CA3113483A1

CA3113483A1 - Lean zone pressurization and management for underlying hydrocarbon recovery operations

Info

Publication number: CA3113483A1
Application number: CA3113483A
Authority: CA
Inventors: Hossein Aghabarati
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2017-12-13
Filing date: 2017-12-13
Publication date: 2019-06-13
Anticipated expiration: 2037-12-13
Also published as: CA2988709A1; CA3113483C; CA2988709C

Abstract

Recovering hydrocarbons can include injecting non-condensable gas via a gas injection well into a hydrocarbon-lean zone being located above and in fluid communication with a hydrocarbon-rich reservoir, to form a gas-enriched region within the hydrocarbon-lean zone, to pressurize the hydrocarbon-lean zone and to displace at least a portion of the water contained therein. ln-situ recovery wells can be operated within the hydrocarbon- rich reservoir and a mobilizing fluid chamber can be formed in the hydrocarbon- rich reservoir. The gas-enriched region can reduce fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water can be displaced away from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber. After recovery from the hydrocarbon-rich reservoir, the hydrocarbon- rich reservoir enters a mature phase and at least a portion of the non-condensable gas can be recovered from the hydrocarbon-lean zone.

Description

LEAN ZONE PRESSURIZATION AND MANAGEMENT FOR UNDERLYING
HYDROCARBON RECOVERY OPERATIONS
TECHNICAL FIELD
[0001] The technical field generally relates to in-situ hydrocarbon recovery, and more particularly, to injection of gas into hydrocarbon-lean zones that overly hydrocarbon-rich reservoirs.
BACKGROUND

[0002] In heavy hydrocarbon-bearing reservoirs, top zones that are hydrocarbon lean and water rich are considered challenging for recovery using techniques such as Steam-Assisted Gravity Drainage (SAGD). SAGD is an enhanced hydrocarbon recovery technology for producing heavy hydrocarbons, such as heavy oil and/or bitumen, from heavy hydrocarbon-bearing reservoirs. Typically, a pair of horizontal wells is drilled into a reservoir, such as an oil sands reservoir, and steam is injected into the reservoir via the upper injection well to heat and reduce the viscosity of the heavy hydrocarbons. The mobilized hydrocarbons drain into the lower production well mainly due to gravity forces and are recovered to the surface. Over time, a steam chamber having a steam chamber pressure forms above the injection well and extends upward and outward within the reservoir as the mobilized hydrocarbons flow toward the production well.

[0003] Conventional SAGD operated in reservoirs with top water-containing, hydrocarbon-lean zones (e.g., lean bitumen zones) can lead to an elevated Steam-to-Oil Ratio (SOR) and low hydrocarbon recovery rates, since heat and steam can be lost to the overlying water-rich zone due to lower pressures in the lean zone and high heat capacity due to high water content in the lean zone. This can result in poor performance in terms of oil production and efficiency due to the fact that significant steam energy can be wasted in heating the hydrocarbon-lean zone, which becomes more important once the steam chamber intercepts the hydrocarbon-lean zone which is generally at a lower pressure than the steam chamber pressure. The high heat capacity of water and tendency of the steam to flow into the lean bitumen zone due to the pressure differential between the hydrocarbon-lean zone and the hydrocarbon-rich reservoir pose challenges to heavy hydrocarbon recovery from reservoirs with a water-saturated, hydrocarbon-lean zone. In addition to an elevated SOR, water production from hydrocarbon-lean zones also has the Date Recue/Date Received 2021-03-30 potential to limit the emulsion treatment capacity of SAGD plant and to reduce bitumen production capacity because of the high water cut.

[0004] Some conventional solutions have been proposed in an attempt to enhance the hydrocarbon recovery rate in such lean zones. A first method includes decreasing the recovery well spacing to promote higher production of bitumen before the steam chamber intercepts the top lean bitumen zone. However, this method increases the capital cost of the operation because of the greater number of wells to be drilled for a given reservoir volume and may not work if the thickness of the heavy hydrocarbon-rich reservoir is uneven. A second method includes co-injecting non-condensable gas (NCG) with steam into the SAGD injection well during SAGD recovery, with the intention of reducing fluid losses and improving the thermal efficiency of the recovery process. The size of the lean bitumen zone can be a relevant factor in the selection of the proper water-depletion method. When the size of the lean bitumen zone is small and limited, the above-mentioned methods may be utilized successfully. However, when the size of lean bitumen zone is larger, such methods have noteworthy drawbacks in developing such reservoirs.

[0005] There are various challenges related to hydrocarbon recovery from reservoirs that are proximate to water-saturated, hydrocarbon lean zones.
SUMMARY

[0006] In one aspect, a process for recovering hydrocarbons is provided. The process includes injecting non-condensable gas via a gas injection well having an injection portion located in a subterranean hydrocarbon-lean zone containing water and having a lower hydrocarbon content than an underlying hydrocarbon-rich reservoir, the hydrocarbon-lean zone being located above and in fluid communication with the hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas injection rate sufficient to form a gas-enriched region within the hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone to a lean zone pressure and to displace at least a portion of the water contained therein;
operating in-situ recovery wells within the hydrocarbon-rich reservoir including an injection well to inject a mobilizing fluid into the hydrocarbon-rich reservoir and a production well to recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber pressure;
monitoring the hydrocarbon-lean zone to determine at least one property of the Date Recue/Date Received 2021-03-30 hydrocarbon-lean zone; and controlling the injection of the non-condensable gas according to the at least one property of the hydrocarbon-lean zone. The gas-enriched region reduces fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water is displaced away from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber formed in the hydrocarbon-rich zone.

[0007] In another aspect, there is provided a process for recovering hydrocarbons. The process includes: injecting non-condensable gas via a gas injection well having an injection portion located in a subterranean hydrocarbon-lean zone containing water and having a lower hydrocarbon content than an underlying hydrocarbon-rich reservoir, the hydrocarbon-lean zone being located above and in fluid communication with the hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas injection rate sufficient to form a gas-enriched region within the hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone to a lean zone pressure and displace at least a portion of the water contained therein; operating in-situ recovery wells within the hydrocarbon-rich reservoir, including an injection well to inject a mobilizing fluid at a mobilizing fluid injection rate into the hydrocarbon-rich reservoir and a production well to recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber pressure; monitoring the lean zone pressure and the chamber pressures; and controlling a pressure differential between the lean zone pressure and the chamber pressures over time to remain within a pressure differential between about 0 kPa and about 200 kPa by adjusting at least one of the gas injection rate and the mobilizing fluid injection rate. The gas-enriched region reduces fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water is displaced away from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber formed in the hydrocarbon-rich zone.

[0008] In another aspect, there is provided a process for producing a recovered non-condensable gas. The process includes: injecting non-condensable gas via a gas injection well having an injection portion located in a subterranean hydrocarbon-lean zone containing water and having a lower hydrocarbon content than an underlying hydrocarbon-rich reservoir, the hydrocarbon-lean zone being located above and in fluid communication with the hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas injection rate sufficient to form a gas-enriched region within the hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone and displace at least a portion of the water Date Recue/Date Received 2021-03-30 contained therein; operating in-situ recovery wells within the hydrocarbon-rich reservoir including an injection well to inject a mobilizing fluid into the hydrocarbon-rich reservoir and a production well to recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber pressure; and after the hydrocarbon-rich reservoir enters a mature phase in which chamber pressure and hydrocarbon recovery performance decrease overtime, recovering at least a portion of the non-condensable gas from the hydrocarbon-lean zone.
The gas-enriched region reduces fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water is displaced away from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber formed in the hydrocarbon-rich zone.

[0009] In another aspect, there is provided a process for recovering hydrocarbons. The process includes: injecting non-condensable gas via a plurality of gas injection wells spaced-apart from one another and each having an injection portion located in a subterranean hydrocarbon-lean zone containing water and having a lower hydrocarbon content than an underlying hydrocarbon-rich reservoir, the hydrocarbon-lean zone being located above and in fluid communication with the hydrocarbon-rich reservoir, the non-condensable gas being injected through the plurality of gas injection wells at respective gas injection rates sufficient to form corresponding gas-enriched regions within the hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone to a lean zone pressure and displace at least a portion of the water contained therein; controlling at least one of the respective gas injection rates of the non-condensable gas into the plurality of injection wells and selecting relative positions of the gas injection wells to avoid coalescence of adjacent gas-enriched regions; and operating in-situ recovery wells within the hydrocarbon-rich reservoir including an injection well to inject a mobilizing fluid into the hydrocarbon-rich reservoir and a production well to recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber pressure. The corresponding gas-enriched regions reduce fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water is displaced away from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber formed in the hydrocarbon-rich zone.

[0010] In another aspect, there is provided a process for recovering hydrocarbons. The process includes: positioning a gas injection well having an injection portion located in a Date Recue/Date Received 2021-03-30 subterranean hydrocarbon-lean zone containing water and having a lower hydrocarbon content than an underlying hydrocarbon-rich reservoir according to a shape of the hydrocarbon-lean zone, the hydrocarbon-lean zone being located above and in fluid communication with the hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas injection rate sufficient to form a gas-enriched region within the hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone to a lean zone pressure and displace at least a portion of the water contained therein; injecting non-condensable gas via a gas injection well; operating in-situ recovery wells within the hydrocarbon-rich reservoir including an injection well to inject a mobilizing fluid at a mobilizing fluid injection rate into the hydrocarbon-rich reservoir and a production well to recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber pressure, and controlling gas injection along a length of the gas injection well to inhibit gas breakthrough into at least one of the in-situ recovery wells. The gas-enriched region reduces fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water is displaced away from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber formed in the hydrocarbon-rich zone.

[0011] In another aspect, there is provided a process for recovering hydrocarbons. The process includes: injecting non-condensable gas via a gas injection well having an injection portion located in a first hydrocarbon-lean zone containing water and having a lower hydrocarbon content than a first region of a hydrocarbon-rich reservoir, the first hydrocarbon-lean zone being located above and in fluid communication with the first region of the hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas injection rate sufficient to form a gas-enriched region within the first hydrocarbon-lean zone, pressurize the first hydrocarbon-lean zone to a lean zone pressure and displace at least a portion of the water contained therein; operating a first set of in-situ recovery wells within the first region of the hydrocarbon-rich reservoir to inject a first mobilizing fluid into the first hydrocarbon-rich reservoir and to recover hydrocarbons therefrom while forming a first mobilizing fluid chamber in the first region; after hydrocarbon recovery from the first set of in-situ recovery wells enters a mature phase resulting in a mature overall formation in which chamber pressures and hydrocarbon recovery performance decrease over time, continuing injection of the non-condensable gas to form a combined gas-enriched region comprising the non-condensable gas and the first mobilizing fluid to pressurize the overall Date Recue/Date Received 2021-03-30 mature formation; and operating a second set of in-situ recovery wells within a second region of the hydrocarbon-rich reservoir adjacent to the first region of the hydrocarbon-rich reservoir to inject a second mobilizing fluid into the second region of the hydrocarbon-rich reservoir and to recover hydrocarbons therefrom while forming a second mobilizing fluid chamber in the second region. The combined gas-enriched region reduces fluid leakage and heat loss from the second mobilizing fluid chamber into the mature overall formation.

[0012] In another aspect, there is provided a process for recovering hydrocarbons. The process includes: injecting non-condensable gas via a gas injection well having an injection portion located in a subterranean hydrocarbon-lean zone containing water and having a lower hydrocarbon content than an adjacent hydrocarbon-rich reservoir, the hydrocarbon-lean zone being in fluid communication with the hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas injection rate sufficient to form a gas-enriched region within the hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone to a lean zone pressure and to displace at least a portion of the water contained therein;
operating in-situ recovery wells within the hydrocarbon-rich reservoir including an injection well to inject a mobilizing fluid into the hydrocarbon-rich reservoir and a production well to recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber pressure;
monitoring the hydrocarbon-lean zone to determine at least one property of the hydrocarbon-lean zone; and controlling the injection of the non-condensable gas according to the at least one property of the hydrocarbon-lean zone. The gas-enriched region reduces fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water is displaced away from a region of the hydrocarbon-lean zone that is adjacent to the mobilizing fluid chamber formed in the hydrocarbon-rich zone.

[0013] In another aspect, there is provided a process for producing a recovered non-condensable gas. The process includes injecting non-condensable gas via a gas injection well having an injection portion located in a subterranean hydrocarbon-lean zone containing water and having a lower hydrocarbon content than an underlying hydrocarbon-rich reservoir, the hydrocarbon-lean zone being located above and in fluid communication with the hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas injection rate sufficient to form a gas-enriched region within the hydrocarbon-lean zone, Date Recue/Date Received 2021-03-30 pressurize the hydrocarbon-lean zone and displace at least a portion of the water contained therein; operating in-situ recovery wells within the hydrocarbon-rich reservoir including an injection well to inject a mobilizing fluid comprising a mobilizing solvent into the hydrocarbon-rich reservoir and a production well to recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber pressure; and after the hydrocarbon-rich reservoir enters a mature phase in which the chamber pressure and hydrocarbon recovery performance decrease over time, recovering at least a portion of the non-condensable gas from the hydrocarbon-lean zone; wherein the gas-enriched region reduces fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water is displaced away from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber formed in the hydrocarbon-rich reservoir.
BRIEF DESCRIPTION OF THE DRAWINGS

[0014] Fig 1 is a vertical cross-sectional view schematic of a hydrocarbon-lean zone located above a main pay zone, with a gas injection well located in the lean zone.

[0015] Fig 2 is a perspective view schematic of hydrocarbon-lean zone with a gas injection well located in the hydrocarbon-lean zone, and an observation passing through the hydrocarbon-lean zone.

[0016] Figs 3A to 3D are vertical cross-sectional view schematics illustrating gas injection and formation of a gas-enriched region within the hydrocarbon-lean zone.

[0017] Figs 4A to 4D are vertical cross-sectional view schematics illustrating gas injection and formation of a gas-enriched region within the hydrocarbon-lean zone above SAGD
operations.

[0018] Fig 5 is a perspective view schematic of a horizontal gas injection well provided in a hydrocarbon-lean zone.

[0019] Fig 6 is a vertical cross-sectional view schematic of a plurality of adjacent hydrocarbon-lean zones each having a different thickness and a corresponding gas injection well in each one of the plurality of hydrocarbon-lean zones.
Date Recue/Date Received 2021-03-30

[0020] Fig 7 is a vertical cross-sectional view schematic of a SAGD operation with a steam chamber at PSAGD and an overlying dewatered gas-enriched region at PG.

[0021] Fig 8 is a vertical cross-sectional view schematic of a reservoir including a plurality of hydrocarbon-lean zones within a high water-saturation formation that is geologically contained and located above a bitumen-rich reservoir.

[0022] Fig 9 is a vertical cross-sectional view schematic of a hydrocarbon-lean zone located above a main pay zone, with a gas injection well converted in a production well.

[0023] Fig 10 is a graph showing simulation results for a hydrocarbon-lean zone having a dome structure versus a hydrocarbon-lean zone having a flat structure.

[0024] Figs 11A to 11E are top plan view schematics of various well arrangements for gas injection wells and an array of underlying in-situ recovery wells extending from a well pad.

[0025] Figs 12A to 12D are vertical cross-sectional view schematics of gas injection wells positioned in hydrocarbon-lean zones having different shapes or geologies.

[0026] Fig 13 is a top view schematic of an area including a hydrocarbon-lean zone having multiple lean regions with different thicknesses.

[0027] Figs 14A to 14E are vertical cross-sectional views schematics of gas injections wells positioned in hydrocarbon-lean zones having different shapes, and in particular, a tapered shape.

[0028] Figs 15A to 15E are vertical cross-sectional views schematics of gas injections wells and pairs of SAGD wells in two adjacent overall formations, including respective gas-enriched regions and mobilizing fluid chambers, as well as a pressurized overall formation.

[0029] Figs 16A to 16D are vertical cross-sectional views schematics of gas injections wells showing different configurations of gas injection sections and isolation packers.

[0030] Fig 17 is a graph depicting the effect of changes water saturation levels, in %, on the capillary pressure for different hydrocarbon-lean zones and hydrocarbon-rich reservoirs.
Date Recue/Date Received 2021-03-30

[0031] Figs 18A and 18B are graphs depicting pressure variations in a hydrocarbon-lean zone as a function of time.

[0032] Fig 19 is a graph depicting pressure transient analysis data and log-log diagnostic plots to assess size increase of a gas-enriched region in a lean zone after a given period of time.

[0033] Fig 20 is a graph depicting variations in gas injection rate over time in a hydrocarbon-lean zone and cumulative gas injection over time, as well as the corresponding impact on pressurization of the hydrocarbon-lean zone, according to results from numerical reservoir simulations.
DETAILED DESCRIPTION

[0034] The proposed techniques generally relate to the injection of a gas into a water-containing, hydrocarbon-lean zone (i.e., a zone where the hydrocarbon saturation is less than the typical saturation of a hydrocarbon-rich reservoir located below such a hydrocarbon-lean zone), to enhanced hydrocarbon recovery from the hydrocarbon-rich reservoir, and to the optional recovery of the injected gas. Various techniques are described for controlling gas injection into the hydrocarbon lean zone and facilitating enhanced performance of lean zone pressurization, hydrocarbon recovery, and/or overall process efficiency.

[0035] Gas, such as non-condensable gas (NCG), is injected into the hydrocarbon-lean zone to increase the gas saturation of the hydrocarbon-lean zone and to form a gas-enriched region overlying a main pay zone in which an in-situ recovery operation is conducted. In some implementations, the in-situ recovery operation is a thermal operation, e.g., Steam-Assisted Gravity Drainage (SAGD). The in-situ recovery operation can also be a solvent assisted gravity drainage process, a solvent-assisted SAGD
process where steam and solvent are injected as mobilizing fluids, or other in-situ recovery processes that include the injection of a mobilizing fluid to increase the mobility of hydrocarbons to facilitate production.

[0036] Gas injection into the hydrocarbon-lean zone can displace water contained therein to surrounding areas and form a gas-enriched region in which the pressure is increased to a level that is ideally closer to operating pressures of the in-situ recovery operation (e.g., Date Recue/Date Received 2021-03-30 SAGD), particularly once the corresponding mobilizing fluid chambers (e.g., SAGD steam chambers) reach the hydrocarbon-lean zone. The overlying gas-enriched region can provide an insulation layer and pressurization above thermal in-situ recovery operations to reduce heat and fluid losses to the hydrocarbon-lean zone. Depending on the operating conditions of the underlying in-situ recovery operation, which can vary based on the injected mobilizing fluid (e.g., steam versus solvent), the gas injection can be adjusted in terms of injection rate, gas-enriched region pressure, nature of the gas that is injected, temperature of the gas, and so on.

[0037] In some implementations, gas injection into the hydrocarbon-lean zone is performed without any production of water from the lean-zone via water production wells.
Water is therefore displaced by the injected gas but is not produced via dedicated water production wells. Multiple gas injection wells can be provided according to various patterns or configurations to facilitate gas pressurization of the lean zone.
Alternatively, water could be produced from the hydrocarbon-lean zone via one or more water production wells, which could be provided around a primary gas injection well located in the hydrocarbon-lean zone.

[0038] A number of variables related to the gas injection can be monitored to promote pressurization of the hydrocarbon-lean zone by the gas, as well as displacement of water from the hydrocarbon-lean zone and corresponding reduction of water saturation, such as the injection rate of the gas, the locations of the gas injection wells and the volume of gas injected, as will be discussed in further detail below.

[0039] In some implementations, hydrocarbon production processes can be performed in reservoirs that include a main hydrocarbon-containing zone (i.e., a main pay zone) and a hydrocarbon-lean zone that has high water saturation, such as at least 30% to 50% vol.
water saturation, such hydrocarbon-lean zones having a tendency to reduce performance of hydrocarbon production from the main pay zone, due to the high heat capacity of water contained in the hydrocarbon-lean zone and/or lower pressure of the hydrocarbon-lean zone compared to the pressures of the recovery operation (e.g., SAGD). Various techniques that are described herein enable enhanced thermal in-situ recovery operations by pressurizing the hydrocarbon-lean zone with gas, or by pressurizing a mature overall formation adjacent a newer overall formation through the hydrocarbon-lean zone.
Date Recue/Date Received 2021-03-30

[0040] The pressurization of the hydrocarbon-lean zone can facilitate a more energy-efficient hydrocarbon recovery process. Injecting NCG into the hydrocarbon-lean zone can facilitate increasing the fluid pressure in the hydrocarbon-lean zone as the gas remains substantially trapped therein, thus reducing the differential pressure between the hydrocarbon-lean zone and the main pay zone. Consequently, heat and steam loss to the hydrocarbon-lean zone is reduced, which in turn can improve the steam-to-oil ratio (SOR), and the bitumen recovery factor.

[0041] In some implementations, the gas injection techniques described herein are used to pressurize a mature overall formation that includes a hydrocarbon-lean zone overlying a hydrocarbon-rich reservoir, the mature overall formation being proximate a newer overall formation, for example adjacent or contiguous, where an in-situ recovery operation is taking place. In such implementations, the gas injection is performed into the hydrocarbon-lean zone, so that the gas-enriched region extends downward into the underlying reservoir from which hydrocarbons have been recovered. Hence, pressure maintenance in the mature overall formation (including both the lean zone and the underlying mature pay zone) can prevent heat and steam losses from the newer overall formation to the proximate mature overall formation, which can improve the process efficiency of the newer overall formation. Gas injection through the hydrocarbon-lean zone can thus have the potential to be used as a wind-down strategy to manage mature overall formations. In addition, it can be advantageous to inject NCG via the gas injection wells located in the lean zone rather than through the SAGD injection wells located in the pay zone during or after wind-down. It is noted that the SAGD wells can be gradually throttled as gas injection is affected via the gas injection wells, and the SAGD wells can eventually be shut in. It is also noted that the gas injection wells and at least one of the SAGD well can both be operated to inject NCG in the context of such wind-down operations.

[0042] It is to be noted that even though some of the drawings and implementations refer to a SAGD operation, it should be understood that other configurations can be used that may or may not involve the use of steam. For example, an injection well may be used to inject a solvent or other chemical that can be used to modify the viscosity of the hydrocarbons in the formation, so that hydrocarbons can be produced by gravity flow to the production well, and steam may not be used in such a configuration. In other configurations, a source of thermal energy other than steam, e.g., electric heat, radio frequency energy, etc., can be used to heat the formation and modify the viscosity of the Date Recue/Date Received 2021-03-30 hydrocarbons to facilitate production by gravity drainage. The in-situ recovery techniques may include steam as a primary mobilizing fluid injected into the formation.
Other mobilizing fluids, such as hydrocarbon-based solvent (e.g., paraffinic or aromatic solvents), that may be at ambient or higher temperatures, can also be injected into the formation alone, co-injected with steam, or injected in an alternating manner with steam to help mobilize the hydrocarbons. In addition, other heating methods can be used, alone or in combination with mobilizing fluid injection, to help mobilize the hydrocarbons for gravity drainage. Furthermore, the in-situ recovery process can be implemented using a well pair that includes an overlying injection well and an underlying production well;
however, other well configurations are possible, such as a single horizontal well setup that has injection and production capabilities (e.g., single-well SAGD). Typically, a lean zone that is pressurized will overly a main pay zone that has multiple wells or well pairs deployed and operating, e.g., forming an array of well pairs with horizontal portions extending substantially parallel to each other and being fluidly connected to a well pad at surface.
The implementations described below in the context of SAGD or referring to SAGD are thus not intended to be limited to SAGD applications.
Characterization of hydrocarbon-lean zones

[0043] Referring to Fig 1, the gas injection is performed into a water-containing, hydrocarbon-lean zone 10 (also referred to herein as a "lean bitumen zone" or "lean zone"). The lean zone 10 can be part of an overall formation 12 that includes various fluids, solid media and lithological properties. The lean zone 10 is located above a hydrocarbon-rich reservoir 14 (also referred to herein as a "main pay zone") in which in-situ hydrocarbon recovery wells can be located. It should be understood that the main pay zones 14 are regions that include higher saturation of hydrocarbons, such as heavy oil or bitumen, than the lean zone 10, and that the hydrocarbons are economically recoverable using an in-situ recovery technique in which a mobilizing fluid is injected into the main pay zone. SAGD
is one such technique, which can include only steam injection or steam and solvent injection. Other techniques include cyclic steam stimulation (CSS), in-situ combustion, steam flooding, and solvent-assisted methods.

[0044] In some alternative implementations, the lean zone 10 may be located beside or below the main pay zone, and the gas injection techniques may be adapted accordingly to account for the different characteristics of the overall formation 12, such as an Date Recue/Date Received 2021-03-30 underlying lean zone would could have higher pressures. A lean zone may be one or several square kilometers, for example, and may have bitumen saturation below 50%, high water saturation, and low pressure. In some implementations, the lean zone has less than approximately 8% to 10% bulk mass fraction of oil and less than about 10%
to 30%
vol. of clay.

[0045] It should be understood that lean zones are regions of an overall formation that generally have higher water-saturation and/or lower pressure compared to a proximate (e.g., adjacent, overlying or underlying) main pay zone, such that performance of an in-situ hydrocarbon recovery process operating in the main pay zone can be reduced due to heat and/or fluid loss to the lean zone. For example, when steam-assisted in-situ hydrocarbon recovery operations are employed in the main pay zone, the steam chamber pressure can be higher than the pressure of the lean zone, which can lead to steam loss to the lean zone and higher heat transfer from the steam to the water in the lean zone. It should nevertheless be noted that some in-situ hydrocarbon recovery operations can use other fluids, such as hydrocarbon solvents, in which case the fluid loss may be of more concern than heat loss in terms of efficient operation.

[0046] Referring to Fig 8, in some implementations, the lean zone 10 or multiple lean zones are part of a geologically-contained water-saturated formation 122, where geological barriers 11 substantially contain the water, rather than being in substantial fluid communication with an aquifer for example. Implementing the process in geologically-contained water-saturated formations can facilitate the pressurization and maintenance of a gas-enriched region, as water migration into the lean zone is reduced.
Character 124 in Fig 8 indicates a bitumen-rich reservoir.

[0047] Candidate lean zones for pressurizing can also be identified using a number of techniques and can be based on various characteristics of the lean zone and the underlying pay zone, as well as economic analyses. Lean zone characteristics such as size, structure type, bitumen saturation, water saturation and pressure can be identified in order to determine whether the gas injection process would be economical. For instance, a lean zone having a dome structure may require less gas injection wells to reach a desired pressure, in contrast to a lean zone having a flat structure (see Fig 10 showing simulation results for dome versus flat geologies).
Date Recue/Date Received 2021-03-30

[0048] Referring to Fig 6, for example, lean zones 10 may vary in thickness and elevation.
A lean zone 10 can also include regions having different thicknesses. In some scenarios, a lean zone can have a tapered shape. Lean zones typically having a thickness (h) ranging between about 3 meters and about 20 meters are candidates for pressurizing according to techniques described herein. These different thicknesses can influence the number of wells in a particular region, as well as the distance between the gas injection wells. For instance, for a region having a relatively small thickness, such as a thickness between about 5 to about 10 meters, a lower number of gas injection wells may be provided to reach the desired pressurization since the lean zone has a smaller volume to receive the injected gas compared to a region of the lean zone that has a larger thickness. Similarly, the gas injection wells in a lean zone having a small thickness may be positioned further apart from each other, since a single gas injection well can provide a sufficient amount of gas to pressurize that region of the lean zone compared to a region of the lean zone that has a larger thickness. Fig 6 illustrates an example of a series of lean zones having different thicknesses and gas injection wells that are located in accordance with the given geology and thickness of each lean zone.

[0049] Fig 8 illustrates a combined lean zone, which is made up of several sub lean zones 10, and is geologically-contained. In some implementations, the gas injection process described herein can be replicated over various portions of a reservoir as the underlying pay zones are developed. For instance, gas injection wells can be added as new portions of a reservoir are being operated to produce hydrocarbons and/or are approaching the overlying lean zone, while other gas injection wells become further away from active production areas of the reservoir and can be shut down or run at a reduced gas injection rate. The gas injection wells can therefore be managed depending on the status and maturity of the underlying in-situ recovery wells and the corresponding pressures in the mobilized chambers in the main pay zones.
Pressurization and displacement of water from hydrocarbon-lean zone

[0050] Referring to Fig 1, a gas injection well 20 is provided in the lean zone 10 and is configured for injecting gas 22, such as NCG, into the lean zone 10 to form a gas-enriched region, or gas cap. It is to be understood that the gas cap can also be referred to as a secondary gas cap, as known in the art. The secondary gas cap is a gas cap that is formed following gas injection, in contrast to a primary gas cap that would be naturally occurring.
Date Recue/Date Received 2021-03-30 In Fig 1, the gas injection well 20 is a vertical well having a lower end near the top of the lean zone 10. Referring to Fig 5, the gas injection well 20 can also include a vertical portion having an upper end and a lower end, and a horizontal portion extending from the lower end of the vertical portion, thus forming a substantially L-shape gas injection well with a heel and a toe, which can also be referred to as a horizontal gas injection well. The gas injection well 20 can also be at other orientations, such as slanted and/or directionally drilled based on the shape and geology of the lean zone, e.g., flat versus domed versus slanted, to follow the contour of the boundary region 24 of the lean zone 10 or to follow another desired trajectory (see Figs 12A to 12D). Figs 14A to 14E depict other examples of gas injection wells having an orientation at least in part based on the shape of the lean zone. It should also be noted that in implementations where a lean zone is located above a hydrocarbon-rich reservoir, the lean zone is not necessarily a zone that includes the boundary region with the ground surface as shown illustratively in Figs 1, 4A-4D, 7 and 9.
Indeed, there would often be at least one other zone located above the lean zone before ground level is reached.

[0051] Referring to Figs 11A to 11E, various well arrangements are illustrated for gas injection wells and underlying in-situ recovery wells. The gas injection wells can be horizontal and arranged to be perpendicular or slanted with respect to the in-situ recovery wells. The gas injection wells can be positioned closer to the heels or toes or the middle of the in-situ recovery wells. The gas injection wells can be multilateral wells that have branches extending over the area of the lean zone. The gas injection wells can be parallel with respect to the in-situ recovery wells, and can be located in between two adjacent in-situ recovery wells or directly above and aligned with corresponding in-situ recovery wells.
The gas injection wells can also include a combination of horizontal and vertical wells.

[0052] The gas injection wells 20 can be provided with suitable apertures, perforations, screens or other means of fluid communication with the lean zone in order to allow gas injection. The gas injection well 20 can also have completions according to various characteristics of the lean zone. For example, slotted liners or screens may be used in the gas injection well 20 in the event that sand production or blockage are potential problems.

[0053] When water is displaced from a certain region of the lean zone due to gas injection, it can be said that the region has been "dewatered", although water has not been produced Date Recue/Date Received 2021-03-30 from the formation. In other cases, when a water production well is used, the lean zone can be dewatered by removal of water from the lean zone via the water production well.

[0054] Referring still to Fig 1, the lean zone 10 is in fluid and pressure communication with the hydrocarbon-rich reservoir 14. In some implementations, the gas injection wells 20 have a lower end that is located in a bottom section of the lean zone 10, for instance within the lean zone 10 proximate to a boundary region 24 that separates the lean zone and the hydrocarbon-rich reservoir 14. In some scenarios, the boundary region 24 is defined by the region having a high saturation of heavy hydrocarbons, the region forming a substantial barrier to gas injection at the gas injection pressures used to inject the gas into the lean zone 10, for instance due to a low mobility of the heavy hydrocarbons at initial conditions. Gas that may reach the boundary region 24 is impeded from passing into the hydrocarbon-rich reservoir 14 and thus advances laterally within the lean zone 10 and forms a gas cap over the hydrocarbon-rich reservoir 14. In other implementations, the lower end of the gas injection well is located in a middle or an upper section of the lean zone 10. Yet in other implementations, the lower end of the gas injection well extends beyond the boundary region 24.

[0055] With reference to Figs 16A to 16D, whether the gas injection well extends along an entire thickness of the lean zone, or only along a portion thereof, the apertures, perforations, screens or other means of fluid communication with the lean zone can be provided along different injection sections of the gas injection well. In such implementations, the injection sections can be delimited for instance with isolations packers 52 or blanks. Fig 16A shows an example of a gas injection well extending beyond the boundary region that includes an isolation packer positioned near the boundary region 24 such that the injected gas remains injected within the lean zone 10. Figs 16B to 16D
show examples of a gas injection well 20 extending along substantially an entire thickness of the lean zone 10, with apertures provided throughout the height of the gas injection well (Fig 16B) or along portions thereof (Figs 16C and 16D). These Figs illustrate different possible configurations for apertures provided along a vertical gas injection well, and can be located depending on geological characteristics of the lean zone, evolution of the gas injection, and various other factors.

[0056] With reference to Fig 14D, two injection sections are provided along a horizontal gas injection well in regions of higher thickness of the lean zone compared to a middle Date Recue/Date Received 2021-03-30 section thereof having a smaller thickness. The positioning of the gas injection along the height, or thickness, of the lean zone 10 can be determined according to the characteristics of the lean zone 10, as will be described in more detail below.

[0057] Referring back to Figs 14A to 14C, in some implementations, the lean zone 10 has a tapered shape, similar to a pinch out reservoir. The tapered lean zone includes a thinner portion at the toe and a thicker portion at the heel. When the tapered lean zone is located above a hydrocarbon-rich reservoir 14 also having a tapered shape such that both narrower portions of the tapered lean zone and of the hydrocarbon-rich reservoir are superposed, an end portion 54 of the gas injection well 20 may end up being in close proximity to the end portion 56 of the SAGD well pair. With such superposition of the lean zone 10 and of the underlying tapered hydrocarbon-rich reservoir 14 is present, care has to be taken to prevent the gas injected through the gas injection well from being short-circuited through the production well of the SAGD well pair and produced back without having contributed to pressurizing the lean zone. Indeed, since the gas is injected in close proximity of the boundary region 24 between the tapered lean zone and the tapered hydrocarbon-rich reservoir, as the hydrocarbons are being pumped out of the production well of the SAGD well pair, there is a possibility that the injected gas reaches the hydrocarbon-rich reservoir 14, and is then pumped up with hydrocarbons through the production well 40. Isolation packers can be provided at various locations along the gas injection well, for instance in the end portion 54 thereof, so that the gas is injected upstream of the end portion 54, in a region of the lean zone 10 that is thicker, thereby contributing to prevent such short-circuit. With reference to Fig 14B, the gas injection well 20 can also be provided with a different orientation so that it remains within the thicker portion of the lean zone and that gas is injected into a thicker region of the lean zone 10.

[0058] In some implementations, the number of gas injection wells, their position through the thickness of the lean zone and their layout in relation to one another is determined at least in part according to information gathered from numerical reservoir simulation results, which can permit estimating the size of a resulting gas cap following gas injection with a given number of gas injection wells disposed in a particular layout, and for a given period of time, based on the thickness of the lean zone and properties of the lean zone such as its permeability, porosity and water saturation level. Hence, gas injection well layouts can be provided depending on the size, structure and geological properties of the lean zone and surrounding formation properties. For instance, for a lean zone having a thickness Date Recue/Date Received 2021-03-30 between about 10 meters and about 15 meters, gas injection wells can be about meters to about 400 meters away from one another so that sufficient gas can be injected in relatively close proximity to form respective gas enriched-regions that contribute to increase the pressure in the lean zone 10. In some scenarios, for a lean zone having a thickness above about 15 meters, the gas injection wells can be positioned closer to each other so that a desired pressure in the lean zone can be reached, whereas for a lean zone having a thickness below about 10 meters, the gas injection wells can be positioned further away from each other.

[0059] In another example, for a lean zone having a thickness between about 10 meters and about 15 meters, one to three gas injection wells may be required to achieve lean zone pressurization, the gas injection wells being about 200 meters to about 400 meters apart when more than one injection wells are present. The number of gas injection wells can also vary depending on their characteristics, for instance whether the gas injection wells are horizontal or vertical. For example, for a given lean zone, one to three vertical gas injection wells may be provided to pressurize the lean zone, compared to one to two horizontal gas injection wells for the same lean zone.

[0060] It is to be noted that it is generally advantageous not to position gas injection wells too close to one another to avoid the gas-enriched regions to coalesce into a single combined gas-enriched region. Gas region coalescence can cause the injected gas to tend to move upwardly, which can reduce the efficiency of the pressurization of the lean zone and the contribution of the injected gas to displace water, compared to gas-enriched regions that remain distinct from each other. On the other hand, it is also generally desirable that the gas injection wells are positioned not too far away from one another, for instance more than about 2 kilometers apart, such that the pressurization of the lean zone becomes less efficient.

[0061] In addition, it is to be understood that once a particular gas injection well number, positioning and layout has been determined to be operational or advantageous for a given lean zone, it may be desirable to revise that particular configuration as time passes and hydrocarbon production is occurring, for instance to adapt to various changes that could occur over time in the overall formation 12, such that some gas injection wells can eventually be shut down, and new gas injection wells can be drilled and operated. For example, in some scenarios, two adjacent gas injection wells can be operated for a period Date Recue/Date Received 2021-03-30 of time, and then a third infill gas injection well can be deployed in between the two initial gas injection wells to provide gas and corresponding pressurization therebetween.

[0062] In some implementations, the fluid that is injected into the gas injection well 20 can include or consist of NCG. NCG remains in gaseous phase, has lower heat capacity properties compared to water, and can facilitate insulation and pressurization of the lean zone 10. Due to lower densities, NCG remains within the lean zone 10 rather than substantially sinking downward into the main pay zone. The NCG can include various gases, such as methane, carbon dioxide, nitrogen, air, natural gas and flue gas. The NCG
can be at least partly derived from the hydrocarbon recovery operation, for instance carbon dioxide or flue gas produced during steam generation. The NCG can also be a produced gas from a SAGD operation. The NCG can penetrate into higher-permeability layers, sandy hydrocarbon-bearing layers as well as water-saturated layers within the lean zone, depending on location and rate of injection. The NCG can be selected according to process economics, gas inventories, existing infrastructure, and/or desired effects within the lean zone.

[0063] In some implementations, the gas is methane or natural gas that is available proximate to the surface facilitates for the in-situ hydrocarbon recovery operation. For example, when high pressured natural gas from a pipeline is used as a fuel for steam generation (e.g., using a once through steam generator (OTSG), direct contact steam generator (DCSG), or another type of boiler or steam generator), the same source of natural gas used for fuel can also be used as a source of gas for lean zone injection. Thus, existing pipelines, tankage, and other infrastructure can be leveraged for lean zone gas injection operations using natural gas or other types of light hydrocarbon fuels that may be used.

[0064] In some implementations, the injected gas is different from existing gases that may be native to the reservoir such as native H2S and CO2. For example, N2 can be chosen as the injection gas which can facilitate gas detection by detecting N2 in the production fluids.
A mixture of injection gases may also be provided so that at least one component of the gas mixture is non-native to the reservoir (e.g., a mixture of N2 and CO2, a mixture of CH4 and H2, or N2 and natural gas). In some implementations, the mixture of CH4 and H2 is a Date Recue/Date Received 2021-03-30 lean gas mixture coming from a bitumen upgrader facility, and contains up to about 10%
vol. of Hz.

[0065] In some implementations, the gas is pre-treated at surface prior to being injected into the lean zone. Pre-treatments can include heating or cooling, purification, and the like.
The pre-treatment of the gas to be injected can be based on permeability properties of the gas through water and porous media of the lean zone. The gas or gas mixture can be selected to avoid acid gases, such as H2S. The gas or gas mixture can also be provided to prevent hydrate formation, by selecting certain gas types and/or by providing appropriate heat to thereby prevent pipe blockage due to hydrate formation.

[0066] In some implementations, different gases can be injected at different times and/or different locations. For example, referring to Figs 3D and 4D, a first NCG can be injected via the gas injection well 20, and a second NCG can be injected via a secondary gas injection wells 36. In addition, an initial NCG can be injected into all of the gas injection wells during an initial period of time (e.g., to establish a gas-enriched lean zone), and then a different NCG can be injected at a later time (e.g., to maintain or modify the gas-enriched lean zone). The timing and location of types of gas to inject can be done according to the properties of the gas and desired effects within the lean zone.

[0067] In some implementations, the injection fluid is not an NCG but is a fluid that has lower heat capacity than that of water and can enable increasing the pressure of the lean zone to be closer to the pressure of the SAGD steam chamber pressures or the pressures encountered in the in-situ recovery operation.
Operation of the gas injection wells

[0068] Referring to Figs 3A to 3D, the general operation and monitoring of the gas injection wells will be described. The gas injection well 20 is operated to inject NCG into the lean zone 10 to increase the lean zone pressure, for instance close to SAGD operating pressures, and displace water therefrom, thus reducing steam leak-off and heat loss from the steam chamber to the lean zone 10 by forming a pressurized gas cap over the hydrocarbon-rich reservoir 14.

[0069] In some implementations, the water saturation in the lean zone is about 45 vol%.
In such implementations, the injection of gas in the lean can advantageously reduce the Date Recue/Date Received 2021-03-30 water saturation to between about 20 vol% and about 25 vol%, with a gas saturation of between about 15 vol% and about 20 vol%. In some implementations, an injection of gas corresponding to approximately twice the pore volume leads to a displacement of up to about 60% of the mobile water. The pressure in the lean zone prior to gas injection can be in the range of about 50 kPa to about 1000 kPa whereas the target pressure in the hydrocarbon-rich reservoir 14 can range, for example, from about 1500 kPa to about 3500 kPa. The initial pressure of the lean zone can be measured using pressure transient analysis (PTA) by installing pressure gauges across the lean zone. This aspect will be described in further detail below. Increasing the pressure in the lean zone to values close to the pressure in the hydrocarbon-rich reservoir 14 can mitigate steam flow from the hydrocarbon-rich reservoir 14 to the lean zone 10. In some scenarios, the pressure in the lean zone 10 is within about 100 to about 200 kPa of the pressure in the hydrocarbon-rich reservoir 14. In other scenarios, the pressure in the lean zone 10 is up to within about 700 kPa of the pressure in the hydrocarbon-rich reservoir 14. As mentioned above, various factors can influence the pressurization (e.g., the speed of pressurization) of the lean zone 10, such as the permeability of the geological structure, its porosity and the original water saturation level. Permeability properties can be determined, for example, based on core samples, simulation modelling, well tests calculations and/or empirical experimentation.
More regarding this aspect will be described in further detail below.

[0070] Referring now to Fig 3B, gas 22 is injected through the gas injection well 20 into the lean zone 10. The gas injection can be regulated by a gas injection controller 32. It should be mentioned that various flow control devices can be deployed at surface and/or downhole to regulate the gas injection rate via the injection well. The downhole flow control devices can facilitate gas injection into target areas of the lean zone by opening or closing or throttling certain devices along the injection well. For example, if additional gas is desired in the lower part of the lean zone, flow control devices in the upper part can be closed and flow control devices in a lower part can be opened.

[0071] As mentioned above, the gas pressurization can be done to achieve a pressure that is similar to SAGD operation pressure, provided that the lean zone pressure does not exceed the fracture pressure or the steam chamber pressure. In some implementations, the gas pressurization is conducted to achieve an increased average pressure in the lean zone compared to its initial pressure. While gas pressurization would ideally increase the pressure as close as possible to the pressures of the thermal in-situ recovery operation, Date Recue/Date Received 2021-03-30 gas injection should not be conducted at a rate to cause substantial and pre-mature channeling and breakthrough of the gas through the water-saturated regions of the lean zone 10.

[0072] As shown in Fig 3B, the gas injection forms a gas-enriched region 34 that expands outwardly from the gas injection well 20. The injection rate of the gas into the lean zone is performed at a rate that allows the formation of a gas-enriched region having certain characteristics. In some implementations, the gas injection rate varies according to pressurization stages in the lean zone, which can include for instance an initial injection stage and a maintenance stage. Gas injection rates can be determined based on a number of factors, including characteristics of the lean zone such as the absolute permeability of the porous medium in the lean zone 10, and the water saturation and distribution within the lean zone 10. Based on the water saturation level, the effective water mobility of the lean zone is influenced by the relative permeability of the water phase and the absolute permeability of the porous medium. For instance, the gas can initially be injected at an initial rate to allow buildup of the gas in the lean zone 10, such as between about 100 E3m3/d and about 300 E3m3/d. In some scenarios, the initial rate is limited at least in part by the fracture pressure and the capacity of the injection valves or sprinklers.
Once pressures are balanced between the lean zone and the steam chamber, the gas can subsequently be injected at a pressure maintenance rate, which can be similar or different from the initial rate. In some implementations, the pressure maintenance rate is between about 10 E3m3/d and about 50 E3m3/d, which may be sufficient to mitigate steam leak-off from the steam chamber to the lean zone 10. Thus, in these implementations, the pressure maintenance injection rate is controlled to be relatively low, and coordinated with permeability of the lean zone, to facilitate pressurization that will provide insulation and pressurization for the thermal in-situ recovery operation. In some scenarios, up to about 500 E3m3/d of gas can be injected in the lean zone 10, which over a period of about 7 to 10 months, can lead to a lean zone including about 2.5 BCF to about 3.5 BCF.

[0073] It can be desirable to inject gas at different elevations through the gas injection well and thus new apertures can be provided or opened along the length of the gas injection well. In some implementations, the interval between the apertures along the gas injection well is determined according to the heterogeneity of the lean zone and to the vertical to horizontal permeability relationship. In some implementations, perforations are provided along substantially the entire length or height of the gas injection well, depending Date Recue/Date Received 2021-03-30 whether the gas injection well is vertical or horizontal, to facilitate an even distribution of the injected gas over the whole height of the lean zone or over a larger radius, respectively, which in turn can contribute to minimize gas override and increase volumetric sweep efficiency. In some scenarios, the lower extremity aperture of the gas injection well is closed, for example by using a sliding sleeve, and new apertures at a higher elevation are used for the gas injection in the gas injection well. Alternatively, the injection of the gas can be performed through apertures at the bottom of the well such that the gas enters a lower part of the lean zone and migrates upward due to density differences.

[0074] Referring to Fig 3C, as gas 22 is injected into the lean zone 10, the gas-enriched region expands outwardly and upwardly. In some implementations, the gas 22 that is injected has low gas solubility in water at the temperature and pressure conditions of the lean zone 10. In some implementations, when the gas is injected proximate to a cap rock defining an upper generally-impermeable gas barrier, part of the gas-enriched region 34 grows in a generally outward direction. It should be noted that the gas injection can be modulated over time depending on the progression of the gas-enriched region 34 within the lean zone 10. In some scenarios, the lean zone 10 can include existing gas-saturated zones, resulting in higher compressibility. In such scenarios, more gas can be injected via the gas injection well 20 in order to increase the lean zone pressure.

[0075] Referring briefly to Fig 3D, in some implementations, after gas injection has led to the formation of a gas-enriched lean zone and displacement of water, secondary gas injection wells 36 can be added and gas injection can continue through all of the gas injection wells in order to maintain the gas-enriched lean zone at a lean zone pressure, which can be provided based on the underlying thermal in-situ recovery operation pressures (e.g., SAGD steam chamber pressures), thereby providing overlying gas insulation and pressurization for the recovery operation.

[0076] In some implementations, once a given pressurization of the lean zone 10 is reached, recovery of hydrocarbons in the main pay zone can start.
Alternatively, recovery of hydrocarbons in the main pay zone can begin prior to gas pressurizing to the target pressure level, for instance when the hydrocarbon-rich reservoir is particularly thick and steam leak-off is expected to occur only after large steam chambers have been generated.
Referring briefly to Figs 4C and 4D, in some implementations, following the gas pressurization of the lean zone 10, the thermal in-situ recovery operation (e.g., SAGD) is Date Recue/Date Received 2021-03-30 commenced in the main pay zone 14. Fig 4C illustrates the formation of SAGD
steam chambers, and Fig 4D illustrates the growth of the SAGD steam chambers toward the gas-enriched lean zone.
Monitoring of gas injection operations

[0077] The pressurization of the lean zone 10 can be monitored according to various techniques. A first technique based on mathematical relationships between flow rate, pressure and time, called pressure transient analysis (PTA), allows estimation of the size and shape of the gas-enriched region around a gas injection well. In an implementation of the PTA technique, a gas injection well 20 is shut in and the rate of pressure fall-off is measured. The gas injection well can be equipped with pressure sensing instrumentation that is downhole and may be distributed along the relevant section of the injection well within the lean zone. Surface pressure sensors can also be used. The rate of pressure fall-off obtained is indicative of the size of the gas-enriched region surrounding that particular gas injection well. Performing this type of technique at multiple locations in the lean zone 10 can facilitate the mapping of the gas-enriched region. By having a better overview of the shape and size of the gas-enriched region, decisions can be made regarding the operation of the gas injection wells, such as whether to add more gas injection wells at given locations or to shut in gas injection wells at other given locations, adjust the gas injection rate, and so on.

[0078] In some implementations, the water contained in the lean zone 10 or a portion thereof is monitored for gas content in order to determine whether injected gas has advanced through the lean zone 10. A gas detector can be installed to perform this detection. It should be noted that gas detection in general can be performed by other methods, such as observation wells 30 provided through the lean zone 10, as illustrated in Fig 2, the observation wells 30 being equipped with appropriate devices for directly and/or indirectly detecting gas and relaying the information so that certain appropriate actions can be taken. The observation well 30 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. The observation well 30 can be an existing well that is equipped with appropriate instrumentation to provide suitable data, such as pressure data. In an example scenario, an observation well is equipped with pressure gauges to monitor the extent of the gas-enriched region. A first pressure gauge Date Recue/Date Received 2021-03-30 is installed in an upper region of the lean zone and a second pressure gauge is installed in a lower region of the lean zone, at a predetermined distance from the first pressure gauge. It can then be inferred from the pressure differential between the first and the second pressure gauges whether a water or gas column is present in the lean zone at the location of a given observation well. For instance, for a distance of 10 meters between the first and the second pressure gauges, if the pressure differential is approximately 100 kPa (the pressure at the bottom of the observation well being higher than the pressure at the top thereof), it can be indicative that water is present in the observation well. However, if the pressure differential is lower than what would be dictated by the presence of water only, it can be indicative that gas is also present in the observation well.

[0079] Volumetric estimates can also be performed, such as measurement of the volumetric sweep efficiency, which evaluates the mobility of fluids by determining the proportion of the volume of the lean zone that has been contacted with the injected gas.
In some implementations, a 10% to 15% volumetric sweep efficiency in a lean zone having a radius of about 1.2 kilometers and a thickness of about 2 meters or more can be obtained. Different volumetric sweep efficiencies can be obtained depending on the operating conditions of the gas injection wells and reservoir parameters such as permeability, thickness and structure.

[0080] Reservoir saturation logs can be used to characterize the geological formation penetrated by a gas injection well or an observation well, and provide insights into certain profiles along the depth of the gas injection well or the observation well by evaluating parameters such as the density, the porosity, and the resistivity log responses. For instance, in an overall formation, a low resistivity can be associated with a high water saturation and thus be indicative of the presence of a lean zone. In contrast, a higher resistivity can be indicative of a region having higher saturations of bitumen. In some implementations, several saturation logs are obtained over a period of time to monitor the gas and water displacements, which can facilitate the process of mapping the gas cap and the monitoring of the gas leaks off of the lean zone.

[0081] Time lapsed seismic, also referred to as 4D seismic, is another technique that can be used to monitor the water saturation level in the lean zone and evaluate the size of the lean zone, by evaluating the changes in the acoustic and elastic properties of the geological formation. In such 4D seismic analysis, changes in amplitude and velocity are Date Recue/Date Received 2021-03-30 compared with baseline seismic interpretation, and maps are then generated to monitor the size, or extent, of the gas cap.

[0082] In some implementations, tracking methods can be used in order to detect various parameters of the process. For example, a tracer chemical can be included in the NCG
injected into the lean zone 10 via the gas injection wells 20. The tracer chemical can be injected in various ways, such as co-injected with the NCG via one, more or all of the gas injection wells, or other injection means. Tracer chemicals can be for gas phase, water phase or oil phase tracing. The tracer chemical can be pre-injected into water present in the reservoir and/or lean zone in order to better determine the location and origin of the water being displaced and produced (e.g., from native water in the reservoir or from injected fluid in the form of condensed steam). Tracer chemicals can thus be used in connection with various aspects of the operations described herein, for various purposes, such as detecting gas breakthroughs, detecting and tracking water displacement, and so on.
Managing thermal in-situ operations and lean zone interactions

[0083] Referring to Figs 4A to 4D, the gas pressurization can be conducted on a lean zone 10 above a main pay zone 14 in which SAGD occurs. In some implementations, the gas-enriched lean zone 10 is formed well before potential heat or fluid losses from the SAGD could occur. However, it should be noted that various timing strategies can be used for the gas pressurization and the SAGD operation. For example, the gas pressurization can be commenced prior to drilling the SAGD wells or prior to start-up of the SAGD wells.
Alternatively, the gas pressurization can begin after start-up of the SAGD
wells, ideally as long as the growth of the SAGD steam chambers is such that that the gas-enriched lean zone is formed before the SAGD steam chambers reach the lean zone.

[0084] Referring to Figs 4A and 4B, the gas injection well 20 is operated to establish a gas-enriched lean zone 10 prior to operating SAGD in the underlying main pay zone 14.
At some stage, SAGD wells are drilled, completed, and started up. As mentioned above, the timing of drilling, completion and start-up activities can depend on a number of factors.
Fig 4C illustrates SAGD well pairs each including a SAGD injection well 40.
After startup of the SAGD well pairs to establish fluid communication between each pair, steam chambers 42 are formed above respective SADG well pairs. In some scenarios, by the Date Recue/Date Received 2021-03-30 time steam chambers 42 begin to form and grow upward, the gas-enriched lean zone has been formed and is being maintained.

[0085] Referring to Fig 4D, eventually the steam chambers 42 approach the lower part of the lean zone 10. It should be noted that there is some heat conducted upward from the upper edge of the steam chambers 42 and can reach the lean zone before the steam chambers 42 themselves. As heat and steam reach the lean zone 10, the gas-enriched lean zone provides insulation and pressurization to reduce heat and fluid losses.

[0086] Figs 4A to 4D illustrate the pressurization process above an array of SAGD well pairs. An array of SAGD well pairs can include various numbers of well pairs that typically extend from a single well pad located at the surface. Typically, a bitumen reservoir is developed in stages, where a first array of SAGD 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 SAGD wells is provided and operated in another portion of the reservoir as a subsequent stage of reservoir development. The first and second arrays of SAGD
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 SAGD wells are provided and operated, new gas injection wells can also be provided in close proximity thereto to form a gas-enriched region that follows the SAGD operations.

[0087] Referring to Fig 7, the pressures PG and PsAGD can both be monitored and adjusted so that the AP is within a desired range. For instance, during early steam chamber development, the pressure difference (AP) between the pressure of the gas-enriched region 34 (PG) and the pressure of the underlying SAGD steam chamber pressures (PsAGD) can be maintained within 200 kPa. The pressure difference (AP) that is achieved can depend on various factors, such as the geology of the lean zone and the economics of gas injection and heat loss for the given in-situ hydrocarbon recovery operation. It should be noted that conventionally, the pressure difference between a lean zone and SAGD
steam chambers could be modified by adjusting the SAGD steam injector. When gas injectors are provided for pressurizing the lean zone 10, the pressure difference can be adjusted using two levers, i.e., the lean zone gas injectors and the SAGD
steam injector, which facilitates additional options for process control.
Date Recue/Date Received 2021-03-30

[0088] As mentioned above, the gas pressurization of the lean zone provides an insulation layer and pressurization above the thermal in-situ recovery operation to reduce heat and fluid losses to the hydrocarbon-lean zone due to advection and to help delay the development of the steam chambers into the lean zone. In addition, a pressurized lean zone 10 can encourage lateral growth of the steam chambers 42 within the main pay zone 14. This promoted lateral growth of steam chambers 42 can also delay the steam chambers 42 expanding into the lean zone 10 and increase hydrocarbon recovery and production rates since higher saturations of hydrocarbons are typically found in such lateral directions within a main pay zone 14.
Recovery of injected gas after in-situ recovery operations

[0089] Referring to Fig 9, when an in-situ recovery operation has reached maturity, and/or a desired hydrocarbon recovery factor has been achieved in a given pay zone, a portion of the gas that has been injected into the lean zone can be produced back and recycled in various other processes. In some implementations, it can be advantageous to produce back the injected gas for re-injection into a formation, for injection into another hydrocarbon-lean zone, or for use in an enhanced oil recovery (EOR) process.
In addition, when the non-condensable gas comprises a light hydrocarbon, such as methane, the recovered non-condensable gas component can be used as a fuel for steam generation or heating processes.

[0090] As shown in Fig 9, producing back the non-condensable gas can include recovering a mixture 44 comprising a portion of non-condensable gas and water from the hydrocarbon-lean zone. The mixture can also include other components that are present in the lean zone, such as oil. Once the mixture is produced to the surface, it can be processed in various ways. For example, the mixture can be separated according to known methods of gas-liquid separation, thus producing a recovered non-condensable gas component and a water component.

[0091] In some implementations, the gas injection well can be converted to a production well 46 to produce back the injected gas. Alternatively, new wells can be drilled and operated for producing the mixture. The gas production wells can be operated in various ways to enhance gas recovery from the lean zone, for example by using flow control devices to promote flow of gas from certain parts of the lean zone with high gas saturation Date Recue/Date Received 2021-03-30 and low water saturation. The composition of the mixture can be monitored over time to assess gas content, and once the gas content notably decreases the production can be ceased or adjusted. In other implementations, the gas injection well can also be converted to produce bitumen and/or water present in the lean zone.

[0092] In addition, in some cases, the presence of the gas in the lean zone can alter properties of various components in the lean zone, and such changes can later be leveraged advantageously. For example, some NCG such as CO2 and methane can reduce the viscosity of heavier hydrocarbons, such as bitumen, particularly when allowed to remain in contact with the bitumen over longer periods of time. Thus, when the lean zone includes heavy oil or bitumen that has been mobilized due to contact with the injected gas, the mixture 44 that is produced can include mobilized hydrocarbons from the reservoir that can be recovered. In such cases, the mixture can be subjected to a separation process at surface to produce a hydrocarbon enriched component for further processing or transportation, and a hydrocarbon depleted component. In some implementations, the mixture 44 is fed into a gas separator to recover gas, and then is fed into a water-hydrocarbon separator to recover a hydrocarbon enriched component. The resulting produced water component can be recycled in various ways, e.g., supplied to a water treatment facility prior to being used as boiler feed water in an OTSG, or supplied directly to a DCSG. In some cases, the mixture can be directly supplied to a DCSG such that the water, gas, and recovered hydrocarbons produce a steam-and-0O2 mixture that can be used for SAGD or other thermal in-situ recovery applications.
Managing mature overall formation through gas injection

[0093] Referring now to Figs 15A to 15E, there is shown a first mature overall formation 12 adjacent to a second newer overall formation 112. The mature overall formation 12 can be for instance a formation that has reached a decrease in hydrocarbon production and/or an increase in SOR, and wind-down strategies are thus put into place to maximize the presence of the mobilizing fluid chambers, in particular in terms of heat and pressure already provided by the presence of the mobilizing fluid. In a first stage of the wind-down strategy, gas is injected into the hydrocarbon-lean zone 10 of the mature overall formation 12 that includes a first array of SAGD well pairs 38, 40 through gas injection wells 20, and provides an insulation layer and pressurization above the hydrocarbon-rich reservoir 14.
It should be noted that the gas injection wells can be operated as per other methods Date Recue/Date Received 2021-03-30 described herein while the SAGD well pairs are operating normally, to form a gas-enriched lean zone. Once the SAGD well pairs become inefficient or uneconomical, wind-down can be initiated.

[0094] The second overall formation 112 is exploited by operating a second array of SAGD well pairs 138, 140 in the hydrocarbon-rich reservoir 114. The drilling, completion and operation of the recovery wells in the second overall formation 112 can occur several years after recovery from the first overall formation 12 has been initiated, although sequential timing is not necessarily required. The main concept is that the recovery process in the first overall formation is entering wind-down while the recovery operation in the second overall formation is still operational or will be operational at higher pressures than the first. The lean zone gas injection wells in the first overall formation can thus be leveraged to pressurize the first overall formation in order to reduce pressure differential with respect to the second overall formation.

[0095] Still referring to Figs 15A to 15D, additional gas injection wells 120 can be provided in the overlying hydrocarbon-lean zone 110 to pressurize the lean zone. These gas injection wells can be operated in a similar manner as the gas injection wells 20 in the first lean zone when the recovery process operating in the first pay zone was in normal operation (prior to wind-down). In a second stage of the wind-down strategy, gas continues to be injected in the mature overall formation 12 such that the mobilizing fluid chambers 42 and the injected gas form a combined gas-enriched region 148 that pressurizes the mature overall formation 12 and provides an insulation layer along the newer overall formation 112 (see in particular Fig 15C). In addition to forming this adjacent gas region, the gas injection wells 120 above the newer overall formation 112 can be operated to inject gas into the corresponding lean zone 110 above the hydrocarbon-rich reservoir 114 provide an insulation layer above the hydrocarbon-rich reservoir 114. Thus, as shown in Fig 15C, the newer hydrocarbon recovery process can be operated in a pay zone that is surrounded by gas-enriched pressurized regions to reduce heat and fluid loss.
Each adjacent or proximate gas-enriched region can be pressurized to a pressure near the operating pressures of the recovery operation. It is noted that a given newer recovery operation can be surrounded on several sides by gas-enriched regions corresponding to Date Recue/Date Received 2021-03-30 natural lean zones (e.g., overlying lean zones) or process-affected lean zones (e.g., with a mature recovery system in wind-down).

[0096] In addition, as the newer overall formation 112 is operated and recovery of hydrocarbons starts to decrease, the newer overall formation 112 can then become a mature overall formation itself. As shown in Figs 15D and 15E, the combination of both mature formations can then become a single pressurized overall formation 150 that is pressurized by gas injection via the gas injection wells 20, 120 in the original lean zones.
It is noted that the pressurizing fluid in the formation is a mixture 152 comprising the injected gas and the mobilizing fluid, and depending on the management of the formation the mixture can change over time (e.g., steam originally present would eventually condense as the temperature decreases and the gas content would thus increase).

[0097] Similar to what is described hereinabove regarding the recovery of gas injected in a lean zone, a portion of the mixture 152 can be produced back from the single pressurized overall formation 150 and recycled in other applications (see Fig 15E with a gas mixture G being produced via one or more of the existing wells in the formation). For instance, the mixture 152 can be fed to a gas separator to recover gas, and then fed to a water-hydrocarbon separator to recover a hydrocarbon enriched component. The mixture can be produced back by converting gas injection wells 20, 120 in production wells to produce back the mixture, and/or by operating one or more SAGD well as a production well. This wind-down strategy can be used for instance as hydrocarbon recovery operations are sequentially initiated and extended within a large formation, with new recovery wells being provided and operated. Thus, as the recovery operation moves from one region of a hydrocarbon-rich reservoir to another, the depleted zones can be pressurized to enhance operations.
RESULTS & SIMULATIONS

[0098] Various simulations were conducted to assess gas injection into hydrocarbon-lean zones.

[0099] With reference to Table 1 below, special core analysis laboratory (SCAL) experiments were performed to evaluate the potential effect of gas injection into a hydrocarbon-lean zone on the displacement of the gas and/or water contained therein.
The SCAL tests were conducted on core samples taken from lean zone intervals.
The Date Recue/Date Received 2021-03-30 core samples were first initialized to a saturation level representative of the lean zone, and then gas injection was started at a low rate to mimic the gas injection process in the reservoir. The results included in Table 1 suggest that with close to twice the pore volume of gas injection, the maximum fractional flow of gas can be reached.
Table 1 CUMULATIVE CUMULATIVE END-FACE
GAS WATER FRACTIONAL
INJECTED, RECOVERED, FLOW GAS-WATER
fraction Vp fraction Vp OF GAS RATIO
0.000 0.000 0.0000 0.00 0.020 0.016 0.0000 0.00 0.046 0.042 0.7592 3.15 0.074 0.068 0.9275 12.8 0.100 0.095 0.9556 21.5 0.130 0.122 0.9707 33.2 0.168 0.149 0.9811 52.0 0.200 0.176 0.9855 67.9 0.219 0.183 0.9874 78.5 0.253 0.186 0.9885 85.8 0.319 0.192 0.9902 101 0.449 0.200 0.9920 124 0.709 0.219 0.9940 166 1.21 0.241 0.9955 221 1.97 0.268 0.9968 315

[0100] With reference to Fig 17, there is shown an example of the effect of changes in water saturation levels on the capillary pressure for different hydrocarbon-lean zones and hydrocarbon-rich reservoirs. In this context, capillary pressure refers the pressure required to be forced out of the porous media in which it is contained. Thus, the pressure of injected gas has to be high enough to overcome this capillary pressure before a displacement process can happen. The graph suggests that for these experiments, at minimum, more than half of the water contained in the hydrocarbon-lean zones is not affected by the capillary pressure, and thus can be mobilized.

[0101] With reference to Figs 18A and 18B, graphs illustrating pressure variations in a hydrocarbon-lean zone as a function of time are presented. In particular, Fig 18A shows pressure variations with a depth correction for a pressure gradient of 10 kPa, whereas Fig 18B shows pressure variations with a depth correction for a pressure gradient of 1 kPa.
Figs 18A and 18B show that displacement of water due to gas injection changes the Date Recue/Date Received 2021-03-30 mobile fluid column, and thus changes the vertical pressure gradient measured in an observation well.

[0102] With reference to Fig 19, there is shown a graph depicting variations in normalized gas potential as a function of time with data points obtained from PTA. The log-log diagnostic plots are used to evaluate the change in the mobility of the gas zones. The comparison of the first data set (orange) with the second data set (blue) shows an increase in the size of gas zone over time. The first data set shows that the area close to the injection well has higher mobility, and after a certain radius R1, the mobility is reduced due to reduction of gas saturation and the thickness of gas zone. For the second data set, this phenomenon has occurred on a later date, i.e. the inflexion point is further right on the time scale, suggesting an increase in R1 and showing the progress of gas-enriched region in the lean zone.

[0103] With reference to Fig 20, there is shown a graph illustrating an example of gas injection rate over time in a hydrocarbon-lean zone and the cumulative gas injection over time, as well as the corresponding impact on pressurization of the hydrocarbon-lean zone, according to results from numerical reservoir simulations.
Date Recue/Date Received 2021-03-30

Claims

34

1. A process for producing a recovered non-condensable gas, comprising:
injecting non-condensable gas via a gas injection well having an injection portion located in a subterranean hydrocarbon-lean zone containing water and having a lower hydrocarbon content than an underlying hydrocarbon-rich reservoir, the hydrocarbon-lean zone being located above and in fluid communication with the hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas injection rate sufficient to form a gas-enriched region within the hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone and displace at least a portion of the water contained therein;
operating in-situ recovery wells within the hydrocarbon-rich reservoir including an injection well to inject a mobilizing fluid into the hydrocarbon-rich reservoir and a production well to recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber pressure; and after the hydrocarbon-rich reservoir enters a mature phase in which the chamber pressure and hydrocarbon recovery performance decrease over time, recovering at least a portion of the non-condensable gas from the hydrocarbon-lean zone;
wherein the gas-enriched region reduces fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water is displaced away from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber formed in the hydrocarbon-rich reservoir.

2. The process of claim 1, wherein recovering the at least a portion of the non-condensable gas from the hydrocarbon-lean zone comprises:
producing a mixture comprising the at least a portion of the non-condensable gas and water from the hydrocarbon-lean zone; and separating the mixture to obtain a water component and a recovered non-condensable gas component.

3. The process of claim 2, wherein the mixture further comprises mobilized hydrocarbons from the hydrocarbon-lean zone.

4. The process of claim 3, further comprising supplying the mixture to a water-hydrocarbon separator to recover a hydrocarbon-enriched component.

5. The process of any one of claims 2 to 4, further comprising recycling the recovered non-condensable gas for re-injection into a formation.

6. The process of claim 5, wherein recycling the recovered non-condensable gas comprises injecting the recovered non-condensable gas into another hydrocarbon-lean zone or another region of the hydrocarbon-lean zone.

7. The process of claim 5, wherein recycling the recovered non-condensable gas comprises using the recovered non-condensable gas in an enhanced oil recovery process.

8. The process of any one of claims 2 to 7, wherein the recovered non-condensable gas is recycled for use as fuel in a steam generation process.

9. The process of any one of claims 2 to 8, wherein producing the mixture comprises converting the gas injection well to a gas production well and producing the mixture therefrom.

10. The process of any one of claims 2 to 8, wherein producing the mixture comprises converting at least one of the injection well and the production well to a gas production well and producing the mixture therefrom.

11. The process of any one of claims 2 to 10, wherein producing the mixture comprises using a flow control device to promote a flow of the non-condensable gas from a high gas saturation zone within the gas-enriched zone.

12. The process of any one of claims 1 to 11, wherein following the hydrocarbon-rich reservoir entering the mature phase, the process further comprises converting at least one of the injection well and the production well to an additional gas injection well to inject additional non-condensable gas into the mobilizing chamber.

13. The process of claim 12, wherein the gas-enriched zone and the mobilizing chamber combine to form a combined gas-enriched region.

14. The process of claim 13, wherein recovering the at least a portion of the non-condensable gas from the hydrocarbon-lean zone comprises recovering the at least a portion of the non-condensable gas from the combined gas-enriched region.

15. The process of any one of claims 1 to 14, wherein the injection well is a steam injection well positioned above the production well, and the mobilizing fluid comprises steam.

16. The process of claim 15, wherein the mobilizing fluid further comprises an organic solvent.

17. The process of claim 15 or 16, wherein the well pair is operated as part of a steam-assisted gravity drainage (SAGD) process.

18. The process of any one of claims 1 to 14, wherein the injection well is configured and operated to inject the mobilizing fluid, and the production well is located proximate to the injection well and configured and operated to recover hydrocarbons.

19. The process of claim 18, wherein the mobilizing fluid comprises an organic solvent.

20. The process of claim 18, wherein the mobilizing fluid is an organic solvent.

21. The process of any one of claims 1 to 20, wherein the non-condensable gas comprises CO2.

22. The process of any one of claims 1 to 20, wherein the non-condensable gas comprises a light hydrocarbon.

23. The process of any one of claims 1 to 20, wherein the non-condensable gas comprises methane.

24. The process of any one of claims 1 to 23, further comprising heating the hydrocarbon-rich reservoir to mobilize at least a portion of the hydrocarbons contained therein.

25. The process of claim 24, wherein heating the hydrocarbon-rich reservoir comprises providing heat to the hydrocarbon-rich reservoir via an external heating source.

26. The process of claim 25, wherein the external heating source comprises electric resistive heating.

27. The process of claim 25, wherein the external heating source comprises radio frequency (RF) heating.

28. The process of any one of claims 1 to 27, wherein no dedicated water production well is provided in the hydrocarbon-lean zone for production of water therefrom.

29. The process of claim 1, wherein the gas injection well is substantially horizontal.

30. The process of claim 1, wherein the injection portion of the gas injection well is entirely located in the hydrocarbon-lean zone and is vertically spaced-apart from an upper part of the underlying hydrocarbon-rich reservoir.

31. A process for producing a recovered non-condensable gas, comprising:
injecting non-condensable gas via a gas injection well having an injection portion located in a subterranean hydrocarbon-lean zone containing water and having a lower hydrocarbon content than an underlying hydrocarbon-rich reservoir, the hydrocarbon-lean zone being located above and in fluid communication with the hydrocarbon-rich reservoir, the non-condensable gas being injected at a gas injection rate sufficient to form a gas-enriched region within the hydrocarbon-lean zone, pressurize the hydrocarbon-lean zone and displace at least a portion of the water contained therein;

operating in-situ recovery wells within the hydrocarbon-rich reservoir including an injection well to inject a mobilizing fluid comprising a mobilizing solvent into the hydrocarbon-rich reservoir and a production well to recover hydrocarbons therefrom while forming a mobilizing fluid chamber in the hydrocarbon-rich reservoir, the mobilizing fluid chamber having a chamber pressure; and after the hydrocarbon-rich reservoir enters a mature phase in which the chamber pressure and hydrocarbon recovery performance decrease over time, recovering at least a portion of the non-condensable gas from the hydrocarbon-lean zone;
wherein the gas-enriched region reduces fluid leakage and heat loss from the mobilizing fluid chamber into the hydrocarbon-lean zone and the water is displaced away from a region of the hydrocarbon-lean zone that overlies the mobilizing fluid chamber formed in the hydrocarbon-rich reservoir.

32. The process of claim 31, wherein recovering the at least a portion of the non-condensable gas from the hydrocarbon-lean zone comprises:
producing a mixture comprising the at least a portion of the non-condensable gas and water from the hydrocarbon-lean zone; and separating the mixture to obtain a water component and a recovered non-condensable gas component.

33. The process of claim 32, wherein the mixture further comprises mobilized hydrocarbons from the hydrocarbon-lean zone.

34. The process of claim 33, further comprising supplying the mixture to a water-hydrocarbon separator to recover a hydrocarbon-enriched component.

35. The process of any one of claims 32 to 34, further comprising recycling the recovered non-condensable gas for re-injection into a formation.

36. The process of claim 35, wherein recycling the recovered non-condensable gas comprises injecting the recovered non-condensable gas into another hydrocarbon-lean zone or another region of the hydrocarbon-lean zone.

37. The process of claim 35, wherein recycling the recovered non-condensable gas comprises using the recovered non-condensable gas in an enhanced oil recovery process.

38. The process of any one of claims 32 to 37, wherein the recovered non-condensable gas is recycled for use as fuel in a steam generation process.

39. The process of any one of claims 32 to 38, wherein producing the mixture comprises converting the gas injection well into a production well and producing the mixture therefrom.

40. The process of any one of claims 32 to 38, wherein producing the mixture comprises converting at least one of the injection well and the production well to a gas production well and producing the mixture therefrom.

41. The process of any one of claims 32 to 39, wherein producing the mixture comprises using a flow control device to promote a flow of the non-condensable gas from a high gas saturation zone within the gas-enriched zone.

42. The process of any one of claims 31 to 41, wherein following the hydrocarbon-rich reservoir entering the mature phase, the process further comprises converting at least one of the injection well and the production well to an additional gas injection well to inject additional non-condensable gas into the mobilizing chamber.

43. The process of claim 42, wherein the gas-enriched zone and the mobilizing chamber combine to form a combined gas-enriched region.

44. The process of claim 43, wherein recovering the tat least a portion of the non-condensable gas from the hydrocarbon-lean zone comprises recovering the at least a portion of the non-condensable gas from the combined gas-enriched region.

45. The process of any one of claims 31 to 44, wherein the non-condensable gas comprises CO2.

46. The process of any one of claims 31 to 44, wherein the non-condensable gas comprises a light hydrocarbon.

47. The process of any one of claims 31 to 44, wherein the non-condensable gas comprises methane.

48. The process of any one of claims 31 to 47, wherein the injection well is positioned above the production well.

49. The process of any one of claims 31 to 48, wherein the injection well is positioned proximate the production well.

50. The process of any one of claims 31 to 49, wherein the mobilizing fluid further comprises steam.

51. The process of any one of claims 31 to 49, wherein the mobilizing fluid is substantially free of steam.

52. The process of any one of claims 31 to 51, wherein the mobilizing solvent comprises a hydrocarbon solvent.

53. The process of any one of claims 31 to 52, wherein the mobilizing solvent comprises a paraffinic solvent.

54. The process of any one of claims 31 to 53, wherein the mobilizing solvent comprises an aromatic solvent.

55. The process of any one of claims 31 to 54, further comprising heating the hydrocarbon-rich reservoir to mobilize at least a portion of the hydrocarbons contained therein.

56. The process of claim 55, wherein heating the hydrocarbon-rich reservoir comprises providing heat to the hydrocarbon-rich reservoir via an external heating source.

57. The process of claim 55, wherein the external heating source comprises electric resistive heating.

58. The process of claim 55, wherein the external heating source comprises radio frequency (RF) heating.

59. The process of any one of claims 31 to 58, wherein no dedicated water production well is provided in the hydrocarbon-lean zone for production of water therefrom.

60. The process of claim 31, wherein the gas injection well is substantially horizontal.

61. The process of claim 31, wherein the injection portion of the gas injection well is entirely located in the hydrocarbon-lean zone and is vertically spaced-apart from an upper part of the underlying hydrocarbon-rich reservoir.