CA3148553A1 - Solvent-assisted gravity drainage process with modulation of injection pressures - Google Patents

Abstract

A solvent-assisted process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation is provided. The process can include a first phase during which a solvent is injected in vapour phase into the hydrocarbon-rich reservoir to form a solvent chamber having a solvent chamber pressure, the solvent being injected at a first injection pressure that is at or higher than an initial reservoir pressure condition;
and a second phase during which the solvent is injected into the hydrocarbon-rich reservoir at a second injection pressure to achieve an overbalance between the solvent chamber pressure and a gas cap pressure of a gas cap having at least a portion located above the hydrocarbon-rich reservoir, the second injection pressure being lower than the first injection pressure.
A non-condensable gas can be injected in the gas cap, and the injection of the non-condensable gas can be adjusted to achieve the overbalance.

Description

SOLVENT-ASSISTED GRAVITY DRAINAGE PROCESS WITH MODULATION OF
INJECTION PRESSURES
TECHNICAL FIELD
[001] The technical field generally relates to processes for recovering heavy oil or bitumen from an underground reservoir using solvent. More particularly, the technical field relates to pressure-related operating strategies for solvent-assisted recovery processes for mobilizing and recovering heavy oil or bitumen from an underground reservoir.
BACKGROUND

[002] In situ recovery of viscous petroleum hydrocarbons, such as heavy oil or bitumen, from an underground formation, can be performed by injecting a solvent within the formation to mobilize the viscous hydrocarbons. Solvent vapor can be injected into the formation via a horizontal well, which can be referred to as an injector well.
When contacting the cold viscous hydrocarbons in the reservoir, the solvent condenses and diffuses into and dissolves the hydrocarbons. As a result, the viscous hydrocarbons are diluted to a lower viscosity fluid, which drains to a production well that can be located vertically below the injector well in a spaced-apart relationship. Depending on the solvent composition that is used, some in situ deasphalting and upgrading of the viscous hydrocarbons can occur. Upon continuing solvent injection, a solvent chamber can grow around and above the injection well. Such hydrocarbon recovery processes can require the use of large quantities of solvent, in part because a portion of the solvent can condense within the chamber prior to reaching the chamber edges. In such scenarios, larger solvent quantities may need to be recovered from the reservoir and then processed in surface facilities for reinjection.

[003] The performance of the solvent hydrocarbon recovery process can be impacted by its operating conditions. Various challenges exist in terms of operating strategies for recovering hydrocarbons, such as heavy oil or bitumen, from an underground reservoir using solvent vapour injection.
Date Recue/Date Received 2022-02-11 SUMMARY

[004] In accordance with an aspect, there is provided a solvent-assisted process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation, the process comprising:
a first phase during which a solvent is injected in vapour phase into the hydrocarbon-rich reservoir via an injection well to form a solvent chamber having a solvent chamber pressure, the solvent being injected at a first injection pressure that is at or higher than an initial reservoir pressure condition; and a second phase during which the solvent is injected into the hydrocarbon-rich reservoir at a second injection pressure that is provided so as to achieve an overbalance between the solvent chamber pressure and a gas cap pressure of a gas cap having at least a portion located above the hydrocarbon-rich reservoir, the second injection pressure being lower than the first injection pressure.

[005] In some implementations, the first injection pressure is at most 1000 kPa above the initial reservoir pressure.

[006] In some implementations, the first injection pressure is between about 50 kPa and about 600 kPa above the initial reservoir pressure.

[007] In some implementations, the overbalance is between about 5 kPa and about 100 kPa.

[008] In some implementations, the overbalance is between about 5 kPa and about 50 kPa.

[009] In some implementations, the overbalance is between about 20 kPa and about 50 kPa.

[0010] In some implementations, the overbalance is provided so as to limit solvent leaking off to the hydrocarbon-rich reservoir.
Date Recue/Date Received 2022-02-11

[0011] In some implementations, the solvent-assisted process further comprises monitoring the overbalance between the solvent chamber pressure and the gas cap pressure, and adjusting the second injection pressure to achieve the overbalance.

[0012] In some implementations, the solvent-assisted process further comprises injecting a non-condensable gas in the gas cap at a non-condensable gas injection pressure.

[0013] In some implementations, the solvent-assisted process further comprises monitoring the overbalance between the solvent chamber pressure and the gas cap pressure, and adjusting the non-condensable gas injection pressure to achieve the overbalance.

[0014] In some implementations, adjusting the non-condensable gas injection pressure comprises at least one of adjusting an injection rate of the non-condensable gas, modifying a location of a gas injection well via which the non-condensable gas is injected into the gas cap, and modifying a number of non-condensable gas injection wells.

[0015] In some implementations, the solvent-assisted process comprises adjusting the second injection pressure to achieve the overbalance.

[0016] In some implementations, monitoring the overbalance between the solvent chamber pressure and the gas cap pressure comprises monitoring data from at least one observation well.

[0017] In some implementations, the at least one observation well is provided in the gas cap to monitor the gas cap pressure.

[0018] In some implementations, the at least one observation well is provided in the solvent chamber to monitor the solvent chamber pressure.

[0019] In some implementations, the at least one observation well comprises a first observation well is provided in the gas cap to monitor the gas cap pressure and a second observation well is provided in the solvent chamber to monitor the solvent chamber pressure.
Date Recue/Date Received 2022-02-11

[0020] In some implementations, the solvent-assisted process further comprises monitoring a growth of the solvent chamber.

[0021] In some implementations, monitoring the growth of the solvent chamber comprises monitoring data from at least one observation well.

[0022] In some implementations, monitoring the growth of the solvent chamber comprises performing reservoir simulations.

[0023] In some implementations, a transition from the fist phase to the second phase is determined at least in part based on the growth of the solvent chamber.

[0024] In some implementations, monitoring the growth of the solvent chamber comprises determining at least one of a size of the solvent chamber, a height of the solvent chamber, a distance from a top edge of the solvent chamber to a lower edge of the gas cap, and a growth rate of the solvent chamber.

[0025] In some implementations, each of the first and second phases comprises:
providing heat to the injection well;
condensing the solvent at a bitumen extraction interface thereby delivering heat to the bitumen and dissolving the bitumen; and recovering a production fluid comprising bitumen and solvent from a production well located below the injection well.

[0026] In some implementations, the heat is provided using downhole heating means delivering heat energy at a rate per unit length ranging about 300 W/m to about 800 W/m.

[0027] In some implementations, the heat is provided by at least one of an electric resistive heater and electromagnetic heating.

[0028] In some implementations, the heat is provided by injecting the solvent as a superheated solvent.

[0029] In some implementations, the heat is provided by injecting the solvent as a superheated solvent at a temperature of at least 100 C above a dew point thereof.
Date Recue/Date Received 2022-02-11

[0030] In some implementations, the superheated solvent has a temperature ranging from about 30 C to about 250 C.

[0031] In some implementations, the superheated solvent has a temperature ranging from about 30 C to about 200 C.

[0032] In some implementations, the superheated solvent has a temperature ranging from about 30 C to about 170 C.

[0033] In some implementations, the superheated solvent has a temperature ranging from about 30 C to about 140 C.

[0034] In some implementations, the first phase is performed after completion of a startup operation for the process for recovering bitumen.

[0035] In some implementations, the first phase is performed as part of a ramp-up phase of the process for recovering bitumen.

[0036] In some implementations, the solvent is selected and provided in an amount to induce asphaltene precipitation in the reservoir.

[0037] In some implementations, the solvent-assisted process further comprises monitoring a process parameter during the first phase and/or the second phase.

[0038] In some implementations, the process parameter comprises at least one of HBR, SBR and a bitumen production rate.

[0039] In some implementations, the first injection pressure ranges from about 350 kPa to about 1000 kPa.

[0040] In some implementations, the first injection pressure ranges from about 350 kPa to about 900 kPa.

[0041] In some implementations, the first injection pressure ranges from about 350 kPa to about 800 kPa.

[0042] In some implementations, the first injection pressure ranges from about 500 kPa to about 700 kPa.
Date Recue/Date Received 2022-02-11

[0043] In some implementations, the first injection pressure ranges from about 600 kPa to about 700 kPa.

[0044] In some implementations, the second phase comprises an initial transition phase during which the first injection pressure is gradually reduced to the second injection pressure.

[0045] In some implementations, gradually reducing the first injection pressure to the second injection pressure comprises a continuous change.

[0046] In some implementations, gradually reducing the first injection pressure to the second injection pressure comprises a step change.

[0047] In some implementations, the solvent comprises propane, butane, pentane, hexane, heptane, condensate, or a mixture thereof.

[0048] In some implementations, the solvent comprises propane.

[0049] In some implementations, the solvent comprises butane.

[0050] In some implementations, a composition of the solvent is substantially the same during the first phase and during the second phase.

[0051] In some implementations, a composition of the solvent during the first phase is different than the composition of the solvent during the second phase.

[0052] In some implementations, the solvent has a variable composition during the first phase and/or during the second phase.

[0053] In some implementations, the solvent-assisted process is a solvent-dominated recovery process.

[0054] In some implementations, the solvent-assisted process is a solvent-only recovery process.

[0055] In accordance with another aspect, there is provided a solvent-assisted process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation, the process comprising:
Date Recue/Date Received 2022-02-11 injecting a gas into a hydrocarbon-lean zone having at least a portion located above the hydrocarbon-rich reservoir to form a gas cap having a gas cap pressure;
injecting a solvent in vapour phase into the hydrocarbon-rich reservoir via an injection well to form a solvent chamber having a solvent chamber pressure, the solvent being injected at a first injection pressure that is at or higher than an initial reservoir pressure condition; and injecting the solvent into the hydrocarbon-rich reservoir at a second injection pressure that is provided so as to achieve an overbalance between the solvent chamber pressure and the gas cap pressure, the second injection pressure being lower than the first injection pressure.

[0056] In some implementations, the gas is a non-condensable gas.

[0057] In some implementations, the non-condensable gas comprises methane.

[0058] In some implementations, the non-condensable gas comprises propane.

[0059] In accordance with another aspect, there is provided a solvent-assisted process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation, the process comprising:
injecting a solvent in vapour phase into the hydrocarbon-rich reservoir to form a solvent chamber having a solvent chamber pressure, the solvent being injected at a first injection pressure that is at or higher than an initial reservoir pressure condition;
monitoring a growth of the solvent chamber; and when a top edge of the solvent chamber approaches a lower edge of an upper zone having at least a portion located above the hydrocarbon-rich reservoir, injecting the solvent into the underground reservoir at a second injection pressure so as to achieve an overbalance between the solvent chamber pressure and an upper zone pressure of the upper zone.

[0060] In some implementations, monitoring the growth of the solvent chamber comprises monitoring data from at least one observation well.
Date Recue/Date Received 2022-02-11

[0061] In some implementations, monitoring the growth of the solvent chamber comprises performing reservoir simulations.

[0062] In some implementations, monitoring the growth of the solvent chamber comprises determining at least one of a size of the solvent chamber, a height of the solvent chamber, a distance from the top edge of the solvent chamber to the lower edge of the gas cap, and a growth rate of the solvent chamber.

[0063] In some implementations, the distance from the top edge of the solvent chamber to the lower edge of the gas cap is a predetermined distance.

[0064] In some implementations, the distance is estimated at least in part based on at least one of a geological characteristic of the reservoir, the gas cap pressure, and a process parameter.

[0065] In some implementations, the process parameter comprises at least one of HBR, SBR and a bitumen production rate.

[0066] In accordance with another aspect, there is provided a solvent-assisted process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation, the process comprising:
a first phase during which a solvent is injected in vapour phase into the hydrocarbon-rich reservoir via an injection well to form a solvent chamber having a solvent chamber pressure, the solvent being injected at a first injection pressure that is at or higher than an initial reservoir pressure condition; and a second phase during which the solvent is injected into the hydrocarbon-rich reservoir at a second injection pressure that is provided so as to achieve an overbalance between the solvent chamber pressure and a hydrocarbon-lean zone pressure of a hydrocarbon-lean zone having at least a portion located above the hydrocarbon-rich reservoir, the second injection pressure being lower than the first injection pressure.
Date Recue/Date Received 2022-02-11 BRIEF DESCRIPTION OF THE DRAWINGS

[0067] The attached figures illustrate various features, aspects and implementations of the technology described herein.

[0068] Fig 1 is a schematic representation of a well pair during a bitumen recovery process, the well pair including an injection well and a production well extending within a hydrocarbon-rich reservoir, wherein a startup fluid is injected into the hydrocarbon-rich reservoir via the injection well, including a representation of a zone comprising mobilized bitumen.

[0069] Fig 2A is a vertical cross-sectional view of a hydrocarbon-rich reservoir overlaid by a gas cap during a startup phase of a bitumen recovery process, with an injection well and a production well being provided in the hydrocarbon-rich reservoir.

[0070] Fig 2B is a vertical cross-sectional view of a hydrocarbon-rich reservoir overlaid by a gas cap during growth of a solvent chamber, with an injection well and a production well being provided in the hydrocarbon-rich reservoir.

[0071] Fig 2C is a vertical cross-sectional view of a hydrocarbon-rich reservoir overlaid by a gas cap when a solvent chamber has approached a lower edge of the gas cap, with an injection well and a production well being provided in the hydrocarbon-rich reservoir.

[0072] Fig 3A is a vertical cross-sectional view of a hydrocarbon-rich reservoir overlaid by a gas cap during a startup phase of a bitumen recovery process, with an injection well and a production well being provided in the hydrocarbon-rich reservoir, and a gas injection well provided in the gas cap to inject an additional gas in the gas cap.

[0073] Fig 3B is a vertical cross-sectional view of a hydrocarbon-rich reservoir overlaid by a gas cap during growth of a solvent chamber, with an injection well and a production well being provided in the hydrocarbon-rich reservoir, and a gas injection well provided in the gas cap to inject an additional gas in the gas cap.

[0074] Fig 3C is a vertical cross-sectional view of a hydrocarbon-rich reservoir overlaid by a gas cap when a solvent chamber has approached a lower edge of the gas cap, with Date Recue/Date Received 2022-02-11 an injection well and a production well being provided in the hydrocarbon-rich reservoir, and a gas injection well provided in the gas cap to inject an additional gas in the gas cap.
DETAILED DESCRIPTION

[0075] Techniques described herein relate to processes for recovering hydrocarbons, such as heavy oil and bitumen, from a subterranean formation using a solvent and optionally heat to enhance mobilization of the hydrocarbons within the subterranean formation. The subterranean formation can include a hydrocarbon-rich reservoir that is at least partially overlaid by a gas cap, or by a hydrocarbon-lean zone, i.e., a zone where the hydrocarbon saturation is less than the typical saturation of a hydrocarbon-rich zone. The recovery process can be operated in such a way that enables modulating a pressure differential between the hydrocarbon-rich reservoir and the gas cap or the hydrocarbon-over time, depending on the phase of the recovery process.

[0076] For instance, in some implementations, a process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation can include a first phase during which a solvent is injected in vapour phase via an injection well into a hydrocarbon-rich reservoir of the subterranean formation. The first phase can be implemented for instance following the completion of a startup phase or near the completion of the startup phase when fluid communication has been established between the injection well and a production well, i.e., in the interwell region; or the first phase can be implemented as part of a ramp-up phase of the recovery process. The subterranean formation also includes a gas cap or a hydrocarbon-lean zone having at least a portion that is located above the hydrocarbon-rich reservoir. Injection of the solvent in vapour phase in the hydrocarbon-rich reservoir can enable the formation of a solvent chamber that grows around the injection well and has a solvent chamber pressure. Once injected into the hydrocarbon-rich reservoir, the solvent vapour can condense on the interface between the solvent chamber and the hydrocarbon-rich reservoir, i.e., on the surface of the solvent chamber, thereby delivering heat to the bitumen and dissolving the bitumen.

[0077] During the first phase of the process, the solvent is injected into the hydrocarbon-rich at a first injection pressure that is at or higher than an initial reservoir pressure condition, and that is typically higher than a long-term planned operating pressure of the recovery process. During a second phase of the process, the solvent is Date Recue/Date Received 2022-02-11 injected into the hydrocarbon-rich reservoir at a second injection pressure that is provided so as to achieve an overbalance between the solvent chamber pressure and the pressure of the gas cap (i.e., the gas cap pressure) or of the hydrocarbon-lean zone (i.e., the hydrocarbon-lean zone pressure), where the second injection pressure is lower than the first injection pressure. The second phase of the process can be initiated for instance when the solvent chamber approaches the gas cap or the hydrocarbon-lean zone. Thus, as the recovery process progresses over time, the injection pressure of the solvent can be modulated such that the pressure of the solvent chamber is tapered down to be closer to the gas cap pressure or the hydrocarbon-lean zone pressure while maintaining an overbalance between the solvent chamber pressure and the gas cap pressure or the hydrocarbon-lean zone pressure.

[0078] As used herein, the term "overbalance" refers to the difference between the solvent chamber pressure and the gas cap pressure, or between the solvent chamber pressure and the hydrocarbon-lean zone pressure, with the solvent chamber pressure being higher than the gas cap pressure or the hydrocarbon-lean zone pressure.
In contrast, the term "underbalance" refers to the difference between the solvent chamber pressure and the gas cap pressure or the hydrocarbon-lean zone pressure, but with the solvent chamber pressure being lower than the gas cap pressure or the hydrocarbon-lean zone pressure.

[0079] "Bitumen" as used herein can refer to hydrocarbon material extracted from bituminous formations, such as oil sands formations, the density of which is typically around 1000 kg/m3 and the American Petroleum Industry's (API) gravity is around 8 .
Bitumen can be recovered from a bitumen-containing reservoir using in situ recovery processes. The bitumen can include various non-hydrocarbon compounds (e.g., sulfur, metals, etc.) that are often found in bitumen and can be associated with certain hydrocarbon components (e.g., asphaltenes). Examples of bitumen include bitumen extracted from the Athabasca and Cold Lake regions, in Alberta, Canada.

[0080] "Heavy oil", which can also be referred to as "heavy crude oil", can refer to any liquid petroleum with an American Petroleum Industry's (API) gravity of less than 22.3 and a density of about 920 to about 1000 kg/m3, although the density could be higher.
Heavy oil usually contains asphaltenes and resins.
Date Recue/Date Received 2022-02-11

[0081] For ease of reading, the term "bitumen" will be used in the following description of exemplary implementations. However, one will understand that the described processes can be used in underground reservoirs containing either bitumen or heavy oil.

[0082] Some of the quantitative expressions mentioned herein can be qualified with the term "about". The term "about" means within an acceptable error range for the particular value as determined by one of ordinary skill in the art, which will depend in part on how the value is measured or determined, i.e., the limitations of the measurement system. It is commonly accepted that a 10% precision measure is acceptable and encompasses the term "about".
General overview of an in situ recovery process

[0083] The processes described herein can contribute to enhancing the performance of an in situ recovery process by implementation operating strategies that involve managing a pressure differential between the pressure of a mobilizing fluid chamber, such as a solvent chamber, and the pressure of a gas cap, or of a hydrocarbon-lean zone, during various phases of the in situ recovery process. Examples of an in situ bitumen recovery process will be described in further detail below.

[0084] An in situ bitumen recovery process generally includes various stages, including a startup phase, optionally followed by a conditioning phase and then a recovery phase or production phase, which can then optionally be followed by blowdown and/or winddown phases. The startup process is generally aimed at mobilizing hydrocarbons in an interwell region of the well pair (i.e., the area of the reservoir surrounding the injection well and/or production well, including the area of the reservoir located between the injection well and the production well), and establish fluid communication between the injection well and the production well of the well pair. The winddown or blowdown stages typically occur once the production stage of the bitumen recovery process has been in operation for a certain period of time and the recovery rate of the hydrocarbon production has started to decrease to uneconomical levels. Once bitumen has been mobilized during the startup process, mobilized bitumen can be produced as a production fluid from the bitumen-containing reservoir during recovery operations that follow the startup phase.
Date Recue/Date Received 2022-02-11

[0085] It should be understood that, in the context of the present description, an in situ bitumen recovery process can refer to any suitable in situ bitumen recovery process for producing mobilized bitumen from a bitumen-containing reservoir using an injection fluid that is introduced in the bitumen-containing reservoir via an injection well.
Such suitable in situ bitumen recovery processes can include, for instance, a solvent-assisted gravity drainage operation that generally uses a solvent as a mobilizing fluid, with or without steam, for introduction as an injection fluid into the bitumen-containing reservoir. When the solvent-assisted gravity drainage operation uses a solvent as a mobilizing fluid without steam, the process can be referred to as a solvent-only gravity drainage operation. When the solvent-assisted gravity drainage operation uses a solvent as a mobilizing fluid with steam, the process can be referred to as a solvent-dominated gravity drainage operation.
Other suitable in situ bitumen recovery processes can include a Steam-Assisted Gravity Drainage (SAGD) process. A SAGD process conventionally uses steam alone as the mobilizing fluid; however, SAGD can also use some other compounds that can be co-injected with the steam (e.g., small amounts of hydrocarbon solvent as in ES-SAGD, surfactants, non-condensable gas, and water wetting agents, among others).

[0086] Fig1 shows an implementation of an in situ bitumen recovery process that is carried out via a horizontal well pair 10 provided in a subterranean formation. The horizontal well pair 10 includes an injection well 12 overlying a production well 14. The injection well 12 and the production well 14 are generally parallel and separated by an interwell region 16. The injection well 10 includes a vertical portion 18 and a horizontal portion 20 extending from the vertical portion 14, and the production well 14 includes a vertical portion 22 and a horizontal portion 24 extending from the vertical portion 22.

[0087] Still referring to Fig 1, the in situ bitumen recovery process includes injecting a solvent 26 as a mobilizing fluid into a hydrocarbon-rich reservoir of the subterranean formation. In the illustrated implementation, the solvent 26 is injected into the hydrocarbon-rich reservoir via a tubing string 28 inserted into the injection well 12. The injection well 12 generally includes a casing in its vertical portion 18, and a liner in its horizontal portion 20.
The liner extends within the wellbore and can include injection ports such that, when the solvent 26 exits the tubing string 28, the solvent 26 can fill the horizontal portion 20 of the injection well 12 and penetrate into the hydrocarbon-rich reservoir through the injection ports. Alternatively, the liner can also include a slotted portion or a screen portion that Date Recue/Date Received 2022-02-11 allows the solvent 26 to exit the injection well 12 and penetrate into the s hydrocarbon-rich reservoir. In some implementations, devices that can include straddle packers, inflatable packers, sleeves and/or coiled tubing can be used to influence the interval at which the solvent 26 is injected into the hydrocarbon-rich reservoir. The solvent 26 can also be injected via the production well 14. In some implementations, when the solvent 26 is injected via the production well 14, it can be done for instance for given periods of time in between which mobilized bitumen recovery through the production well 14 can resume to sustain formation of a bitumen-depleted region and of a solvent chamber. In yet other implementations, the solvent can be injected into the hydrocarbon-rich reservoir via a single well configuration that is operated in a cyclic mode.

[0088] The solvent 26 can be injected into the hydrocarbon-rich reservoir as vapour.
The vaporization of the solvent 26 can occur at surface using conventional heating means.
A heater string 30 can also be inserted in the injection well 12 to provide heat to the solvent 26 as it is being carried through the injection well 12 via the tubing string 28, either to vapourize the solvent 26 prior to exiting from the tubing string 28, or to maintain the solvent 26 in vapour phase prior to exiting from the tubing string 28 so that upon exiting the injection well 12, the solvent 26 is in vapour phase.

[0089] In addition to vapourizing and/or maintaining the solvent 26 in vapour phase while the solvent 26 travels along the injection well 12, the heater string 30 can also provide heat to the interwell region 16, for instance to pre-heat the bitumen prior to the injection of the solvent 26 into the hydrocarbon-rich reservoir. In some implementations, a heater (e.g., through electric resistive heaters, RF heaters or other heating means) can also be provided in the production well 14 to provide additional heat to the interwell region 16. More details regarding heating of the interwell region 16 are provided below.
Operation of an in situ recovery process in presence of a gas cap

[0090] Referring to Figs 2A to 2C, the in situ recovery process can be performed in a subterranean formation that includes a hydrocarbon-rich reservoir 32 that is at least partially overlaid by a gas cap 34. The injection well 12 and production well 14 described above in reference to Fig 1 are provided in the hydrocarbon-rich reservoir 32.
Figs 2A to 2C illustrates the progression over time of the in situ recovery process.
Date Recue/Date Received 2022-02-11

[0091] Fig 2A illustrates the subterranean formation during a startup phase. As mentioned above, the startup phase is generally aimed at mobilizing hydrocarbons in an interwell region 16 of the well pair and the area surrounding the injection well and/or production well, and establish fluid communication between the injection well 12 and the production well 14. Gas 36 is present in the gas cap 34. The gas cap 34 has a gas cap pressure PG. When no additional gas is injected into the gas cap 34, for instance to increase the pressure PG, the pressure PG can remain substantially similar throughout the various phases of the recovery process. Alternatively, a gas, such as a non-condensable gas, can be injected into the gas cap 34 via a gas injection well to increase the pressure PG, for instance if the pressure in the gas cap PG is lower than the planned long term solvent chamber pressure. This aspect will be described in further detail below.

[0092] The startup phase can include techniques such as fluid injection, fluid circulation, electrical heating, radio-frequency (RF) heating, chemical injection in at least one of the injection well and production well. Various combinations of these techniques can also be implemented. The injected or circulated fluid can include a hydrocarbon solvent, steam or a combination thereof, and the fluid can be provided as a vapour or a liquid. Techniques used during the startup phase can also be conducted in more than one stage, using a different technique for each stage.

[0093] In some implementations, the startup phase can include a conditioning phase during which a mobilizing fluid, such as a non-deasphalting fluid, is introduced in the injection well and then pushed out from the injection well to the production well to sweep the interwell region. An initial pre-heating of the horizontal wells can be performed before injecting the non-deasphalting fluid. During the conditioning phase, the mobilizing fluid can include diesel, naphtha or any other fluid known in the art for assisting mobilizing the bitumen in the interwell region and establish communication between the injection and production well. The fluid can also include steam, or a combination of a hydrocarbon-based fluid as mentioned above and steam.

[0094] Once the startup procedure is completed or near the end of the startup procedure, a mobilizing fluid, such as a solvent, is introduced into the injection well 12 and injected into the area surrounding the injection well 12. The solvent is injected into the hydrocarbon-rich reservoir in vapour phase. When contacting the cold bitumen in the Date Recue/Date Received 2022-02-11 hydrocarbon-rich reservoir, the solvent condenses on the bitumen surface and releases latent heat of condensation which is transferred to the bitumen. In addition to providing heat to the bitumen, the solvent can also contribute to diluting the bitumen.
The bitumen that has been diluted and heated produces a mobilized fluid having a lower viscosity, enabling the mobilized fluid to drain towards the production well 14. From the production well 14, the mobilized bitumen can be recovered to the surface as a production fluid and be further treated using surface facilities. The production fluid, in addition to the mobilized bitumen and some solvent, can include water that can be present in the reservoir, such as connate water from the pores of rock sediments, and also some solids and gas.
Depending on the solvent composition that is used, some degree of in situ solvent deasphalting can occur, and asphaltenes can be precipitated within the reservoir resulting in an in situ upgrading of the bitumen.

[0095] Referring now to Fig 2B, upon continuation of solvent injection, a solvent chamber 38 can grow upward and outward from the injection well 12. Optionally, to reduce early condensation of solvent and therefore solvent demand, additional heat can be provided to the reservoir. Heat addition can assist in maintaining the solvent in vapor state within the solvent chamber 38 such that less solvent is produced with the bitumen when the production fluid is recovered to the surface via the production well 14.
In such implementations, the heat can be provided at the injection well 12, at the production well 14, or at both. The heat can also be provided proximate the injection, e.g., above the injection well 12, within the solvent chamber 38. Various methods and equipment can be used to provide heat, including for instance providing downhole heaters or injecting solvent that has been superheated at surface.

[0096] In the in situ recovery process described herein, at least one solvent can be injected into the hydrocarbon-rich reservoir to dissolve bitumen and thereby reduce the bitumen viscosity, such that bitumen having a reduced viscosity can drain towards the production well and be recovered to the surface. In some implementations, the solvent can be selected and provided in an amount sufficient to induce asphaltene precipitation and deposition within the reservoir. Examples of solvents that can be used are low molecular weight alkanes, such as propane, butane, pentane hexane, heptane, and condensate. Combinations of such solvents can also be used.
Date Recue/Date Received 2022-02-11

[0097] In some implementations, the composition of the solvent can remain substantially the same whether the solvent is injected into the hydrocarbon-rich reservoir during the first phase of the process or during the second phase of the process.
Alternatively, the composition of the solvent can change depending on whether the solvent is injected during the first phase or during the second phase, i.e., the composition of the solvent injected into the hydrocarbon-rich reservoir during the first phase can be different than the composition of the solvent injected into the hydrocarbon-rich reservoir during the second phase. In addition, the composition of the solvent injected into the hydrocarbon-rich reservoir can change during the first phase, and/or the composition of the solvent injected into the hydrocarbon-rich reservoir can change during the second phase. In some implementations, the one or more changes in the composition of the solvent during the first phase, during the second phase, and/or when transitioning from the first phase to the second phase can advantageously leverage the properties of each of the components of the solvent or of each solvent, with regard to their effect on bitumen and solvent chamber growth during the recovery process. For instance, in some implementations, heavier solvents can be used during the second phase of the process compared to those used during the first phase of the process, as heavier solvents tend to preferentially condense within the solvent chamber or close to it rather than be carried away into the gas cap, which in turn can contribute to reducing solvent losses to the gas cap when the solvent chamber approaches the gas cap.

[0098] As mentioned above, the solvent is injected into the hydrocarbon-rich reservoir in vapour phase, i.e., as a vaporized solvent. Various methods can be used to introduce the solvent as vaporized solvent into the hydrocarbon-rich reservoir. For instance, in some implementations, heat can be provided to the injection well by direct wellbore heating, for instance by using electric resistive heaters. In other implementations, the solvent can be injected in a superheated state. A combination of superheated solvent and downhole heating can also be used. In this context, the expression "superheated solvent" refers to a solvent that is injected at a temperature above its dew point temperature at the operating reservoir pressure. Other heating means can include hot tubes that use a circulating heating media provided in the well, induction or electromagnetic heating, RF
heating, microwave heating, or the like.
Date Recue/Date Received 2022-02-11

[0099] In some implementations, the injection design can include injecting the solvent in vapour phase and then controlling the degree of superheating of the vapour via surface heaters and downhole electric resistive heaters. The degree of superheat can be 20 C, 30 C, 40 C or more. In some implementations, the superheated solvent can be injected at a temperature of at least 100 C above a dew point of the solvent. In some implementations, the superheated solvent can be injected up to an upper temperature threshold. The upper temperature threshold can be a temperature at which coking of bitumen is avoided in the reservoir. The upper temperature threshold can be a temperature determined according to practical considerations of the process. For example, the upper temperature threshold can be about 200 C, or can be about 250 C. In other implementations, the solvent can be injected in a superheated state at a temperature ranging from about 30 C to about 200 C, or from about 30 C to about 170 C, or from about 30 C to about 140 C. If butane is used as the solvent, a temperature from about 30 C to about 140 C can be suitable.

[00100] In some implementations, heating through downhole heating and/or injecting a superheated solvent having a certain degree of superheat can contribute to maintaining solvent within the solvent chamber in a vaporized state.

[00101] The operating pressure in the solvent chamber 38, i.e., the pressure Ps within the solvent chamber 38, and, optionally, the heat input provided to keep the solvent in vapor state in at least a portion of the solvent chamber 38, can impact the performance of the bitumen recovery process. For instance, process parameters such as solvent-bitumen ratio (SBR), hold-up bitumen ratio (HBR) and/or bitumen production rate can be particularly affected. For instance, injecting solvent such that the solvent chamber operating pressure Ps is at a high pressure, or within a range of high pressures, can facilitate rapid solvent chamber development, which in turn can result in a higher production rate. On the other hand, operating the solvent chamber at a high pressure can result in a high SBR and HBR, which can be undesirable, for example for economical reasons. Operating the solvent chamber at a low pressure, or within a range of low pressures, can results in a low SBR and HBR, which can be advantageous under certain circumstances.
Date Recue/Date Received 2022-02-11

[00102] In the context of the present in situ recovery process, an example of an operating pressure strategy that modulates the solvent injection pressure throughout the bitumen recovery process can include initially injecting solvent in the hydrocarbon-rich reservoir 34 at a first injection pressure that is higher than the initial reservoir pressure condition. In some implementations, initially injecting solvent at a first injection pressure that is higher than the initial reservoir pressure condition can mean injecting the solvent at a first injection pressure that is higher than a long-term planned operating pressure.
Injecting the solvent at a pressure that is higher than the initial reservoir pressure can contribute to facilitate rapidly growing the solvent chamber 38 in the hydrocarbon-rich reservoir 34. The initial rapid solvent chamber growth can result in a solvent chamber 38 having a large surface area, which can facilitate bitumen drainage when subsequently operating at lower pressures as recovery operations continues over time. In other words, injecting the solvent at a pressure that is higher than the initial reservoir pressure can encourage the solvent to push beyond the edges of the solvent chamber 38 and mix with bitumen, and can result in production at suitable rates compared to solvent that would be injected at a lower pressure, which relies more heavily on diffusion and can result in lower oil production.

[00103] In addition, when the hydrocarbon-rich reservoir 34 includes one or more regions of high water mobility, injecting the solvent at a pressure that is higher than the initial reservoir pressure can take advantage of the presence of water to also force the solvent beyond the edges of the solvent chamber 38, thereby facilitating mixing with bitumen and not only relying on diffusion mechanisms to dilute the bitumen. In other words, when the hydrocarbon-rich reservoir 34 includes one or more regions of high water mobility, deeper penetration of the solvent without dissolution into bitumen can be achieved to allow for the solvent chamber to grow more rapidly.

[00104] It is to be noted that in the context of the present description, when referring to the solvent being injected at a first injection pressure, it is intended to mean the pressure Ps that is reached in the solvent chamber 38 upon solvent injection, which generally corresponds to the pressure at which the solvent is injected. The expression "extraction pressure" or "injection pressure" can also be used to refer to such pressure in the reservoir.
As mentioned above, the first injection pressure is also above the initial reservoir pressure conditions. The terms "initial reservoir pressure condition" or "initial reservoir pressure"
Date Recue/Date Received 2022-02-11 refer to the pressure in the reservoir before initiating the present two-phase recovery process, which corresponds to the reservoir native pressure.

[00105] By injecting the solvent at a high pressure in the first phase of the process, solvent leak-off can be facilitated which, in turn, can enhance convective mixing of the solvent with the bitumen. The solvent/bitumen fluid that is produced in situ can then drain towards the production well 14 and be produced at the surface, resulting in a rapid growth of the solvent chamber 38 in the hydrocarbon-rich reservoir 32.

[00106] In some implementations, the first injection pressure during the first phase of the process can range from about 50 kPa to about 1000 kPa above the initial reservoir pressure. In other implementations, the first injection pressure in the first phase can range from about 50 kPa to about 800 kPa, from about 50 kPa to about 500 kPa, or from about 50 kPa to about 400 kPa, or from about 50 kPa to about 300 kPa, or from about 50 kPa to about 200 kPa, or from about 50 kPa to about 100 kPa above the initial reservoir pressure. In other implementations, the first injection pressure during the first phase of the process can range from about the initial reservoir pressure to about 50 kPa above the initial reservoir pressure.

[00107] As previously mentioned, the solvent used for assisting the bitumen recovery from the underground reservoir can be butane. When butane is used as the solvent, the first injection pressure in the first phase can range from about 350 kPa to about 1000 kPa, for example. In some implementations where butane is the solvent that is injected in the reservoir, the first phase injection pressure can range from about 350 kPa to about 900 kPa, or from about 350 kPa to about 800 kPa, or from about 500 kPa to about 700 kPa.
In other implementations, butane can be injected in the first phase at a first injection pressure ranging from about 600 kPa to about 700 kPa. The selection of the pressure in the first phase of the process can be determined for instance in accordance with at least one of the type of reservoir, the type of solvent, and the initial pressure condition thereof.
In addition, the first phase can be operated at a generally constant first injection pressure, or can be operated at different injection pressures that are within a given operating envelope.

[00108] In some implementations, the first phase of the process involving injecting the solvent at a first injection pressure that is higher than the initial reservoir pressure can be Date Recue/Date Received 2022-02-11 performed after completion of the startup phase for the recovery process. This first phase can therefore be performed as part of the ramp-up phase of the recovery process. During the ramp-up phase, the fluid communication zone in the interwell region 16 is expanded axially along the full well pair length to enhance conformance along the well, and the solvent chamber 38 grows upwardly toward the top of the hydrocarbon-rich reservoir 32.

[00109] In some implementations, the first phase of the process can be performed until the solvent chamber 38 approaches the gas cap 34, as illustrated in Fig 2C. In some implementations, the timing of the solvent chamber 38 approaching the gas cap 34 can coincide with the end of ramp-up/early stages of the plateau phase of production of the recovery process. When referring to the solvent chamber 38 approaching the gas cap 34, it is meant that the solvent chamber 38 has grown, i.e., expanded, upwardly to be within a given distance from a lower edge of the gas cap 34. In some implementations, the given distance from the lower edge of the gas cap 34 can be a predetermined distance that has been estimated based on various factors, such as geological characteristics of the reservoir, pressure of the gas cap 34, design of the recovery process, and process parameters such as HBR, SBR and production rate, among other factors. For instance, production data can be used to monitor the SBR to detect an undesirable increase in the SBR at some point during the first phase of the process, which can be indicative that the solvent chamber has approached the lower edge of the gas cap, and is within a distance that is suitable for initiating the second phase of the process during which the overbalance between the solvent chamber pressure and the gas cap pressure is kept within a certain range, to avoid solvent further escaping to the gas cap.

[00110] Once the first phase of the process is completed, a second phase of the process is initiated. In the second phase of the process, the pressure at which the solvent is injected in the hydrocarbon-rich reservoir 32 is reduced, such that the solvent is injected in the hydrocarbon-rich reservoir 32 at a second injection pressure that is a lower pressure than the first injection pressure of the first phase. In some implementations, the injection pressure can be gradually decreased from the first injection pressure to the second injection pressure. In other words, a transition phase can be implemented at the end of the first phase until reaching the second injection pressure intended to be used for the second phase. The gradual decrease from the first injection pressure to the second injection pressure can be substantially continuous, or can be achieved following one or Date Recue/Date Received 2022-02-11 more step changes in the injection pressure. In some implementations, data from observation wells can be relied upon to help determine a desired strategy for changing the pressure at which the solvent is injected in the hydrocarbon-rich reservoir 32 from the first pressure to the second pressure.

[00111] During the second phase of the recovery process, the second injection pressure is determined so as to achieve a given overbalance between the solvent chamber pressure Ps and the gas cap pressure PG, with the second injection pressure being lower than the first injection pressure. In some implementations, the overbalance between the solvent chamber pressure Ps and the gas cap pressure PG can be between about 5 kPa and about 100 kPa, between about 5 kPa and about 50 kPa, or between about 20 kPa and about 50 kPa. In some implementations, the overbalance between the solvent chamber pressure Ps and the gas cap pressure PG can be at most about 200 kPa, or at most about 150 kPa.

[00112] Injecting the solvent at a second injection pressure that is lower than the first injection pressure and to achieve a given overbalance Ps > PG between the solvent chamber pressure Ps and the gas cap pressure PG that is within a certain range can help reducing solvent losses to the gas cap 34 as the solvent chamber 38 expands upwardly.
If the overbalance during the second phase of the process is too high, solvent losses to the gas cap 34 and the native reservoir can occur, which can negatively impact the economics of the recovery process. On the other hand, if the pressure difference between the solvent chamber pressure Ps and the gas cap pressure PG results in an underbalance PS < PG, with the pressure of the solvent chamber 38 being lower than the pressure of the gas cap 34, gas 36 present in the gas cap 34 can flow into the solvent chamber 38, which can prevent the solvent from condensing at the chamber edge and negatively impact the recovery process. In other words, it may be desirable to keep a net flow from the solvent chamber 38 to the gas cap 34, while controlling this net flow with a given overbalance to prevent solvent losses to the gas cap 34. Advantageously, reducing the operating pressure of the solvent chamber can contribute to maintain solvent in vaporized form within the solvent chamber 38, thus reducing HBR and SBR.

[00113] In some implementations, an operating pressure strategy that includes a first phase during which vaporized solvent is injected at a first injection pressure, i.e., a high Date Recue/Date Received 2022-02-11 pressure, followed by a second phase during which vaporized solvent is injected at a second injection pressure that is lower than the first injection pressure and such that the overbalance between the solvent chamber pressure Ps and the gas cap pressure PG is within a certain range, can be monitored according to key performance indicators (KPIs) related to the production data of the recovery process. Examples of such KPIs can include the solvent chamber pressure Ps itself, the pressure at which is injected the solvent, the SBR or the solvent-to-oil ratio (SvOR), the HBR and/or the bitumen production rate. One or more of these variables can be used in a feedback loop to ensure that the overbalance is within a certain range, thereby also ensuring that solvent losses or gas influx from the gas cap are minimized.

[00114] In some implementations, one or more observation wells can be provided in the subterranean formation to monitor the pressure PG of the gas cap 34 and/or the pressure Ps of the solvent chamber 38. Monitoring the pressure PG of the gas cap 34 and/or the pressure PS of the solvent chamber 38 using observation wells can facilitate assessing the overbalance between the solvent chamber pressure and the gas cap pressure.
The observation wells can be equipped with appropriate devices, such as pressure gauges, for measuring pressure at a selected location and relaying the information so that certain appropriate actions can be taken. The observation well can be a separate well drilled in a selected location of the reservoir for the dedicated purpose of observing parameters, such as fluid levels, and gas content and pressure within the reservoir. In an example scenario, an observation well is equipped with pressure gauges to monitor the extent of the solvent chamber. A first pressure gauge can be installed in an upper region of the solvent chamber and a second pressure gauge can be installed in a lower region of the solvent chamber, at a predetermined distance from the first pressure gauge. The pressure of the solvent chamber can then be inferred from the pressure differential between the first and the second pressure gauges at the location of a given observation well. The pressure of the gas cap can also be monitored in a similar fashion. In some implementations, the pressure differential can be calculated based on the difference between a pressure measured in the solvent chamber or in the gas cap, and the atmospheric pressure.

[00115] In some implementations, the pressure PG in the gas cap 34 can be measured using downhole instrumentation, such as pressure gauges, provided on the injection well 12, such that pressure at one location can be inferred if pressure at another location is Date Recue/Date Received 2022-02-11 known. For instance, in some implementations, when fluid communication between the solvent chamber and the gas cap has been established, it may be inferred that a gas column extends from the injection well to the gas cap, and the vertical pressure variation can be used to determine the pressure PG in the gas cap according to the equation P =
p.g. h. The KPIs described above can be used together with the downhole instrumentation to ensure that the monitoring of the overbalance is as accurate as possible and can be appropriately adjusted if desired or needed. In such scenarios, the downhole instrumentation can be used as a guide, and the KPIs can be used to confirm the information provided by the downhole instrumentation.

[00116] In some implementations, the growth of the solvent chamber can be monitored to determine when to transition from the first injection pressure to the second injection pressure. The growth of the solvent chamber can be assessed in various ways.
For instance, the size of the solvent chamber can be used as an indicator of the growth of the solvent chamber. The height of the solvent chamber and thus the distance from the top edge of the solvent chamber to the lower edge of the gas cap can also be used as an indicator of the growth of the solvent chamber, thereby enabling to determine if the solvent chamber is in close proximity of the lower edge of the gas cap. Another variable that can be used to evaluate the growth of the solvent chamber is the growth rate of the solvent chamber, which can be predictive of the moment when the top edge of the solvent chamber will be within a given distance from the lower edge of the gas cap. In some implementations, if there are already existing wells in the neighborhood that are producing, then their performance can also be used to calculate when fluid communication between the solvent chamber and the gas cap is likely to happen.

[00117] The growth of the solvent chamber can be inferred using various techniques, some of which are presented below.

[00118] In some implementations, one or more observation wells can also be provided to monitor the growth of the solvent chamber. When an observation well is used to monitor the growth of the solvent chamber, pressure gauges can be provided along the height of the observation well and used as described above to evaluate the rate at which the growth of the solvent chamber is progressing. Accordingly, as the location of the lower edge of the gas cap 34 is typically known, it is possible to estimate the moment in time when the Date Recue/Date Received 2022-02-11 solvent chamber will be at a given distance from the lower edge of the gas cap 34. The observation well can also be used to monitor the growth of the solvent chamber by monitoring the water saturation of the hydrocarbon-rich reservoir and/or the gas cap, and the temperature of the solvent chamber.

[00119] In some implementations, reservoir simulations can be performed and matched with history data, and considering geology models for that reservoir, the moment in time when the solvent chamber will be at a certain distance from the lower edge of the gas cap 34 can be estimated. In accordance with the output of the simulations, once it is determined that the solvent chamber is approaching the lower edge of the gas cap, the transition from the first injection pressure to the second injection pressure can be performed, to achieve a given overbalance between the solvent chamber pressure and the gas cap pressure. The reservoir simulations can include performing a first set of simulations over a first range of simulation pressures to determine a first injection pressure at which to inject the solvent in a first phase of the process. In other words, an initial reservoir pressure is set in a simulation model, and this initial pressure can be determined for instance taking into account reservoir permeability, water saturation, and water mobility. Simulations are run for the life of the well at the initial pressure chosen.
Simulations are then repeated to determine the impact on solvent chamber growth, compared to other pressures used in the simulations. Simulations can also be performed at different pressures to obtain data that is indicative of solvent consumption over the life of the well. Based on the results of the reservoir simulations regarding the growth of the solvent chamber, it can be determined at which point during the life of the well the first injection pressure can be transitioned to the second injection pressure to achieve a desired overbalance. Thus, reservoir simulations can be a useful tool to optimize the injection pressures and strategy for transitioning from the first injection pressure to the second injection pressure. The learning from the simulation data can be used to design the initial process, which can then be modified as desired as actual field data comes in and the simulation model is updated with operational !earnings.

[00120] Time lapsed seismic, also referred to as 4D seismic, is another technique that can be used to evaluate the size of the solvent chamber, by evaluating the changes in the acoustic and elastic properties of the geological formation. In such 4D
seismic analysis, Date Recue/Date Received 2022-02-11 changes in amplitude and velocity are compared with baseline seismic interpretation, and maps are then generated to monitor the size, or extent, of the solvent chamber.

[00121] During the first phase of the recovery process, when the solvent is injected at a first injection pressure that is higher than the initial reservoir pressure condition, and during the second phase of the process which is performed at a lower pressure than the first phase to maintain a certain overbalance between the solvent chamber pressure and the gas cap pressure, heat energy can be provided in at least a portion of the solvent chamber, for instance to the injection well, to maintain the solvent in vaporized form.

[00122] In some implementations, the approach selected for providing the desired heat during the first phase of the process can be different than the heating method used during the second phase. For instance, superheated vaporized solvent can be injected at high pressure during the first phase, and then solvent can be injected at a lower temperature while heat is provided using downhole heating during the second phase.
Alternatively, the first phase can involve injecting vaporized solvent at high pressure and heating the injection well using downhole heating, and then injecting superheated solvent during the second phase. The two phases can also utilize both heating methods to different degrees, such that one phase uses more superheating energy than the other. In some implementations, the solvent injected temperatures and pressures can be varied in the first phase and the second phase, using surface and downhole equipment and/or by varying the degree of solvent superheat at surface.

[00123] In some implementations, the heat provided during the first phase and the second phase of the recovery process can be the same. However, it can be advantageous, in some implementations, to vary the heat input in the first phase and the second phase of the process. In some implementations, the heat energy provided during the first phase of the process while injecting the solvent at high pressure can be lower than the heat energy provided during the second phase of the process while injecting the solvent at lower pressure. In other implementations, the heat energy provided during the first phase of the process while injecting the solvent at high pressure can be higher than the heat energy provided during the second phase of the process while injecting the solvent at lower pressure. For instance, during the first phase of the process, the solvent can be injected at a first injection pressure, i.e., at a high pressure, that is sufficient to facilitate Date Recue/Date Received 2022-02-11 convective mixing of the solvent with the bitumen at the extraction interface, as the solvent chamber is still small and it may be advantageous to limit the heat provided such that solvent is still under conditions that it can condenses at the extraction interface. Then, as the first phase of the process transitions to the second phase of the process and as the solvent chamber grows, increased heat can be provided since the solvent chamber is now larger. Then, during the second phase of the process, the amount of heat can be chosen such that sufficient solvent remains in vapor phase within the solvent chamber to maintain the desired overbalance between the solvent chamber pressure Ps and the gas cap pressure PG. Use of a downhole electric resistive (ER) heater to provide the desired heat energy can be particularly convenient in the context of the present description, although other downhole heating means can also be contemplated, as previously mentioned.

[00124] The amount of heat energy can be adapted depending on the type of solvent that is injected. Higher heat energy can be desired to maintain a solvent having a higher molecular weight in vapour phase. For instance, if the solvent is pentane, the heat energy can be higher than the heat energy provided if butane or propane are used as the solvent, at the same operating pressure.

[00125] When the solvent is injected in a superheated state, the heat energy transferred by the solvent to the reservoir around the injection well can be sufficient to limit early condensation of the solvent in the proximity of the injection well. Therefore, in some implementations, the recovery process can involve injecting superheated solvent during the first phase and the second phase of the process, without requiring additional downhole heating means. However, if the degree of superheating of the solvent vapour provided by surface heaters is insufficient, downhole electric resistive heaters, or any other downhole heating means, can be used to increase the superheated solvent temperature in either one or both phases of the process.

[00126] In some implementations, the determination of the degree of superheat during each of the first phase and the second phase can be done in accordance with the injection pressure of the solvent during these respective phases. In some implementations, injecting the solvent at a higher degree of superheat can contribute to maintain a given operating pressure of the solvent chamber since the solvent will thus have a higher tendency to remain in vapour phase in the solvent chamber.
Date Recue/Date Received 2022-02-11

[00127] In some implementations, the superheated solvent can be injected at a temperature of at least 100 C above a dew point of the solvent. In some implementations, the superheated solvent can be injected up to an upper temperature threshold.
The upper temperature threshold can be a temperature at which coking of bitumen is avoided in the reservoir. The upper temperature threshold can be a temperature determined according to practical considerations of the process. For example, the upper temperature threshold can be 200 C, or can be 250 C.

[00128] In other implementations, the solvent can be injected in a superheated state at a temperature ranging from about 30 C to about 200 C, or from about 30 C to about 170 C, or from about 30 C to about 140 C. If butane is used as the solvent, a temperature from about 30 C to about 140 C can be suitable.

[00129] The second phase of the process can continue for instance as long as the bitumen production rate is economic and/or that the SBR does not increase to an undesirable limit. In some implementations, solvent injection is then ceased and a wind-down phase can be implemented, where a non-condensable gas (NCG) can be injected under pressure in the context of a pressure maintenance strategy.

[00130] Several well pairs can be deployed from a well pad and are typically arranged so that at least some of the well pairs are in provided parallel and side-by-side relative to each other to form an array of well pairs in the reservoir. For an array of side-by-side well pairs, the solvent injection can be controlled so that multiple well pairs, and optionally all of the well pairs, are transitioned from the high pressure phase to the low pressure phase generally substantially at the same time. Coordinating the transition from high to low pressure for the side-by-side well pairs can reduce the risk of high pressure solvent inadvertently leaking from a high pressure chamber into an adjacent low pressure chamber. In some implementations, adjacent well pairs are transitioned from the higher pressure phase to the low pressure phase together. Surface operations can also be facilitated when all adjacent well pairs are converted together from high to low pressure modes. Nevertheless, depending on well pair spacing, chamber growth, and the progression of the process for each well pair, it may be desirable to operate some adjacent well pairs at different pressure phases.
Date Recue/Date Received 2022-02-11

[00131] It is also noted that an array of adjacent well pairs can be operated so that all of the injection wells are operated under a similar pressure during the first phase of the process, and at a similar pressure during the second phase of the process.
Alternatively, the well pairs can be operated at different specific pressures from each other while all being within a general pressure operating envelope for the given phase. In addition, for an array of wells, eventually adjacent chambers can coalesce to form a common chamber that has a generally uniform pressure. The well pairs can be operated such that coalescence occurs during the second phase and thus under lower pressure conditions, and that the overbalance is evaluated between the coalesced solvent chamber and the gas gap.

[00132] The pressure and heating operating conditions of the process described above can vary depending on the nature of the bitumen reservoir and the initial reservoir parameters. However, thermal solvent bitumen recovery from any bitumen reservoir can benefit from the two-phase strategy described herein.

[00133] Referring now to Figs 3A to 3C, a recovery process similar to the one described in reference to Figs 2A to 2C is illustrated. A difference between the recovery process exemplified in Figs 3A to 3C compared to the recovery process exemplified in Figs 2A to 2C is that a gas injection well 40 extends in the gas cap 34 to inject an additional gas 42 into the gas cap 34. Injection of additional gas 42 into the gas cap 43 can be performed for instance in scenarios when it is determined that the gas cap 34 is at a lower pressure PG compared to a planned long term pressure Ps of the solvent chamber 38. In such scenarios, the pressure PG of the gas cap 34 can be increased via the injection of the additional gas 42, which can be for instance a non-condensable gas (NCG) such as methane or propane. In some implementations, the selection of gases can be made for instance in accordance with the thickness of the gas cap 34. For instance, for a thicker gas cap, a less expensive gas, such as methane, can be selected for injection since a larger volume of this additional gas will end up being injected compared to a scenario where the gas cap would be thinner. For a thinner gas cap, a wider range of gas may be available, including more expensive ones such as propane, since the volume of gas to be injected will be smaller. Considerations other than the cost can also influence the choice of the additional gas 42 into the gas cap 43. The additional gas 42 chosen to increase the pressure PG of the gas cap 34 can be introduced into the gas cap 34 via a gas injection Date Recue/Date Received 2022-02-11 well 40 drilled directly into the gas cap 34 as shown in Figs 3A to 3C, which can contribute to preventing solvent losses as well as steam losses if steam is co-injected with solvent.

[00134] In some implementations, the region overlying the hydrocarbon-rich reservoir 32 can be a hydrocarbon-lean zone, i.e., a zone where the hydrocarbon saturation is less than the typical saturation of a hydrocarbon-rich zone 32. In such implementations, a gas corresponding to the additional gas 42 described above can be injected into the hydrocarbon-lean zone to move water present in the hydrocarbon-lean zone away, and increase the pressure within the hydrocarbon-lean zone in a similar fashion as when the gas cap 34 is pressurized. When an additional gas is injected into the hydrocarbon-lean zone, the hydrocarbon-lean zone can thus subsequently be converted to a gas cap.
Alternatively, the hydrocarbon-lean zone can remain as is, i.e., without an additional gas being injected therein to pressurize the hydrocarbon-lean zone. Accordingly, it is to be understood that the concepts described herein in relation to a gas cap are applicable to a hydrocarbon-lean zone as well. Furthermore, it is to be understood that in the context of the present description, a gas cap and a hydrocarbon-lean zone can each be referred to as an "upper zone" having at least a portion overlying a hydrocarbon-lean zone, and that the expression "upper zone" can be used interchangeably with the expressions "gas cap"
and "hydrocarbon-lean zone".

[00135] In some implementations, the pressurization of the gas cap 34 (or of the hydrocarbon-lean zone) can be conducted prior to the startup phase or as part of the startup phase. In other implementations, for instance when the gas cap 34 is not in fluid communication with a larger gas zone, the gas cap 34 can be pressurized while the solvent chamber 38 is growing, rather than in advance of the recovery process, i.e., rather than prior to or during the startup phase. In some implementations, the pressurization of the gas cap 34 can be initiated prior to drilling the wells. Alternatively, the pressurization of the gas cap 34 can begin after the startup phase, ideally as long as the growth of the solvent chamber 38 is such that the desired pressurization of the gas cap 34 is performed before the solvent chamber 38 reaches the gas cap 34. However, it should be noted that various Date Recue/Date Received 2022-02-11 timing strategies can be used for increasing the pressure PG in the gas cap 34, for instance depending on the design of the recovery process.

[00136] In the implementation shown in Fig 4A, the gas injection well 40 is operated to increase the pressure PG in the gas cap 34 prior to operating the recovery process in the underlying hydrocarbon-rich reservoir 32, for instance prior to the startup phase. At some stage, the injection well and the production well are drilled, completed, and started up. As mentioned above, the timing of drilling, completion and startup phase can depend on a number of factors. With reference to Fig 4B, after startup of the well pair to establish fluid communication between the injection well 12 and the production well 14, the solvent chamber 38 is formed and expands upwardly around the injection well 12.

[00137] Referring to Fig 4C, the solvent chamber 18 eventually approaches the lower part of the gas cap 34. It should be noted that there can be some heat conducted upward from the upper edge of the solvent chamber 38 and that can reach the gas cap 34 before the solvent chamber 38 itself. As heat and solvent vapour approaches the gas cap 34, the gas gap 34 provides insulation and pressurization to reduce heat and solvent losses.

[00138] It is to be noted that although a single well pair is shown in Figs 3A
to 3C, an array of well pairs can alternatively be provided in the hydrocarbon-rich reservoir 32. An array of well pairs can include various numbers of well pairs that typically extend from a single well pad located at the surface. Typically, a hydrocarbon-rich reservoir is developed in stages, where a first array of wells is provided and operated in a first portion of the reservoir as a first stage of reservoir development, and then a second array of wells is provided and operated in another portion of the reservoir as a subsequent stage of reservoir development. The first and second arrays of wells can be located adjacent to each other, and the arrays can be generally parallel to each other or at various angles, depending on the reservoir geology and hydrocarbon distribution in the pay zones. As new arrays of wells are provided and operated, additional gas injection wells can also be provided in close proximity thereto to form a pressurized gas cap that follows the recovery operations.

[00139] Referring to Figs 2C and 3C, the pressures PG and Ps can both be monitored and adjusted so that the overbalance is within a desired range. In some implementations, the overbalance can be controlled by modifying the injection rate of the solvent in the Date Recue/Date Received 2022-02-11 hydrocarbon-rich reservoir 32. When a gas injection well 40 is provided in the gas cap 34 such as shown in Fig 3C, the overbalance can also be controlled by modifying the injection rate of the additional gas 42 in the gas cap 34. Accordingly, when a gas injection well 40 is provided in the gas cap 34 such as shown in Fig 3C, the overbalance can be controlled based on two levers, i.e., the injection well 12 and the gas injection well 40, which facilitates additional options for process control.

[00140] Several alternative implementations and examples have been described and illustrated herein. The implementations of the technology described above are intended to be exemplary only. A person of ordinary skill in the art would appreciate the features of the individual implementations, and the possible combinations and variations of the components. A person of ordinary skill in the art would further appreciate that any of the implementations could be provided in any combination with the other implementations disclosed herein. It is understood that the technology may be embodied in other specific forms without departing from the central characteristics thereof. The present implementations and examples, therefore, are to be considered in all respects as illustrative and not restrictive, and the technology is not to be limited to the details given herein. Accordingly, while the specific implementations have been illustrated and described, numerous modifications come to mind.
Date Recue/Date Received 2022-02-11

Claims (63)

33

1. A solvent-assisted process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation, the process comprising:
a first phase during which a solvent is injected in vapour phase into the hydrocarbon-rich reservoir via an injection well to form a solvent chamber having a solvent chamber pressure, the solvent being injected at a first injection pressure that is at or higher than an initial reservoir pressure condition; and a second phase during which the solvent is injected into the hydrocarbon-rich reservoir at a second injection pressure that is provided so as to achieve an overbalance between the solvent chamber pressure and a gas cap pressure of a gas cap having at least a portion located above the hydrocarbon-rich reservoir, the second injection pressure being lower than the first injection pressure.

2. The solvent-assisted process of claim 1, wherein the first injection pressure is at most 1000 kPa above the initial reservoir pressure.

3. The solvent-assisted process of claim 2, wherein the first injection pressure is between about 50 kPa and about 600 kPa above the initial reservoir pressure.

4. The solvent-assisted process of any one of claims 1 to 3, wherein the overbalance is between about 5 kPa and about 100 kPa.

5. The solvent-assisted process of any one of claims 1 to 3, wherein the overbalance is between about 5 kPa and about 50 kPa.

6. The solvent-assisted process of any one of claims 1 to 3, wherein the overbalance is between about 20 kPa and about 50 kPa.

7. The solvent-assisted process of any one of claims 1 to 6, wherein the overbalance is provided so as to limit solvent leaking off to the hydrocarbon-rich reservoir.

8. The solvent-assisted process of any one of claims 1 to 7, further comprising monitoring the overbalance between the solvent chamber pressure and the gas cap pressure, and adjusting the second injection pressure to achieve the overbalance.

9. The solvent-assisted process of any one of claims 1 to 7, further comprising injecting a non-condensable gas in the gas cap at a non-condensable gas injection pressure.

10. The solvent-assisted process of claim 9, further comprising monitoring the overbalance between the solvent chamber pressure and the gas cap pressure, and adjusting the non-condensable gas injection pressure to achieve the overbalance.

11. The solvent-assisted process of claim 10, wherein adjusting the non-condensable gas injection pressure comprises at least one of adjusting an injection rate of the non-condensable gas, modifying a location of a gas injection well via which the non-condensable gas is injected into the gas cap, and modifying a number of non-condensable gas injection wells.

12. The solvent-assisted process of claim 10 or 11, comprising adjusting the second injection pressure to achieve the overbalance.

13. The solvent-assisted process of any one of claims 8 to 12, wherein monitoring the overbalance between the solvent chamber pressure and the gas cap pressure comprises monitoring data from at least one observation well.

14. The solvent-assisted process of claim 13, wherein the at least one observation well is provided in the gas cap to monitor the gas cap pressure.

15. The solvent-assisted process of claim 13, wherein the at least one observation well is provided in the solvent chamber to monitor the solvent chamber pressure.

16. The solvent-assisted process of claim 13, wherein the at least one observation well comprises a first observation well is provided in the gas cap to monitor the gas cap pressure and a second observation well is provided in the solvent chamber to monitor the solvent chamber pressure.

17. The solvent-assisted process of any one of claims 1 to 16, further comprising monitoring a growth of the solvent chamber.

18. The solvent-assisted process of claim 17, wherein monitoring the growth of the solvent chamber comprises monitoring data from at least one observation well.

19. The solvent-assisted process of claim 17 or 18, wherein monitoring the growth of the solvent chamber comprises performing reservoir simulations.

20. The solvent-assisted process of any one of claims 17 to 19, wherein a transition from the fist phase to the second phase is determined at least in part based on the growth of the solvent chamber.

21. The solvent-assisted process of claim 20, wherein monitoring the growth of the solvent chamber comprises determining at least one of a size of the solvent chamber, a height of the solvent chamber, a distance from a top edge of the solvent chamber to a lower edge of the gas cap, and a growth rate of the solvent chamber.

22. The solvent-assisted process of any one of claims 1 to 21, wherein each of the first and second phases comprises:
providing heat to the injection well;
condensing the solvent at a bitumen extraction interface thereby delivering heat to the bitumen and dissolving the bitumen; and recovering a production fluid comprising bitumen and solvent from a production well located below the injection well.

23. The solvent-assisted process of claim 22, wherein the heat is provided using downhole heating means delivering heat energy at a rate per unit length ranging about 300 W/m to about 800 W/m.

24. The solvent-assisted process of claim 23, wherein the heat is provided by at least one of an electric resistive heater and electromagnetic heating.

25. The solvent-assisted process of claim 22 or 23, wherein the heat is provided by injecting the solvent as a superheated solvent.

26. The solvent-assisted process of claim 22 or 23, wherein the heat is provided by injecting the solvent as a superheated solvent at a temperature of at least 100 C above a dew point thereof.

27. The solvent-assisted process of claim 26, wherein the superheated solvent has a temperature ranging from about 30 C to about 250 C.

28. The solvent-assisted process of claim 26, wherein the superheated solvent has a temperature ranging from about 30 C to about 200 C.

29. The solvent-assisted process of claim 26, wherein the superheated solvent has a temperature ranging from about 30 C to about 170 C.

30. The solvent-assisted process of claim 26, wherein the superheated solvent has a temperature ranging from about 30 C to about 140 C.

31. The solvent-assisted process of any one of claims 1 to 30, wherein the first phase is performed after completion of a startup operation for the process for recovering bitumen.

32. The solvent-assisted process of any one of claims 1 to 31, wherein the first phase is performed as part of a ramp-up phase of the process for recovering bitumen.

33. The solvent-assisted process of any one of claims 1 to 32, wherein the solvent is selected and provided in an amount to induce asphaltene precipitation in the reservoir.

34. The solvent-assisted process of any one of claims 1 to 33, further comprising monitoring a process parameter during the first phase and/or the second phase.

35. The solvent-assisted process of claim 34, wherein the process parameter comprises at least one of HBR, SBR and a bitumen production rate.

36. The solvent-assisted process of any one of claims 1 to 35, wherein the first injection pressure ranges from about 350 kPa to about 1000 kPa.

37. The solvent-assisted process of any one of claims 1 to 36, wherein the first injection pressure ranges from about 350 kPa to about 900 kPa.

38. The solvent-assisted process of any one of claims 1 to 37, wherein the first injection pressure ranges from about 350 kPa to about 800 kPa.

39. The solvent-assisted process of any one of claims 1 to 38, wherein the first injection pressure ranges from about 500 kPa to about 700 kPa.

40. The solvent-assisted process of any one of claims 1 to 39, wherein the first injection pressure ranges from about 600 kPa to about 700 kPa.

41. The solvent-assisted process of any one of claims 1 to 40, wherein the second phase comprises an initial transition phase during which the first injection pressure is gradually reduced to the second injection pressure.

42. The solvent-assisted process of claim 41, wherein gradually reducing the first injection pressure to the second injection pressure comprises a continuous change.

43. The solvent-assisted process of claim 41, wherein gradually reducing the first injection pressure to the second injection pressure comprises a step change.

44. The solvent-assisted process of any one of claims 1 to 43, wherein the solvent comprises propane, butane, pentane, hexane, heptane, condensate, or a mixture thereof.

45. The solvent-assisted process of any one of claims 1 to 43, wherein the solvent comprises propane.

46. The solvent-assisted process of any one of claims 1 to 43, wherein the solvent comprises butane.

47. The solvent-assisted process of any one of claims 1 to 46, wherein a composition of the solvent is substantially the same during the first phase and during the second phase.

48. The solvent-assisted process of any one of claims 1 to 46, wherein a composition of the solvent during the first phase is different than the composition of the solvent during the second phase.

49. The solvent-assisted process of any one of claims 1 to 46, wherein the solvent has a variable composition during the first phase and/or during the second phase.

50. The solvent-assisted process of any one of claims 1 to 49, wherein the solvent-assisted process is a solvent-dominated recovery process.

51. The solvent-assisted process of any one of claims 1 to 49, wherein the solvent-assisted process is a solvent-only recovery process.

52. A solvent-assisted process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation, the process comprising:
injecting a gas into a hydrocarbon-lean zone having at least a portion located above the hydrocarbon-rich reservoir to form a gas cap having a gas cap pressure;
injecting a solvent in vapour phase into the hydrocarbon-rich reservoir via an injection well to form a solvent chamber having a solvent chamber pressure, the solvent being injected at a first injection pressure that is at or higher than an initial reservoir pressure condition; and injecting the solvent into the hydrocarbon-rich reservoir at a second injection pressure that is provided so as to achieve an overbalance between the solvent chamber pressure and the gas cap pressure, the second injection pressure being lower than the first injection pressure.

53. The solvent-assisted process of claim 52, wherein the gas is a non-condensable gas.

54. The solvent-assisted process of claim 53, wherein the non-condensable gas comprises methane.

55. The solvent-assisted process of claim 53 or 54, wherein the non-condensable gas comprises propane.

56. A solvent-assisted process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation, the process comprising:
injecting a solvent in vapour phase into the hydrocarbon-rich reservoir to form a solvent chamber having a solvent chamber pressure, the solvent being injected at a first injection pressure that is at or higher than an initial reservoir pressure condition;

monitoring a growth of the solvent chamber; and when a top edge of the solvent chamber approaches a lower edge of an upper zone having at least a portion located above the hydrocarbon-rich reservoir, injecting the solvent into the underground reservoir at a second injection pressure so as to achieve an overbalance between the solvent chamber pressure and an upper zone pressure of the upper zone.

57. The solvent-assisted process of claim 56, wherein monitoring the growth of the solvent chamber comprises monitoring data from at least one observation well.

58. The solvent-assisted process of claim 56 or 57, wherein monitoring the growth of the solvent chamber comprises performing reservoir simulations.

59. The solvent-assisted process of any one of claims 56 to 58, wherein monitoring the growth of the solvent chamber comprises determining at least one of a size of the solvent chamber, a height of the solvent chamber, a distance from the top edge of the solvent chamber to the lower edge of the gas cap, and a growth rate of the solvent chamber.

60. The solvent-assisted process of claim 59, wherein the distance from the top edge of the solvent chamber to the lower edge of the gas cap is a predetermined distance.

61. The solvent-assisted process of claim 59 or 60, wherein the distance is estimated at least in part based on at least one of a geological characteristic of the reservoir, the gas cap pressure, and a process parameter.

62. The solvent-assisted process of claim 61, wherein the process parameter comprises at least one of HBR, SBR and a bitumen production rate.

63. A solvent-assisted process for recovering bitumen from a hydrocarbon-rich reservoir of a subterranean formation, the process comprising:
a first phase during which a solvent is injected in vapour phase into the hydrocarbon-rich reservoir via an injection well to form a solvent chamber having a solvent chamber pressure, the solvent being injected at a first injection pressure that is at or higher than an initial reservoir pressure condition; and a second phase during which the solvent is injected into the hydrocarbon-rich reservoir at a second injection pressure that is provided so as to achieve an overbalance between the solvent chamber pressure and a hydrocarbon-lean zone pressure of a hydrocarbon-lean zone having at least a portion located above the hydrocarbon-rich reservoir, the second injection pressure being lower than the first injection pressure.