extend concentrically within the production conduit.

[047] In another aspect, there is provided a packing module 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 module 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 in response to an axial pressure differential therebetween.

[048] In some implementations, the packing module 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.

[049] 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 T" an elastomeric material or a combination thereof.

[050] 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.

[051] 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.

[052] 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.

[053] 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 tubular 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.

[054] 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.

[055] In some implementations, the process can include monitoring the injection pressure within the injection section.

[056] In some implementations, the process can include producing the mobilizing fluid conveyed from the injection section into the production section.

[057] In some implementations, the process can include using a packing module as defined herein.

[058] 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 modules 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.

[059] 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.

[060] In some implementations, the method can include simultaneously performing injection and production once the continuous operation is achieved.

[061] 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.

[062] In some implementations, the method can include monitoring a presence of hydrocarbons in the mobilized fluids that flow via the production sections.

[063] 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.

[064] 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.

[065] In some implementations, the method can include heating the solvent or diluent prior to being supplied into the injection sections.

[066] In some implementations, the method can include the solvent or diluent after soaking.

[067] 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 modules 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.

[068] In some implementations, the method can include alternating the injection of the mobilizing fluid and the production of the mobilized fluids in time.

[069] 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.

[070] In some implementations, the method can include comprising simultaneously performing injection and production once the continuous operation is achieved.

[071] In some implementations, the method can include monitoring a presence of hydrocarbons in the mobilized fluids.

[072] 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.

[073] 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.

[074] In some implementations, the method can include heating the solvent or diluent prior to being injected into the injection sections.

[075] In some implementations, the method can include producing the solvent or diluent after soaking.

[076] In another aspect, 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 modules allowing axial fluid communication between pairs of adjacent production and injection sections, the mobilized fluids including the solvent or diluent and mobilized hydrocarbons.

[077] In some implementations, the method can include heating the solvent or diluent prior to being injected via the injection sections.

[078] 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.

[079] In some implementations, the method can include alternating injection of the mobilizing fluid and production of mobilized fluids over time.

[080] 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.

[081] In some implementations, the method can include simultaneously performing injection and production once the continuous operation is achieved.

[082] 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.

[083] In some implementations, the method can include monitoring a presence of hydrocarbons in the mobilized fluids.

[084] 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.

[085] In some implementations, the solvent or diluent can be injected and left to soak in liquid phase during start-up.
[085a] In another aspect, there is provided a packing module 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 module comprising:

a sealing element axially separating an injection section of the wellbore from a production section of the wellbore, the mobilizing fluid being provided to the hydrocarbon-containing reservoir via the injection section and the mobilized hydrocarbons being produced via the production section;
wherein the sealing element is positionable within the wellbore in:
a sealing position, in which the sealing element seals a wellbore space between the injection section and the production section to prevent fluid communication therebetween via the wellbore; and an open position, in which an annular fluid passage is formed within the wellbore space and along an outer surface of the sealing element, the annular 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.

[086] 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.
14a

[087] 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

[088] 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.

[089] 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.

[090] Figure 3 is a perspective view of an experimental set up including a packing module separating an injection section from a production section of the annulus of a single wellbore.

[091] 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 module in an axial direction of the well.

[092] 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 module in an axial direction of the well.

[093] Figure 6 is an upper view of a wellbore surrounded by a liner and including tubing circumferentially distributed around the wellbore.

[094] Figure 7 is a cross-sectional view along line B-B showing the different elements of a packing module which are located inside or outside of the well bore.

[095] Figure 8 is a semi-transparent side view of a single wellbore showing a packing module cooperating with concentric injection and production conduits.

[096] Figure 9 is a schematic cross-sectional view of a module-fluid passage of a packing module including a flow control device.

[097] Figure 10 is another schematic cross-sectional view of a module-fluid passage of a packing module including a flow control device.

[098] Figure 11 is a cross-sectional side view of a single well bore showing a packing module separating an injection section and a production section of the well, and circulation of a mobilizing fluid and mobilized fluids with operational conditions.

[099] Figure 12 is a schematic cross-sectional view of a packing module separating an injection section and a production section of a single well, and including a sealing element in an expanded state.

[100] Figure 13 is a schematic cross-sectional view of a packing module separating an injection section and a production section of a single well, and including a sealing element in a deactivated state.

[101] Regarding the figures, the following list of numerical references is provided to facilitate reference to the various components that are illustrated:
- reservoir (1) - packing module (2, 20) - liner (4) - mobilizing fluid (5) - mobilizing fluid portions (5a, 5b) - well, well bore, 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) - tubular 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) DETAILED DESCRIPTION

[102] The present description relates to enhanced single-well steam-assisted gravity-drainage (SW-SAGD) techniques, and more particularly to a packing module for use in a well completion. The packing module separates adjacent production and injection sections of the well to avoid 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

[103] 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.

[104] 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 module described herein can form part of the well completion.

[105] 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.

[106] 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).

[107] 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.

[108] 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.

[109] 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.

[110] 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 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.

[111] 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.

[112] Known 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 derive from the use of a packer isolating 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 (lower permeability for the injected mobilizing fluid), thereby potentially reaching a Maximum Operating Pressure (MOP) which can hinder caprock integrity of the reservoir.
Packing module implementations

[113] 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 module providing a designed fluid flow from an injection section to an adjacent production section of the annulus.

[114] In one aspect, there is provided a packing module which axially separates an injection section from an adjacent production section of the well. The packing module includes a sealing element which seals the annular-like space of the well and at least one fluid passage allowing a portion of the mobilizing fluid to flow from the injection section into the adjacent production section in response to an axial injection-production pressure differential. The packing module can therefore provide controlled pressurization of both injection section and production section. It should be noted that the terms "module", "device", "apparatus", "packer" can be used interchangeably within the context of the present description.

[115] 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 module. This axial injection-production pressure differential is to be distinguished from a production pressure differential which is 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.
Packing module including a tubular fluid passage

[116] Figure 4 illustrates an example implementation of a packing module (2) in sealing engagement with the liner (4) of a single well (6) and cooperating with concentric injection and production conduits (8, 10). The packing module (2) includes a downhole sealing element (12) which is secured to the liner (4) of the wellbore to contain fluids and pressures in their respective sections of the well (6). The packing module (2) further includes at least one tubular fluid passage (14) allowing fluids to flow from one side of the packing module (2) to another side of the packing module (2) in response to the axial pressure differential.
Sealing element

[117] 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.

[118] In some implementations, the sealing element is an annular sealing element extending radially and outwardly from the production conduit to axially isolate the injection section with respect to the production section of the wellbore.

[119] 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).

[120] 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.

[121] 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. In other implementations, the expandable 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.

[122] In other implementations, the sealing element can include a pair of opposed sealing rings which define 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 well bore and other components of the well to provide the sealing engagement. Alternatively, single or double-cup sealing members can be used to provide sealing of the annulus by the packing module. Further 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. It should be understood that some sections of the annulus can be provided with a packing module at each end thereof, said sections being exempt of any injection and production ports.

[123] In the implementation shown in Figure 3, the packing module 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 module (2) is provided in a section of the 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.

[124] It should be further noted that Figure 3 only shows a portion of the well completion and that a plurality of annular 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 annular 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 annular sealing elements provided respectively about injection/production conduit portions extending on either side of one production sub can define a production section therebetween.
Tubular fluid passage

[125] 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.

[126] In response to such drawback, the packing module as described herein offers an escape flow path to the condensed mobilizing fluid. In this embodiment, the packing module includes at least one tubular fluid passage enabling fluid communication from one side of the packing module to the other. The sealing elements as described above can be used in combination with the at least one tubular fluid passage.

[127] 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. The tubular fluid passage can be generally cylindrical or have cylindrical portions; and can 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 passages can thus be distinguished from the type of fluid passages that can be formed by the interstices and pores of a particulate solid material.

[128] The tubular fluid passage has an inlet in fluid communication with an injection section of the annulus and an outlet in fluid communication with a production section of the annulus. The condensed mobilizing fluid can therefore be conducted through the at least one tubular fluid passage from the injection section into the production section, so as to be produced via a corresponding production port of the production conduit, thereby reducing formation of a liquid pool in the injection section. The flowrate of the condensed mobilizing fluid through the tubular fluid passage depends on the axial injection-production pressure differential across the packing module (between the injection section and the production section).

[129] 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 well bore 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.

[130] In some implementations, the packing module 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.

[131] In another implementation, the at least one tubular fluid passage can be defined by a tube bypassing the annular sealing element.

[132] Figures 6 and 7 also illustrate a configuration of the packing module (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).

[133] In this implementation where the tubular fluid passage bypasses the annular sealing element, tubing can generally be within the completion and outside the annular sealing element by extending along the liner or casing, within the liner or casing, or within the reservoir itself. Many configuration variations can be encompassed as could be envisioned, as long as a designed fluid communication from an injection section into an adjacent production section of the annulus is enabled.

[134] Figure 5 shows an example implementation of a packing module (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. Fluid passages (14) can be generally distributed radially around the injection conduit (8) and the production conduit (10) within the annular sealing element (12), although the fluid passages could be provided in other arrangements through the sealing element. 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 annular sealing element, such that the fluid passages are positioned near a liquid pool that could form in the injection section of the well.

[135] In an implementation wherein a plurality of packing modules are axially provided along the well, the total open cross-sectional area of the packing module, which is defined by the fluid passages, may vary from one packing module to another packing module 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 module located near a distal end of the well (toe) to a last packing module 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 module may be modified by varying the number of fluid passages or the cross-section of each fluid passage.

[136] In some implementations, 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 module 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 module to a second side, while resisting fluid flow from the second side of the packing module to the first side.

[137] 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 module 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.

[138] 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.

[139] It should be noted that the packing module 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.

[140] 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 module. This configuration enables limiting vapour flow from the injection side to the production side of the packing module. 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.

[141] 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.

[142] 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 module.

[143] 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).

[144] 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.

[145] 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. In addition, downhole pumps having specialized intakes to help reduce vapour inflow and maximizing liquid inflow can be used to feed the tubular fluid passages.

[146] Although implementations illustrated in the Figures show a plurality of tubular fluid passages, the packing module can include a single tubular fluid passage which location can be strategically chosen to further favor passage of condensed mobilizing fluid rather than uncondensed mobilizing fluid.

[147] Although implementations illustrated in the Figures mainly show a concentric configuration where the injection conduit extends along and within the production conduit, one skilled in the art will readily understand that other conduit configurations can be used to implement the packing module, including the production conduit extending along and within the injection conduit.

[148] Related method

[149] Reservoir pressure changes as hydrocarbon-containing fluids (mobilized fluids) are produced from the reservoir. Techniques described herein further provide a method for controlling an axial pressure differential within the annulus of a single well completion, so as to enhance production of the hydrocarbon-containing fluids.

[150] Referring to the implementation illustrated in Figure 11, 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 module (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 module (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).

[151] 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 module 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 module 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.

[152] 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 module and relieving pressure in the injection section.

[153] 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 module 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.

[154] 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.

[155] 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 module 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.

[156] 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.

[157] 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.

[158] 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.
Packing module including a reversibly deformable sealing element

[159] In another embodiment, there is provided another packing module configuration 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 module 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.

[160] Referring to Figures 12 and 13, the packing module (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 module (20) can cooperate with concentric injection and production conduits (8, 10). One skilled in the art will readily understand that the packing module (20) can also cooperate with injection and production subs as detailed above.

[161] Still referring to Figures 12 and 13, the packing module (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 module (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 module (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).

[162] Still referring to Figures 12 and 13, the packing module (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).

[163] 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.

[164] 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.

[165] 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 module to another side of the packing module.

[166] 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.

[167] Figure 13 shows an implementation of the packing module (20) including a sleeve-shaped sealing element (18). The resulting fluid passage (28) can therefore have a generally annular cross. Other designs of sealing elements can be used as long as they enable to reversibly seal the annulus upon activation by fluid pressure.

[168] 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 module (20).

[169] 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.

[170] Still referring to Figures 12 and 13, the packing module (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).

[171] 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).

[172] 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 module. For example, the packing module 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.

[173] 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.

[174] Although not shown in the Figures, implementations described in relation to the packing module (20) including the energizable sealing element (18) could be combined with the implementations described in relation to the packing module (2) including the at least one tubular fluid passage (14). For example, a packing module 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 method

[175] 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 module as above described and disposed between the injection section and the production section.

[176] The method includes injecting a mobilizing fluid into the injection section via the packing module at an injection flow rate, and managing the injection flow rate to control the expansion or deformation of the packing module within the annulus. The injection flow rate can be controlled for example according to the pressure imposed at the well head.

[177] Controlling the expansion or deformation of the packing module 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.

[178] 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 module (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.

[179] 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.

[180] It should be understood that shrinking of the sealing element of the packing module refers to a reduction of the volume of the injection chamber of the packing module. 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.

[181] Packing module 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.

[182] Implementations described in relation to the packing module including at least one tubular fluid passage can be combined with the implementations described in relation to the packing module including at least one injection port. Indeed, the packing module 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 module.
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.

[183] It should be noted that the implementations illustrated in the Figures include one packing module 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 modules as herein described and claimed, isolating injection sections and production sections alternately disposed along the single well.

[184] It should be noted that, as the mobilizing fluid flows across the packing module 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 module 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 module.
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 module 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.

[185] While generally described in relation to single well completions, it should further be noted that certain implementations of the packing module can be used or adapted for other completions, such as dual-well SAGD, or highly-deviated production or infill wells.

[186] It should be noted that configurations of the packing module 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 method

[187] 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.

[188] 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 modules 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.

[189] 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.

[190] 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 modules 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.

[191] 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.

[192] While implementations of the packing module 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 module 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.

[193] 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.

Claims

1. A packing module 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 module 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.

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

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

4. The packing module 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 module 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 module 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 module of any one of claims 1 to 5, wherein the at least one tubular 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 module of any one of claims 1 to 7, comprising from 1 to 30 tubular fluid passages.

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

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

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

17. The packing module of any one of claims 10 to 16, wherein the tube has an inner cross-sectional diameter between 0.5 and 30 mm.

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

19 The packing module of any one of claims 1 to 18, wherein the annular sealing element is an expandable element which expands in response to a stimulus to seal the annular space which axially separates the injection section from the production section.

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

21. The packing module 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 module 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 module 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 module of any one of claims 1 to 23, wherein the mobilizing fluid includes steam, an organic solvent, a surfactant or a combination thereof.

25. The packing module of claim 24, wherein the mobilizing fluid includes or consists essentially of the organic solvent that is a C1-C5 alkane solvent.

26 The packing module of claim 25, wherein the alkane solvent comprises propane, butane or a mixture thereof.

27. The packing module of claim 24, wherein the mobilizing fluid is steam.

28. The packing module of claim 24, wherein the mobilizing fluid is a mixture of steam and ammonia.

29. A packing module 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 module 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 tubular 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.

30. The packing module of claim 29, 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

31. The packing module of claim 29 or 30, 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.

32. The packing module of any one of claims 29 to 31, wherein the tubular fluid passage has cross-sectional dimensions which vary along the axial direction.

33. The packing module of any one of claims 29 to 32, 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

34. The packing module of claim 33, 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

35. The packing module of claim 33 or 34, wherein the cross-sectional diameter of the upstream portion of the at least one tubular fluid passage is between 1.5 and 4 times smaller than the cross-sectional diameter of the downstream portion.

36. The packing module of any one of claims 29 to 35, wherein the at least one tubular fluid passage is defined by a tube

37. The packing module of claim 36, wherein the tube extends along the axial direction of the wellbore and across the sealing element.

38. The packing module of claim 37, wherein the tube extends across an intermediate part of the sealing element spaced away from both the inner wellbore surface and the outer production conduit surface.

39. The packing module of claim 37 or 38, wherein the tube is linear or curvilinear.

40. The packing module of claim 36, wherein the tube has a central portion extending along the axial direction of the wellbore and bypassing the sealing element.

41. The packing module of claim 40, 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

42. The packing module of any one of claims 36 to 41, 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.

43. The packing module of any one of claims 36 to 42, wherein the tube has an inner cross-sectional diameter between 0 5 mm and 30 mm.

44. The packing module of any one of claims 36 to 43, wherein the tube has a length between 20 mm and 1000 mm.

45 The packing module of any one of claims 29 to 44, wherein the at least one tubular fluid passage comprises a plurality of tubular fluid passages distributed radially within the single wellbore.

46. The packing module of claim 45, wherein the tubular fluid passages are evenly spaced apart from one another.

47. The packing module of claim 45 or 46, wherein pairs of fluid passages are symmetric about the axial direction.

48. The packing module of any one of claims 45 to 47, 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.

49. The packing module of any one of claims 29 to 48, wherein the sealing element is an expandable element which expands in response to a stimulus to seal the annular space which axially separates the injection section from the production section, the stimulus comprising swelling conditions, axial compression, pressure in the injection conduit or a combination thereof.

50. The packing module of claim 49, wherein the expandable element is a swellable element comprising an elastomeric material which swells in presence of hydrocarbons and/or water

51. The packing module of claim 49, 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.

52. The packing module of any one of claims 29 to 48, wherein the annular sealing element comprises a sealing mechanism which is a hydraulic, mechanical or interference setting mechanism.

53. The packing module of any one of claims 29 to 52, wherein the injection conduit extends within the production conduit along the axial direction.

54. The packing module of claim 53, wherein the injection conduit is concentric with respect to the production conduit

55. The packing module of any one of claims 29 to 54, wherein the mobilizing fluid comprises steam, an organic solvent, a surfactant or a combination thereof.

56. The packing module of claim 55, wherein the mobilizing fluid comprises or consists essentially of the organic solvent that is a C1-C5 alkane solvent

57. The packing module of claim 56, wherein the alkane solvent comprises propane, butane or a mixture thereof.

58. The packing module of claim 55, wherein the mobilizing fluid is steam.

59. The packing module of claim 55, wherein the mobilizing fluid is a mixture of steam and ammonia.

60. 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 module comprising:
a sealing element axially separating the injection section from the production section and providing a seal therebetween, and at least one tubular 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.

61. The system of claim 60, wherein the packing module comprises at least one of the characteristics as defined in any one of claims 29 to 59.

62. The system of claims 60 or 61, wherein the injection conduit comprises a tubular injection line having a diameter between 20 mm and 300 mm.

63. The system of claim 62, wherein the diameter of the tubular injection line is between 50 mm and 150 mm.

64. The system of any one of claims 60 to 63, wherein the production conduit comprises a tubular production line that has a diameter between 60 mm and 300 mm.

65. The system of claim 64, wherein the diameter of the tubular production line is between 100 mm and 150 mm.

66. The system of any one of claims 60 to 65, wherein a wellbore section has a diameter between 100 mm and 300 mm.

67. The system of any one of claims 60 to 66, wherein the injection conduit axially extends within the production conduit, the injection conduit being concentric with respect to the production conduit.

68. 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 tubular 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 tubular 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.

69. The process of claim 68, 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.

70. The process of claim 68 or 69, wherein discharging the pressurized mobilizing fluid comprises providing sonic choked flow upon discharge of the mobilizing fluid via the at least one injection port.

71. The process of any one of claims 68 to 69, 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.

72. The process of claim 71, wherein the at least one tubular fluid passage is defined by a tube axially extending across sealing element.

73. The process of claim 71, 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.

74. The process of any one of claims 68 to 73, comprising monitoring a pressure into the injection section and compare the pressure to an upper threshold value.

75. The process of any one of claims 68 to 64, comprising limiting uncondensed mobilizing fluid flowing down the at least one tubular fluid from the injection section into the production section.

76. The process of any one of claims 68 to 75, wherein the injection conduit extends concentrically within the production conduit.

77. A packing module 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 module 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 in response to an axial pressure differential therebetween.

78. The packing module of claim 77, 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.

79. The packing module of claim 77 or 78, wherein the flexible sleeve is made of a material comprising a metallic element.

80. The packing module of any one of claims 77 to 79, wherein the flexible sleeve is made of a material comprising Teflon TM, an elastomeric material or a combination thereof.

81. 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.

82. The method of claim 81, 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.

83. The method of claim 82, comprising 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.

84. The method of claim 83, wherein decreasing the production pressure within the production section comprises increasing the production flow rate.

85. The method of any one of claims 82 to 84, 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.

86. The method of claim 85, wherein increasing the production pressure within the production section comprises decreasing the production flow rate.

87. The method of any one of claims 81 to 86, comprising decreasing the injection flow rate when the injection pressure within the injection section reaches a maximum operating value.

88. The method of any one of claims 81 to 88, comprising monitoring the injection pressure within the injection section.

89. The method of any one of claims 81 to 88, comprising producing the mobilizing fluid conveyed from the injection section into the production section.

90. The method of claim 81, comprising using a packing module as defined in any one of claims 1 to 59

91. 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 modules 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.

92. The start-up method of claim 91, comprising increasing a quantity of the mobilizing fluid to be injected at each injection section over time until continuous operation is achieved.

93. The start-up method of claim 92, comprising simultaneously performing injection and production once the continuous operation is achieved.

94. The start-up method of any one of claims 91 to 93, wherein injection of the mobilizing fluid is performed at a temperature below saturation conditions to maintain the mobilizing fluid in condensed phase upon injection into the injection sections.

95. The start-up method of claim 93, comprising monitoring a presence of hydrocarbons in the mobilized fluids that flow via the production sections.

96. The start-up method of claim 95, comprising 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.

97. The start-up method of any one of claims 91 to 96, comprising 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.

98. The start-up method of claim 97, comprising heating the solvent or diluent prior to being supplied into the injection sections.

99. The start-up method of claim 97 or 98, comprising producing the solvent or diluent after soaking.

100. A 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 modules 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.

101. The start-up method of claim 100, further comprising alternating the injection of the mobilizing fluid and the production of the mobilized fluids in time

102. The start-up method of claim 101, further comprising increasing a quantity of the mobilizing fluid to be injected at each injection section over time until continuous operation is achieved.

103. The start-up method of claim 102, further comprising simultaneously performing injection and production once the continuous operation is achieved.

104. The start-up method of any one of claims 100 to 103, further comprising monitoring a presence of hydrocarbons in the mobilized fluids.

105. The start-up method of claim 104, further comprising 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

106. The start-up method of any one of claims 100 to 105, further comprising 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.

107. The start-up method of claim 106, further comprising heating the solvent or diluent prior to being injected into the injection sections.

108. The start-up method of claim 106 or 107, further comprising producing the solvent or diluent after soaking

109. A 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 modules allowing axial fluid communication between pairs of adjacent production and injection sections, the mobilized fluids including the solvent or diluent and mobilized hydrocarbons.

110. The start-up method of claim 109, further comprising heating the solvent or diluent prior to being injected via the injection sections.

111. The start-up method of claim 109 or 110, further comprising 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.

112. The start-up method of claim 111, further comprising alternating injection of the mobilizing fluid and production of mobilized fluids over time

113. The start-up method of claim 112, further comprising increasing a quantity of the mobilizing fluid to be injected at each injection section over time until continuous operation is achieved.

114. The start-up method of claim 113, further comprising simultaneously performing injection and production once the continuous operation is achieved.

115. The start-up method of any one of claims 111 to 113, wherein injection of the mobilizing fluid is performed at a temperature below saturation conditions to maintain the mobilizing fluid in condensed phase upon injection into the injection sections

116. The start-up method of claim 115, further comprising monitoring a presence of hydrocarbons in the mobilized fluids.

117. The start-up method of claim 115 or 116, further comprising 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.

118. The start-up method of any one of claims 109 to 117, wherein the solvent or diluent is injected and left to soak in liquid phase during start-up.

119. A packing module 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 module comprising:
a sealing element axially separating an injection section of the wellbore from a production section of the wellbore, the mobilizing fluid being provided to the hydrocarbon-containing reservoir via the injection section and the mobilized hydrocarbons being produced via the production section;
wherein the sealing element is positionable within the wellbore in:
a sealing position, in which the sealing element seals a wellbore space between the injection section and the production section to prevent fluid communication therebetween via the wellbore; and an open position, in which an annular fluid passage is formed within the wellbore space and along an outer surface of the sealing element, the annular 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.

120. The packing module of claim 119, wherein the sealing element is a flexible sleeve having at least a portion which outwardly deflects to seal the wellbore space upon being pressurized by the mobilizing fluid flowing in the injection conduit.

121. The packing module of claim 119 or 120, wherein the injection conduit extends within the production conduit along the axial direction.

122. The packing module of claim 121, wherein the injection conduit is concentric with respect to the production conduit.

123. The packing module of any one of claims 119 to 122, wherein the mobilizing fluid comprises steam, an organic solvent, a surfactant, or a combination thereof.

124. The packing module of claim 123, wherein the mobilizing fluid comprises the organic solvent that is a C1-C5 alkane solvent.

125. The packing module of claim 123, wherein the mobilizing fluid consists essentially of the organic solvent that is a C1-C5 alkane solvent.

126. The packing module of claim 124 or 125, wherein the alkane solvent comprises propane, butane or a mixture thereof.

127. The packing module of claim 123, wherein the mobilizing fluid is steam.

128. The packing module of claim 123, wherein the mobilizing fluid is a mixture of steam and ammonia.

129. The method of claim 81, comprising using a packing module as defined in any one of claims 77 to 80.

130. The method of claim 81, comprising using a packing module as defined in any one of claims 119 to 128.