In SITU combustion in late life bitumen recovery wells

Abstract

In situ combustion can be implemented in a vapour chamber formed by a solvent- or steam-assisted process, where various methods are leveraged. Ignition can be facilitated by heating the well through which an oxygen containing gas is injected using a downhole heater previously used in the context of the solvent- or steam-assisted process. The solvent- or steam-assisted process can be operated until the vapour chambers of adjacent well pairs coalesce in order to enhance combustion sweep efficiency between the well pairs. In addition, the in situ combustion stage can be combined with blowdown or winddown stages to enhance certain aspects of the hydrocarbon recovery operation and solvent recovery.

Description

IN SITU COMBUSTION IN LATE LIFE BITUMEN RECOVERY WELLS TECHNICAL FIELD [1] The technical field generally relates to the recovery of heavy hydrocarbons from underground reservoirs, and more particularly to in situ combustion processes for recovering heavy hydrocarbons, such as bitumen. BACKGROUND [2] In situ combustion has been used to recover hydrocarbons from underground reservoirs. In such processes, an oxygen containing gas is injected into the reservoir under conditions to promote ignition using the hydrocarbons as a source of fuel. In situ combustion generates heat and combustion gases, which can enhance mobility of the hydrocarbons and drive the hydrocarbons to a production well. There are a number of challenges related to in situ combustion and other processes for recovering heavy hydrocarbons from underground reservoirs. SUMMARY [3] In situ combustion can be implemented in a vapour chamber formed by a solvent-dominated process where various methods are leveraged to enhance the process. For example, ignition can be facilitated by heating the well through which an oxygen containing gas is injected using an electric resistance heater previously used in the context of the solvent-dominated process. In another example, the solvent-dominated process can be operated until the vapour chambers of adjacent well pairs coalesce in order to enhance sweep efficiency between the well pairs. Other examples include combining the in situ combustion stage with blowdown and winddown stages to enhance certain aspects of the hydrocarbon recovery operation and solvent recovery. [4] In some implementations, there is provided a process for recovering bitumen from a reservoir in which a well pair array is provided, the well pair array comprising multiple spaced-apart well pairs each comprising an injection well overlying a production well, the process comprising: a production stage, comprising: injecting a deasphalting solvent in vapour phase via the injection well into the reservoir to dissolve and mobilize bitumen which drains by gravity toward the production well, and forming a vapour chamber above the injection well and comprising precipitated asphaltenes and residual deasphalting solvent, and wherein the vapour chambers of respective adjacent well pairs coalesce to form a coalesced chamber above the adjacent well pairs; and producing a production fluid comprising drained partially deasphalted bitumen and condensed deasphalting solvent via the production well; and an in situ combustion stage, comprising: injecting an oxygen containing gas into the coalesced chamber and providing conditions to cause in situ combustion that is fueled by hydrocarbons including the precipitated asphaltenes, thereby forming a combustion front that drives a portion of the residual deasphalting solvent and residual bitumen through the coalesced chamber toward at least one late-life recovery well of the well pair array; and producing a late-life production fluid comprising bitumen and residual deasphalting solvent from the reservoir via the late-life recovery well. [5] In some implementations, there is provided a process for recovering bitumen from a reservoir in which a well pair array is provided, the well pair array comprising multiple spaced-apart well pairs each comprising an injection well overlying a production well, the process comprising: a startup stage, comprising establishing fluid communication between the injection well and the production well of each well pair; a production stage, comprising: injecting a mobilizing fluid via the injection well into the reservoir to mobilize bitumen which drains by gravity toward the production well, and forming an vapour chamber above the injection well; and producing a production fluid comprising drained bitumen via the production well; heating an interwell region between the injection well and the production well during the startup stage, heating the mobilizing fluid during the production phase, or both, using an electric resistance heater (ERH) or a closed-loop circulation system (CLCS) disposed in a heating well that is part of the well pair array; an in situ combustion stage, comprising: injecting an oxygen containing gas into an oxygen injection well that was operated as the heating well during the startup stage, the production stage, or both; operating the ERH or CLCS in the oxygen injection well to heat a near wellbore region around the oxygen injection well to provide an ignition temperature therein, thereby promoting ignition of hydrocarbons and oxygen in the near wellbore region; continuing air injection to sustain combustion and cause a combustion front to drive residual mobilizing fluid and bitumen toward at least one late-life recovery well of the well pair array; and producing a late-life production fluid comprising bitumen and residual mobilizing fluid from the reservoir via the late-life recovery well. [6] In some implementations, there is provided a process for recovering bitumen from a reservoir in which a well pair array is provided, the well pair array comprising multiple spaced-apart well pairs each comprising an injection well overlying a production well, the process comprising: a production stage, comprising: injecting a mobilizing fluid via the injection well into the reservoir to mobilize bitumen which drains by gravity toward the production well, and forming an vapour chamber above the injection well; and producing a production fluid comprising drained bitumen via the production well; a blowdown stage, comprising: reducing an injection rate of the mobilizing fluid via the injection well; and reducing an operating pressure of the vapour chambers to a blowdown pressure; and an in situ combustion stage, comprising: injecting an oxygen containing gas via an oxygen injection well into the vapour chamber at the blowdown pressure and providing conditions to cause in situ combustion, thereby forming a combustion front that drives residual bitumen through the vapour chamber toward at least one late-life recovery well; and producing a late-life production fluid comprising bitumen from the reservoir via the late-life recovery well. [7] In some implementations, there is provided a process for recovering bitumen from a reservoir in which a well pair array is provided, the well pair array comprising multiple spaced-apart well pairs each comprising an injection well overlying a production well, the process comprising: a production stage, comprising: injecting a mobilizing fluid via the injection well into the reservoir to mobilize bitumen which drains by gravity toward the production well, and forming an vapour chamber above the injection well; and producing a production fluid comprising drained bitumen via the production well; a winddown stage, comprising: reducing an injection rate of the mobilizing fluid via the injection well; and injecting a winddown vapour into the vapour chamber to maintain an operating pressure of the vapour chamber; and an in situ combustion stage, comprising: injecting an oxygen containing gas via an oxygen injection well into the vapour chamber and providing conditions to cause in situ combustion, thereby forming a combustion front that drives residual bitumen through the vapour chamber toward at least one late-life recovery well; and producing a late-life production fluid comprising bitumen from the reservoir via the late-life recovery well. [8] In some implementations, there is provided a process for recovering bitumen from a reservoir in which a well pair array is provided, the well pair array comprising multiple spaced-apart well pairs each comprising an injection well overlying a production well, the process comprising: a production stage, comprising: injecting a mobilizing fluid via the injection well into the reservoir to mobilize bitumen which drains by gravity toward the production well, and forming an vapour chamber above the injection well; and producing a production fluid comprising drained bitumen via the production well; an in situ combustion stage, comprising: injecting an oxygen containing gas via an oxygen injection well into the vapour chamber and providing conditions to cause in situ combustion, thereby generating heat and forming a combustion front that drives residual bitumen through the vapour chamber toward at least one late-life recovery well; and producing a late-life production fluid comprising bitumen from the reservoir via the late-life recovery well; and recovering heat from the reservoir, comprising: supplying a heat transfer fluid into at least one of the wells of the well pair array that is heated by the heat from the in situ combustion to form a heated fluid in the at least one well; and producing the heated fluid from a heat recovery well to surface. [9] In some implementations, there is provided a process for recovering bitumen from a reservoir in which a well pair array is provided, the well pair array comprising multiple spaced-apart well pairs each comprising an injection well overlying a production well, the process comprising: a production stage, comprising: injecting a mobilizing fluid via the injection well into the reservoir to mobilize bitumen which drains by gravity toward the production well, and forming an vapour chamber above the injection well; and producing a production fluid comprising drained bitumen via the production well; an in situ combustion stage, comprising: injecting an oxygen containing gas via an oxygen injection well into the vapour chamber and providing conditions to cause in situ combustion, thereby generating heat and forming a combustion front that drives residual bitumen through the vapour chamber toward at least one late-life recovery well; and producing a late-life production fluid comprising bitumen from the reservoir via the late-life recovery well; and storing a fluid in the reservoir, comprising supplying the fluid into at least one of the wells of the well pair array, wherein the fluid comprises water, wastewater, brine, tailings, diluted bitumen or a waste material.

[10] In some implementations, there is provided a process for recovering bitumen from a reservoir in which a well pair array is provided, the well pair array comprising multiple spaced-apart well pairs each comprising an injection well overlying a production well, the process comprising: a production stage, comprising: injecting a mobilizing fluid via the injection well into the reservoir to mobilize bitumen which drains by gravity toward the production well, and forming an vapour chamber above the injection well; and producing a production fluid comprising drained bitumen via the production well; an in situ combustion stage, comprising: injecting an oxygen containing gas via an oxygen injection well into the vapour chamber and providing conditions to cause in situ combustion, thereby generating heat and forming a combustion front that drives residual bitumen through the vapour chamber toward at least one late-life recovery well; and producing a late-life production fluid comprising bitumen from the reservoir via the late-life recovery well; and utilizing the well pair array for heat recovery, temporary fluid storage and / or fluid disposal by supplying a corresponding fluid into at least one of the wells before, during and / or after the in situ combustion stage.

[11] In some implementations, there is provided a process for recovering bitumen from a reservoir in which a well pair array is provided, the well pair array comprising multiple spaced-apart well pairs each comprising an injection well overlying a production well, the process comprising: a production stage, comprising: injecting a mobilizing fluid comprising a solvent via the injection wells such that the solvent enters into the reservoir in vapour phase to dissolve and mobilize bitumen which drains by gravity toward the production well, and forms vapour chambers above the injection well, wherein the vapour chambers of respective adjacent well pairs coalesce to form a coalesced chamber above the adjacent well pairs; and producing a production fluid comprising drained bitumen and condensed solvent via the production well; and an in situ combustion phase, comprising: injecting an oxygen containing gas into the coalesced chamber and providing conditions to cause in situ combustion that is fueled by hydrocarbons present therein, thereby forming a combustion front that drives a portion of residual solvent and residual bitumen through the coalesced chamber toward at least one late-life recovery well of the well pair array; and producing a late-life production fluid comprising bitumen and residual solvent from the reservoir via the late-life recovery well. BRIEF DESCRIPTION OF THE DRAWINGS

[12] Figs 1a to 1f are cross-sectional view schematics of two adjacent well pairs in a reservoir showing various stages of the operation including start-up, solvent-assisted production, and in situ combustion, where an electric resistance heater operates during certain stages.

[13] Figs 2a to 2d are cross-sectional view schematics of two adjacent well pairs in a reservoir showing different stages of the operation including a production stage, a blowdown stage, and an in situ combustion stage.

[14] Fig 3 is a cross-sectional view schematic of two adjacent well pairs in a reservoir during a winddown stage.

[15] Fig 4 is a cross-sectional view schematic of three adjacent well pairs in a reservoir during in situ combustion with injection of an oxygen containing gas via the central well pair.

[16] Fig 5 is a cross-sectional view schematic of two adjacent well pairs in a reservoir as well as an infill well in between the pairs, during in situ combustion.

[17] Fig 6 is a perspective view schematic of an injection well for injection during a production stage and during an in situ combustion stage, and having an electric resistance heater (ERH) provided therein.

[18] Fig 7 is a cross-sectional view schematic of multiple adjacent well pairs that form a well pair array and an adjacent well pair that is not hydraulically connected.

[19] Fig 8 is a diagram that shows potential fluid transfers between different operations, including mining, in situ, electrical grid, external markets, and late life reservoirs, for heat recovery, fluid storage, and fluid disposal. DETAILED DESCRIPTION

[20] Conducting in situ combustion in late-life heavy hydrocarbon recovery operations can facilitate leveraging an earlier recovery process while benefiting from certain characteristics of in situ combustion.

[21] In some implementations, the in situ combustion stage is performed using a late-life array of horizontal well pairs that were operated according to a solvent-dominated gravity based recovery process using the injection of a deasphalting solvent vapour resulting in a coalesced vapour chamber that includes residual solvent and precipitated asphaltenes. The in situ combustion stage can leverage the residual solvent present in the near wellbore region for ignition, and then the precipitated asphaltenes present in the vapour chamber to facilitate sustaining combustion to drive residual bitumen and solvent in the chamber toward an adjacent well pair for production. The in situ combustion process can thus facilitate recovery of solvent, recovery of additional bitumen, some in situ upgrading of bitumen, and the use precipitated asphaltenes as an in situ fuel source.

[22] In some implementations, the in situ combustion stage is initiated by energizing an electric resistance heater (ERH) that extends down one of the wells of a late-life array of horizontal well pairs. The ERH can have been present in the well for delivering heat to the reservoir during a startup stage and / or for delivering heat to a mobilizing fluid injected down that well during the production stage. The ERH can be controlled to heat the wellbore and near wellbore region of the designated gas injecting well through which the oxygen containing gas is injected, thereby ensuring timely ignition in order to initiate the in situ combustion. The ERH can then be shut off as the combustion becomes self-sustaining and the combustion front travels through the vapour chamber above the well pairs. The ERH can thus be utilized as a multifunctional device for different stages of the overall in situ recovery operation. A blowdown stage can be contemplated in particular when the vapour chamber dedicated for in situ combustion is not hydraulically connected to a high pressure region of the reservoir, such as an adjacent vapour chamber operating in the higher-pressure production stage.

[23] In some other implementations, the in situ combustion stage is performed after a blowdown stage where the injection rate of the mobilizing fluid has been ramped down and the pressure of the vapour chamber has been reduced to a blowdown pressure. Operating the in situ combustion stage at lower pressures can facilitate lower injection requirements for the oxygen containing gas to sustain the combustion.

[24] In further implementations, the in situ combustion stage can be performed after a winddown stage where the injection rate of the mobilizing fluid has been decreased while supplementing with a pressure maintenance fluid, such as natural gas or another non-condensable gas. The winddown stage can facilitate recovery of residual solvent that is present in the vapour chamber after the main production stage has run its course economically. By maintaining pressure in the vapour chamber, undesired fluid infiltration from a high pressure region of the reservoir (e.g., an adjacent vapour chamber operating in the higher-pressure production stage) can be avoided or reduced. At the same time, the solvent that is recovered from the chamber during winddown should not be required for initiating or maintaining the in situ combustion reactions; moreover, by reducing the solvent content in the chamber, the combustion reactions would utilize the heavier hydrocarbon fractions present in the chamber as fuel which can lead to high temperature combustion.

[25] In some implementations, heat recovery methods are used to recover heat generated by the in situ combustion. In situ combustion operates at much higher temperatures than processes that utilize deasphalting solvent for the production stage, which presents opportunities for recovering heat generated by in situ combustion. For example, in situ combustion can leave the depleted chamber regions at temperatures above 150°C, above 200°C, or 250°C versus the 40°C to 80°C of a solvent-dominated process. The average temperature of the chamber after in situ combustion can be at least double or triple or 100°C more than the temperature after the solvent-dominated process. The heat recovery methods can include introducing a heat transfer fluid down one or more of the wells of the well pair array, allowing the fluid to heat up due to the high temperatures in the surrounding reservoir, and producing back the heated fluid to the surface, and then using the recovered heat at surface.

[26] Referring now to Figs 1a to 1f, an example of an in situ bitumen recovery operation having a number of different stages will be described. The Figs show an array 10 of wells that includes two adjacent well pairs 12. Each well pair 12 includes a production well 14 and an overlying injection well 16. Each pair is separated by an interwell region 18, and the adjacent well pairs 12 are separated from each other by a well separation distance 20. The wells are first drilled and completed, and then a startup stage is initiated.

[27] Fig 1a shows the well pairs 12 during the startup stage, which is performed to establish hydraulic communication between the injection well 16 and the production well 14. Various startup methods can be used, including the circulation of mobilizing fluid, injection of mobilizing fluid, use of various kinds of heaters that are deployed within one or more of the wells. In one implementation, an electric resistance heater (ERH) 22 is provided in one or both of the wells in the well pair 12, optionally in the injection well 16 only. The ERH 22 heats up the wellbore and near wellbore region of the well in order to mobilize bitumen. By warming the bitumen above a certain temperature, the bitumen will become mobile and can be removed via one or more of the wells, for example using a pressure differential between the wells. During the electric heating, a circulation fluid (not shown here), which can be hydrocarbon based, can also be circulated through one or both of the wells to begin dissolving and removing bitumen from the near wellbore region. The startup stage can then include creating a pressure sink in the production well 14, and optionally injecting a drive fluid 24 via the injection well 16 in order to drive the mobilized bitumen toward the production well 14. The drive fluid and mobilized bitumen are then recovered via the production well 14 such that bitumen is mobilized and removed from the interwell region, thus establishing fluid communication between the wells.

[28] Referring to Fig 1b, after the startup stage, the well pairs can be operated in a production stage where a mobilizing fluid 26, such as steam, solvent or a combination thereof, is injected via the injection wells 16 in order to mobilize bitumen and form a vapour chamber 28. Each well pair 12 forms its own vapour chamber 28 which extends upwardly and outwardly over time from the injection well 16, as shown. The mobilizing fluid 26 is injected as a vapour and thus it travels upward through the vapour chamber 28, condenses on the cooler bitumen in the reservoir, and forms mobile hydrocarbon phase that drains by gravity toward the production well 14. The production well 14 can have a pump to enable the production fluid to be recovered to surface where it is processed. It is noted that the mobilizing fluid 26 enters the reservoir as a vapour, but it could be supplied down the well as a vapour or as a liquid that is vaporized within the well prior to entering the reservoir.

[29] Depending on the mobilizing fluid 26 that is used, the process and the vapour chamber 28 can have different properties. For example, when steam is used, as in a steam-assisted gravity drainage (SAGD) process, the steam heats the bitumen and condenses such that the production fluid includes mainly water and bitumen and the vapour chamber 28 is wet and includes some residual bitumen. On the other hand, when a deasphalting solvent (e.g., propane, butane, pentane, or light hydrocarbon blends) is used, the production fluid includes mainly solvent and dissolved bitumen and the vapour chamber 28 includes residual solvent and precipitated asphaltenes that have come out of the bitumen and deposited on the mineral matrix of the reservoir due to contact with the solvent. Various mobilizing fluids can be used alone, co-injected via the same well or injected via different wells, depending on the particular recovery process. The mobilizing fluid that is used for a given well pair or process can also be changed over time by adding a co-injected fluid at a given point in time or changing the nature of the mobilizing fluid, if desired.

[30] It is also noted that hybrid solvent-steam processes can be used in the production stage. For example, expanding-solvent (ES) SAGD can use diluent, such as naphtha, as the solvent that is co-injected with steam at lower solvent concentrations, such as 1% to 15%. Other processes using steam-solvent co-injection, cyclic or alternating processes using steam and solvent injection, and other processes that use co-injection of different mobilizing fluids, can also be used in the production stage. In addition, various hydrocarbon solvents can be used in certain implementations of the process, including paraffinic solvents; aromatic solvents; solvents derived from hydrocarbon streams that may be obtained form refining or on-site separation units, such as naphtha, natural gas condensates, one or more cuts from distillation towers; and mixtures of one or more of such streams and / or compounds. The solvent can be selected based on one or more of its properties, such as deasphalting ability, solubility with bitumen, heat transfer properties, vapour pressure, density, viscosity, etc., at operating conditions of the process to be implemented.

[31] Referring to Fig 1c, over time the vapour chambers extending from adjacent well pairs expand so that they coalesce together, forming a coalesced chamber 30. The coalescence can begin at a point along the length of the well pairs and gradually expand such that much or substantially all of the vapour chambers coalesce together along their horizontal length. Chamber coalescence can be detected by identified pressure equalization between the two vapour chambers as they become hydraulically linked, and / or using four-dimensional seismic techniques, and / or observation wells. The coalesced chamber 30 can have various shapes, but will typically have a cross-section that appears as two inverted, conjoined, round-cornered triangles that define a hump- shaped bypassed region 32 between the two well pairs 12. The bypassed region 32 has higher bitumen saturation and is cooler compared to the coalesced chamber 30. After coalescence, the recovery operation can continue generally as before with injection of mobilizing fluid and production of the production fluid.

[32] The coalescence need not extend the entire length of the well for the combustion stage to begin. The vapour chambers could be coalesced along 5% to 100% of their lengths, or along at least 10%, at least 20%, or at least 50% of their lengths. The vapour chambers could also be coalesced along at least 20 meters, 50 meters, 100 meters, 500 meters, or 1000 meters. Since the progression of the combustion front depends on the gases to move through the chamber, even a relatively small coalesced region can be sufficient to provide the hydraulic connectivity for the combustion to evolve through the chamber toward an adjacent well pair. In some implementations, a higher degree of coalescence can be sought out since this can facilitate improved sweep efficiency. The in situ combustion stage can be initiated at some point after coalescence has been detected, or before coalescence but once the combustion front reaches a far point of the chamber the chambers have coalesced to some degree.

[33] The timing of initiating the in situ combustion stage can depend on various factors. For example, in situ combustion can be initiated based on the economic life of the solvent-based process. The extent of the economic life of a solvent-based process can be determined through forecasting oil production rates, emulsion production rates, injected solvent to produced oil ratio, ratio of make-up solvent or solvent lost in the reservoir. Solvent, energy and other operating costs used in conjunction with these and other so- called key performance indicators can help guide the decision to transition from solvent injection to winddown and / or blowdown stages, followed by combustion. Alternatively, transitioning from solvent injection directly to a combustion stage and skipping winddown and blowdown stages may prove advantageous for the overall economic performance and expected ultimate recovery. Well spacing, infill drilling and other capital costs can also impact the optimal duration of each recovery process stage. Optimal development strategies may differ for different reservoir types according to the reservoir thickness, rock quality, fluid saturations, and various subsurface impairments.

[34] It is also noted that the timing of ceasing injection of the mobilizing fluid and commencing ERH heating and injection of the oxygen containing gas can vary depending on certain factors. For example, in some implementations, for a given well pair array, all of the injection wells of the array cease injecting the mobilizing fluid before one or more selected ERHs commence preheating and before injection of oxygen containing gas is initiated. By stopping injection of mobilizing fluid in all of the wells, a pressure sink can be created to encourage the combustion front to progress across the chamber.

[35] In another example implementation, for a given well pair array, injection of mobilizing fluid ceases in a first well pair so that the ERH heating and then oxygen injection can be performed, but in one or more of the other well pairs the injection of the mobilizing fluid continues to a certain degree while combustion is developing at the first well pair. Since the combustion front takes time to advance through the chamber, other wells can continue operation in a production stage simultaneously with the combustion stage occurring at another well in the same chamber. These timing considerations can depend on factors such as the well spacing (see distance 20 in Fig 1a), the productivity of the different well pairs, reservoir properties, and so on. It is also possible to initiate combustion at a first well pair which has an vapour chamber that is not yet coalesced with an adjacent vapour chamber, particularly if coalescence occurs by the time the combustion front reaches a coalescence point and can pass through and into the adjacent chamber and toward the adjacent well pair. This can be done if one well pair is mature and ready for in situ combustion while the adjacent well pair is close but not quite ready for combustion but will be by the time the combustion front arrives.

[36] At a certain point in time the recovery operation will become less efficient and eventually economically unsuitable to continue full injection of the mobilizing fluid. The injection of mobilizing fluid can be ramped down and eventually stopped, while production can continue for a certain period of time. One of the goals at this stage is to recover as much mobilizing fluid as possible from the coalesced chamber 30, especially when the mobilizing fluid has a relatively high commercial value as is the case for various hydrocarbon solvents. The residual solvent that remains in the coalesced chamber 30 should be recovered, if possible.

[37] A solvent recovery stage can include various steps and characteristics. For example, the solvent recovery stage can include a blowdown stage where injection is decreased or stopped while production continues and results in pressure reduction in the coalesced chamber, and / or a winddown stage where injection of the mobilizing fluid is replaced with another fluid (e.g., a non-condensable gas) to maintain the pressure in the chamber while continuing to produce bitumen and condensed mobilizing fluid. More regarding the blowdown and winddown stages will be discussed further below.

[38] Referring to Fig 1d, once the injection of the mobilizing fluid has ceased, an in situ combustion stage can be initiated. The in situ combustion stage includes the injection of an oxygen containing gas 33, such as air, into at least one well provided in the coalesced chamber 30. This well can be referred to as an oxygen injection well 34. Fig 1d illustrates the implementation where the ERH 22 previously used for startup and / or production stages is energized to heat the near wellbore region around the oxygen injection well 34. The ERH 22 heats the neat wellbore region to at least an ignition temperature to facilitate ignition of hydrocarbons and oxygen in the near wellbore region. The oxygen containing gas can then be injected into the heated near wellbore region, causing ignition followed by sustained combustion. Fig 1d illustrated the ERH 22 heating the near wellbore region, and the injection of the oxygen containing gas. The heating can occur before starting oxygen injection, or the oxygen injection can be performed during the heating. The ignition temperature provided by the ERH 22 can depend on the properties of the fluids in the reservoir; if a light solvent such as butane is the mobilizing fluid then the ignition temperature will be lower compared to steam.

[39] It is also noted that other types of downhole heaters or heating methods could be used to provide the heating (e.g., closed-loop circulation heaters such as steam or oil heaters, injection of superheated fluid, electromagnetic antennae, and so on). The downhole heater can be deployed during startup for preheating the interwell region. For example, the downhole heater could be a closed-loop circulation heater that includes concentric tubing strings, one for flowing hot fluid (e.g., steam) down the well and the other for returning the hot fluid (e.g., condensate). In some implementations, the heating can be conducted by injecting a hot vapour into the near wellbore region. The hot vapour could be steam, which could be superheated. When steam is injected, it could also be done so that steam fills at least part of the chamber 30 such that the subsequent in situ combustion will be "wet". Wet combustion can have certain benefits, for instance in terms of providing a more even and uniform combustion and lower air requirements. Thus, steam injection could not only heat the near wellbore region high enough for ignition, but could also facilitate wet combustion. Wet combustion could also be facilitated by co-injecting water with the oxygen containing gas or performing intermittent steam injection during the in situ combustion stage. It is also noted that multiple methods could be used simultaneously or sequentially to heat the near wellbore region for ignition, such as injecting steam and also activating or operating an ERH 22 present in the well.

[40] Referring to Figs 1e and 1f, the combustion results in a combustion front 36 that progresses away from the oxygen injection well 34 and drives residual mobilizing fluid and bitumen toward at least one late-life recovery well 38 of the well pair array. In the illustrated implementation, the late-life recovery well 38 is the production well 14 of an adjacent well pair 12. However, it should be noted that the late-life recovery well 38 could be another well provided in the reservoir (e.g., a previous injection or production well of the well pair array, a new dedicated production well drilled in the reservoir, or an infill or step-out well provided in the reservoir). Fig 1f also illustrates that the residual bitumen in the bypassed region 32 is also mobilized and recovered via the late-life recovery well 38.

[41] At the end of the in situ combustion stage, the air injection is ceased and one or more wells can be put on production to recover mobilized bitumen, combustion products, and solvent. To be clear, some production can occur at the same time as air injection via certain production wells, and then once air injection is ceased production can continue, if desired, via the same production wells and / or additional production wells. After in situ combustion, the chamber may be relatively depleted with low residual oil and asphaltene saturation as well as reduced solvent saturation. There may be some low- value coke-like heavy ends that remain in the pore space of the reservoir at the end of the combustion stage. Of course, there is a range of coke and oil components that may be deposited or left behind within the swept regions of the chamber, with the swept regions ranging from clean sand with very minor or trace oil to sand with coke deposits to sand with residual oil that is asphaltenes or heavier ends.

[42] The combustion uses residual hydrocarbons and injected oxygen as fuel. When the production stage uses a deasphalting solvent (e.g., paraffins such as butane) as the mobilizing fluid, resulting in asphaltene precipitation in the vapour chambers, the combustion is fueled by hydrocarbons including the precipitated asphaltenes. Heavy hydrocarbon fractions such as asphaltenes can be an interesting fuel source for in situ combustion for various reasons. First, the asphaltenes would have been lost to the reservoir and thus their use as fuel has notable efficiencies. Second, heavy fractions can facilitate sustaining in situ combustion and reaching high temperature combustion which is desirable. Furthermore, the combustion of heavy fractions can also facilitate in situ cracking reactions resulting in upgraded hydrocarbons that are driven to the late-life recovery well for recovery, while leaving coke and / or other undesirable compounds in the reservoir. In addition, a solvent-dominated process using certain deasphalting solvents, such as butane, can be operated such that the production stage leaves between 15 vol% and 50 vol%, or between 25 vol% and 40 vol%, or 25 vol% to 35 vol%, of the bitumen in the vapour chambers as a heavy fraction that comprises the precipitated asphaltenes. Of course, this can depend on the solvent used. This rejected heavy fraction can be leveraged as fuel for the in situ combustion process.

[43] The in situ combustion burns heavy fractions and some other residual hydrocarbons as fuel, generates cracked hydrocarbons and causes pressure to increase in the chamber. The increased pressure helps to drive residual solvent and bitumen toward the late-life recovery well for production to surface, aiding solvent recovery from the chamber. In situ combustion thus can facilitate recovery of deasphalting solvent (or another mobilizing fluid, if desired), mobilization and recovery of bypassed and residual bitumen, leveraging the deposited heavy asphaltic fractions in the reservoir, maintaining pressure in the late-life chamber which can be useful if adjacent to less mature patterns, as well as utilizing combustion flue gases for other purposes such as pressurizing other regions of the formation (e.g., thief zones).

[44] In some implementations, the production fluid contains flue gases that can be separated from the produced liquids at surface. The separated flue gas can be reused, e.g., for injection into another formation for storage or other purposes. Some flue gases generated in the reservoir can flow separately to the surface via the casing, and can be captured at surface. Flue gases that are separated or captured at surface can be handled in various ways, such as compressing and pipelining to another well paid (e.g., one that injects into a gas cap or lean zone) or reinjected into the air injection well (e.g., later on the in situ combustion stage once there is enough oxygen in the reservoir to sustain the desired combustion). It is also possible that some flue gases could be vented to atmosphere.

[45] When a deasphalting solvent (e.g., propane, butane or pentane) is used during the production stage, the downhole operating conditions can be such that the vapour chamber temperatures are generally below the ignition temperature for combustion. While the deasphalting solvent can be injected at superheated conditions or the ERH can be operational during the production phase to provide a relatively high injection well temperature (e.g., about 250°C, or higher up to 350°C depending on equipment limitations), the vapour chambers can be closer to 40°C and 80°C. Thus, during transition from the production stage to the in situ combustion stage, the injection well can cool to become closer to the temperature of the vapour chambers by the time injection of the oxygen containing gas is initiated. The reheating of the injection well and its near wellbore region can facilitate ensuring the desired ignition conditions. Leveraging the ERH 22 to provide this reheating can facilitate efficiencies and safety, since the process would not have to run new heaters into the well, preheat the air, inject other heating fluids into the well, or deploy chemical ignition aids.

[46] The ERH 22 can be operated to provide a local ignition temperature above 200°C to cause ignition in the near wellbore region, optionally between 200°C and 280°C, 220°C and 260°C or 230°C and 250°C, for example. In addition, if during transition to the in situ combustion stage the mobilizing fluid condenses around the injection well, the ERH 22 is well suited to revaporize the mobilizing fluid in the near wellbore region to facilitate ignition. After ignition, the ERH 22 can be turned off since the combustion can be self- sustaining. The ERH 22 could be run out of the well during oxygen gas injection, or could be left in the well during the entire in situ combustion stage.

[47] Turning back to Figs 1d to 1f, certain wells can be shut in during the in situ combustion stage. For example, the production well 14 of the well pair that includes the oxygen injection well 34 can be shut, as can be the injection well 16 of the well pair that includes the late-life recovery well 38. Alternatively, the production well 14 of the well pair 12 that includes the oxygen injection well 34 can be converted into a second oxygen injection well 34, and / or the injection well 16 of the adjacent well pair 12 could be converted to a second late-life recovery well 38. In addition, if separate dedicated oxygen injection well 34 and late-life recovery well 38 are drilled into the reservoir, then all of the existing wells of the well pairs 12 could be shut in during the in situ combustion process. However, notable efficiencies can be gained by leveraging the existing well infrastructure for in situ combustion.

[48] Regarding the operation of the oxygen injection well, the oxygen containing gas can be injected to maintain the combustion at a combustion temperature between 400°C and 800°C within the coalesced chamber. This can involve increasing the oxygen injection rate over time as the combustion front expands and the volume of the combusted region increases. The initial oxygen injection can be relatively low, though sufficient to provide enough oxygen in the near wellbore region to enable ignition. It is also noted that initially the oxygen-to-oil ratio or air-to-oil ratio, i.e., the ratio of injected oxygen or air to produced oil, can be relatively low and then can increase over time.

[49] It is also noted that initially the oxygen containing gas could be oxygen enriched air to reduce the amount of volume required or reduce the ignition temperature, and then regular air can be used for the bulk of the in situ combustion stage, particularly the phases that require high air injection rates for economical reasons. Alternatively, air could be used at the start of the process and then oxygen enriched air could be used for subsequent phases of the combustion, if desired. Using oxygen enriched air reduces the overall injection rate of the gas needed to supply the same amount of oxygen, and since higher oxygen injection rates can be required as the combustion progresses it could be beneficial to use gas with higher oxygen contents. Higher oxygen content can lead to lower flue gas production, which can be beneficial, as well as other enhancements, although it also requires higher cost considerations.

[50] In addition, in some implementations, it may be desirable to inject less- enriched or regular air for pressure maintenance purposes, such that sufficient oxygen is provided for combustion while the other gases act to pressurize the vapour chambers. Furthermore, since oxygen is only need at the combustion front and high oxygen concentrations can increase low temperature oxidation reactions, it can be beneficial to inject air without oxygen enrichment. It is also noted that the injection via the oxygen injection well can be managed to ensure oxygen is present at the combustion front while minimizing the amount expensive gas that fills up the void space upstream of the combustion front. This can be done by injecting regular air throughout the process, or by reinjecting flue gases or other waste gases later in the in situ combustion stage so that such gases take up the space behind the air and the combustion front.

[51] Turning now to Fig 6, the ERH 22 provided in the injection well 16 can include an elongate heater cable that is surrounded by a sleeve and deployed within a liner of the well. Various completion systems can be deployed in the well and can include tubular strings, instrumentation, flow control devices, and other downhole equipment. Optionally, the injection well 16 includes a single heater cable or a cluster of cables within a sleeve that provides generally uniform heating along most or substantially the entire length of the horizontal section of the well. By heating and injecting oxygen along the length of the well, the in situ combustion can have enhanced conformance along the well as the combustion front can extend along the well. Alternatively, the ERH 22 could be provided at one or more locations along the well to provide spot heating. For example, one of the heaters located at a certain location (e.g., at the toe, at the heel or at an intermediate location along the well) could be exclusively used for promoting ignition; and in such a case the oxygen containing gas could also be injected only or primarily at the corresponding spot- heated location. It is also noted that the oxygen containing gas could also be injected at different locations along the well, as long as the oxygen can reach the heated near wellbore regions to enable ignition. Various configurations for completions that include ERH and / or closed-loop circulation heating could be used, for example. Nevertheless, it is noted that due to increased corrosion risks during in situ combustion, the completion equipment (e.g., tubing strings, liners, instrumentation, ERH or other heater, and / or others) can include enhanced corrosion resistance in the form of corrosion-resistant coatings or materials. In some implementations, the same completion and heaters used for the solvent-dominated process are also used in the follow-on in situ combustion stage. Alternatively, different equipment could be deployed for the in situ combustion stage.

[52] Considering the ERH 22 in a given well during the lifetime of the well, the ERH can be configured and operated to warm bitumen in the interwell region during startup from native conditions up to above a mobilization temperature, to maintain the near wellbore region at a temperature above 250°C during the production phase, and to heat the near wellbore region above an ignition temperature of 200°C (or another higher temperature) for the in situ combustion stage. The ERH 22 can thus be provided with the structural and operational capacity for these stages of the process. In some implementations, the ERH 22 (or other heater such as a closed-loop circulation heater) is designed for heating at multiple stages including startup, production, and in situ combustion, where one or more of the stages have different heating requirements. The heater can thus be overdesigned for one stage so that it has the desired capacity for another.

[53] Turning now to Figs 2a to 2d, the process can also include performing a blowdown stage (Fig 2b) in between the production stage (Fig 2a) and the in situ combustion stage (Figs 2c-2d). The blowdown stage involves reducing or ceasing the injection of the mobilizing fluid, resulting in reducing pressures in the chamber while fluids continue to be recovered via the production wells.

[54] The blowdown stage can be performed for a reservoir region that is relatively isolated or contained with respect to surrounding high pressure regions of the reservoir. For instance, when the recovery operation is performed using an array of well pairs that were drilled and operated at generally the same time such that they generally reach the same maturity at the same time, the overall coalesced chamber can be suitable for blowdown as a unit, assuming there are no proximate regions of the reservoir undergoing high pressure operations (e.g., the production stage of another well pair array). In other words, the blowdown stage can be appropriate depending on the surrounding reservoir conditions, which can depend on timing of operations.

[55] Fig 2a shows the process during the production stage where mobilizing fluid is injected into the chamber 30. The chamber is thus at an extraction operating pressure (PE) during this stage, which can be slightly higher than the native reservoir pressure and can be between 500 kPag and 1000 kPag. For example, the operating pressure PE can be 100-300 kPa above the reservoir pressure, or 150-250 kPa above the reservoir pressure, and the pressure difference can be determined by various factors such as the initial water mobility of the reservoir and / or the presence of thief zones. For example, in high mobility reservoirs, the operating pressure can be kept quite close to the reservoir pressure, e.g., within 50 or 100 kPa. The extraction operating pressure (PE) can vary during the production stage depending on various factors, but it would likely be kept within a certain operating window.

[56] Fig 2b illustrates the process during the blowdown stage where the injection rate of the mobilizing fluid is reduced, and the pressure of the chamber decreases to a blowdown pressure (PBD). The blowdown pressure (PBD) can be between 150 kPag and 250 kPag lower than the operating pressure of the production stage, and can be reached by gradually decreasing the injection rate of the solvent although one or more step changes is also possible. In some implementations, the PBD is as low as possible to keep pumping via the production wells. The blowdown stage can also be relatively short compared to the other stages.

[57] A relatively simple blowdown strategy is to reduce the injection rate of the mobilizing fluid. However, more complex blowdown strategies can be performed where the overall vapour injection rate is reduced while some of the mobilizing fluid is also replaced with another vapour, such as a non-condensable gas (NCG). For example, methane or another NCG could replace some of the mobilizing fluid while the overall injection rate via the injection well is reduced, thereby decreasing the pressure in the chamber and decreasing the quantity of mobilizing fluid that is injected. In addition, it is possible to conduct the same or similar injection rate reductions for all of the injection wells of the well pair array, or modify the injection rates in respective wells in different ways. For example, the injection rate in one injection well could remain the same while the injection rate in another well is throttled back, such that the overall injection rate and chamber pressure decreases. It is also noted that the blowdown strategy could be performed to facilitate production of liquid phase fluid or vapour phase fluid. When liquid production is targeted, NCG injection can be avoided or limited and the production wells can be operated at subcooled conditions. When vapour phase production is performed, NCG and / or combustion gases can be injected to promote vaporizing the solvent to facilitate production in vapour phase. Ideally, the blowdown is operated to avoid a multiphase gas- liquid production fluid, which causes difficulties in terms of separation and fluid handling. Thus, depending on the solvent recovery strategy, the blowdown stage can be operated in different ways.

[58] Fig 2c illustrates the initiation of the in situ combustion stage by injecting the oxygen containing gas 33 into the chamber 30 which is at the blowdown pressure (<semantics>PBD<annotation encoding="application / x-tex">P_{BD}< / annotation>< / semantics>). It should be noted that the ignition after blowdown could be aided by preheating, e.g., using an ERH 22 as described above.

[59] Fig 2d illustrates the in situ combustion stage with continued injection of the oxygen containing gas as the combustion front moves toward the adjacent well pair and the late-life recovery well received and produces hydrocarbons and residual mobilizing fluid.

[60] Since the chamber is at a lower pressure compared to the production stage pressure, the injection of the oxygen containing gas can be facilitated. In addition, as the combustion process drives hydrocarbons toward the late-life production well, the lower pressures can facilitate combustion front development and recovery of hydrocarbons from the late-life production well given the greater pressure difference between the combustion region and the adjacent region of the chamber. Nevertheless, lower pressure can also lead to lower production rates, and therefore the pressure can be provided to provide a desired balance between production rates and in situ combustion performance.

[61] Turning now to Fig 3, the process can include a winddown stage after the production stage and before the in situ combustion stage. In the winddown stage, the injection rate of the mobilizing fluid via the injection well is reduced, while a winddown vapour is also injected into the vapour chamber to generally maintain an operating pressure of the vapour chamber. The extraction pressure (PE) during the production stage can thus be similar to the winddown pressure (PWD) achieved during winddown. Thus, the mobilizing fluid is replaced by one or more winddown fluids in the chamber. The winddown vapour can be methane or another non-condensable gas, for example, but it is noted that the selection of the vapour and the operation of winddown can be tailored for the given process.

[62] This type of winddown stage can be beneficial when there is a proximal region of the reservoir or formation that has high pressure fluid that is or could be in fluid communication with the chamber. By maintaining the pressure in the chamber, infiltration of fluids from proximal reservoir regions can be avoided or prevented. For instance, in large commercial operations, there may be multiple well pair arrays in relatively close proximity which are operating at different stages, such that one well pair array may be near the end of its economic life in terms of the production stage while a close-by well pair array may just be beginning its production stage. In such a situation, if the more mature well pair array were to be transitioned to blowdown with reduced pressure, there could be a risk that the chambers of the younger well pair array could leak mobilizing fluid into the older chambers, which could result in notable loss of valuable fluids and reduced performance by the younger well pair array. Thus, a winddown stage in the older array can prevent leaks from proximate operations.

[63] In some implementations, the winddown stage includes gradually decreasing the injection rate of the solvent and gradually increasing the injection rate of the winddown vapour. The operating pressure cab be maintained within 5% of the production stage pressure during the winddown stage, for example, or high enough to prevent leaking from an adjacent recovery operation and thus could depend on the operating pressure of that recovery operation.

[64] It should be noted that the winddown stage could be performed until the adjacent recovery operation reaches a mature stage and is ready to transition to another stage. At that point, both well pair arrays could be transitioned together to perform a blowdown stage followed by in situ combustion, or directly to in situ combustion without a preliminary blowdown stage. In one example, there is a first mature well pair array that is operated in winddown while a proximate well pair array is operated for production. In another example, when well pairs are brought online progressively, the more mature well pair or array could be operated using winddown while the newer well pair is operated in its production stage. It is also noted that the winddown stage could be performed when there is no adjacent pressurized region or recovery operation.

[65] Since winddown replaces the mobilizing fluid with another fluid in the chamber, it may result in different system dynamics within the reservoir for combustion. Nevertheless, when the winddown vapour is a non-condensable gas it can rise and accumulate in the upper region of the chamber, such that the lower region of the chamber is still relatively similar in terms of its composition compared to the production stage. For example, when a solvent is used as the mobilizing fluid, the near wellbore region of the injection well may still have a high solvent content and a relatively low non-condensable gas (NCG) content. This means that ignition at that near wellbore region will have similar properties to a scenario with no winddown. As the combustion progresses across the chamber, it may encounter a high NCG content region where the combustion dynamics change.

[66] When considering solvent recovery strategies after the production stage, various factors can be considered. In greenfield operations where a well pair array is not surrounded by other recovery operations, straight blowdown after may be performed for solvent recovery, followed by the in situ combustion stage. However, pressure maintenance in certain more mature chambers can become more relevant in commercial settings, and therefore a preliminary winddown stage can be performed in more developed fields that include multiple well pair arrays operating at various stages of maturity. Another method to promote solvent recovery involves reducing solvent injection while increasing the downhole heating, which maintains or increases the chamber pressure and can promote continued production of solvent to the surface. The heating can be performed using the ERH present in the injection wells, or by other downhole heating devices. In situ combustion provides another complementary method for solvent recovery in late-life operations, particularly when heavy fractions are used as fuel to generate combustion gases which drive residual solvent as well as bitumen and combustion products toward the late-life recovery well.

[67] The in situ combustion stage can be monitored in order to control certain operating conditions of the process. For example, one or more of the wells can be equipped with instrumentation, such as temperature sensors, to monitor the temperature downhole and assess whether the preheating temperature has reached the ignition temperature, whether high temperature combustion is occurring, and so on. Compositional features of production fluids are also relevant to monitor, e.g., to determine gas composition to assess oxygen content for safety purposes as well as process performance via CO2 / CO, H / C, oxygen utilization. For example, certain key performance indicators can be monitored to assess combustion performances, e.g., higher CO2 / CO ratio indicates better combustion, oxygen levels can indicate that combustion is not consuming all of the oxygen or there is a short-circuit. The compositional properties of the production fluid can be monitored by sampling at surface or using online devices, e.g., using gas chromatography or near infrared methods.

[68] Referring to Fig 4, it is noted that the oxygen injection well 34 can be selected from a middle well pair that two adjacent well pairs on either side. In this scenario, the combustion front can have two sides that progress in respective directions toward two late-life recovery wells of the adjacent well pairs.

[69] Referring to Fig 5, it is noted that the well pair array can also include an infill well 40 provided in between two adjacent well pairs 12. The infill well can be used as the oxygen injection well or as a late-life recovery well as illustrated. A step-out well can also be part of the well pair array.

[70] Regarding infill wells, it is also noted that an infill well can be provided and operated in the bypassed region depending on various factors of the overall recovery process. For example, since solvent processes can be operated at relatively low temperatures, the bypassed region can be relatively cold near the end of the solvent- based process such that operating an infill production well would not be desirable. In such a case, the in situ combustion stage can be conducted without infills. However, since combustion can generate significant heat in the reservoir, the bypassed region can be notably heated during the in situ combustion stage, such that its hydrocarbons may be mobilized to facilitate production via an infill well. Thus, an infill well could be drilled at any stage of the process (e.g., before in situ combustion, after or during) and the infill well can be operated on production mode to recover hydrocarbons heated by the combustion process. The infill well could also be operated at times for injection of solvent or another mobilizing fluid to mobilize the near wellbore region and promote fluid communication with the hotter mobilized zones of the bypassed region.

[71] Turning now to Fig 7, the well pair array 10 can include multiple well pairs 12 with a large coalesced chamber 30 and the combustion front can progress past a first late- life recovery well 38a an on to a second late-life recovery well 38b at a further well pair 12. In this manner the late-life recovery wells can be operated sequentially and turned off once the combustion front reaches and passes by. An analogous operating strategy can be used for the oxygen injection wells. For example, a primary oxygen injection well 34a can be initially used, and once the combustion front expands to a certain degree (e.g., past a well in an adjacent well pair) then a secondary oxygen injection well 34b can be operated alone or in combination with the primary oxygen injection well 34a.

[72] The heat recovery methods used in conjunction with the in situ combustion can take various forms. For example, a heat transfer fluid, such as water, can be supplied down one or more of the wells where it is stored and allowed to increase in temperature due to the heat released by combustion. The heat transfer fluid can be fed down one, some or all of the wells not used as the oxygen injection well or the late-life recovery well. The heat transfer fluid can be fed down the well to remain static as it heats up (e.g., with the well being shut in), or the fluid can be circulated within the well. If the well has a closed- loop circulation system, the heat transfer fluid can be circulated therein for continuous heat recovery.

[73] In terms of timing, the heat transfer fluid can be supplied down the well prior to the combustion stage, during the combustion stage, or after the combustion stage has completed. The heated fluid can be pumped back up to so surface after a predetermined amount of heating time, or when the fluid reaches a measured temperature that is detected by downhole sensors. The heat transfer fluid can be supplied into the well and retrieved from the well in liquid phase, or can be supplied as a liquid and retrieved as a vapour- liquid mixture or as a vapour, depending on the temperature and phase transition properties of the heat transfer fluid. The heat transfer fluid can be water (e.g., process water), diluent, or various other fluids that may be available at surface. In addition, the heat transfer fluid can be selected based on storage capacity at surface, such that the wells are used not only as heat transfer equipment but also as storage equipment. The heated fluid can be produced from the well and then subjected to indirect heat transfer or direct use as a heated fluid at surface. If the fluid indirectly transfers heat to another fluid at surface, the resulting cooled heat transfer fluid can be reintroduced down the same or another well for heat recovery. When introduced into the well, the heat transfer fluid can be allowed to be in contact with the wellbore, and thus the reservoir, or it can remain within an isolated conduit depending on the completion of the well. The heat recovery well can be an injection well or a production well of the well pair, an infill well, or a step-out well that was part of the in situ recovery operation; or could be a new dedicated well that is drilled in to the chamber and can have various lengths, depths, diameters, orientations and completions.

[74] The in situ combustion reservoir can be used for late life energy heat recapture and / or for fluid storage purposes. Fig 8 provides an illustration of the various fluid transfer possibilities between different operations, including LLRs illustrated as the central bubble. For example, late life wells can be used for permanent storage for wastewater; circulation of water (wastewater or fresh water) to capture heat from the reservoir; permanent storage of brine or non-consolidating fines, ions, and / or salts; tailings storage; temporary diluted bitumen (also called dilbit) storage; temporary water storage; and so on. The storage and heat recovery can be performed as part of an integrated strategy utilizing late life reservoirs (LLRs) in parallel or series. The LLRs can be at various stages and can have used various recovery processes (e.g., SAGD, solvent dominated, in situ combustion, other hybrid processes like ES-SAGD or cyclic or alternating processes, and combinations thereof). For instance, the selection and implementation of each heat recovery or fluid storage process can be timed appropriately based on various factors, such as in situ operations, mine operations, external markets, and electrical grids. The selection and timing of implementing these techniques can be based on the maturity and temperature of the LLRs. For example, earlier on in the LLRs, a well can be used for geothermal heat capture, and when the reservoir temperature declines the well could then be used for disposal of tailings or brine.

[75] Thus, it is possible to utilise one or more wells before, after and / or during the in situ combustion stage as described herein, to store materials and / or recover heat in various ways. For instance, one or more wells can be used for temporarily storing water or hydrocarbons within the LLR; injecting wastewater, brine and / or tailings or other waste materials into the LLR; recovering heat from the LLR, particularly if the measured temperature is above a certain threshold, and optionally by circulating water or another heat transfer fluid through the well and / or through the LLR; storing waste in the LLR; and / or storing water in the LLR. During the in situ combustion stage, certain wells may be available at different times for fluid injection or circulation in order to enable the storage and / or heat recovery. The timing and well selection can be based on the temperature in different regions of the reservoir that have undergone or are undergoing in situ combustion, particularly for heat recovery applications given the high temperature of combustion.

[76] Certain examples of heat recovery and fluid storage methods are briefly described below. In one example, the method includes temporarily storing water or hydrocarbons in the LLR, and injecting wastewater, brine and / or tailings into the LLR. Another example method for utilizing an LLR, includes measuring LLR temperature; if the LLR is above a pre-determined temperature, recovering heat from the LLR until the LLR falls to the pre-determined temperature; storing hydrocarbons or water in the LLR; producing at least some of the hydrocarbons or water from the LLR; and storing waste in the LLR. Another example method can be used for temporarily storing water in an LLR, and includes injecting the water into the LLR; storing the water in the LLR for a desired time period; during storage, drawing out water from water production wells surrounding the water injection well; and injecting gas through gas injection wells surrounding the water production wells to reduce water migration. It is also noted that at least a portion of the water can be produced and then used in various other hydrocarbon recovery or extraction operations.

[77] In some implementations, the reservoir is an oil sands reservoir with relatively high permeability, particularly in the chamber, and little to no thief zones that would result in loss of mobilizing fluid, air and combustion products.

[78] In some implementations, only air or enriched air is injected to initiate the combustion. However, is it also possible to inject an ignition aid prior to injecting the air. The ignition aid could be a highly ignitable compound, such as linseed oil. The ignition aid could be in the form of a liquid or solid particles deployed via a carrier fluid.

[79] It is also noted that when a hydrocarbon solvent is used as the mobilizing fluid, the transition from production or blowdown or winddown stage to the in situ combustion stage can be done judiciously to enhance safety. For example, all solvent affected conduits and vessels can be purged of solvent prior to oxygen delivery into the well. In another example, the solvent affected conduits and equipment can be flushed with a flushing fluid prior to delivery of the oxygen containing gas. When the oxygen containing gas will be injected down certain tubing strings or conduits, they can be flushed with a low flammability fluid prior to oxygen delivery. In addition, precautions can be taken to cool certain conduits or equipment (e.g., using time or active cooling with a cooling fluid) prior to oxygen delivery to avoid ignition risks. It can also be desirable to establish a hazard management system including process hazard assessment, controls and mitigation measures.

Claims

1. A process for recovering bitumen from a reservoir in which a well pair array is provided, the well pair array comprising multiple spaced-apart well pairs each comprising an injection well overlying a production well, the process comprising: a production stage, comprising: injecting a deasphalting solvent in vapour phase via the injection well into the reservoir to dissolve and mobilize bitumen which drains by gravity toward the production well, and forming a vapour chamber above the injection well and comprising precipitated asphaltenes and residual deasphalting solvent, and wherein the vapour chambers of respective adjacent well pairs coalesce to form a coalesced chamber above the adjacent well pairs; and producing a production fluid comprising drained partially deasphalted bitumen and condensed deasphalting solvent via the production well; and an in situ combustion stage, comprising: injecting an oxygen containing gas into the coalesced chamber and providing conditions to cause in situ combustion that is fueled by hydrocarbons including the precipitated asphaltenes, thereby forming a combustion front that drives a portion of the residual deasphalting solvent and residual bitumen through the coalesced chamber toward at least one late-life recovery well of the well pair array; and producing a late-life production fluid comprising bitumen and residual deasphalting solvent from the reservoir via the late-life recovery well.

2. The process of claim 1, wherein the deasphalting solvent comprises a paraffinic solvent.

3. The process of claim 2, wherein the paraffinic solvent comprises propane.

4. The process of claim 2 or 3, wherein the paraffinic solvent comprises butane.

5. The process of any one of claims 2 to 4, wherein the paraffinic solvent comprises pentane.

6. The process of any one of claims 1 to 5, wherein the oxygen containing gas is injected via at least one well of the well pair array designated as an oxygen injection well.

7. The process of claim 6, wherein one of the injection wells during the production stage is converted to the oxygen injection well.

8. The process of any one of claims 1 to 7, wherein the late-life recovery well is a well of the well pair array.

9. The process of claim 8, wherein one of the production wells during the production stage is converted to the late-life recovery well.

10. The process of any one of claims 1 to 9, wherein, in the production stage, the deasphalting solvent is injected at superheated conditions.

11. The process of claim 10, wherein the deasphalting solvent is preheated at surface to the superheated conditions.

12. The process of claim 10, wherein the deasphalting solvent is heated downhole within the injection well to the superheated conditions prior to injection into the reservoir.

13. The process of any one of claims 1 to 12, wherein, in the production stage, the deasphalting solvent is injected in the absence of steam or water.

14. The process of any one of claims 1 to 13, wherein the injection of the deasphalting solvent is ceased in all wells prior to injecting the oxygen containing gas.

15. The process of claim 14, further comprising detecting the formation of the coalesced chamber based on equalizing pressures of the vapour chambers and / or four- dimensional seismic measurements.

16. The process of any one of claims 1 to 15, wherein the well pair array comprises at least three side-by-side well pairs, and the coalesced chamber is formed from at least three respective vapour chambers.

17. The process of claim 16, wherein the oxygen injection well is the injection well of a corresponding well pair having an adjacent well pair on either side.

18. The process of claim 17, wherein the at least one late-life recovery well comprises a first late-life recovery well that is part of an adjacent well pair on one side of the oxygen injection well and a second late-life recovery well that is part of another adjacent well pair on the other side of the oxygen injection well.

19. The process of any one of claims 1 to 18, wherein the production stage is performed such that between 20 vol% and 50 vol%, or between 25 vol% and 40 vol%, of the bitumen in the reservoir is left within the vapour chambers as a heavy fraction that comprises the precipitated asphaltenes.

20. The process of any one of claims 1 to 18, wherein the production stage is performed such that between 25 vol% and 35 vol%, of the bitumen in the reservoir is left within the vapour chambers as a heavy fraction that comprises the precipitated asphaltenes.

21. The process of any one of claims 1 to 20, wherein the production stage is performed such that the vapour chambers are at an operating pressure close to the native reservoir pressure.

22. The process of claim 21, wherein the operating pressure is between 300 and 2000 kPag.

23. The process of claim 21, wherein the operating pressure is between 500 and 1200 kPag.

24. The process of any one of claims 1 to 23, wherein the production stage is performed such that the vapour chambers are at an operating temperature between 40°C and 80°C.

25. The process of claim 24, wherein the deasphalting solvent is butane.

26. The process of any one of claims 1 to 25, wherein the production stage is performed such that the injection wells are operated at a wellbore temperature above 250°C.

27. The process of any one of claims 1 to 25, wherein the in situ combustion stage comprises: providing a local ignition temperature above 200°C to cause ignition; and injecting the oxygen containing gas to maintain the combustion at a combustion temperature between 400°C and 800°C within the coalesced chamber.

28. The process of claim 27, wherein the local ignition temperature is provided above 200°C and below 350°C.

29. The process of claim 27 or 28, wherein the local ignition temperature is provided by an electric resistance heater, and after ignition the electric resistance heater is turned off.

30. The process of any one of claim 27 or 28, wherein the local ignition temperature is provided by a closed-loop circulation system, and after ignition fluid circulation through the closed-loop circulation system is ceased.

31. The process of any one of claims 27 to 30, further comprising increasing an injection rate of the oxygen containing gas over time as the combustion front expands, wherein the injection rate is increased in accordance with oxygen demand for maintaining high- temperature combustion.

32. The process of any one of claims 1 to 31, wherein the oxygen containing gas is air.

33. The process of any one of claims 1 to 32, further comprising: a startup stage for establishing fluid communication between the injection well and the production well of each well pair, the startup stage comprising: heating the reservoir surrounding the injection well and the production well; and introducing a non-deasphalting hydrocarbon solvent into the reservoir to dissolve and remove bitumen from around and between the injection well and the production well.

34. The process of any one of claims 1 to 33, wherein the chambers are coalesced along at least 5% of a length thereof before the combustion front reaches a coalescence region joining the chambers.

35. The process of any one of claims 1 to 34, wherein the solvent is introduced into the injection well in the vapour phase.

36. The process of any one of claims 1 to 34, wherein the solvent is introduced into the injection well in a liquid phase or in a mixed liquid-vapour phase, and is vaporized within the injection well prior to entering the reservoir in the vapour phase.