CA3111218A1

CA3111218A1 - Systems and methods for utilizing late life in situ reservoirs

Info

Publication number: CA3111218A1
Application number: CA3111218A
Authority: CA
Inventors: Ivan Beentjes; Lai Hang Cheung
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2020-03-05
Filing date: 2021-03-04
Publication date: 2021-09-05

Abstract

Strategies are provided for executing, in parallel and/or in series, methods of utilizing LLISRs.
An LLISR can be used to store water, hydrocarbons (e.g., dilbit), tailings and brine. Additionally, a heat sweeping or other working fluid of water and/or hydrocarbons and/or non-hydrocarbons and/or gas phases, with any range of additives in the solid, liquid or gas phases, can be circulated through an LLISR to recover heat remaining from thermal bitumen recovery processes. The order and selection of LLISR operations can be determined based on LLISR
maturity. The LLISR can also be used for temporary water or hydrocarbon storage, and subsequently used for disposal of wastewater, brine and/or tailings. An integrated strategy can in part include a method of storing water in an LLISR.

Description

SYSTEMS AND METHODS FOR UTILIZING LATE LIFE IN SITU RESERVOIRS
TECHNICAL FIELD
[0001] The following generally relates to the utilization of late life in situ reservoirs, for example to recover heat, and/or to temporarily store water or hydrocarbons, and/or to permanently store a waste product.
BACKGROUND

[0002] Oil sands are a natural mix of sand, clay, water, and bitumen.
Bitumen is considerably viscous and does not flow like conventional crude oil. As such, bitumen is recovered from oil sands using either surface mining techniques or in situ techniques. In surface mining, overburden is removed to access the underlying bitumen reservoir, and the oil sands are transported to an extraction facility to separate the bitumen from the other components of the oil sands (i.e. tailings). For in situ techniques, the bitumen reservoir is heated and the bitumen within flows into one or more horizontal production wells, leaving the formation rock in the bitumen reservoir in place. In such techniques, the bitumen in the bitumen reservoir is often emulsified to enhance recovery. Both surface mining and in situ processes produce a bitumen product that is subsequently sent to an upgrading and/or refining facility, to be refined into one or more petroleum products.

[0003] Bitumen reservoirs that are too deep to feasibly permit bitumen recovery by mining techniques are typically accessed by drilling wellbores into the bitumen reservoir and implementing an in situ technology. There are various in situ technologies available that use thermal methods to liberate bitumen from the reservoir with heated fluids, e.g., steam, hydrocarbon solvent vapour, or steam and solvent in combination. In many conventional thermal in situ techniques, the heated fluids can be injected into the reservoir. However, in newer techniques, e.g., electrically resistive heating, EM radio frequency, and induction, heated fluids can be generated from fluids present in the reservoir.

[0004] Common in situ techniques include Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS). In SAGD, a pair of horizontally oriented wells are drilled into the bitumen reservoir, such that the pair of horizontal wells are vertically aligned with respect to each other and separated by a relatively small distance, typically in the order of several meters.
The well installed closer to the surface and above the other well is generally referred to as an injection well, and the well positioned below the injection well is referred to as a production well.
The injection well and the production well are then connected to various subsurface equipment, CPST Doc: 338962.1 Date Recue/Date Received 2021-03-04 such as electric submersible pumps (ESPs) and sensors, and to equipment installed at a surface site. The injection well facilitates steam injection into the reservoir. The injected steam propagates vertically and laterally into the reservoir to develop what is referred to as a steam chamber. Latent heat released by the injected steam mobilizes the bitumen by lowering its viscosity. The bitumen, in turn, drains due to gravity and is produced, along with condensed water, by the production well. Typically, multiple well pairs are drilled substantially parallel to each other (e.g., from approximately 50 to greater than 120 m apart) to create what is referred to as a well pad.

[0005] In CSS, a single, vertical, production/injection well extending into a bitumen reservoir can be used for both steam injection and production. CSS typically involves three main phases, namely an injection phase, a shut in phase, and a production phase. During the injection phase, steam is injected through the production/injection well into the bitumen reservoir. Next, the bitumen reservoir is shut in to allow heat from the steam to reduce the viscosity of the bitumen in the reservoir. The bitumen of reduced viscosity can then be produced through the production/injection well, and the three-phase cycle can be repeated.

[0006] The production wells at in situ well pads tend to decline over time.
When approaching "late life", these wells may require pad maintenance, reservoir pressure maintenance, blow down, and eventual abandonment strategies for the wells and the surrounding reservoir. These strategies are often not fully understood or optimized.

[0007] It would be advantageous to provide a system and method for late stage reservoir usage.
SUMMARY

[0008] Provided herein are systems and methods for utilizing late life in situ reservoirs to recover heat, store fluids, recover hydrocarbons left behind, or permanently store waste, according to various strategies.

[0009] In one aspect, provided herein is a method of a method of controlling fluid migration from a first hydrocarbon reservoir, the method comprising: creating a first fluid migration barrier between the first hydrocarbon reservoir and a second hydrocarbon reservoir by injecting a plugging material into a surrounding formation via at least one well positioned in the first hydrocarbon reservoir.

[0010] In another aspect, there is provided a system for controlling fluid migration from a first hydrocarbon reservoir, the system comprising: a first fluid migration barrier between the first Date Recue/Date Received 2021-03-04 hydrocarbon reservoir and a second hydrocarbon reservoir created by injecting a plugging material into a surrounding formation via at least one well positioned in the first hydrocarbon reservoir.

[0011] In an implementation, the method can include placing a first packer at one end of the at least one well; and injecting the plugging material through at least one port in the first packer.
The one end of the at least one well can include a toe of the at least one well, the plugging material being injected through the toe of the at least one well into the surrounding formation.
The one end of the at least one well can also comprise a heel of the at least one well, the plugging material being injected through the heel of the at least one well between the first packer and an obstruction. The obstruction can include a leading packer placed ahead of the first packer positioned at the heel of the at least one well. The leading packer and the first packer can be connected.

[0012] In an implementation, the plugging material can be injected by tubing extending to the first packer in the at least one well.

[0013] In an implementation, the method can include creating a second fluid migration barrier between the first hydrocarbon reservoir and a third hydrocarbon reservoir by injecting the plugging material into a surrounding formation at a position spaced from first fluid migration barrier. In an implementation, the method can further include placing a second packer at another end of the at least one well; and injecting the plugging material through at least one port in the second packer. The other end of the at least one well can include a toe of the at least one well, the plugging material being injected through the toe of the at least one well into the surrounding formation. The other end of the at least one well can also include a heel of the at least one well, the plugging material being injected through the heel of the at least one well between the second packer and an obstruction. The obstruction can include a leading packer placed ahead of the second packer positioned at the heel of the at least one well. The leading packer and the second packer can be connected.

[0014] In an implementation, the plugging material can be injected by tubing extending to the second packer in the at least one well.

[0015] In an implementation the plugging material can be injected through a slotted liner, a perforated liner, or one or more openings in a liner of the at least one well.

[0016] In an implementation, the plugging material can comprise mature fine tailings (MFTs).

[0017] In an implementation, the plugging material can comprise mining tailings.

[0018] In an implementation, the plugging material can comprise a cement squeeze Date Recue/Date Received 2021-03-04 product.

[0019] In an implementation, gas wells can be positioned along at least one side of the first hydrocarbon reservoir to buffer the at least one well in the first hydrocarbon reservoir from at least one active reservoir adjacent the first hydrocarbon reservoir using the gas wells.

[0020] In an implementation, the first hydrocarbon reservoir can comprise a late life in situ reservoir (LLISR). The LLISR can be used for fluid storage. The LLISR can also be used for fluid disposal. The LLISR can also be used for heat recovery from the first hydrocarbon reservoir.

[0021] In yet another aspect, there is provided a method of controlling fluid migration into an actively producing hydrocarbon reservoir, the method comprising: injecting fluid into a first late life in situ reservoir (LLISR) that is adjacent to the actively producing reservoir, to a first level that is at or below a first threshold level; and injecting fluid into a second LLISR that is adjacent to the first LLISR, to a second level that is above the first threshold level and at or below an upper formation barrier in second LLISR, wherein the first LLISR is positioned between the actively producing reservoir and the second LLISR.

[0022] In yet another aspect, there is provided a system of controlling fluid migration into an actively producing hydrocarbon reservoir, the method comprising: a first late life in situ reservoir (LLISR) that is adjacent to the actively producing reservoir, comprising fluid injected to a first level that is at or below a first threshold level; and a second LLISR that is adjacent to the first LLISR, comprising fluid injected to a second level that is above the first threshold level and at or below an upper formation barrier in second LLISR, wherein the first LLISR is positioned between the actively producing reservoir and the second LLISR.

[0023] In an implementation, the method can further include injecting fluid into the first LLISR to a third level that is above the first threshold level, as the actively producing hydrocarbon reservoir transitions to being a third LLISR, wherein the third LLISR is adjacent to another actively producing hydrocarbon reservoir; and injecting fluid into the third LLISR to a fourth level that is at or below the first threshold level.

[0024] In an implementation, gas wells can be positioned along at least one side of the first LLISR to buffer at least one well in the first LLISR from the actively producing reservoir adjacent the first LLISR, using the gas wells. Gas wells positioned between the first LLISR and the second LLISR can be decommissioned as the second LLISR transitions from being an actively producing reservoir.

[0025] In an implementation, the first LLISR can receive overflow fluids from the second Date Recue/Date Received 2021-03-04 LLISR to act as a buffer against flooding into the actively producing reservoir.

[0026] In an implementation, the fluid can be injected into a plurality of well pairs in each of the first and second LLISRs, each well pair comprising an injection well and a production well positioned below the injection well.

[0027] In an implementation, the first LLISR can be used for heat recovery using the injected fluid.

[0028] In an implementation, the second LLISR can be used for heat recovery using the injected fluid. The fluid can comprise water.

[0029] In an implementation, at least one of the first and second LLISR has been subjected to a steam assisted gravity drainage (SAGD) process prior to injecting the water for heat recovery.

[0030] In an implementation, at least one of the first and second LLISR has been subjected to an expanding solvent SAGD (ES-SAGD) process prior to injecting the water for heat recovery.

[0031] In an implementation, at least one of the first and second LLISR has been subjected to a thermal solvent recovery process prior to injecting the water for heat recovery.

[0032] In an implementation, at least one of the first and second LLISR has been subjected to a cyclic steam stimulation (CSS) process prior to injecting the water for heat recovery.

[0033] In an implementation, at least one of the first and second LLISR has been subjected to a steam flood process prior to injecting the water for heat recovery.

[0034] In an implementation, at least one of the first and second LLISR has been subjected to an in situ combustion process prior to injecting the water for heat recovery.

[0035] In an implementation, at least one of the first and second LLISR has been subjected to an electromagnetically assisted solvent extraction (EASE) process prior to injecting the water for heat recovery.

[0036] In an implementation, at least one of the first and second LLISR has been subjected to an electrical heating process prior to injecting the water for heat recovery.

[0037] In an implementation, at least one of the first and second LLISR has been subjected to an electromagnetic spectrum heating process prior to injecting the water for heat recovery.

[0038] In an implementation, at least one of the first and second LLISR has been subjected to a radio frequency heating process prior to injecting the water for heat recovery.

[0039] In an implementation, at least one of the first and second LLISR has been subjected to a thermal solvent recovery process prior to injecting the water for heat recovery.

Date Recue/Date Received 2021-03-04

[0040] The above strategies for using late stage reservoirs can include making use of empty pore space and a heated formation to temporarily or permanently store fluids, extract heat for use in other applications, and reduce consumption of water, combustion gases, steam, etc.
BRIEF DESCRIPTION OF THE DRAWINGS

[0041] Embodiments will now be described with reference to the appended drawings wherein:

[0042] FIG. la is schematic diagram of an integrated strategy for using a late life in situ reservoir (LLISR) to extract benefits for mining or in situ operations, external markets, or an electrical grid.

[0043] FIG. lb is a schematic diagram illustrating a series of alternative phased strategies for using an LLISR.

[0044] FIG. lc, ld and le illustrate a vertical well configuration for heat recovery as an example of one of the phased strategies for using an LLISR.

[0045] FIG. 2 is a block diagram of a multi-phase process applied to an LLISR.

[0046] FIG. 3 is a flow chart illustrating a process for utilizing an LLISR
in which water is temporarily stored prior to permanently storing a waste product in the LLISR.

[0047] FIG. 4a illustrates a first stage of the process shown in FIG. 3.

[0048] FIG. 4b illustrates a second stage of the process shown in FIG. 3.

[0049] FIG. 5 is a flow chart illustrating a process for utilizing an LLISR
in which a heat recovery stage is applied prior to temporary water storage and permanent waste disposal stages.

[0050] FIG. 6a illustrates a first stage of the process shown in FIG. 5.

[0051] FIG. 6b illustrates a second stage of the process shown in FIG. 5.

[0052] FIG. 6c illustrates a third stage of the process shown in FIG. 5.

[0053] FIG. 7 is a flow chart illustrating a process for utilizing an LLISR
in which water migration is mitigated during a water storage stage by using gas injection wells.

[0054] FIG. 8a illustrates a first stage of the process shown in FIG. 7.

[0055] FIG. 8b illustrates a second stage of the process shown in FIG. 7.

Date Recue/Date Received 2021-03-04

[0056] FIG. 9a is a schematic diagram of a first configuration for implementing the process shown in FIG. 7.

[0057] FIG. 9b is a schematic diagram of an alternative to the first configuration for implementing the process shown in FIG. 7.

[0058] FIG. 10 is a schematic diagram of a second configuration for implementing the process shown in FIG. 7.

[0059] FIG. 11a is a schematic cross-sectional view of a portion of the configuration shown in FIGS. 9 and 10.

[0060] FIG. llb is a schematic cross-sectional view of the portion of the configuration shown in FIGS. 9 and 10 with a variation to the water mound.

[0061] FIGS. 11c and 11d are schematic cross-sectional views similar to FIG. 11b, with a solid, semisolid and/or liquid boundary to retain injected wastewater for energy recovery by injecting into either or both the injection and production wells.

[0062] FIG. 12 is a process flow diagram for a temporary or permanent water storage system using an LLISR.

[0063] FIG. 13 is a process flow diagram for a temporary hydrocarbon storage system using an LLISR.

[0064] FIG. 14 is a process flow diagram for a brine storage system using an LLISR.

[0065] FIG. 15 is a process flow diagram for a heat recovery system using an LLISR in a direct use to mine operations.

[0066] FIG. 16 is a process flow diagram for a heat recovery system using an LLISR in a direct use at an in situ operation.

[0067] FIG. 17 is a process flow diagram for a heat recovery system using an LLISR in an electricity production application.

[0068] FIG. 18 is a process flow diagram for storing mature fine tailings or fine froth tailings using an LLISR.

[0069] FIG. 19 is a process flow diagram for storing mature fine tailings or fine froth tailings using an LLISR in an alternative configuration.

Date Recue/Date Received 2021-03-04

[0070] FIG. 20 is a schematic cross-sectional view of an overburden formation heat recovery process.

[0071] FIGS. 21a to 21f illustrate heating of, and recovery of heat from, an underburden of an LLISR.

[0072] FIG. 22a is a schematic diagram illustrating a water migration barrier between adjacent well pads in series, with the boundary created at the toes of the wells in an LLISR.

[0073] FIG. 22b is a schematic diagram illustrating a water migration barrier between adjacent well pads in series, with the boundary created at the heels of the wells in an LLISR.

[0074] FIG. 22c is a schematic diagram illustrating water migration barriers between adjacent well pads in series, with the boundaries created at both the toes and the heels of the wells in an LLISR.

[0075] FIG. 23a is a schematic cross-sectional view of a heel of a well in which a water migration barrier has been established.

[0076] FIG. 23b is a schematic cross-sectional view of a toe of a well in which a water migration barrier has been established.

[0077] FIGS. 24a to 24d are schematic diagrams illustrating a water injection strategy for providing a buffer reservoir between actively producing reservoirs and high water LLISRs.

[0078] FIG. 25 is a side-by-side graphical model showing water migration adjacent an actively producing reservoir.
DETAILED DESCRIPTION

[0079] The following provides an integrated strategy for executing, in parallel and/or in series, methods of utilizing LLISRs. In an implementation, an LLISR can be used to store water, hydrocarbons (e.g., dilbit), tailings and brine. Additionally, a heat sweeping or other working fluid of water and/or hydrocarbons and/or non-hydrocarbons and/or gas phases, with any range of additives in the solid, liquid or gas phases, can be circulated through an LLISR to recover heat remaining from thermal bitumen recovery processes. Such heat can be used in, e.g., power generation, oil sands mining, and in situ recovery operations.

[0080] In an implementation, the order and selection of LLISR operations can be determined based on LLISR maturity. For example, a recently shut in (or immature) LLISR can be considerably hot and thus can be suitable for a heat recovery operation after injecting a Date Recue/Date Received 2021-03-04 working fluid to capture heat from the LLISR. The LLISR can also be used for temporary water or hydrocarbon storage, and subsequently used for disposal of wastewater, brine and/or tailings.

[0081] In another implementation, the integrated strategy can in part include a method of storing water in an LLISR. For example, water generated from various hydrocarbon recovery operations can be stored while water is in abundance, such that the water can be saved for when such operations are "water short". The LLISR usage strategy can also be implemented in depleted reservoirs around, near, or adjacent active hydrocarbon producing reservoirs. In such scenarios, water migration from the LLISR towards the active reservoir can be mitigated by surrounding the well through which water is injected into the LLISR, with a number of water production wells and gas injection wells surrounding the water production wells. In this way, the water producers can draw out water migrating away from the water injection well, and the water can be recycled back into the LLISR through the injection well. The gas injection wells on the perimeter of the LLISR can provide pressure control to limit such migration.

[0082] It will be understood that the term "LLISR" as used herein can mean any hydrocarbon bearing reservoir having a hydrocarbon depleted zone therein formed from a thermal recovery process. Accordingly, when it is stated that a fluid is stored in, injected into, drawn from, or produced from an LLISR, it will be understood that such fluid is stored in, injected into, drawn from, or produced from the hydrocarbon depleted pay zone (i.e., storage volume) in the LLISR.

[0083] Turning now to the figures, FIG. la schematically illustrates an example of an integrated strategy for utilizing an LLISR 12, in this example a late life SAGD reservoir. It can be appreciated that the LLISR 12 can include one or more wells configured to implement an in situ hydrocarbon recovery process. The one or more wells can be located at one or more well pads or other in situ "sites". It can also be appreciated that the LLISR 12 can be situated adjacent, between or otherwise relative to one or more active in situ sites, such as wells positioned in pay regions that are at an earlier stage. For example, the LLISR
12 can be positioned adjacent sites actively injecting steam, solvent, or steam plus solvent, and/or producing a hydrocarbon from the site(s). The LLISR 12 can have been subjected to various advanced in situ hydrocarbon recovery processes prior to being used as herein described.
These hydrocarbon recovery processes can include, without limitation, SAGD, CSS, expanding solvent SAGD (ES-SAGD), steam flood, in situ combustion, electromagnetically assisted solvent extraction (EASE), thermal solvent recovery, electrical, electromagnetic, radio frequency, etc.

Date Recue/Date Received 2021-03-04

[0084] The LLISR 12 can be utilized for temporary storage of a substance, material or "product" 14; and/or circulation of same for heat recovery or additional hydrocarbon recovery;
and/or permanent storage and closure of the well(s) associated with the LLISR
12. The LLISR
12 therefore can be characterized by having pore space left behind from prior hydrocarbon recovery and can have some energy such as heat remaining that can be extracted from the LLISR 12 and/or surrounding formation. FIG. la illustrates several example products 14 that can be circulated through, or temporarily or permanently stored in the LLISR
12, including without limitation, water (including wastewater), hydrocarbons, tailings, and brine. FIG. 1 also illustrates that other products 14 can be recovered from the LLISR 12 and/or surrounding formation, including without limitation, geothermal power and geothermal heat introduced by an earlier process such as hydrocarbon recovery.

[0085] The strategy illustrated in FIG. la can include one or more operations or applications that either provide or receive one or more of the products 14. In this example, mine operations 16, in situ operations 18 (e.g., active in situ sites), external markets 22, and an electrical grid 24 are shown. Each of these operations or applications can use or provide products 14 that utilize and leverage the pore space and/or remaining energy left behind in the LLISR
12.

[0086] FIG. lb illustrates numerous possible strategies for utilizing an LLISR 12 in phases.
In this example, Phase 1 can include water injection (e.g., for mining or in situ disposal), followed by a subsequent phase. For example, a Phase 2 can include heat recovery and, optionally, a Phase 3 with brine or mature fine tailings (M FT) disposal as a permanent closure operation. It can be appreciated that such disposal could also or instead include drilling mud, treated or partially treated dewatered tailings, e.g., the disposal of PASS
slurry or dewatered M FT from a centrifuge. In one example, this can include dewatering, e.g., 30%
M FT to 50-70%
solids before injection. The Phase 3 can also include further water injection, e.g., for mining or in situ disposal operations as discussed in greater detail below. FIG. lb also illustrates that Phase 3 can also be implemented after Phase 1, e.g., by executing a permanent closure operation such as brine, drilling mud, MFT (or other waste) storage in the LLISR 12. In one implementation, this can include the disposal of a brine concentrate from a tailings water treatment process to avoid the cost associated with creating a solid waste.

[0087] FIGS. lc, 1 d and le illustrate an example of a phased strategy in which vertical wells are used for a heat recovery operation. In this example a vertical injection well 60 and a vertical production well 62 are drilled through the overburden and caprock into an LLISR 12 as shown in FIG. lc. Typically, the reservoir would be warm and gas filled due to it being a late-life reservoir.

Date Recue/Date Received 2021-03-04 In a first phase, the LLISR 12 can be filled with waste water as shown in FIG.
1d. In a second phase, shown in FIG. le, the waste water that has been added to the LLISR 12 has been heated by the warm reservoir and can be produced and cycled using the vertical wells 60, 62 to recover energy. This recovered energy can be used for various purposes as discussed below. It can be appreciated that the example configuration shown in FIGS. 1c-le can be applied to any of the configurations and staged strategies discussed herein. Similarly, horizontal wells or closed loop wells (either vertical, L-shaped or U-shaped closed loops) may be used in any of the configurations and strategies discussed herein.

[0088] FIG. 2 illustrates an example of an integrated multi-phase strategy for using an LLISR 12. In this example a first phase (Phase 1) includes a water flood process. The water flood process includes filling the LLISR 12 with a water source 30 to achieve additional hydrocarbon recovery 32 when producing the water back from the LLISR 12. Phase 1 is typically under 2 years for a single well pair. A wider range of water sources can be used, including once through steam generator (OTSG) blowdown and/or produced water as the water source 30. The objective of the water flood process is to increase the hydrocarbon recovery factor from depleted well(s) associated with the LLISR 12.

[0089] A second phase (Phase 2) includes a heat recovery process. The heat recovery process in this example includes circulating water (e.g., the water source 30) through the LLISR
12 to recover heat from the LLISR 12. As noted above, it can be appreciated that for heat recovery phase, any heat sweeping or other working fluid of water and/or hydrocarbons and/or non-hydrocarbons and/or gas phases, with any range of additives in the solid, liquid or gas phases can be used. A heat exchanger 34 can be used to recover geothermal heat from the circulated water (that has been heated by the LLISR 12) for use in an application 36 such as to pre-heat boiler water. More than one application 36 can benefit from the extracted geothermal heat, by cascading the heated water from higher to lower temperature applications, such as electricity production, heat trace applications, and/or direct use at low temperatures. The extracted geothermal heat can also, or instead, be used directly by an application 38. For example, the heated water can be used for a mineable bitumen recovery process instead of using natural gas- or coke-fired steam boilers. In this implementation, pipelines to and from in situ facilities and primary extraction plants can be provided. Phase 2 can last for a relatively longer time than Phase 1, for example, approximately 5-20 years.

[0090] A third phase (Phase 3) in this example includes a permanent fill process. The permanent fill process includes obtaining or receiving a waste product 40 from a disposal Date Recue/Date Received 2021-03-04 source, which is injected into the LLISR 12 for permanent disposal or closure of the well(s) associated with the LLISR 12. The permanent fill process can last approximately 2-3 years and can involve the injection of various waste products 40 such as high chloride brine streams, or fluids containing small clay and/or sand particles, e.g., M FT (raw and/or treated), froth treatment tailings (FTT) (raw and/or treated) from a mining or in situ site, or drilling waste.

[0091] As illustrated in FIG. 2, the strategy can include moving from a current LLISR 12 (LLISRN) to a next LLISR 12 (LLISRN,i).

[0092] The phases shown in FIG. 2 are illustrative and certain ones of these phases can be implemented alone or in combination and incorporate desired applications as depicted in the integrated strategy shown in FIG. 1. FIG. 3 is a flow chart for implementing a storage and disposal process using an LLISR 12. In this example, water, hydrocarbons, or multi-component emulsions including hydrocarbons are injected or otherwise fed into the LLISR
12 at step 50 and kept in the LLISR 12 for a period of time. This can be done to store water generated from a process that can be utilized later rather than disposed of, or to store a hydrocarbon such as diluted bitumen (dilbit) to take advantage of potentially large storage volumes to mitigate lost profits incurred by production curtailments, seasonal hydrocarbon price fluctuations and storage limitations in general. The period of time can therefore vary based on various environmental, production, or market factors, and when the period of time has lapsed, the water or hydrocarbons can be produced from the LLISR 12. Producing the water or hydrocarbons can be implemented using any applicable production techniques, such as artificial lift (e.g., pumps), using a production well or any well positioned in the LLISR 12 in fluid communication with the stored volume of water or hydrocarbons. After the water or hydrocarbons have been removed from the LLISR 12, a waste product 40 can be injected into the LLISR 12 for permanent storage at step 52. As discussed in greater detail below, the waste product 40 can include, for example, wastewater, brine, MFT, FTT, treated tailings, or drilling waste.

[0093] FIGS. 4a and 4b illustrate the steps in FIG. 3 schematically. In the example shown, the LLISR 12 includes at least one injection well 60 and at least one production well 62. The injection well 60 can be used in Stage 1 to inject the water or hydrocarbons into the LLISR 12 for temporary storage after which the water or hydrocarbons can be removed from storage using the production well 62. In Stage 2, the injection well 60 can be used to inject the waste product 40 for permanent storage. However, as shown in dashed lines, it can be appreciated that for Stage 2 both the injection well 60 and the production well 62 can be used to inject the waste product 40 for permanent storage.

Date Recue/Date Received 2021-03-04

[0094] FIG. 5 is a flow chart for implementing another strategy for using an LLISR 12 in this case wherein heat is first recovered from the LLISR 12 before using the LLISR
12 for temporary or permanent storage (or both as illustrated in FIG. 5). At step 72, heat is recovered from the LLISR 12, e.g., by circulating a fluid such as water through the LLISR 12 to have the LLISR 12 heat that fluid and thereby extract heat from the LLISR 12 and surrounding formation. As noted above, it can be appreciated that for heat recovery phase, any heat sweeping or other working fluid of water and/or hydrocarbons and/or non-hydrocarbons and/or gas phases, with any range of additives in the solid, liquid or gas phases can be used. The process of recovering heat from the LLISR 12 at step 72 can be performed until the temperature of the LLISR
12, measured at step 74, falls to a predetermined threshold temperature. The heat recovery stage (Stage 1) is illustrated in FIG. 6a in which a temperature measurement 90 is taken using a temperature measurement device 92 positioned in a the LLISR 12. A heat recovery fluid 94 such as water can be injected into the injection well 60 and produced via the production well 62 to generate a heated fluid 96.

[0095] The LLISR 12 can be used, in an example implementation, to store water or hydrocarbons at step 78 and the water or hydrocarbons produced from the LLISR
12 at step 80, e.g., as described above. The water or hydrocarbons are therefore temporarily stored in the LLISR 12 after the heat has been recovered and prior to permanent storage of a waste material at step 82. It can be appreciated that, as shown in FIG. 1 b, the stages exemplified herein can be implemented independently and in different combinations. For example, a temporary storage phase can be followed by a waste disposal stage without any heat recovery in other implementations. FIGS. 6b and 6c illustrate Stages 2 and 3 of the example process illustrated in FIG. 5.

[0096] An LLISR 12 that is available for further use according to a strategy outlined herein can be located between, adjacent or otherwise near an actively producing reservoir. When in proximity of such an actively producing reservoir, migration of stored fluids such as water, hydrocarbons or waste from the LLISR 12 can lead to fluid loss and/or contamination of the actively producing reservoir. FIG. 7 is a flow chart for implementing yet another strategy for using an LLISR 12 that mitigates such migration of stored fluids. Migration can be mitigated by surrounding an injection well 60 with a number of production wells 62, and a number of gas injection wells 63 (see also FIG. 8a) surrounding the production wells 62. At step 100, water can be injected into the LLISR 12 and the injected water stored in the LLISR
12 for a period of time at step 102. During storage of this water at step 102, at least some of the water that Date Recue/Date Received 2021-03-04 migrates towards the production well(s) 62 can be drawn out of the LLISR 12 by monitoring what fluid drains to the production well(s) 62 and cycling fluid using the production wells 62 at step 104. The water that is drawn out of the production well(s) 62 can be returned to the LLISR
12 via the injection well 60. At the same time or after determining that some migration has occurred (e.g., via presence in the production well(s) 62), a gas can be injected through gas injection wells 63 that surround the production wells 62 at step 106. The gas wells 63 provide a buffer between the injection/production wells 60, 62 and any adjacent or nearby actively producing reservoirs, further details of which are provided below. Optionally, as shown in dashed lines, at least a portion of the water stored in the LLISR 12 can be produced at step 108.

[0097] The gas injection wells 63 can also be used for short-, medium-, and long-term sequestration of a gas, such as 002. That is, the gas used to provide a buffer between an LLISR 12 and nearby active reservoirs can be one where a temporary or long-term storage is desired. For example, CO2 to be sequestered can first be used as the buffer gas described above and then subsequently left behind after the operations involving the LLISR 12 are complete. It can be appreciated that there can also be gas co-injected with an injected water stream and thus injecting gas into the LLISR 12 should not be limited to gas injection wells 63. It can also be appreciated that the gas left behind in the gas injection wells 63 can be pressurized to a maximum allowable pressure to avoid the liquid water from flashing into steam, considering that as reservoir temperature drops so can the pressurization of gas.
Similarly, the CO2 or other gas that is injected into the gas injection wells 63 can be produced back up to surface at a later time if the gas is needed in another process.

[0098] FIGS. 8a and 8b illustrate the stages associated with the process shown in FIG. 7.
As shown in FIG. 8a, water can be injected into the LLISR 12 via an injection well 60 that is surrounded by production wells 62 on either side thereof. The production wells 62 are positioned to enable water that migrates away from the injection well 60 to be drawn out of the LLISR 12 and potentially injected back into the LLISR 12 via the injection well 60 or used in an application. Gas wells 63 are positioned to surround the production wells 62 and can be injected with a pressure control fluid, i.e., fluids that are injected into subsurface formations for the purposes of, e.g., pressure control or controlling hydrocarbon movement within and/or between reservoirs. Pressure control fluids can be, for example, non-condensable gases (NCGs), e.g., N2, CO2, or methane or vaporized condensable gases (e.g., naphtha, pentane).

[0099] The pressure controlled fluid (gas being shown for illustrative purposes) is used to create a buffer, i.e. a "wall" or "fence" to prevent or at least mitigate the injection wells 60 and/or Date Recue/Date Received 2021-03-04 production wells 62 in the LLISR 12 from pulling in steam or other fluids from a nearby active reservoir. Stage 2 shown in FIG. 8b illustrates that during storage, the gas can be injected into the gas wells 63 and, if needed, water can be drawn out of the LLISR 12 via the production wells 62 that surround the injection well 60. As shown in dashed lines, the water drawn out of the production wells 62 can be reinjected to the LLISR 12 via the injection well 60.

[00100] FIG. 9a provides an aerial schematic view of an area comprising an LLISR 12 that is positioned between actively producing reservoirs 110. In this example, the actively producing reservoirs 110 include at least one active well 130 that injects steam into the reservoir 110. The LLISR 12 includes a number of wells or well pairs from one or more depleted well pads associated with the LLISR 12, which can be repurposed as water injection wells 60, water production wells 62 or gas injection wells 63. Referring to the legend in FIG.
9a, in this example, two injection wells 60 are positioned with production wells 62 on either side to enable water that migrates away from the injection wells 60 to be drawn out of the LLISR 12 during storage of the fluid. Surrounding the outer production wells 62 are perimeter gas injection wells 63 that provide the buffer between the LLISR 12 and the actively producing reservoirs 110. The perimeter gas injection wells 63 effectively create a gas fence or wall around the LLISR 12 by maintaining a higher pressure than the injection and production wells 60, 62 they contain, while being at a slightly lower pressure than the neighboring active wells 130. For example, if the LLISR 12 is operated at a pressure of 1495 kPa or lower, and the active wells 130 are operated at approximately 1500 kPa, the gas injection wells 63 can be operated at approximately 1495 kPa to mitigate any outward migration from the LLISR 12 while only allowing a relatively small amount of steam to trickle towards the gas injection wells 63. In the example shown in FIG. 9a the wells associated with the LLISR 12 are shown perpendicular to the active wells 130, however, it can be appreciated that such wells can also be positioned parallel thereto (or in any other relative orientation that was employed). Moreover, while active wells 130 are shown on two sides of the LLISR 12, other active wells 130 can exist adjacent or nearby the other sides.
FIG. 9b illustrates an alternative configuration in which the upper actively producing reservoir 110 includes a steam injection well 130 adjacent a gas injection well 63 that is adjacent a production well 62 that can be used to produce water driven out of the area by the gas injection well 63. As such, it can be appreciated that various perimeter well configurations can be implemented between an LLISR 12 and a nearby actively producing reservoir 110.

[00101] FIG. 10 is an aerial schematic view of an area comprising an LLISR
12 in yet another configuration. In this other configuration, the LLISR 12 is adjacent a cold reservoir 140, which Date Recue/Date Received 2021-03-04 may include a depleted or cold bitumen reservoir or another type of formation that does not include any actively producing reservoirs 110. In this example, multiple rows of injection and production wells 60, 62 are positioned between the cold reservoir 140 and an actively producing reservoir 110 in which steam is being injected. Similar to the configuration in FIG. 9, the LLISR
12 shown in FIG. 10 is buffered against the active reservoir 110 by positioning gas injection wells 63 in between. The bottom row in FIG. 10 includes an injection well 60 adjacent the cold reservoir 140 to illustrate that the wells to that side of the LLISR 12 can be configured in either order.

[00102] FIG. 11a provides a cross-sectional view of a set of wells 60, 62, 63, 64 in an LLISR
12. In the configuration shown in FIG. 11a, a series of adjacent well pairs 155 are repurposed for heat recapture, temporary storage and/or permanent storage in the LLISR
12. This configuration can be achieved using existing wells in an LLISR 12. However, it can be appreciated that the principles discussed herein can also be implemented using newly drilled wells. The well pairs 155 in this example can be existing SAGD well pairs 155 wherein the upper one of the well pair 155 was used as a steam injection well, and the lower one of the well pair 155 was used as a SAGD production well. For ease of illustration, the wells 60, 62, 63 are identified using different cross-hatching or fills according to a legend provided in FIG. 11a. It can be seen that in this example, five well pairs 155 are repurposed in the LLISR 12 to further utilize the pore space and potentially to extract heat in the surrounding formation. The central one of the well pairs 155 is configured to provide an injection well 60 in the upper well and the lower well of the well pair 155 is closed off to become an inactive well 64.
On each side of the central well pair 155, the lower ones of those well pairs 155 are used as production wells 62 and the upper ones of the well pairs 155 closed off as inactive wells 64. On each side of the central three well pairs 155 is a pair of gas injection wells 63. It can be appreciated that either one or the other of the outer well pairs 155 can be used as a gas injection well 63 rather than using both as illustrated.

[00103] FIG. lla illustrates water, hydrocarbons, or multi-component emulsions including hydrocarbons being injected from the centrally located injection well 60 and an example of a fluid mound 150 that can form below the injection well 60 and around the production wells 62.
The gas wells 63 are operated to mitigate migration of the injected fluid from the LLISR 12 and into adjacent formations, which can include cold or active reservoirs. As indicated above, when used for temporary storage, fluids can be drawn out of the LLISR 12 using the production wells 62 and the drawn-out fluids can be re-injected into the LLISR 12 through the injection well 60.

Date Recue/Date Received 2021-03-04 FIG. llb illustrates another example of a fluid mound 150 illustrating that the fluid being injected from the centrally located injection well 60 may descend more rapidly towards the production wells 62, e.g., where the formation is relatively more permeable when compared to the fluid mound 150 shown in FIG. 11a.

[00104] Turning now to FIG. 11c, the cross-sectional view of FIGS. ha and lib can be used to illustrate that a solid, semisolid and/or liquid boundary (shown using grey zones surrounding what may be referred to herein as boundary wells 165) can be used to retain injected wastewater for energy recovery, by injecting into either or both the injector and production wells 60, 62. It can be appreciated that these barriers can be on either or both sides of the well pad, or on either or both sides of the edge gas wells 63 (e.g., on both sides as shown in FIG. 11c).
The boundary wells 165 can also take the place of gas injection well(s) 63, and can enable liquid level build up by withdrawing the water before it seeps over into the next active well pad to increase the water in the heat recovery pad due to the reduced risk of seepage. The boundary wells 165 can be created using various mechanisms, such as cement squeeze, or using a material such as a non-Newtonian MFTs (or treated MFTs), a specific gravity (SG) > 1 material, a hydrophobic material, etc.

[00105] FIG. lid also uses the cross-sectional views of FIGS. lla and llb to illustrate an effect of using boundary mechanisms. In this example, it can be appreciated that the gas barrier provides an opposing pressure to steam. The entire LLISR 12 can effectively become a NCG-filled chamber wherein the NCG comes from the gas injection wells 63 at the boundary edge of the LLISR 12. In the example shown in FIG. 11d, the boundary wells 165 illustrated in FIG. 11c are also included. It can be appreciated that the water injection process illustrated in FIG. lid is gravity dominated, meaning that the liquid water tends to move to the bottom of the reservoir.
Since gas is orders of magnitude less dense than water, one would not assume that gas would displace water at the bottom of the reservoir. Gas injection is thus used to inhibit steam from migrating from an active well pad to the LLISR 12 and to maintain pressure in the reservoir to ensure that the hot liquid water does not, for example, flash to steam because of a drop in pressure. The production well(s) 62 can be used to limit the migration of injected liquid water over to the active well pad(s). That is, in the absence of a physical barrier (e.g., oil wedge, MFT
barrier, cement squeeze, etc.), the production well 62 would potentially be both the first and last line of defense. As such, the production well(s) 62 can be in substantially constant production for both heat recovery and to lower the water head at the edge of the LLISR
pad.

Date Recue/Date Received 2021-03-04

[00106] It can also be appreciated from FIG. 11d that the gas injection well(s) 62 can be positioned in various locations depending on the permeability of the LLISR 12.
For example, in an LLISR 12 with a relatively high permeability the gas injection well(s) 62 can be located anywhere in the LLISR 12 and not necessarily on the edges.

[00107] FIG. 12 illustrates further detail for an example for implementing a water circulation or storage strategy using an LLISR 12. Using SAGD as an example, a typical water cycle at a SAGD facility already uses the heat from the reservoir. The fluid produced from the SAGD wells can be transported to a central processing facility (CPF), where the water and bitumen can be cooled via heat exchangers using treated water, then separated. Alternatively, the water and bitumen can be separated to avoid heat exchanger fouling and then the heat recovered. The water is then treated and recycled with the addition of make-up water. This treated water passes through a heat exchanger with the original hot fluid, increasing the temperature, e.g., back up to 140-170 C. As fresh boiler feed water the heated water moves to a steam generation system, where it is heated back into steam. The water is then re-injected as steam into the SAGD well. When it comes to steam generation, OTSGs 213 produce a boiler blowdown waste stream of concentrated impurities. Injecting this blowdown into an LLISR 12 can provide at least two advantages. First, the amount of blowdown being turned into solid waste can be reduced, which would otherwise require landfill; or can reduce the load on the disposal wells currently used. Second, the volume of disposable OTSG blowdown can be increased, which can improve the quality of boiler feedwater by allowing the operation to flush out more of the impurities and organics. The increased removal of impurities can enable operations to improve steam quality to the well pads, which can drive down operating costs.
Additionally, organics removal is considered increasingly important due to fouling, which can damage downstream pipelines and drive up maintenance and chemical costs.
Improved water quality can thus help to avoid steam header issues of erosion, corrosion, and flow accelerated corrosion.

[00108] In the example shown in FIG. 12, a water source, such as produced water 202 or a disposal source 204 such as blowdown delivered using a pipeline 206 can be provided to a filtration stage 208 at the LLISR 12 well pad. It can be appreciated that process water blowdown can encompass water streams such as connate water, tailings treatment release water (i.e. from mine tailings processed using the advanced dewatering (ADVV) process), dyke seepage, or mine depressurization water, which can be categorized as total dissolved solids (TDS) of <4000 mg/L and TDS >4000 mg/L. The filtration stage 208 can be used to extract Date Recue/Date Received 2021-03-04 solids from the water source prior to injecting same into the LLISR 12 via the injection well 60.
Water that is drawn out, produced or circulated through the LLISR 12 via the production well 62 can be directed to a gas/emulsion separator 210 to obtain any produced gas from the emulsion.
The emulsion can be fed to a water/hydrocarbon separator stage 214 to separate the produced hydrocarbons from the produced water 202. Since the LLISR 12 may retain some heat, a heat recovery stage 212 can be used to extract heat from the produced water 202, e.g., to preheat boiler feed water before feeding the boiler feed water to an OTSG 213 or other steam generating unit to generate steam. The produced water 202 from the LLISR 12 can be fed back to the filtration stage 208 and re-injected into the LLISR 12 via the injection well 60. The injection/circulation of the water source can be used in a water flooding phase as shown in FIG.
2, in a temporary water storage phase, in a heat recovery phase, or in a permanent storage phase for wastewater. As such, while the produced water 202 from the LLISR 12 is shown as being re-injected, this produced water 202 can also be redirected to another application when desired. The produced hydrocarbon can be sent to a pipeline, transport channel or to storage.
It can be appreciated that the storage can include storage in an LLISR 12, as shown in FIG. 13.

[00109] Turning now to FIG. 13, the LLISR 12 in this example is equipped to permit the storage and recovery of a hydrocarbon such as diluted bitumen (dilbit) or other hydrocarbon emulsions or products such as emulsified bitumen, froth, or upgraded products.
Operational constraints such as curtailment or changes in seasonal demand can mean that produced hydrocarbons such as dilbit in some circumstances enter the market at less than ideal conditions. Temporarily storing dilbit in an LLISR 12 can enable producers to produce back and sell an increased volume of hydrocarbons once a curtailment ends or at another time when more profitable. In this way, interruptions to production can be mitigated. It may be noted that the increased mobility of hydrocarbons such as dilbit at lower temperatures as compared to bitumen enables the injected dilbit to be produced back when desired or required. Depending on the nature of the LLISR 12, considerations should be taken to eliminate contaminate of residual connate and/or ground water by applying a chloride treatment.
Moreover, pressure controls should be implemented since inadequate reservoir pressure controls could allow the dilbit to rise above its boiling point in a high temperature LLSR 12, allowing the naphtha to vaporize in situ, increasing the reservoir pressure while returning the dilbit to bitumen.
Furthermore, it is appreciated that dilbit is lighter than connate water so can be driven upwards in the reservoir and lost while only connate water is produced.

Date Recue/Date Received 2021-03-04

[00110] The hydrocarbon, such as dilbit, can be fed via a pipeline 206 to the well pad associated with the LLISR 12 and injected via the injection well 60. NCG can be added to the hydrocarbon at the point of injection. When the hydrocarbon is retrieved it is produced via the production well 62 and fed to a gas/emulsion separator 210 to separate produced gas from the emulsion. The emulsion can then be subjected to an optional heat recovery stage 212 (as illustrated in dashed lines) and a water/hydrocarbon separate stage 214 as discussed above.
The produced hydrocarbons can be fed to a pipeline or transport channel or storage. The produced fluids from the separator 214 can be fed into a water treatment stage 224 to extract skimmed oil and generate produced water 202 that can be used in any suitable application, including storage in an LLISR 12 as shown in FIG. 12.

[00111] The produced gas can be fed to a light end separator/condenser stage 220 to extract diluent, if present, for storage in a storage tank 222. The diluent from the storage tank 222 can be reclaimed and used elsewhere or fed back into the separated emulsion to be mixed with the hydrocarbons that are separated in stage 214.

[00112] FIG. 14 illustrates a disposal strategy for an LLISR 12 for the permanent disposal of brine, in which produced water 202 is fed to a desalinator 230 (or brine concentration system that utilizes natural or enhanced evaporation to create a concentrated saline solution), to separate clean water from a brine component. It may be noted that tailings could also be treated with desalination to produce a brine and enable the discharge of clean water.
The desalinator 230 (or brine concentration system) can be part of a water treatment facility that can be used to treat the water to ensure that the clean stream can be returned to the water source such as a river or other body of water. For example, brine process water is a component of in situ produced water blowdown and has been found to have a concentration of salt that is already too high to be returned to a water source such as a river. Disposing of concentrated brine into an LLISR 12 as shown in FIG. 14 can be an effective water quality strategy to control this problem associated with the relatively high concentration of salt in the blowdown.
Water treatment can be implemented since, with brine injection, there is a possibility of premature reservoir plugging due to the presence of particulates, precipitates and/or secondary reactions.

[00113] The brine component resulting from the water treatment desalinator 230 can be fed to a pipeline 206 via a pumping stage 232 and applied to a filtration stage 208 to extract solids prior to injecting the brine into the LLISR 12 for disposal. Fluids that are drawn out or otherwise returned via the production wells 62 can be processed to separate gas and hydrocarbons using Date Recue/Date Received 2021-03-04 stages 210, 214 as discussed above. The produced water 202 resulting from the separation stages 210, 214 can be returned to the LLISR 12.

[00114] FIG. 15 illustrates a strategy for extracting heat from an LLISR 12 and directly using the heated water in mining operations. It may be noted that the heated LLISR
water can be kept separate from the extraction fluid by using heat exchangers for the transfer of heat and the configuration shown is for illustrative purposes. In some estimates, a base mining plant can use as much as 160 gallons of 85 C water to process 1 ton of ore, which in turn produces 0.65 bbls of oil. A combination of heat recovery, coke and natural gas combustion can raise 61,000 US
gal/min (13,855 m3/hr) of water from ambient tailings pond temperature to 85 C. One way to provide 85 C water to a base plant is to pipe higher temperature LLISR water and dilute it with cooler tailings water. Assuming that current waste heat recovery at the base plant raises the tailings water to 50 C, and an average LLISR hot water temperature of 140 C, the base plant could operate for several years on several LLISR wells, while reducing 002, coke or natural gas consumption. Moreover, the LLISR hot water could be piped straight to the base plant and would not require filtration prior to being used in a mining process. Also, any entrained bitumen could be produced in the base plant extraction process.

[00115] In this example, water from a water pond 240 can be extracted by a pumping stage 232 and then fed to a pipeline 206 for transport to a filtration stage 208 at the well pad associated with the LLISR 12. The filtration stage 208 can be used to remove solids from the water source prior to being injected into the LLISR 12 via the injection well 60. The water produced via the production well 62 is heated by the LLISR 12 and fed to a gas/emulsion separator 210 to extract produced gas from a low bitumen emulsion. The low bitumen emulsion can be pumped via a second pumping stage 242 to second pipeline 244 that is coupled to a primary extraction stage 246 used in the mine operations. The primary extraction stage 246 in this example can add make-up water from the water pond 240 to cool the heated LLISR water.
Tailings water generated by the primary extraction process can be returned to the water pond 240. It can be appreciated that the first and second pipelines 206, 244 can be implemented using a two-way pipeline between the well pad associated with the LLISR 12 and the mine site.
It can be appreciated that since non-aqueous extraction (NAE) processes (e.g., using solvents) require heat and thus the water can be used to heat a future process fluid or solvent to prepare it for use in such an NAE or other process.

[00116] FIG. 16 illustrates a strategy for extracting heat from an LLISR 12 and directly using the heated water in an in situ operation, e.g., to replace natural gas consumption for steam Date Recue/Date Received 2021-03-04 production and/or for a heat trace operation. In this example, disposal make-up water 250 can be transported to the well pad associated with the LLISR 12 via a pipeline 206 and fed to a filtration stage 208 to extract solids prior to being injected into the LLISR
12 via the injection well 60. The filtered water that is injected into the LLISR 12 is heated by way of geothermal heating and when produced via the production well 62 can be used to offset natural gas combustion. In the example shown in FIG. 16, after being fed through a gas/emulsion separator 210 the heated water can be coupled to a heat exchanger 212 and glycol loop steam pre-heat stage 252 to recover heat. The pre-heat stage 252 can also be coupled to a glycol loop heat trace 254.

[00117] The emulsion from the separator 210 can be fed to a water/hydrocarbon separator 214 to separate produced water from the hydrocarbons in the emulsion, which can be fed to a pipeline, transport channel or storage.

[00118] FIG. 17 illustrates a strategy for extracting heat from an LLISR 12 and using the extracted heat to generate electricity that can be fed into an electrical grid. In this example, disposal make-up water can be transported to the well pad associated with the LLISR 12 via a pipeline 206 and fed to a filtration stage 208 to extract solids prior to being injected into the LLISR 12 via the injection well 60. The filtered water that is injected into the LLISR 12 is heated by way of geothermal heating and when produced via the production well 62 can be used to generate electricity. In the example shown in FIG. 17, after being fed through a gas/emulsion separator 210 the heated water can be coupled to a heat exchanger 212 and optional glycol loop steam pre-heat stage 252 (as shown in dashed lines) to recover heat. The pre-heat stage 252 can also be coupled to an organic Rankin cycle (ORC) unit 260 to convert the heat to electricity that can be exported to an electrical grid.

[00119] As indicated above, the LLISR 12 can be used in a process for permanent M FT
and/or FTT storage. The injection of untreated MFT and FTT into an LLISR pore space can contribute to plugging the reservoir. FIG. 18 illustrates a configuration for an MFT/FTT
permanent storage strategy that includes tailings treatment operations prior to injecting the tailings into the LLISR 12. Tailings from a tailings pond can be extracted by applying a dredge operation 270 with some dredge recycling being fed back to the tailings pond.
The dredge can be fed to a screen unit 272 to prevent plugging and remove debris 274. The screened tailings can be subjected to a coarse cyclone process 275, which removes construction materials 278 via an underflow; followed by a fine screen process 280 (e.g. using a rotating drum or pusher centrifuge) to extract further debris 282. It can be appreciated that the coarse and fine screening stages can be combined into a single unit with a two-stage screen at stage 272, as shown in the Date Recue/Date Received 2021-03-04 alternative configuration in FIG. 19. The fine screened tailings can then be subjected to a fine cyclone 284 where the larger particles (debris 285) are removed by the underflow and sent back to the tailings pond for tailings treatment 286. The overflow from the fine cyclone can be examined for particle size such that only treated tailings with a particle size at or below a predetermined threshold are fed to a pipeline 206. Tailings with larger particle sizes can be fed to a blunge stage 290 and returned to the fine cyclone 284 for further processing.

[00120] Segregating the MFT/FTT can use a two-stage cyclone process as shown schematically in FIGS. 18 and 19, with a fine pusher type centrifuge 280 and a blunger 290 to segregate the streams into larger construction sized particles (-<44 pin), intermediate clay particles (>5 pin but <44 pin), and the < 5 pm stream for injection well 60 deposit. The coarse particles in the finer fractions can be substantially clays which could be disaggregated with blunging, namely a clay process involving high intensity mixing. Blunging of the coarse fraction of the final product promotes a controlled top size for downhole injection. To address any potential issues with viscosity, for injection, the MFT/FTT could be diluted with other waste waters for injection. It is also possible to use a centrifuge in place of a cyclone for the the M FT
separation process.

[00121] The pipeline 206 can carry the treated tailings to a well pad associated with the LLISR 12 and injected into the LLISR 12 via the injection well 60. Fluids produced from the production well 62 can be fed to a gas/emulsion separator 210 and water/hydrocarbon separator 212 as described above. The produced water from the separate 212 can be sent to a next well pad (if applicable), wherein secondary water streams with thin MFT
generated at that well pad can be fed back to the LLISR 12 for permanent storage.

[00122] When an in situ hydrocarbon recovery process, such as SAGD, has been implemented for an extended period of time, it has been found that through conduction there can be substantial heat stored in the overburden formation. This heat can also be recovered, as illustrated in FIG. 20. As shown in FIG. 20, injection and production wells 60, 62 can be drilled into the overburden formation (fm2) that is positioned above the caprock overlying the reservoir formation (fm1). It can be appreciated that such an overburden heat recovery process from fm2 can be performed either in parallel with a heat recovery process applied to fm1 (e.g., as described above), or prior to fm1 becoming an LLISR 20. That is, the overburden heat recovery process shown in FIG. 20 can be implemented at any suitable time where there is sufficient heat in fm2 to recover energy therefrom.

Date Recue/Date Received 2021-03-04

[00123] In the example shown in FIG. 20, cold water is injected into the injection well 60 and heated water is recovered via the production well 62. Using the upper formation (fm2) independently or in conjunction with the lower formation (fm1) creates additional options for heat recovery. When compared to the techniques described above, this overburden heat recovery process occurs above the caprock. This means that the two reservoirs (fm1, fm2) are hydraulically isolated from each other, implying that there is likely not a need for the gas injection techniques described above to maintain reservoir pressure or to mitigate the risk of fluid communication with active SAGD pads. It may be noted that this configuration is not thermally isolated as the heat originates (i.e. is conducted up) from the SAGD
reservoir below.
The overburden heat recovery process shown in FIG. 20 could be implemented using sealed pipes that run in a closed loop through the artificially heated overburden, or in the same manner as described above, where water is driven between horizontal or vertical injector and production wells 60, 62.

[00124] Turning now to FIG. 21a, a reservoir that will become an LLISR 12 subsequent to a hydrocarbon recovery process is shown. In this example, a SAGD process is being implemented at the reservoir, in which steam is injected into the reservoir adding heat to the formation. During this process, heat is transferred throughout the reservoir by conduction, convection and, to a lesser extent, radiation. Similarly, heat is transferred to the overburden 160 and the underburden 170 by conduction and, to a lesser extent, radiation, as shown in FIG.
21a. That is, the heat that is added to the reservoir during active production and up to the point that the reservoir becomes an LLISR 12, the LLISR 12 can act as a source of heat to both the overburden 160 and underburden 170. Similar to the process illustrated in FIG.
20, heat can also be recovered from the underburden 170 as illustrated in FIGS. 21b and 21c.

[00125] One way to recover heat from the underburden 170 is shown in FIG. 21b, in which a similar configuration as that shown in FIG. 20 is implemented by drilling an injection well 60 and a production well 62 into the underburden 170. Water can then be cycled through the injection and production wells 60, 62 to recover heat in the underburden 170. As shown using dashed lines in FIG. 21b, recovering heat from the underburden 170 using the wells 60, 62 can also be implemented while the hydrocarbon recovery process (SAGD in this example) remains active, i.e., before becoming an LLISR 12. The configuration shown in FIG. 21b could also be implemented using sealed pipes that run in a closed loop through the artificially heated overburden, for example, U-shaped, vertical, or L-shaped as shown in FIGS. 21c-21e respectively.

Date Recue/Date Received 2021-03-04

[00126] Another way to recover heat from the underburden 170 can occur during the heat recovery process described above as shown, for example, in FIG. 21f. Referring now to FIG.
21f, it may be noted that heat recovery through water injection into an LLISR
12 as discussed above, is a gravity dominated process, which means that the injected water should preferentially follow along and remain at the base of the reservoir. Since conduction is expected to provide the majority of the heating of the underburden, conduction is also expected to be the mechanism by which heat is recovered from the underburden by the water in the LLISR 12. As shown in FIG. 21f, the water flows parallel to the interface of the LLISR 12 and the top of the underburden 170 and substantially perpendicular to the heat flux vector.

[00127] As discussed above, strategies can be employed to mitigate horizontal migration between laterally adjacent or "parallel" well pads (i.e., parallel actively producing reservoirs 110), such as in the configuration shown in FIG. 10, by including gas injection wells 63 between active well pads and the LLISR 12. Turning now to FIGS. 22a-22c, fluids such as water can also flow between well pads that are longitudinally adjacent or in "series" with each other. This issue can be particularly prevalent if the injection and production wells 60, 62 from one pad overlap a pad in series, and if no natural boundary or bitumen wedge exists. In the example shown in FIG.
22a, it is assumed that an adjacent actively producing reservoir 110 (having one or more well pads each including a set of injection and production wells 60, 62 and shown below the LLISR
12 in the figure) is an actively producing reservoir 110 implementing a SAGD
process. To enable the LLISR 12 to be filled with a fluid such as water (e.g., for heat recovery, disposal, etc.
as discussed herein) and to mitigate or avoid migration into the adjacent actively producing reservoir 110 that is aligned in series with the LLISR 12, a plugging material such as MFTs, or a commercially available cement squeeze product, etc., can be injected into the toe 302 of the injection wells 60, production wells 62, and gas wells 63 associated with the LLISR 12 to create a fluid migration barrier 300. This configuration also assumes that the wells 60, 62, 63 are drilled in the same direction such that the toes 302 of those wells 60, 62, 63 extend in substantially the same direction, as illustrated in FIG. 22a.

[00128] As shown in FIG. 22b, assuming the same orientation for the wells 60, 62, 63 in the LLISR 12, a fluid migration barrier 304 can be implemented at or substantially near the heels 306 of the injection wells 60, production wells 62, and gas wells 63 of the LLISR 12, again assuming that the wells 60, 62, 63 are drilled in the same direction. As such, it can be appreciated that the fluid migration barriers 300, 304 can be implemented at either or both ends of the LLISR 12 as illustrated in the configuration shown in FIG. 22c.

Date Recue/Date Received 2021-03-04

[00129] It may be noted that in FIG. 22a, an actively producing reservoir 110 is shown opposite the LLISR 12 and beyond the fluid migration barrier 300, whereas the actively producing reservoir shown in FIG. 22b is shown opposite the LLISR 12 and beyond the fluid migration barrier 304. FIG. 22c illustrates that both barriers 300, 304 can be implemented to inhibit or prevent fluid migration from the LLISR 12 to actively producing reservoirs 110 positioned relative to the LLISR 12, in any direction.

[00130] FIGS. 23a and 23b illustrate cross-sectional schematic diagrams of the fluid migration barriers 304 and 300 respectively. Referring first to FIG. 23a, when creating the fluid migration barrier 304 at the heel 306 of the injection, production, and gas wells 60, 62, 63 a leading packer 310 can be placed ahead of a trailing packer 310 connected to injection tubing 312 to enable a plugging slurry of MFTs, cement squeeze product, etc., can be pumped down into the void between the packers 310 and through the slotted liner, perforated liner, or other passages into the surrounding area of the formation, to create the barrier 304. The plugging slurry would typically progress outwardly into the formation following the permeability of the formation, however, a localized perforation or dilation can be used to initially guide the plugging slurry in a particular direction. It can be appreciated that a variety of packers 310 can be used, for example, straddle packers (wherein the packers 310 are connected in a single unit ¨ as shown with dashed lines in FIG. 23a - with expanding sections to plug off the well), wireline packers, mechanical packers, inflatable packers, etc. These types of packers 310 allow fluid to pass through them via one or more ports. While a plug or other obstruction could be used for the leading packer 310 (and later drilled out or retrieved, packers 310 permitting fluid to flow through ports therein are particularly efficient in this implementation.

[00131] In the configuration shown in FIG. 23b, a packer 310 can be placed near the toe 302 of the wells 60, 62, 63 and connected to injecting tubing 312 to enable the plugging slurry to be pumped down into the toe 302 and then into the surrounding area of the formation via a slotted liner, perforated liner, or other passages as illustrated.

[00132] Referring now to FIGS. 24a-24d, when storing fluids such as water in an LLISR 12 (whether permanently or temporarily), fluid flow rates and fluid levels can be varied over time to both mitigate fluid migration to adjacent actively producing reservoirs 110 and, when being used to recover heat from the formation, enable more heat to be harvested from a reservoir by having certain LLISRs 12 filled to the top of the reservoir and, for example, be heated by way of conduction through less permeable (or impermeable) overburden and underburden layers above and below the reservoir.

Date Recue/Date Received 2021-03-04

[00133] FIG. 24a illustrates a first stage in which a depleted reservoir, namely an LLISR 12 as described herein, is adjacent actively producing reservoirs 110 to either side. The LLISR 12 can be isolated by gas wells 63 as described above and shown using solid barriers denoted by numeral 63 in FIG. 24a. Since the LLISR 12 is directly adjacent the actively producing reservoirs 110, water is injected into the LLISR 12, via injection wells 60, to a low water threshold, e.g., 1.5-2m above the adjacent producer wells 62. By filling the adjacent LLISR 12 to the low water threshold, the risk of disposal water spilling into the adjacent actively producing reservoir 110 can be reduced. Heat can be recovered from the reservoir using water injected up to the low water threshold, but significant amounts of the heat in the upper portion of the reservoir would not be recovered because the low water level would not reach the upper portion.

[00134] When two parallel well pads or reservoirs are depleted and can both be utilized as LLISRs 12 as herein described, the LLISR 12a that is next to the actively producing reservoir 110 can be filled to the low water threshold and become a buffer for the next LLISR 12b as shown in FIG. 24b. In FIG. 24b, LLISR 12b can also be filled with water up to the low water threshold and, with LLISR 12a acting as a buffer between it and the actively producing reservoir 110, can be filled beyond that threshold, to a high water level, by increasing the disposal injection rate to further mound the water up to the top of the reservoir, as shown using a darker shade in FIG. 24cf0r LLISR 12b. This can be done since the risk of flooding the actively producing reservoir 110 is mitigated or even eliminated by having the buffer LLISR 12a to absorb any water migrating towards the actively producing reservoir 110.

[00135] FIG. 24d illustrates that this water level variation strategy can be employed in a staged implementation throughout an oil recovery site as reservoirs become depleted and are repurposed as LLISRs 12.

[00136] The high water LLISRs 12b are advantageous since by filling more of the reservoir, additional heat can be harvested, e.g., by conduction via the overburden and underburden or other impermeable layer. Moreover, the high water LLISR 12b can reduce the amount of gas being used by driving the gas used in the gas wells 63 (to maintain the pressure), into the adjacent buffer LLISR 12a. The high water LLISR 12b can also accelerate the availability of the disposal volume by enabling more water to be disposed of earlier in time, rather than waiting until the entire interconnected reservoir is depleted..

[00137] If LLISR 12b was in operation longer than LLISR 12a, the temperature would be likely be lower in LLISR 12b. In that case, cold water could be injected into LLISR 12b, enabling the lower temperature reservoir to heat the cold water to an intermediate or "medium"

Date Recue/Date Received 2021-03-04 temperature. Then, such medium temperature water would flow over to the hotter LLISR 12a allowing for hotter water to be brought to surface. If water was only pumped to surface from LLISR 12a this would improve the efficiency of the heat recovery process because hotter water could be brought to surface for a longer period of time. This strategy employs the same principles as a counter flow heat exchanger, thus driving the efficiency of the heat exchange process between the reservoir and flowing water towards the maximum.

[00138] FIG. 25 illustrates the progression of water mounding in the buffer LLISR 12a and high water LLISR 12b from an end view perspective wherein the well pairs 60, 62 are shown spaced through the LLISRs 12a, 12b. It can be seen that the buffer LLISR 12a can accommodate an migration from the high water LLISR 12b and over time prevents or substantially mitigates migration and flooding into the actively producing reservoir 110.

[00139] For simplicity and clarity of illustration, where considered appropriate, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.
In addition, numerous specific details are set forth in order to provide a thorough understanding of the examples described herein. However, it will be understood by those of ordinary skill in the art that the examples described herein may be practiced without these specific details. In other instances, well-known methods, procedures and components have not been described in detail so as not to obscure the examples described herein. Also, the description is not to be considered as limiting the scope of the examples described herein.

[00140] The examples and corresponding diagrams used herein are for illustrative purposes only. Different configurations and terminology can be used without departing from the principles expressed herein. For instance, components and modules can be added, deleted, modified, or arranged with differing connections without departing from these principles.

[00141] The steps or operations in the flow charts and diagrams described herein are just for example. There may be many variations to these steps or operations without departing from the principles discussed above. For instance, the steps may be performed in a differing order, or steps may be added, deleted, or modified.

[00142] Although the above principles have been described with reference to certain specific examples, various modifications thereof will be apparent to those skilled in the art as outlined in the appended claims.

Date Recue/Date Received 2021-03-04

Claims

Claims:

1. A method of controlling fluid migration from a first hydrocarbon reservoir, the method comprising:
creating a first fluid migration barrier between the first hydrocarbon reservoir and a second hydrocarbon reservoir by injecting a plugging material into a surrounding formation via at least one well positioned in the first hydrocarbon reservoir.

2. The method of claim 1, further comprising:
placing a first packer at one end of the at least one well; and injecting the plugging material through at least one port in the first packer.

3. The method of claim 2, wherein the one end of the at least one well comprises a toe of the at least one well, the plugging material being injected through the toe of the at least one well into the surrounding formation.

4. The method of claim 2, wherein the one end of the at least one well comprises a heel of the at least one well, the plugging material being injected through the heel of the at least one well between the first packer and an obstruction.

5. The method of claim 4, wherein the obstruction comprises a leading packer placed ahead of the first packer positioned at the heel of the at least one well.

6. The method of claim 5, wherein the leading packer and the first packer are connected.

7. The method of any one of claims 1 to 6, wherein the plugging material is injected by tubing extending to the first packer in the at least one well.

8. The method of any one of claims 1 to 7, further comprising:
creating a second fluid migration barrier between the first hydrocarbon reservoir and a third hydrocarbon reservoir by injecting the plugging material into a surrounding formation at a position spaced from first fluid migration barrier.

Date Recue/Date Received 2021-03-04

9. The method of claim 8, further comprising:
placing a second packer at another end of the at least one well; and injecting the plugging material through at least one port in the second packer.

10. The method of claim 9, wherein the other end of the at least one well comprises a toe of the at least one well, the plugging material being injected through the toe of the at least one well into the surrounding formation.

11. The method of claim 9, wherein the other end of the at least one well comprises a heel of the at least one well, the plugging material being injected through the heel of the at least one well between the second packer and an obstruction.

12. The method of claim 11, wherein the obstruction comprises a leading packer placed ahead of the second packer positioned at the heel of the at least one well.

13. The method of claim 12, wherein the leading packer and the second packer are connected.

14. The method of any one of claims 8 to 13, wherein the plugging material is injected by tubing extending to the second packer in the at least one well.

15. The method of any one of claims 1 to 14, wherein the plugging material is injected through a slotted liner, a perforated liner, or one or more openings in a liner of the at least one well.

16. The method of any one of claims 1 to 15, wherein the plugging material comprises mature fine tailings (MFTs).

17. The method of any one of claims 1 to 15, wherein the plugging material comprises mining tailings.

18. The method of any one of claims 1 to 15, wherein the plugging material comprises a cement squeeze product.

Date Recue/Date Received 2021-03-04

19. The method of any one of claims 1 to 18, wherein gas wells are positioned along at least one side of the first hydrocarbon reservoir to buffer the at least one well in the first hydrocarbon reservoir from at least one active reservoir adjacent the first hydrocarbon reservoir using the gas wells.

20. The method of any one of claims 1 to 19, wherein the first hydrocarbon reservoir comprises a late life in situ reservoir (LLISR).

21. The method of claim 20, wherein the LLISR is being used for fluid storage.

22. The method of claim 20 or claim 21, wherein the LLISR is being used for fluid disposal.

23. The method of any one of claims 20 to 22, wherein the LLISR is being used for heat recovery from the first hydrocarbon reservoir.

24. A method of controlling fluid migration into an actively producing hydrocarbon reservoir, the method comprising:
injecting fluid into a first late life in situ reservoir (LLISR) that is adjacent to the actively producing reservoir, to a first level that is at or below a first threshold level; and injecting fluid into a second LLISR that is adjacent to the first LLISR, to a second level that is above the first threshold level and at or below an upper formation barrier in second LLISR, wherein the first LLISR is positioned between the actively producing reservoir and the second LLISR.

25. The method of claim 24, further comprising:
injecting fluid into the first LLISR to a third level that is above the first threshold level, as the actively producing hydrocarbon reservoir transitions to being a third LLISR, wherein the third LLISR is adjacent to another actively producing hydrocarbon reservoir; and injecting fluid into the third LLISR to a fourth level that is at or below the first threshold level.

26. The method of claim 24 or claim 25, wherein gas wells are positioned along at least one side of the first LLISR to buffer at least one well in the first LLISR from the actively producing reservoir adjacent the first LLISR, using the gas wells.

Date Recue/Date Received 2021-03-04

27. The method of claim 26, wherein gas wells positioned between the first LLISR and the second LLISR are decommissioned as the second LLISR transitions from being an actively producing reservoir.

28. The method of any one of claims 24 to 27, wherein the first LLISR
receives overflow fluids from the second LLISR to act as a buffer against flooding into the actively producing reservoir.

29. The method of any one of claims 24 to 28, wherein the fluid is injected into a plurality of well pairs in each of the first and second LLISRs, each well pair comprising an injection well and a production well positioned below the injection well.

30. The method of any one of claims 24 to 29, wherein the first LLISR is being used for heat recovery using the injected fluid.

31. The method of any one of claims 24 to 30, wherein the second LLISR is being used for heat recovery using the injected fluid.

32. The method of claim 30 or claim 31, wherein the fluid comprises water.
33. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to a steam assisted gravity drainage (SAGD) process prior to injecting the water for heat recovery.

33. The method of any one of claims 24 to 32, wherein at least one of the first and second

LLISR has been subjected to an expanding solvent SAGD (ES-SAGD) process prior to injecting the water for heat recovery.

35. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to a thermal solvent recovery process prior to injecting the water for heat recovery.

Date Recue/Date Received 2021-03-04

36. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to a cyclic steam stimulation (CSS) process prior to injecting the water for heat recovery.

37. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to a steam flood process prior to injecting the water for heat recovery.

38. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to an in situ combustion process prior to injecting the water for heat recovery.

39. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to an electromagnetically assisted solvent extraction (EASE) process prior to injecting the water for heat recovery.

40. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to an electrical heating process prior to injecting the water for heat recovery.

41. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to an electromagnetic spectrum heating process prior to injecting the water for heat recovery.

42. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to a radio frequency heating process prior to injecting the water for heat recovery.

43. The method of any one of claims 24 to 32, wherein at least one of the first and second LLISR has been subjected to a thermal solvent recovery process prior to injecting the water for heat recovery.

Date Recue/Date Received 2021-03-04

44. A system for controlling fluid migration from a first hydrocarbon reservoir, the system comprising:
a first fluid migration barrier between the first hydrocarbon reservoir and a second hydrocarbon reservoir created by injecting a plugging material into a surrounding formation via at least one well positioned in the first hydrocarbon reservoir.

45. The system of claim 44, further comprising:
a first packer placed at one end of the at least one well; and tubing to inject the plugging material through at least one port in the first packer.

46. The system of claim 45, wherein the one end of the at least one well comprises a toe of the at least one well, the plugging material being injected through the toe of the at least one well into the surrounding formation.

47. The system of claim 45, wherein the one end of the at least one well comprises a heel of the at least one well, the plugging material being injected through the heel of the at least one well between the first packer and an obstruction.

48. The system of claim 47, wherein the obstruction comprises a leading packer placed ahead of the first packer positioned at the heel of the at least one well.

49. The system of claim 48, wherein the leading packer and the first packer are connected.

50. The system of any one of claims 44 to 49, wherein the plugging material is injected by the tubing extending to the first packer in the at least one well.

51. The system of any one of claims 44 to 50, further comprising:
a second fluid migration barrier created between the first hydrocarbon reservoir and a third hydrocarbon reservoir by injecting the plugging material into a surrounding formation at a position spaced from first fluid migration barrier.

52. The system of claim 51, further comprising:
a second packer placed at another end of the at least one well; and tubing to inject the plugging material through at least one port in the second packer.

Date Recue/Date Received 2021-03-04

53. The system of claim 52, wherein the other end of the at least one well comprises a toe of the at least one well, the plugging material being injected through the toe of the at least one well into the surrounding formation.

54. The system of claim 52, wherein the other end of the at least one well comprises a heel of the at least one well, the plugging material being injected through the heel of the at least one well between the second packer and an obstruction.

55. The system of claim 54, wherein the obstruction comprises a leading packer placed ahead of the second packer positioned at the heel of the at least one well.

56. The system of claim 55, wherein the leading packer and the second packer are connected.

57. The system of any one of claims 51 to 56, wherein the plugging material is injected by the tubing extending to the second packer in the at least one well.

58. The system of any one of claims 44 to 57, wherein the plugging material is injected through a slotted liner, a perforated liner, or one or more openings in a liner of the at least one well.

59. The system of any one of claims 44 to 58, wherein the plugging material comprises mature fine tailings (MFTs).

60. The system of any one of claims 44 to 58, wherein the plugging material comprises mining tailings.

61. The system of any one of claims 44 to 58, wherein the plugging material comprises a cement squeeze product.

62. The system of any one of claims 44 to 61, further comprising gas wells positioned along at least one side of the first hydrocarbon reservoir to buffer the at least one well in the first Date Recue/Date Received 2021-03-04 hydrocarbon reservoir from at least one active reservoir adjacent the first hydrocarbon reservoir using the gas wells.

63. The system of any one of claims 44 to 62, wherein the first hydrocarbon reservoir comprises a late life in situ reservoir (LLISR).

64. The system of claim 63, wherein the LLISR is being used for fluid storage.

65. The system of claim 63 or claim 64, wherein the LLISR is being used for fluid disposal.

66. The system of any one of claims 63 to 65, wherein the LLISR is being used for heat recovery from the first hydrocarbon reservoir.

67. A system of controlling fluid migration into an actively producing hydrocarbon reservoir, the method comprising:
a first late life in situ reservoir (LLISR) that is adjacent to the actively producing reservoir, comprising fluid injected to a first level that is at or below a first threshold level; and a second LLISR that is adjacent to the first LLISR, comprising fluid injected to a second level that is above the first threshold level and at or below an upper formation barrier in second LLISR, wherein the first LLISR is positioned between the actively producing reservoir and the second LLISR.

68. The system of claim 67, wherein:
fluid is injected into the first LLISR to a third level that is above the first threshold level, as the actively producing hydrocarbon reservoir transitions to being a third LLISR, wherein the third LLISR is adjacent to another actively producing hydrocarbon reservoir;
and fluid is injected into the third LLISR to a fourth level that is at or below the first threshold level.

69. The system of claim 67 or claim 68, further comprising gas wells positioned along at least one side of the first LLISR to buffer at least one well in the first LLISR from the actively producing reservoir adjacent the first LLISR, using the gas wells.

Date Recue/Date Received 2021-03-04

70. The system of claim 69, wherein gas wells positioned between the first LLISR and the second LLISR are decommissioned as the second LLISR transitions from being an actively producing reservoir.

71. The system of any one of claims 67 to 70, wherein the first LLISR
receives overflow fluids from the second LLISR to act as a buffer against flooding into the actively producing reservoir.

72. The system of any one of claims 67 to 71, wherein the fluid is injected into a plurality of well pairs in each of the first and second LLISRs, each well pair comprising an injection well and a production well positioned below the injection well.

73. The system of any one of claims 67 to 72, wherein the first LLISR is being used for heat recovery using the injected fluid.

74. The system of any one of claims 67 to 73, wherein the second LLISR is being used for heat recovery using the injected fluid.

75. The system of claim 73 or claim 74, wherein the fluid comprises water.

76. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to a steam assisted gravity drainage (SAGD) process prior to injecting the water for heat recovery.

77. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to an expanding solvent SAGD (ES-SAGD) process prior to injecting the water for heat recovery.

78. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to a thermal solvent recovery process prior to injecting the water for heat recovery.

Date Recue/Date Received 2021-03-04

79. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to a cyclic steam stimulation (CSS) process prior to injecting the water for heat recovery.

80. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to a steam flood process prior to injecting the water for heat recovery.

81. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to an in situ combustion process prior to injecting the water for heat recovery.

82. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to an electromagnetically assisted solvent extraction (EASE) process prior to injecting the water for heat recovery.

83. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to an electrical heating process prior to injecting the water for heat recovery.

84. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to an electromagnetic spectrum heating process prior to injecting the water for heat recovery.

85. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to a radio frequency heating process prior to injecting the water for heat recovery.

86. The system of any one of claims 67 to 75, wherein at least one of the first and second LLISR has been subjected to a thermal solvent recovery process prior to injecting the water for heat recovery.

Date Recue/Date Received 2021-03-04