CA3050701C

CA3050701C - Hydrocarbon recovery with injection of pressurized fluid and production via single well

Info

Publication number: CA3050701C
Application number: CA3050701A
Authority: CA
Inventors: Martin Lastiwka; Alan Watt
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2017-05-01
Filing date: 2017-05-01
Publication date: 2021-12-07
Anticipated expiration: 2037-05-01
Also published as: CA3050701A1; CA2965633A1; CA2965633C

Abstract

A process for recovering hydrocarbons from a reservoir can include providing an injection conduit and a production conduit in a same horizontal wellbore section, and having spaced-apart injection ports offset with production ports; delivering a pressurized mobilizing fluid into the injection conduit so as to be in substantially liquid phase within the injection conduit; discharging the pressurized mobilizing fluid into the reservoir through the injection ports to at least partially vaporise into a gas phase upon discharge to contact and mobilize the hydrocarbons in the reservoir; and recovering a production fluid comprising mobilized hydrocarbons via the production ports of the production conduit. The mobilizing fluid can include water or organic solvent. The injection and production conduits can be part of a concentric assembly. The process can facilitate enhanced operations over traditional methods, such as conventional steam- assisted gravity drainage (SAGD) using steam injection and a well pair.

Description

I
HYDROCARBON RECOVERY WITH INJECTION OF PRESSURIZED FLUID AND
PRODUCTION VIA SINGLE WELL
TECHNICAL FIELD
[001] The technical field generally relates to in situ hydrocarbon recovery operations and, more particularly, to hydrocarbon recovery using the injection of a pressurized fluid which may be done via a single well.
BACKGROUND

[002] In situ hydrocarbon recovery operations can use high temperature fluids for injection into a hydrocarbon-bearing reservoir. The hot injected fluids heat the hydrocarbons in the reservoir, reducing the viscosity and increasing the mobility of the hydrocarbons to facilitate production. The produced fluids that are recovered from the reservoir can then be separated to generate a hydrocarbon-enriched stream and a hydrocarbon-depleted stream.
Various techniques have been developed to enhance mobilization of hydrocarbons by injection of a mobilizing fluid.

[003] In conventional steam-assisted gravity drainage (SAGD) processes, a well pair is drilled into the reservoir such that a horizontal injection well is vertically spaced above a horizontal production well. Steam is injected into the reservoir via the horizontal injection well in order to heat and mobilize hydrocarbons in the reservoir. Mobilized hydrocarbons flow by gravity toward the horizontal production well, and are then produced to the surface for processing. There are various challenges and drawbacks with respect to drilling, completing and operating such a SAGD well pair.
SUMMARY

[004] In some implementations, there is provided a process for recovering hydrocarbons from a reservoir, the process comprising: providing an injection conduit and a production conduit extending within a horizontal wellbore section, the injection conduit comprising a plurality of spaced-apart injection ports along a length thereof, and the production conduit comprising a plurality of spaced-apart production ports that are off-set with respect to the injection ports; delivering a pressurized mobilizing fluid into the injection conduit so as to be in substantially liquid phase within the injection conduit; discharging the pressurized mobilizing fluid into the reservoir through the injection ports of the injection conduit, the pressurized mobilizing fluid at least partially vaporizing into a gas phase upon discharge to contact and mobilize the hydrocarbons in the reservoir; and recovering a production fluid comprising mobilized hydrocarbons via the production ports of the production conduit.

[005] In some implementations, discharging the pressurized mobilizing fluid comprises providing a sufficient pressure drop across the injection ports to at least partially vaporize the mobilizing fluid upon discharge into the reservoir.

[006] In some implementations, the process includes heating the mobilizing fluid before delivery into the reservoir. In some implementations, the heating of the mobilizing fluid is performed before, after or during the pressurizing the mobilized fluid. In some implementations, the mobilizing fluid includes water, an organic solvent, or a combination thereof. In some implementations, the mobilizing fluid includes or consists essentially of the organic solvent that is a Cl-05 alkane solvent. In some implementations, the alkane solvent comprises propane, butane or a mixture thereof. In some implementations, the mobilizing fluid is water. In some implementations, the mobilizing fluid is a mixture of water and organic solvent.

[007] In some implementations, the mobilizing fluid is pressurized between 3 MPa and 16 MPa at a temperature between 100 C and 350 C within the injection conduit.

[008] In some implementations, the process includes delivering multiple different mobilizing fluids into the injection conduit. In some implementations, multiple independent injection conduits are provided within the horizontal section of the well, and the process comprises delivering multiple mobilizing fluids into the respective multiple injection conduits.

[009] In some implementations, the injection conduit includes a tubular injection line that has a diameter between 20 mm and 300 mm. In some implementations, the diameter of the tubular injection line is between 50 mm and 150 mm. In some implementations, the production conduit includes a tubular production line that has a diameter between 60 mm and 200 m. In some implementations, the diameter of the tubular injection line is between 100 mm and 150 mm. In some implementations, the horizontal well bore section has a diameter between 100 mm and 300 m.

[010] In some implementations, discharging the pressurized mobilizing fluid comprises providing sonic choked flow upon discharge of the mobilizing fluid. The sonic choked flow can be provided by configuring or controlling flow control devices located at each injection port.

[011] In some implementations, the process further includes inhibiting production of the gas phase of the mobilizing fluid via the production ports. The inhibiting of production of the gas phase can include configuring or controlling flow control devices located at each production port, providing packers or isolation devices in between adjacent injection ports and production ports to inhibit gas flow therebetween, and/or directing gas flow from the injection ports away from adjacent production ports.

[012] In some implementations, the process includes applying a pressure differential in an axial direction along the well to form alternating lower-pressure regions and higher-pressure regions in the reservoir. The applying of the axial pressure differential can cindlue providing an injection pattern tailored to a given axial pressure differential to produce the alternate higher-pressure regions and lower-pressure regions within the reservoir, configuring and operating the injection ports to inject the gas phase of the mobilizing fluid in axial directions away from the production ports that are adjacent to the respective injection ports, placing at least one packer between an injection location and an adjacent production location.

[013] In some implementations, the injection conduit and the production conduit are provided as a concentric injection-production assembly. The concentric injection-production assembly can include an inner injection tube defining the injection conduit for transmitting the mobilizing fluid; an outer tube concentric with the inner tube and defining therebetween an annular passageway as the production conduit, the outer tube fluidly communicating with the production ports to receive and transmit the production fluid therethrough; and a fluid passage fluidly connecting the inner tube to the injection ports for discharge of the mobilizing fluid therethrough.

[014] The concentric injection-production assembly can include an injection module including a chamber outside of the outer tube and being in fluid communication with the fluid passage for receiving the mobilizing fluid. The injection ports can be provided on the injection module so that the mobilizing fluid can flow through the chamber and be discharged from the injection ports. Multiple injection modules can be provided in spaced relation along the concentric injection-production assembly. Each module of the concentric injection-production assembly can include a tubular wall that is generally concentric with the outer tube and defines the chamber. The tubular wall of each module of the concentric injection-production assembly can have two opposed spaced-apart rings. The injection ports can be provided on the rings of the module, and the injection ports can be positioned and oriented to provide two opposed sets of injection ports on opposed axial sides of each module. The two opposed sets of injection ports can be positioned and oriented to inject the mobilizing fluid toward each other.

[015] In some implementations, the horizontal well section follows a variable base elevation along a length thereof and is positioned proximate to the base of the reservoir.
The horizontal well section is located at a substantially constant distance away from the base along the length thereof.

[016] In some implementations, there is provided a process for recovering hydrocarbons from a reservoir, the process comprising: delivering a pressurized mobilizing fluid into an injection conduit extending within a horizontal wellbore section so as to be in substantially liquid phase within the injection conduit, the injection conduit comprising a plurality of spaced-apart injection ports along a length thereof; discharging the pressurized mobilizing fluid into the reservoir through the injection ports of the injection conduit, the pressurized mobilizing fluid at least partially vaporizing into a gas phase upon discharge to contact and mobilize the hydrocarbons in the reservoir; and recovering a production fluid comprising mobilized hydrocarbons via a production conduit located in the horizontal wellbore section and comprising a plurality of spaced-apart production ports that are off-set with respect to the injection ports of the injection conduit.
[016a] In another implementation, there is provided a process for recovering hydrocarbons from a reservoir wherein an injection conduit and a production conduit extend through the reservoir in an axial direction, the process comprising:
delivering a mobilizing fluid into the injection conduit;
providing a pressure differential in the axial direction of the reservoir to form alternating lower-pressure regions and higher-pressure regions along the injection conduit, wherein providing the pressure differential comprises discharging the mobilizing fluid into the higher-pressure regions of the reservoir via the injection conduit; and Date Recue/Date Received 2021-02-26 4a producing mobilized hydrocarbons from the lower-pressure regions of the reservoir via the production conduit, wherein the producing comprises drainage of the mobilized hydrocarbons into the production conduit.

[017] In some implementations, there is provided a process for recovering hydrocarbons from a reservoir, the process comprising: discharging a pressurized mobilizing fluid into the reservoir via an injection conduit extending within a horizontal well, wherein a pressure differential between the injection conduit and the reservoir induces liquid to gas phase transition of at least a portion of the mobilizing fluid upon discharge thereof into the reservoir; mobilizing the hydrocarbons using the injected gas phase of the mobilizing fluid to form a production fluid comprising mobilized hydrocarbons; and producing the production fluid via a production conduit extending within the horizontal well.
Date Recue/Date Received 2021-02-26

[018] It is noted that various features mentioned above or herein can be combined with such process implementations.

[019] In some implementations, there is provided a process for recovering hydrocarbons from a reservoir wherein an injection conduit and a production conduit extend through the reservoir in an axial direction and are provided as a concentric injection -production assembly comprising: an inner injection tube defining the injection conduit for transmitting the mobilizing fluid; an outer tube concentric with the inner tube and defining therebetween an annular passageway as the production conduit, the outer tube fluidly communicating with production ports to receive and transmit the production fluid therethrough;
and a fluid passage fluidly connecting the inner tube to injection ports for discharge of the mobilizing fluid therethrough; the process comprising: delivering a mobilizing fluid into the inner injection tube; providing a pressure differential in the axial direction of the reservoir to form alternating lower-pressure regions and higher-pressure regions along the injection conduit, wherein providing the pressure differential comprises discharging the mobilizing fluid into the higher-pressure regions of the reservoir via the injection ports; and producing mobilized hydrocarbons from the lower-pressure regions of the reservoir via the production ports.

[020] In some implementations, the mobilizing fluid is delivered in liquid phase into the injection conduit and at least partially vaporizes during discharge through the injection ports into the reservoir, such that the vaporized gas phase facilitates formation of the high-pressure regions.

[021] In some implementations, there the injection conduit and the production conduit are deployed within in a same horizontal wellbore section. Such implementation can include additional features as described above and herein.

[022] In some other implementations, the injection conduit and the production conduit are respectively deployed within two different well sections. The two well sections can include a horizontal injection well accommodating the injection conduit, and a horizontal production well located generally vertically below the injection well and accommodating the production conduit, the horizontal injection well and the horizontal production well forming a horizontal well pair. The horizontal production well and the horizontal injection well can extend from the same vertical well section or from two distinct vertical well sections.
The two-well implementation can have various features as described herein that are applicable to a two-well configuration.

[023] It is also noted that there are various systems provided for implementing processes described herein. For example, a system for recovering hydrocarbons can include a well that includes injection and production conduits extending along a horizontal well section, injection and production ports that are optionally offset from one another, a pressurization unit for pressurizing a mobilizing fluid for transmitting the fluid in liquid phase via the injection conduit, the injection ports being configured to enable vaporization of at least a portion of the mobilizing fluid upon discharge into the reservoir. The system can also include modules, an injection-production conduit assembly, and various other units as described herein.

[024] While aspects of the process will be described in conjunction with example implementations, it will be understood that it is not intended to limit the scope of the process to such implementations. On the contrary, it is intended to cover all alternatives, modifications and equivalents as may be included as defined by the present description.
The objects, advantages and other features of the process 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

[025] Figure 1 is a schematic drawing of hydrocarbon recovery equipment and operation via a single well.

[026] Figure 2 is a simulated cross-section of the gas chamber along an axial direction of a reservoir and at three different times.

[027] Figure 3 is a schematic cross-section of a gas chamber surrounding a single well along a vertical direction of a reservoir.

[028] Figures 4A and 4B are schematic drawings of two process configurations for fluid injection.

[029] Figure 5 is a schematic drawing of a hydrocarbon recovery process including a controlling unit.

[030] Figure 6 is a schematic drawing of an injection conduit and a production conduit according to an operation pattern.

[031] Figure 7 is a schematic drawing of an injection conduit and a production conduit according to another operation pattern.

[032] Figure 8 is a schematic drawing of an injection conduit and a production conduit according to yet another operation pattern.

[033] Figure 9 is a schematic drawing of hydrocarbon recovery equipment and operation via a single well including injection modules.

[034] Figure 10 is a schematic perspective view of an injection module.

[035] Figure 11 is another schematic drawing of hydrocarbon recovery equipment and operation via a single well including concentric injection and production lines with packers.

[036] Figure 12 is a schematic perspective view of another injection module with concentric injection and production lines.

[037] Figure 13 is a simulated cross-section of a section of a reservoir including a growing steam chamber when recovering hydrocarbons with SAGD.

[038] Figure 14 is a simulated cross-section of a section of a reservoir when recovering hydrocarbons via a single well in operation conditions similar to SAGD.

[039] Figure 15 is a simulated temperature profile of a well portion between two well bore points and at a well-reservoir interface.

[040] Figure 16 is a simulated mass flow production profile of the same well portion as per Figure 12 and at a well-reservoir interface.

[041] Figure 17 is a graph of oil production in m3/day for simulated oil recovery via a single well operation with comparative three different axial pressure differences (high dP, medium dP, and low dP) and via SAGD operation.

[042] Figure 18 is a graph of oil production in m3/day for simulated oil recovery via a single well operation with two different axial pressure differences (high dP and low dP) and a packer.

[043] Figure 19 is another schematic drawing of hydrocarbon recovery equipment and operation via a single well including concentric injection and production lines.

[044] Figures 20A to 20E are cross-sectional side view schematics illustrating various configurations of part of a production-injection conduit assembly having an injection module.
DETAILED DESCRIPTION

[045] Implementations of processes and systems for recovering hydrocarbons from a sub-surface hydrocarbon-bearing reservoir are provided. A fluid, including water and/or solvent, can be heated and pressurized so as to travel in liquid phase and be delivered in gas phase into the reservoir, thereby providing various advantages, such as downsizing of surface and sub-surface equipment. Utilizing liquid phase delivery of the mobilizing fluid via a single well that is also used to produce mobilized hydrocarbons from the reservoir facilitates advantages related to efficient deployment and operation of hydrocarbon recovery wells.

[046] Hydrocarbons are contained in porous or fractured rock formations having high porosity, which keeps the viscous hydrocarbons immobile under existing reservoir conditions. Hydrocarbons may be referred to or understood as oil or bitumen.
The reservoir can include, for example, a heavy oil reservoir (where the oil is initially mobile), an oil sands reservoir, a tar sands reservoir or any bituminous sands reservoir having an exploitable pay zone.

[047] To mobilize the hydrocarbons, the process includes injecting the heated and pressurized fluid via an injection conduit and into the reservoir. The fluid in liquid phase under the injection conduit conditions vaporizes upon exiting the injection conduit under the reservoir conditions. A gas chamber is thereby created and expands laterally outwardly within the reservoir. It should be noted that the gas 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 gas chamber can be referred to as a steam chamber. Within the gas chamber, higher gas-phase saturation will be at the center while at the boundaries of the gas 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 gas chamber is transmitted to the hydrocarbons, which lowers their viscosity to enable drainage thereof. It should be noted that, in the case where a solvent is used as a pressurized fluid, hydrocarbon viscosity can be reduced when the solvent dissolves in the in-place hydrocarbons (as opposed to simply heating the hydrocarbon). For soluble solvents, the hydrocarbons can be mobilized from both increased temperature and dilution effects. The condensed or dissolved gas phase and mobilized hydrocarbons are then produced, and can be referred to together as the production fluid.
The acceleration due to gravity will cause the production fluid to move downward along the draining edges of the gas chamber and into a production conduit. The process further includes production of the mobilized hydrocarbons via the production conduit.

[048] In some implementations, the injection conduit and the production conduit can be located within a same well bore and are thus part of a single well. As the fluid to be injected is pressurized sufficiently to be in liquid phase, a smaller conduit can be used for injection in comparison to a typical SAGD operation. The injection conduit and the production conduit can be located within the single well to further simplify and downsize equipment. The single well configuration can also have certain economic advantages, since the drilling, maintenance and operational costs can be reduced compared to a dual well configuration.
However, proximity of the injection conduit and the production conduit present challenges, such as production of the injected gas phase via the production conduit.
Various solutions are described hereinafter to address such challenges.

[049] In other implementations, the injection conduit and the production conduit may be located in an injection well and a production well respectively, as in a traditional dual well configuration, e.g. a well pair in a SAGD, configuration. Other configuration are also possible, such as providing a SAGD well pair in which at least one of the wells is completed with injection-production capabilities so as to be operable as a single well during certain stages of the operation.
Injection implementations

[050] Implementations of injection of a heated and pressurized mobilizing fluid via an injection conduit into a sub-surface reservoir are described in further detail below.

Water and/or solvent

[051] It should be noted that the term fluid refers to a substance or a mixture having the ability to flow. Depending on the conditions within the conduits or the reservoir, the fluid may be in liquid state, referred to as the liquid phase, or in a gaseous state, referred to as the gas phase.

[052] In some implementations, the mobilizing fluid can include water, an organic solvent or a mixture thereof. Optionally, the organic solvent can be a lower alkane solvent, including propane and/or butane, which is compressible to a transportable liquid. The mobilizing fluid can also include other chemical compounds in various concentrations.

[053] Water and solvent may be mixed in a ratio between 5:1 and 12:1, optionally between 7:1 and 11:1, and further optionally around 10:1. It should be noted that solvent only may be used as an injection fluid, where the produced fluids can have a solvent-to-oil ratio optionally between 3:1 and 9:1, further optionally between 5:1 and 7:1. Thus, various ratios of solvent and water can be used for injection.

[054] In some implementations, the solvent and water are combined together using equipment at surface facilities, and then the solvent-water mixture is injected as the heated pressurized fluid. The mixing, heating and pressurization steps can be conducted in various orders and using various units and equipment.
Downhole liquid-to-gas phase

[055] The process can take advantage of the injection of the mobilizing fluid in liquid state from the surface and transitioning to a gaseous state upon being subjected to reservoir conditions.

[056] Referring to Figure 1, hydrocarbons are contained within an in-situ reservoir 2, in which a wellbore 4 has been drilled. It should be noted that various completions can be provided, including casings and liners, within different sections of the wellbore 4. Recovery of the hydrocarbons involves flowing of the mobilizing fluid in liquid phase via an injection conduit 6. The injection conduit 6 extends downwardly from the surface within a vertical section of the wellbore 4 and then horizontally within a horizontal section of the wellbore 4 located in reservoir 2 at a desired depth.

[057] It should be noted that in the implementation illustrated in Figure 1, a cased-hole completion can be provided for the well, including the wellbore 4 containing a first portion of both injection and production conduits, and a liner 5 extending horizontally from a distal end of the well bore and containing both the injection and production conduits.
The liner 5 can be slotted, screened, or perforated to enable fluid communication with the reservoir.
Variations in the well completion design may exist as available to one skilled in the art. It is also noted that for some reservoirs the injection and production conduits can be located within the horizontal section of the wellbore without a liner.

[058] Implementations of the process include maintaining the fluid substantially in liquid state while flowing within the injection conduit. The mobilizing fluid in liquid phase then experiences a liquid-to-gas phase change when exiting the injection conduit at a downhole location, and the gas phase fluid enters the reservoir.

[059] It should be noted that the mobilizing fluid may not be fully in liquid phase and may vaporize to some extent or include some vapour phase within the injection conduit depending on the temperature and pressure conditions that are maintained within the injection conduit. The term "substantially" is therefore used to reflect this behavior of the fluid.

[060] It should be further noted that the mobilizing fluid, depending on the nature of its components, may not fully vaporize upon discharge via the injection conduit.
In this case, a gas-liquid mixture may be discharged into an annulus of the well at a lower temperature and pressure than in the injection conduit. The gas phase can exit the well through buoyancy-drive, whereas the liquid phase mainly remains within the horizontal section of the wellbore.

[061] Heat conduction is part of the oil recovery mechanisms. Therefore, the mobilizing fluid can be heated to subsequently provide at least part of this heat to the hydrocarbons and reduce viscosity thereof. In some implementations, pre-heating equipment located at the surface may be used to pre-heat the fluid to an adequate temperature before being made to flow within the injection conduit. For example, referring to Figure 1, produced water 102 may be used as low quality steam in a heating unit 24, such as a heat exchanger. In other implementations, the fluid may be alternatively or additionally heated downhole within the injection conduit prior to being discharged within the reservoir. For example, downhole heating may be effected through a closed-loop circulation of a heating fluid, such as a hot oil; through the use of electric resistance-based heating (e.g., in the form of heating cables);
or through the use of downhole electric induction heaters or other types of heaters that can be deployed downhole.

[062] To maintain the heated fluid in substantially liquid phase, the process further includes pressurizing the heated fluid within an adequate pressure range. It should be noted that the conditions of pressure and temperature imposed in the injection conduit may vary according to the nature of the fluid used to mobilize the hydrocarbons.
Referring to Figure 1, a pressurization unit 26 can be provided at the surface to pressurize the mobilizing fluid before delivery into the injection conduit 6. For example, a pump may be used and configured to put the fluid under adequate pressure for maintaining a liquid state. It should further be understood that various equipment available to one skilled in the art may be used to impose a given desired pressure to the injected fluid, including for example a horizontal electric pump. Depending on the configuration of the at-surface equipment, various structural and operational features can be implemented to maintain and/or impart the desired temperature and pressure to the fluid to be injected. It should further be noted that heating and pressurizing may be performed simultaneously or in any order suited to fulfill adequate operation conditions for the injection. The pressure can be provided based on the composition and the temperature of the fluid that is injected, as well as the fluid dynamic properties of the injection conduit (e.g., friction, internal diameter, length, pressure loss), to facilitate the mobilizing fluid to be in substantially liquid state until discharge into the reservoir.

[063] For example, water may be heated to a temperature between 200 C and 350 C, and pressurized between 3 MPa and 16 MPa. Optionally, water may be heated to about 315 C and pressurized at about 11 MPa. In another example, butane may be heated to a temperature between 100 C and 200 C and pressurized between 3 MPa and 5 MPa.
Optionally, butane may be heated to about 150 C and pressurized at about 4 MPa. It is noted that the pressure and temperature conditions and/or fluid composition can be modified over time, for example at different stages of the hydrocarbon recovery operation.

[064] The pressure differential existing between the injection conduit and the reservoir allows for downhole vaporization of the mobilizing fluid from liquid phase to gas phase upon discharge into the reservoir via the injection conduit. Pressure differentials can be monitored using various pressure sensors, estimated, and regulated by adjusting various parameters of the process.

[065] It should be understood that implementations of the process and the injection conduit are not limited to flowing a liquid for flashing upon injection into the reservoir.
Optionally, some implementations of the process can include flowing a high-pressure mobilizing gas phase fluid (e.g., high-pressure steam) within the injection conduit and distributing the steam along the conduit through the injection ports.
Injection equipment implementations

[066] Referring to Figure 1, the injection of the mobilizing fluid can include injection via a plurality of injection ports 8 providing sufficient pressure drop to vaporize the fluid entering the reservoir. The injection ports 8 are provided along a horizontal section of the injection conduit 6 to enable axial distribution of the gas phase within the reservoir.
The injection ports 8 may be spaced apart from one another in a regular pattern to promote spreading of the generated gas phase within the reservoir 2. As better seen on Figure 2, the spreading pattern of the injected gas phase may change over time as the gas chambers grow and coalesce.

[067] It should be noted that the injection ports 8 can be spaced unevenly along the injection conduit at strategic and/or pre-determined locations. The positioning of the injection ports 8 can be based on various factors, such as reservoir characteristics (e.g., geological barriers, hydrocarbon distribution within pay zone, etc.) or fluid dynamic properties of the mobilizing fluid and/or the production fluid. The recovery operations can therefore include strategically positioning the injection ports 8 along the injection conduit to promote and tailor gas chamber growth and oil recovery in a way that optimizes, enhances or maximizes oil production rate in variable geology.

[068] As supplying the fluid through the injection conduit in liquid state enables using conduits with smaller diameter than in a traditional SAGD process, using multiple injection conduits within a same well can be facilitated and can present further advantages.

[069] In some implementations, the mobilizing fluid can include multiple components (which may also be referred to as multiple mobilizing fluids) that can be injected, for example, via the same or different injection conduits provided in the well.
Specific sets of temperature and pressure conditions can be applied to each component flowing in each injection conduit. For example, heated and pressurized water can be injected into the reservoir via a first conduit, and heated and pressurized butane can be injected into the reservoir via a second conduit, extending along the first conduit in parallel relationship therewith. Injection ports of the first and second conduits may be as defined above and distributed in parallel or staggered rows. The injection ports of the different injection conduits can be provided at similar locations along the length of the well, or at different longitudinal locations to achieve certain fluid injection patterns and effects. The multiple injection conduits can be distinct tubular conduits arranged beside each other, or co-annular conduits that may have tubular or annular forms depending on the overall completion design.

[070] Referring to Figure 4A, a first mobilizing fluid 101 and a second mobilizing fluid 103 can be delivered simultaneously within a single injection conduit 6 and discharged into the reservoir 2 via the injection ports 8. Referring to Figure 4B, the first mobilizing fluid 101 and the second mobilizing fluid 103 can be delivered simultaneously into respective first and second independent injection conduits 6 and 60, and then discharged into the reservoir via respective injection ports 8 and 80. It should be noted that, when multiple mobilizing fluids are delivered via independent injection conduits, they can be discharged successively, alternatingly, or simultaneously into the reservoir. It is also noted that there may be at least two distinct injection conduits for injecting similar or different fluids at similar or different conditions into similar or different regions of the reservoir.

[071] The injection conduit can have various structural and operational features. In some implementations, the injection conduit can have an outer diameter between 20 mm and 300 mm, optionally between 30 mm and 200 mm, further optionally between 60 mm and mm. In addition, the injection conduit can be insulated to limit heat loss of the injection fluid before reaching the injection ports. Insulation can be provided along certain portions of the injection conduit (e.g., primarily along upstream portions, portions with greater risk of heat loss and/or portions in which the wellbore has a larger diameter to facilitate accommodation of insulation liners or materials). The injection conduits can be provided as tubular strings for transmitting the fluid, as generally illustrated in Figures 4 to 8 for example; or as part of a co-annular constructions that includes both the injection and production conduits, as generally illustrated in Figure 11.

[072] In some implementations, distribution of the injection fluid into the reservoir may be performed via a plurality of injection modules, spaced-apart from one another along the longitudinal axis of the horizontal wellbore. Examples of injection modules 80 are shown in Figures 9 to 12, 19 and 20. The injection modules are in in fluid communication with one another via a longitudinal passageway that extends along the injection conduit, and the injection modules define spaced-apart adjacent injection locations. The injection modules can be used in particular when the injection and production conduits are arranged generally concentrically, e.g., where the injection conduit includes a central passageway defined by an inner tube and the production conduit is defined as an annular passageway between the inner tube and an outer tube, which is optionally co-axial with the inner tube. Each injection module may be configured and designed to include an injection annulus 82 that is generally co-annular with the outer tube, and a radial passage that fluidly connects each injection annulus 82 with the inner tube so that the mobilizing fluid can flow from the inner tube, through the radial passage, into the injection annulus 82 and then be expelled from the injection ports that are located as one or more locations around the injection annulus 82.
The injection modules 80 deliver the injection fluid into the reservoir via the injection ports 8 that can be distributed around the injection annulus. The injection ports 8 can be formed as apertures through the wall that defines part of the injection annulus, and the location and direction in which the apertures point can be provided to enable desired injection effects.
Referring to Figures 9 to 12, the injection module 80 may include two injection rings 82 located at each opposed end of the module 80. Each injection ring can include a rim that faces the opposed rim of the other injection ring, and on which the injection ports are located, for example distributed in a generally circular pattern around the rims. Various other configurations can be used where two sets of injection ports 8 generally face each other in order to expel the vaporized fluid toward each other's general direction.

[073] Referring still to Figures 9 to 12 and 19, the injection ports 8 provided on the module can be positioned and configured so that the fluid is injected in a generally axial direction. In the case of the illustrated injection modules, two opposed sets of the injection ports face each other, such that the axes of the apertures are generally parallel with each other and with respect to the wellbore and conduits. Alternatively, the injection ports could be configured for oblique injection direction of the fluid, i.e., the fluid would be injected at an upward angle relative to the longitudinal axis of the wellbore and/or relative to the adjacent conduit. Other arrangements and configurations are also possible for the injection ports to enable injection of the fluid at certain angles and directions. Optionally, the injection ports are arranged so that there are at least two spaced-apart injection ports that are oriented to inject fluid in each other's general direction to facilitate formation of a high-pressure region in a reservoir region in the vicinity between the two spaced-apart injection ports. Figures 20A to 20E illustrate some possible configurations of injection modules and ports that can be used.

[074] With reference to implementations shown in Figures 9 to 12 and 19, each corresponding set of injection ports 8 can be configured to inject the injection fluid in substantially facing directions to facilitate formation of a higher-pressure region (HP) (a) between two adjacent modules (as in Figure 9) or (b) between two rings of a same module (as in Figures 11 and 19). Optionally, the modules may be spaced apart from each other at a distance between 5 m and 100 m, further optionally between 10 m and 25 m.

[075] As it may be appreciated, number of modules, distance between the modules, injection pattern from the modules, and other structural and operational features can vary to meet design completion requirements in relation to the characteristics of the reservoir. For example, it should be noted that the injection ports can be configured or controlled to provide different injection rates at different locations along the wellbore (e.g., higher injection rates near or at the toe compared to the heel, lower injection rates near or at the toe compared to the heel, or higher injection rates at particular locations along the wellbore due to certain geological characteristics of the reservoir in that region or due to certain process performance characteristics). The injection pattern and approach can be facilitated by deployment of flow control devices at injection ports, which will be discussed further below.
Flow control devices for injection

[076] Optionally, each injection port of the injection conduit is equipped with a flow control device (FCD), which can be configured to provide sonic choked flow to the injected mobilizing fluid. It should be understood that sonic choked flow is achieved when the mobilizing fluid reaches the speed of sound (i.e., M =1) through the FCD. At the speed of sound, pressure variations between the injection conduit and the reservoir can no longer be communicated upstream of the FCD (i.e., within the injection conduit). Indeed, the speed at which these pressure changes are propagated is limited by the speed of sound.
The FCD

can be provided with a restriction or nozzle which is able to isolate the injection conduit from the downstream reservoir side such that the pressure differential is not propagated upstream of the restriction in the injection conduit. Any reduction in downstream pressure within the reservoir has therefore no effect on the mass flow rate of the mobilizing fluid.

[077] Other implementations of the FCD may include those described in Canadian Patent Application No. 2940953. Other FCDs can also be used. The FCDs used along the injection conduits can be the same or different FCDs can be used at different locations to achieve a desired effect. The FCDs can be active or dynamic, meaning that they can be actively controlled or changed, or the FCDs can be passive and predesigned for a particular purpose.
Production implementations

[078] Implementations of the process include production of a production fluid via the production conduit. Various aspects and details regarding production will be discussed below.

[079] Referring to Figure 3, the gas chamber 12 has a vertical section corresponding to the reservoir area contacted by the injected mobilizing fluid 14 and depending on the vertical sweep efficiency of the injected mobilizing fluid 14. As the mobilizing fluid 14 mobilizes the hydrocarbons at the interface between the gas chamber 12 and the reservoir 2, a fluid including mobilized hydrocarbons 16 is formed and referred to herein as the production fluid. The force of gravity will cause the production fluid 16 to move downward and flow by gravity drainage to the production conduit 10. The production fluid may accumulate at a downhole location 18 below the gas chamber 12 depending on the production flowrate.

[080] Referring to Figure 1, the production conduit 10 is located proximate to the injection conduit 6 within the same well. Production is performed via a plurality of production ports 20 that are provided along a horizontal section of the production conduit 10. The production ports 20 may be spaced away from one another in a regular pattern to promote drainage of the generated production fluid along an axial direction of the reservoir 2, or in an irregular pattern optimized based on the reservoir deliverability. The production fluid may undergo various downstream treatment operations to recover the mobilized hydrocarbons.
For example, a separation unit 28 may be provided to separate mobilized hydrocarbons 106 from water 102 and produced mobilized fluid 104. Water 102 and recovered fluid 104 may be recycled. For example, fresh mobilizing fluid 108 may be supplied and mixed with produced mobilizing fluid 104 before injection via the injection conduit.

[081] When using distinct tubes as the production and injection conduits, the position of the production conduit compared to the injection conduit can vary and the two tubular conduits can simply be deployed within the same wellbore 4. Deployment can be conducted so that the injection and production ports are offset, as discussed further below, but otherwise there is no particular arrangement that is required. Alternatively, the production and injection conduits could be arranged in some relative position to each other (e.g., beside each other, one on top of each other, etc.). The production conduit 10 thus extends into the reservoir and within the horizontal section of the well bore 4. When using a concentric configuration, such as the one shown in Figures 11 and 12, the production conduit can be defined as an annular passageway between inner and outer tubes, as described above. Other configurations of production and injection conduits can also be envisioned.
Control of gas phase production

[082] In some implementations, the process may include reducing or preventing production of the gas phase via the production conduit. Due to the proximity of the production conduit with respect to the injection conduit, some production of the gas phase generated via the injection conduit can occur. Several gas phase production control means or methods can be used.

[083] For example, as illustrated in Figure 1, the production ports 20 may be distributed along the production conduit 10 in an offset configuration with respect to the injection ports 8, to reduce production via the production ports 20 of the gas phase exiting the injection ports 8. Depending on the type, location and number of injection and production ports that are used, different offset features can be implemented.

[084] To further reduce production of the mobilizing fluid in gaseous state, each production port may be equipped with a flow control device (FCD), as described above in relation to the injection ports. FCDs on the production string can ce provided to preferentially limit the flow of gas phase relative to a liquid phase, ensuring production of mostly liquid phase at the production conditions.

[085] In some implementations, the process may include controlling injection and production via the respective injection and production ports (e.g., via FCDs).
Referring to Figure 5, a control unit 110 may be provided to provide control of FCDs 22 located on the injection and productions conduits 6 and 10. The control unit can be configured to remotely control opening and closing of the devices, injection pressure, mobilizing fluid flowrate, production fluid flowrate, etc., via various instrumentation that can be provided within the well via at least one instrumentation line 24. For example, injection and production ports may be opened and closed in such a manner as to maximize the pressure difference between injection and production locations in the annular space, while minimizing gas-phase short circuiting.
Produced water

[086] The production fluid may include condensed water that is produced to surface through the production tubing. In some implementations, the process may include providing the produced water as a component of the mobilizing fluid injected via the injection conduit.
The produced water may also be used to produce low-quality steam for pre-heating the mobilizing fluid via a heat exchanger, as schematized on Figure 1. Proximity of the production and injection conduits may render reuse of the produced water possible and beneficial.

[087] As noted previously, depending on the nature of the mobilizing fluid as well as the temperature and pressure conditions within the conduits and the reservoir, a portion of the injected fluid flashes to gas phase (referred to as flashed portion) and another portion of the injected fluid remains in liquid phase (referred to as liquid portion). For example, preliminary work has indicated that when water is used as the heated injected fluid, approximately 15 wt% to 30 wt% (or about 18 wt% to 25 wt%) of the water boils to gas phase (i.e., steam) upon injection. Thus, a notable quantity of liquid water is injected into the reservoir. There are a few notable points worth discussing in relation to the liquid portion that is injected.

[088] First, the injected liquid has to be drained out of the reservoir, and is thus allowed to flow toward at least one production port to be produced as part of the production fluid. The proximity of the production conduit in a single well configuration facilitates this water drainage. A two-well configuration is less practical as liquid water has to be produced to avoid flooding the injection well and reducing injectivity. The production fluid that is recovered to the surface thus includes a notable portion of the mobilizing fluid that drained soon after entering the reservoir. There is thus a liquid passageway in between the injection ports and the production ports to enable adequate drainage of the injected liquid portion of the fluid.

[089] Second, the injected liquid portion and its circulation through the system¨including from the injection ports to the production ports and back through the production conduit¨can facilitate heating and maintaining temperature uniformity along the length of the well, which can benefit overall performance. Thus, the injection of the liquid portion of the fluid can facilitate certain advantages.

[090] Third, since a notable amount of the fluid is injected as a liquid and drained to form part of the production fluid, the production fluid can have higher fluid-to-oil ratios compared to some conventional operations. In addition, in some implementations, a fluid-oil separator can be provided proximate to the wellhead at the surface in order to separate a significant portion of the fluid from the produced oil, so that the fluid can be reinjected. The fluid-oil separator can be provided on or near the wellpad from which the well or well extend into the reservoir.

[091] In this regard, when water is used as the injection fluid approximately 15 wt% to 30 wt% vaporization upon injection has been estimated, but other mobilizing fluids can have relatively different vaporization characteristics depending on the properties of the fluid and the reservoir characteristics. In addition, mixtures of mobilizing fluids (e.g., water and solvent mixture, or solvent mixture that includes at least two different components, etc.) can display different vaporization properties depending on the particular composition of the mixture. The equipment and operation of the system can thus be designed with the characteristics of the fluid vaporization and liquid portion as factors.
Single wellbore configuration

[092] In some implementations, the process may include production via the production conduit located within the same well bore as the injection conduit. The production conduit may have a diameter between 60 mm and 200 mm, or between 100 mm to 150 mm, for example. Further optionally, the diameter of the horizontal section of the well in which the production and injection conduits are located may be between 0.100 m and 300 mm.

[093] In some implementations, the diameter of the wellbore and the dimensions of the production and injection conduits are coordinated to promote efficient and cost-effective wellbore drilling and completion, while enabling good performance in terms of injection and production rates. The injection and production conduits can be sized to facilitate deployment downhole while enabling sufficient structural integrity (e.g., pressure ratings) to withstand the temperature and pressure conditions of the fluids transported therethrough.
Smaller wellbores can be more economical to drill and complete, and thus the sizing of the wellbore as well as the injection and production conduits can be provided to balance drilling and completion costs with operational performance and production rates.

[094] It should be noted that, in some implementations, the production conduit can be disposed along the injection conduit and in substantial alignment with the injection conduit.
Thus, the production and injection conduits can take the form of two distinct tubular lines that extend within the wellbore.

[095] In some implementations, the injection conduit and the production conduit can be configured to be concentric. For example, the injection conduit can be located within the production conduit. The process can also include injecting the injection fluid via injection modules configured to rest on the production conduit and be in fluid communication with the internal injection conduit. It should be noted that, in the case of a concentric configuration, the injection conduit may be referred to as an injection string or injection line to refer to the path taken by the injection fluid from the surface to the reservoir up to the injection module.
Similarly, the production conduit may be referred to as the production string or line.

[096] Referring to Figures 11 and 19 which generally illustrate a concentric configuration, the injection conduit 6 extends concentrically within the production conduit 10 in an axial direction of the wellbore. As mentioned previously, delivery of the injection fluid into the reservoir 2 can be performed via injection modules 80 that can be configured to wrap around the production conduit 10 at specific and spaced-apart injection locations. The injection modules 80 can take various forms, e.g., a concentric module that wraps around the production conduit or a chamber that is disposed at a position outside of the production conduit (such as only on an upper part of the production conduit). To ensure fluid communication between the injection conduit 6 and the injection modules 80, at least one injection fluid path 90 is provided for each module 80 while preventing fluid communication between the injection string and production string. The fluid path can be a channel defined by walls that fluidly connects the module 80 with the injection line and passes through part of the annular production conduit and thus allows production fluid to pass around it. The injection fluid path 90 delivers the injection fluid into a fluid chamber 84 of the injection module 80, where the injection fluid is ready to be injected into the reservoir via the injection ports 8, which can be located about a radial wall of injection rings.

[097] As seen on Figure 12, the injection ports 8 may be positioned and configured to provide two sets of facing injection jets for a same module, thereby facilitating formation of a higher-pressure region above the corresponding injection module as the fluid is injected toward a central region in between the two sets of injection ports. In contrast, a lower-pressure region forms in the reservoir region between two adjacent injection modules. This axial pressure difference, also referred to as pressure drive, can enhance convection mechanisms and accelerate production of the oil-water emulsion or production fluid via the production ports. The axial pressure difference generally refers to the pressure differences between different regions in the reservoir located above the longitudinal axis of the wellbore. It should again be noted that liquid water that does not flash into the reservoir can be drained and produced via the production ports without risking flooding the injection ports.

[098] Referring to Figure 11, in some implementations, packers 100 can be provided within the annular space between the liner 5 and an exterior surface of the production conduit 10, and longitudinally in between an injection location and a production location to enhance the pressure drive therebetween. Packers can be provided to reduce or prevent production of vaporize gas phase fluid that is injected. In addition, the packers can be located and configured to inhibit gas phase production, while facilitating liquid phase flow to and production via the production ports. For example, partial packers can be used to allow water drainage from the injection ports and/or avoid pressure build-up within the annular space. In some implementations, the packers can be controlled in order to provide full or partial packing or isolation, when desired. The control of the packers can be performed from a remote surface location or by pre-configuring the packers.

[099] It should be noted that variations in design and positioning of the injection modules and production ports can exist. The production ports can be positioned at a variable distance from the injection modules. For example, the production ports can be located proximate to or on the injection module, depending on the setup, and a production fluid path can be created to distribute the production fluid to the production conduits.
Alternatively, production modules, including multiple production ports may be distributed in a staggered relationship with the injection modules in an axial direction of the reservoir along the production conduit. Optionally, production ports may be disposed radially about the production conduit or production module.

[100] In some implementations, the injection and productions conduits may be provided within a single well and without any liner (as schematically shown on Figure 9). As the near-well reservoir region warms up, the sand can slough in against the injection and production conduits or against the concentric injection-production conduits, as the case may be.
Presence of sand may be beneficial in limiting or eliminating gas-phase short circuiting between injection and production points. In some alternative implementations, a particular material can be placed in the wellbore surrounding the injection and production conduits.
Alternative well configurations

[101] In some implementations, the process can include production via the production conduit located in a separate well, e.g., disposed separately and below the well in which the injection conduit is deployed or present.

[102] In other implementations, the process may include injection and production via a single infill well located between two typical SAGD well pairs. In other terms, the single well that includes production and injection conduits, as described above, can be deployed as an infill well in a region of the reservoir defined between two adjacent SAGD
well pairs. Such an infill well can be drilled, completed, and operated at any time during the operation of the adjacent SAGD well pairs. In another implementation, the single well that includes production and injection conduits can be deployed as a step-out well beside an existing recovery operation, e.g., beside a SAGD well pair.

[103] In some implementations, multiple single wells can be deployed as an array extending from a well pad. The wells can be arranged so that they are generally parallel to each other and the horizontal sections can be located at a similar elevation within the pay zone and extending a similar length.

[104] It is also noted that the production and injection conduits can be deployed in a single wellbore and can be operated in various modes, e.g., in production-only mode, injection-only mode, or injection-production mode. These different operating modes can be implemented at different phases of the recovery operations (e.g., startup, ramp-up, plateau, wind-down, etc.), according to the availability of fluid and/or equipment at surface facilities, or according to the performance of the recovery process. Deploying both production and injection conduits within a wellbore also provides operational flexibility for the well over its lifetime.

[105] It should be noted that the production can be facilitated via a pump (e.g., electric submersible pump) deployed in the wellbore, typically near the heel section, via gas lift, or via natural lift, depending on the particular characteristics of the reservoir, the well, and the process operation.
Operational implementations

[106] It should be noted that the process equipment and design completion described herein can be used according to various operational strategies.

[107] For example, the hydrocarbon recovery process may include a start-up phase where injection and production are cyclically iterated to initiate recovery. In other words, an injection fluid can be continuously injected without any production, and then the injected fluid can optionally be let to soak with both injection and production turned off, followed by a production phase without simultaneous injection. This type of alternating injection-production operation can be conducted to initiate mobilization of the near reservoir region that surrounds the wellbore.

[108] Another way to initiate recovery can include injection of the injection fluid at cooler temperatures such that there is no flashing upon exiting the injection conduit initially, and/or circulation of the hot fluids back up through the production conduit, and then gradually increasing the injection fluid temperature to flashing conditions. Other start-up operations can be conducted, such as injecting fluid so that the fluid is in gas phase within the injection conduit and as it enters the reservoir. Start-up phase can also use different fluids compared to later more mature stages of operation (e.g., aromatic or aliphatic hydrocarbon solvents during start-up followed by water or water-solvent mixture for normal operation). Start-up operations can also use other heating means, such as electric or EM radiation heaters, that are deployed in the wellbore.

[109] As will be explained below, implementations of the single well with injection and production conduits have been found to have various advantages compared to conventional example SAGD processes. For instance, the single well can enhance recovery of cellar oil, which is oil that is located below the production well and above the base of the pay zone.
Since the single well position in the reservoir is not constrained by its position relative to a second well, which is the case for SAGD well pairs which should have relatively consistent inter-well spacing, the single well can be drilled to follow the base of the pay zone. Thus, for bases that change in elevation over the long lengths of horizontal wells, the single well can follow the base along its entire length and thus facilitate access to such low-lying hydrocarbons that are close to the base.
Leveraging convection

[110] It should be understood that, in some implementations, operation of the process within a single well can be referred to as Convection-Induced Gravity-Assisted Recovery (CIGAR). Typical SAGD operation benefits from uniform pressure along an axial direction of the injection well, thereby allowing even distribution of the injected steam into the reservoir.
However, due the proximity of the injection conduit with respect to the production conduit according to implementations of the present process, uniform pressure within the reservoir along an axial direction may not facilitate efficient production of the production fluid including mobilized hydrocarbons.

[111] In some implementations, the process can include creating lower-pressure regions along a length of the well to induce convection of the production fluid towards the production conduit. An axial pressure differential or gradient can be provided to create alternating lower-pressure regions and higher-pressure regions along the length of the well.
It should be noted that an axial direction refers to the direction along the length of the well, such that the injection conduit and the production conduit are extending into the reservoir in the axial direction (can also be referred to the horizontal direction).

[112] Figures 6 to 9 illustrate various optional implementations of the process related to providing axial pressure differentials. Optionally, the axial pressure differential along the well may be provided by a specific injection pattern through the injection ports. For example, referring to Figure 6, the injection pattern may include injecting in a first direction from a first injection port 8 and injecting in a second direction and against the first direction from a second and directly adjacent second injection port 8. A higher-pressure (HP) region is thereby formed between the first and second injection ports 8, and a lower-pressure (LP) region is created between the second injection port 8 and an adjacent third injection port 8 that is spaced away in a direction opposed to the injection direction of the second injection port. In other words, at least two injection ports are oriented and configured so that they inject the fluid toward each other, thereby facilitating the formation of a higher-pressure region in the reservoir above those injection locations. The injection pattern may be repeated along the injection conduit to provide for alternate higher and lower-pressure regions promoting convection of the production fluid towards the production conduit.

[113] It should be noted that various designs for the injection equipment may be provided to facilitate completion of a desired injection pattern promoting axial pressure differential along the well. For example, referring to Figure 7, multiple sets of injection ports 8, including two or more injection ports, may be provided along the length of the injection conduit 6 so as to create higher-pressure (HP) regions at discharge. The fluid jets may be oriented in different configurations to facilitate convection through lower-pressure (LP) regions.

[114] Optionally, the axial pressure differentials along the injection well may be provided by discharging the mobilizing fluid at different pressures along the injection conduit. For example, referring to Figure 8, a series of discharge pressures (P1, P2, P3, P4) of the mobilizing fluid can be controlled at specific injection ports 8, thereby creating lower-pressure regions whereby the production fluid drains and is produced at a series of production pressures (Pa, Pb, Pc) via the production ports. It should be noted that various combinations of pressure distributions within the annular space can be used, such combinations being cycled in time for instance.

[115] In some implementations, the formation of axial pressure differentials (dP) may be facilitated along the well by positioning packer(s) between the staggered injection and production ports around the respective conduits and within the well. In such cases, each packer can serve as an at least partial seal between a higher-pressure region and a lower-pressure region of the well. Optionally, the packers may be retrievable, or provide only partial flow isolation, allowing an axial pressure differential to be established without sealing off axial flow entirely within the well.

[116] It should be noted that various pressures and pressure differentials can be provided in the context of the processes described herein. In one example, the process can be operated such that the gas chamber pressures are in the range of about 800 kPa and 1200 kPa, and the fluid pressure in the injection conduits is between 3 MPa and 6 MPa, although other pressure ranges are also possible. When higher gas chamber pressures are employed, the fluid pressure in the injection conduit can be increased accordingly to facilitate the desired pressure drop and vaporization across the injection ports. In addition, the pressure differentials or gradients between the high-pressure regions and the low-pressure regions of the well annulus can be, for example, between about 10 kPa and about 500 kPa, between about 50 kPa and about 400 kPa or between about 100 kPa and about 300 kPa, when considering the highest pressure of the high-pressure region and the lowest pressure of the lower-pressure region. The pressure gradients can be different from one pair of adjacent high/low pressure regions to another. The pressure gradients can be implemented and adjusted by modifying one or more variables, such as fluid injection pressure, production pressure, pressure drop across the injection ports, and mobilizing fluid composition.
SIMULATIONS

[117] It has been found that oil recovery and production rates for SAGD and CIGAR
processes can be similar; however, implementation of an axial pressure differential between an injection point and a production point was found to encourage the start of the process.

[118] Referring to Figures 13 and 14, a 20-meter portion of horizontal wells was modelled for example SAGD and CIGAR processes under similar conditions and operating limits.
Pressures in the well annulus (in communication with reservoir) were bounded between 700 kPa and 1200 kPa. In the case of the example CIGAR process (Figure 14), the injection fluid was liquid water at 250 C, allowed to flash at the injection location as the pressure was dropped to the maximum allowable pressure of 1200 kPa. Resulting simulated steam chamber shapes are different, including a higher cellar-oil recovery for the CIGAR model. Similar oil recovery rate is still obtained for both models.

[119] Figures 15 and 16 result from a simulation model (using ANSYSCFXTM, which is a computation fluid dynamic modelling tool) that modelled injection of steam via an injection conduit and production of mobilized hydrocarbons via a production conduit, both injection and production conduits being located within the same wellbore. Figure 15 offers visualization of a temperature gradient along a portion of a well including an injection location. Injection of steam from a first injection port is modelled to be directed to the left as may be apparent from the higher temperature at the injection location. Figure 16 offers visualization of the mass flow production along the same modelled well portion as per Figure 15. The production is not homogeneous along the well. The region where the injection jets from the first injection port and a second adjacent injection port (not illustrated on Figure 16) meet corresponds to a higher-pressure region where steam flows into the reservoir best, whereas the production is maximized away from the first injection port in an opposite direction along the well at a lower-pressure region.

[120] Figure 17 is a graph illustrating a comparison of the oil production rate between an example SAGD process and example single well operations for several axial pressure differences between injection and production locations in an axial direction of the reservoir.
The axial pressure difference between injection and production locations was varied to create high-pressure difference examples (300 kPa dP), medium pressure difference examples (100 kPa dP), and lower pressure difference examples (10 kPa dP).
Figure 17 shows an early ramp up of oil production for both SAGD and single well operation with higher pressure drive, with the CIGAR with high pressure different (dP) outperforming SAGD in terms of production rates at all time periods. The medium pressure different CIGAR example also outperformed SAGD in terms of production rates at later time periods.

[121] Figure 18 is a graph illustrating a comparison of the oil production rate for single well operations with several axial pressure differences between injection and production locations in an axial direction of the reservoir. Figure 18 indicates that enhanced oil production can be obtained with a higher-pressure drive and that a similar production profile may be obtained whether the higher-pressure drive is created by a tailored and controlled injection pattern or by using a packer between injection and production locations.

[122] It should be noted that any one of the above-mentioned aspects of the process may be combined with any other of the aspects thereof, unless two aspects clearly cannot be combined due to their mutually exclusivity. For example, the operational steps and/or structural elements of the process described herein-above, herein-below and/or in the appended Figures, may be combined with any of the general process descriptions appearing herein and/or in accordance with the appended claims.

Claims

29

1. A process for recovering hydrocarbons from a reservoir wherein an injection conduit and a production conduit extend through the reservoir in an axial direction, the process comprising:
delivering a mobilizing fluid into the injection conduit;
providing a pressure differential in the axial direction of the reservoir to form alternating lower-pressure regions and higher-pressure regions along the injection conduit, wherein providing the pressure differential comprises discharging the mobilizing fluid into the higher-pressure regions of the reservoir via the injection conduit; and producing mobilized hydrocarbons from the lower-pressure regions of the reservoir via the production conduit, wherein the producing comprises drainage of the mobilized hydrocarbons into the production conduit.

2. The process of claim 1, wherein the mobilizing fluid is delivered in liquid phase into the injection conduit and at least partially vaporizes during discharge through the injection conduit into the reservoir, to form a vaporized gas phase that facilitates formation of the high-pressure regions.

3. The process of claim 1 or 2, wherein the injection conduit and the production conduit are deployed within a same horizontal well section.

4. The process of claim 3, wherein the injection conduit and the production conduit are provided as a concentric injection-production assembly.

5. The process of claim 1 or 2, wherein the injection conduit and the production conduit are respectively deployed within two different well sections.

6. The process of claim 5, wherein the two well sections include a horizontal injection well accommodating the injection conduit, and a horizontal production well located generally vertically below the injection well and accommodating the production conduit, the horizontal injection well and the horizontal production well forming a horizontal well pair.

7. The process of claim 6, wherein the horizontal production well and the horizontal injection well extend from the same vertical well section or from two distinct vertical well sections.

8. The process of any one of claims 3 to 7, wherein each of the two well sections follows a variable base elevation along a length thereof and is positioned proximate to a base of the reservoir.

9. The process of claim 8, wherein each of the two well sections is located at a substantially constant distance away from the base along the length thereof.

10. The process of any one of claims 3 to 9, wherein each of the two well sections has a diameter between 100 mm and 300 m.

11. The process of any one of claims 1 to 10, comprising heating and pressurizing the mobilizing fluid prior to transmitting the pressurized mobilizing fluid via the injection conduit.

12. The process of claim 11, wherein the heating and the pressurizing are performed at surface.

13. The process of any one of claims 1 to 12, wherein the mobilizing fluid includes water, an organic solvent, or a combination thereof.

14. The process of claim 13, wherein the mobilizing fluid includes or consists essentially of the organic solvent that is a C1-05 alkane solvent.

15. The process of claim 14, wherein the Ci-Cs alkane solvent comprises propane, butane or a mixture thereof.

16. The process of any one of claims 1 to 13, wherein the mobilizing fluid is water.

17. The process of any one of claims 1 to 13, wherein the mobilizing fluid is a mixture of water and organic solvent.

18. The process of any one of claims 1 to 17, comprising pressurizing the mobilizing fluid between 3 MPa and 16 MPa at a temperature between 100 C and 350 C within the injection conduit.

19. The process of any one of claims 1 to 18, comprising delivering multiple different mobilizing fluids into the injection conduit, in sequential or alternating fashion.

20. The process of claim 19, wherein the injection conduit is a first injection conduit of multiple independent injection conduits that are extending through the reservoir in the axial direction, and the process comprises delivering the multiple different mobilizing fluids into the respective multiple independent injection conduits.

21. The process of any one of claims 1 to 20, wherein the injection conduit includes a tubular injection line that has a diameter between 20 mm and 300 mm.

22. The process of claim 21, wherein the diameter of the tubular injection line is between 50 mm and 150 mm.

23. The process of any one of claims 1 to 22, wherein the production conduit includes a tubular production line that has a diameter between 60 mm and 200 m.

24. The process of claim 23, wherein the diameter of the tubular injection line is between 100 mm and 150 mm.

25. The process of any one of claims 1 to 24, wherein discharging the mobilizing fluid into the higher-pressure regions comprises providing sonic choked flow upon discharge of the mobilizing fluid.

26. The process of any one of claims 1 to 25, wherein providing the pressure differential in the axial direction comprises providing an injection pattern tailored to a given axial pressure differential to produce the alternate higher-pressure regions and lower-pressure regions within the reservoir.

27. The process of claim 26, wherein discharging the mobilizing fluid into the higher-pressure regions of the reservoir is performed via a plurality of axially spaced-apart injection ports that are in fluid communication with the injection conduit, and producing the mobilized hydrocarbons from the lower-pressure regions of the reservoir is performed via a plurality of axially spaced-apart production ports that are in fluid communication with the production conduit and that are off-set with respect to the injection ports.

28. The process of claim 27, comprising configuring and operating the injection ports to inject the mobilizing fluid in directions away from the production ports that are adjacent to the respective injection ports.

29. The process of claim 27 or 28, further comprising inhibiting production of the gas phase of the mobilizing fluid via the production conduit.

30. The process of claim 29, wherein inhibiting the production of the gas phase of the mobilizing fluid comprises configuring or controlling a flow control device that is provided at each production port.

31. The process of claim 29 or 30, wherein inhibiting the production of the gas phase of the mobilizing fluid comprises providing a packer or an isolation device between each injection port and the adjacent production port.

32. The process of any one of claims 27 to 31, wherein the injection conduit extends inside the production conduit, and wherein the injection ports are provided on an injection module comprising a chamber surrounding the production conduit, the chamber being in fluid communication with the injection conduit for receiving the mobilizing fluid, so that the mobilizing fluid can flow into the chamber and be discharged from the injection ports into the high-pressure regions of the reservoir.

33. The process of claim 32, wherein multiple injection modules are provided in spaced relation along the production conduit to define multiple injection sections.

34. The process of claim 33, wherein the injection ports of the injection module are provided on each of two axial sides of the chamber so as to define two sets of injection ports, and the injection ports of one set are positioned and oriented to discharge the mobilizing fluid in a direction opposed to that of the injection ports of the other set.

35. The process of claim 34, wherein opposed sets of injection ports from two adjacent injection modules that are positioned and oriented to discharge the mobilizing fluid at an angle toward each other and away from the production ports.

36. The process of any one of claims 33 to 35, wherein the chamber of each injection module is defined by a tubular wall that is generally concentric with the production conduit and two opposed spaced-apart rims that are connected to edges of the tubular walls.

37. The process of claim 36, wherein the injection ports of the injection module are distributed on the two opposed spaced-apart rims and defined by apertures that point to a specific direction to enable a desired injection effect.

38. The process of claim 37, wherein the injection ports are distributed in a generally circular pattern.

39. The process of any one of claims 36 to 38, wherein the injection ports from the rim of a first injection module are configured to discharge the mobilizing fluid towards a direction of discharge of the injection ports located on a facing rim from an adjacent second injection module.

40. The process of any one of claims 27 to 39, comprising positioning the injection ports along the injection conduit to promote a gas chamber growth and maximize an oil production rate according to a reservoir geology.

41. The process of any one of claims 1 to 40, wherein the hydrocarbons comprise bitumen.