CA3141040A1 - Integrated heating systems for heating startup fluid and solvent in solvent-assisted hydrocarbon recovery processes - Google Patents

Abstract

An integrated heating process and system for mobilizing hydrocarbons, such as bitumen, in a hydrocarbon-containing reservoir in the context of in situ hydrocarbon recovery operations using a well pair is provided. The process can include heating a circulation fluid using a heating unit and circulating the heated circulation fluid via a circulation system deployed in the well pair during the startup phase to heat and mobilize the bitumen. The process can include pre-heating an injection fluid using the heating unit to be introduced into the injection well during the production phase to dissolve and mobilize the bitumen. The diluted bitumen can be recovered in the production well of the well pair.
The system can include a heating unit, which can include a heat exchanger, a closed-loop system to circulate the heated circulation fluid, and an injection tubing string for injecting the injection fluid.

Description

INTEGRATED HEATING SYSTEMS FOR HEATING STARTUP FLUID AND SOLVENT
IN SOLVENT-ASSISTED HYDROCARBON RECOVERY PROCESSES
TECHNICAL FIELD
[001] The technical field generally relates to processes for in situ recovery of hydrocarbons, such as mobilizing bitumen from bitumen-containing reservoirs.
In particular, the technical field relates to techniques for heating and circulating fluids for enhancing hydrocarbon recovery which can involve mobilizing hydrocarbons such as bitumen during solvent-assisted recovery processes. The technical field also relates to enhanced startup of solvent-assisted recovery processes.
BACKGROUND

[002] There are various techniques for performing in situ recovery of heavy hydrocarbons, such as heavy oil and/or bitumen, from heavy hydrocarbon-containing reservoirs. Some techniques include Steam-Assisted Gravity Drainage (SAGD) recovery processes where steam is injected into the heavy hydrocarbon-containing reservoir to help mobilize the bitumen for subsequent recovery. Other techniques include solvent-assisted recovery processes that can have similarities with conventional SAGD, although solvent is injected into the heavy hydrocarbon-containing reservoir instead of or along with steam.

[003] In an example of a solvent-assisted recovery process, a pair of horizontal wells including an upper injection well and a lower production well can be provided in the heavy hydrocarbon-bearing reservoir, which can be an oil sands reservoir.
Prior to the implementation of the solvent-assisted recovery process, the region between the injection well and the production well, i.e., the interwell region, is characterized by various levels of hydrocarbon saturation and fluid mobility, and will generally include a region having high saturation of hydrocarbons and limited fluid mobility. A
startup process can be implemented to increase the mobility of the hydrocarbons in the interwell region, for instance by warming the interwell region using various methods, such as using electric resistive heaters, circulating hot fluids such as steam, or injecting fluids into the hydrocarbon-bearing reservoir.
Date recue / Date received 2021-12-03

[004] Once fluid communication is established in the region between the injection well and the production well, injection of a mobilizing fluid can promote growth of an extraction chamber around the injection well. The extraction chamber eventually extends upwardly and outwardly from the injection well within the reservoir as the mobilized hydrocarbons flow toward the production well mainly due to gravity forces.
Over time, a production fluid including the mobilized hydrocarbons and a portion of the mobilizing fluid is recovered to the surface. The extraction chamber can be formed using various mobilizing fluids, such as steam, various hydrocarbon or organic solvents, and combinations thereof.

[005] When a solvent is used as a mobilizing fluid during a solvent-assisted recovery process, heating the solvent prior to injection into a bitumen-containing reservoir can facilitate dissolving and mobilizing bitumen. However, conventional methods used for heating solvent can pose various challenges. For instance, direct heating of a solvent with a fuel-burning heater can be problematic in the event of a leak.
Furthermore, conventional methods for heating a solvent can involve the use of dedicated heating equipment at surface that is different than the equipment used to produce steam during a startup phase, which can contribute to increased capital costs.
Thus, the heating of different fluids during the startup phase and the production phase can typically involve multiple heating units provided at surface that each work to heat the various fluids used to facilitate mobilization of the heavy hydrocarbons.

[006] These challenges related to heating and mobilizing heavy hydrocarbons during the different stages of in situ recovery provide a need for further technological developments in this field.
SUMMARY

[007] In accordance with one aspect, there is provided a process for recovering hydrocarbons from a hydrocarbon-containing reservoir using a well pair comprising an injection well overlying a production well, the process comprising: heating a circulation fluid using a heating unit located at surface to produce a heated circulation fluid;
circulating the heated circulation fluid via a circulation system deployed in at least one of the injection well and the production well to heat the hydrocarbons surrounding the at least one of the injection well and the production well; pre-heating an injection fluid using Date recue / Date received 2021-12-03 the heating unit to produce a pre-heated injection fluid; introducing the pre-heated injection fluid into the hydrocarbon-containing reservoir via an injection tubing string provided in the injection well to dissolve and mobilize the hydrocarbons; and recovering a production fluid comprising diluted hydrocarbons via the production well.

[008] In some implementations, circulating the heated circulation fluid into the at least one of the injection well and the production well comprises: introducing the heated circulation fluid into the circulation system; circulating the heated circulation fluid in the circulation system; and supplying a return circulation fluid back to the heating unit.

[009] In some implementations, the process further comprises heating the return circulation fluid to produce a heated return circulation fluid, the heated return circulation fluid corresponding to the heated circulation fluid.

[0010] In some implementations, pre-heating the injection fluid using the heating unit comprises supplying the heated circulation fluid and the injection fluid to a heat exchanger to produce the pre-heated injection fluid.

[0011] In some implementations, pre-heating the injection fluid using the heating unit comprises supplying the injection fluid and a portion of the heated circulation fluid to a heat exchanger to produce the pre-heated injection fluid.

[0012] In some implementations, pre-heating the injection fluid using the heating unit comprises supplying the injection fluid and substantially all of the heated circulation fluid to a heat exchanger to produce the pre-heated injection fluid.

[0013] In some implementations, the circulation system comprises a closed-loop system.

[0014] In some implementations, the circulation system comprises an open-loop system.

[0015] In some implementations, the circulation system comprises a dual mode circulation system operable in a closed-loop mode and an open-loop mode.

[0016] In some implementations, circulating the heated circulation fluid is performed in the injection well.
Date recue / Date received 2021-12-03

[0017] In some implementations, the process further comprises heating the pre-heated injection fluid travelling downhole in the injection well while the heated circulation fluid is being circulated in the injection well to further heat the pre-heated injection fluid.

[0018] In some implementations, the heating unit is provided at a well pad.

[0019] In some implementations, the heating unit is provided at a central processing facility.

[0020] In some implementations, the heating unit is configured to supply heat to the well pair and to at least one additional well pair of the well pad.

[0021] In some implementations, the heating unit is configured to supply heat to the well pair and to at least one additional well pair of an additional well pad.

[0022] In some implementations, the process further comprises introducing the heated circulation fluid into the at least one additional well pair.

[0023] In some implementations, the process further comprises monitoring respective heat requirements for the well pairs and the at least one additional well pair, and adjusting an injection rate of the pre-heated injection fluid into a corresponding injection well of the well pair and the at least one additional well pair based on the respective heat requirements.

[0024] In some implementations, the process further comprises monitoring a corresponding stage of production for each of the well pair and the at least one additional well pair, and adjusting an injection rate of the pre-heated injection fluid into a corresponding injection well of the well pair and the at least one additional well pair based on the corresponding stage of production.

[0025] In some implementations, the process further comprises monitoring an available heating capacity of the heating unit, wherein the circulation fluid is heated and circulated in a corresponding injection well of the well pair and the at least one additional well pair based on the available capacity of the heating unit.
Date recue / Date received 2021-12-03

[0026] In some implementations, the process further comprises adjusting at least one of heating the circulation fluid, circulating the heated circulation fluid, pre-heating the injection fluid, and injecting the pre-heated injection fluid based on the monitoring.

[0027] In some implementations, the at least one of the injection well and the production well is the injection well and the production well, and the process further comprises removing the circulation system from the production well following completion of a startup phase.

[0028] In some implementations, the heated circulation fluid comprises steam.

[0029] In some implementations, the heating unit comprises a steam generator.

[0030] In some implementations, the steam generator comprises at least one of a once-through steam generator (OTSG), a drum boiler, and a direct-fired steam generator (DFSG).

[0031] In some implementations, the process further comprises supplying water to the heating unit for producing the steam.

[0032] In some implementations, the injection fluid comprises a solvent.

[0033] In some implementations, the solvent comprises a paraffinic solvent.

[0034] In some implementations, the solvent comprises pentane.

[0035] In some implementations, the solvent comprises butane.

[0036] In some implementations, the solvent comprises propane.

[0037] In some implementations, the hydrocarbons comprise bitumen and/or heavy oil.

[0038] In accordance with another aspect, there is provided a process for recovering hydrocarbons from a hydrocarbon-containing reservoir using a well pair comprising an injection well overlying a production well, the process comprising: heating a circulation fluid using a heating unit located at a surface to produce a heated circulation fluid;
circulating the heated circulation fluid in a closed-loop system provided in at least one of Date recue / Date received 2021-12-03 the injection well and the production well to heat the hydrocarbons surrounding the at least one of the injection well and the production well; supplying a return circulation fluid from the closed-loop system back to the heating unit for re-heating to produce the heated circulation fluid; pre-heating an injection fluid using the heated circulation fluid to produce a pre-heated injection fluid; injecting the pre-heated injection fluid into the hydrocarbon-containing reservoir through the injection well to dissolve and mobilize the hydrocarbon; and recovering a production fluid comprising diluted hydrocarbons via the production well.

[0039] In some implementations, the closed-loop system is provided in the injection well.

[0040] In some implementations, the heated circulation fluid is further circulated in an additional closed-loop system provided in the production well.

[0041] In some implementations, the process further comprises removing the additional closed-loop system from the production well after the return circulation fluid has been supplied back to the heating unit following completion of a startup phase.

[0042] In some implementations, pre-heating the injection fluid using the heating unit comprises supplying the heated circulation fluid and the injection fluid to a heat exchanger to produce the pre-heated injection fluid.

[0043] In some implementations, the process further comprises heating the pre-heated injection fluid travelling downhole in the injection well while the heated circulation fluid is being circulated in the injection well to further heat the pre-heated injection fluid.

[0044] In some implementations, the heated circulation fluid comprises steam.

[0045] In some implementations, the heating unit comprises a steam generator.

[0046] In some implementations, the steam generator comprises at least one of a once-through steam generator (OTSG), a drum boiler, and a direct-fired steam generator (DFSG).

[0047] In some implementations, the injection fluid comprises a solvent.
Date recue / Date received 2021-12-03

[0048] In some implementations, the hydrocarbons comprise bitumen and/or heavy oil.

[0049] In accordance with another aspect, there is provided an integrated heating system for recovering hydrocarbons from a hydrocarbon-containing reservoir using a well pair comprising an injection well overlying a production well, the integrated heating system comprising: a heating unit located at surface and configured to heat a circulation fluid to produce a heated circulation fluid and to pre-heat an injection fluid to produce a pre-heated injection fluid; a closed-loop system in fluid communication with the heating unit and positionable in at least one of the injection well and the production well to heat hydrocarbons surrounding the at least one of the injection well and the production well, the closed-loop system comprising an introduction tubing string and a return tubing string in fluid communication with each other; and an injection tubing string in fluid communication with the heating unit and positionable along at least a portion of the injection well, the injection tubing string being configured for injecting the pre-heated injection fluid into the hydrocarbon-containing reservoir to dissolve and mobilize hydrocarbon.

[0050] In some implementations, the heating unit comprises a heat exchanger configured to transfer heat from at least a portion of the heated circulation fluid to the injection fluid.

[0051] In some implementations, the introduction tubing string is arranged within the return tubing string and an inner annulus is defined between the introduction tubing string and the return tubing string, and wherein the introduction tubing string comprises an open end near a toe of the at least one well and the return tubing comprises a closed end near the toe of the at least one of the injection well and the production well.

[0052] In some implementations, the return tubing string is arranged within the introduction tubing string and an inner annulus is defined between the introduction tubing string and the return tubing string, and wherein the return tubing string comprises an open end near a toe of the at least one well and the introduction tubing comprises a closed end near the toe of the at least one of the injection well and the production well.
Date recue / Date received 2021-12-03

[0053] In some implementations, the integrated heating system further comprises a fluid inflow control device positioned proximate to the open end to control a rate at which the heated circulation fluid is introduced into the inner annulus.

[0054] In some implementations, the closed-loop system further comprises an outer tubing string, wherein the introduction tubing string and the return tubing string are arranged inside the outer tubing string.

[0055] In some implementations, the integrated heating system further comprises insulation disposed around at least one of the introduction tubing string and the return tubing string.

[0056] In some implementations, the at least one of the introduction tubing string and the return tubing string comprises a vacuum insulated tubing.

[0057] In some implementations, the closed-loop system is positioned in the injection well adjacent to at least a portion of the injection tubing string and is configured to provide indirect heat to the pre-heated injection fluid.

[0058] In some implementations, the closed-loop system is provided inside the injection tubing string, thereby forming an intermediate annulus between an outer surface of the closed-loop system and the injection tubing string.

[0059] In some implementations, the injection tubing string comprises outlets along a length thereof for injecting the pre-heated injection fluid at multiple locations along the injection well.

[0060] In some implementations, the outlets comprise nozzles.

[0061] In some implementations, wherein the heating unit further comprises a steam generator to produce steam as the heated circulation fluid.

[0062] In some implementations, the steam generator comprises at least one of a once-through steam generator (OTSG), a drum boiler, and a direct-fired steam generator (DFSG).
Date recue / Date received 2021-12-03

[0063] In some implementations, the hydrocarbons comprise bitumen and/or heavy oil.

[0064] In accordance with another aspect, there is provided an integrated heating system for mobilizing hydrocarbons in a hydrocarbon-containing reservoir using a well pair comprising an injection well overlying a production well, the system comprising: a heating unit located at surface, the heating unit comprising: a circulation fluid heater configured to heat a circulation fluid to produce a heated circulation fluid;
and a heat exchanger configured to receive the heated circulation fluid as a heat exchange fluid to heat an injection fluid via transfer of heat from the heated circulation fluid to the injection fluid to produce a pre-heated injection fluid; an injection tubing string positionable along at least a portion of the injection well and configured to be in fluid communication with the heat exchanger for injecting the pre-heated injection fluid into the hydrocarbon-containing reservoir; and a closed-loop system positionable proximal to the injection tubing string in the injection well, the closed-loop system comprising an introduction tubing string and a return tubing string in fluid communication with each other, the introduction tubing string being configured to be in fluid communication with the circulation fluid heater to receive the heated circulation fluid and the return tubing string being configured to be in fluid communication with the circulation fluid heater to supply a return circulation fluid thereto.

[0065] In some implementations, the integrated heating system further comprising an additional closed-loop system comprising an additional introduction tubing string and an additional return tubing string, wherein the additional closed-loop system is configured to be arranged in the production well and the additional introduction tubing string is in fluid communication with the heating unit to receive the heated circulation fluid and the additional return tubing string is in fluid communication with the heating unit to supply the return circulation fluid to the heating unit.

[0066] In some implementations, the closed-loop system is arranged within the injection tubing string and an outer wall of the closed-loop system defines an outer annulus with the injection tubing string and wherein the outer annulus is configured to receive the pre-heated injection fluid.
Date recue / Date received 2021-12-03

[0067] In some implementations, the hydrocarbons comprise bitumen and/or heavy oil.
BRIEF DESCRIPTION OF THE DRAWINGS

[0068] The attached figures illustrate various features, aspects and implementations of the technology described herein.

[0069] Fig 1A is a side view schematic of a well pair during the startup phase, including a closed-loop system in both wellbores.

[0070] Fig 1B is a side view schematic of a well pair configured for operation during a production phase, with a closed-loop system being provided in one of the wellbores.

[0071] Fig 2A is an example of a process flow of an in situ hydrocarbon recovery operation.

[0072] Fig 2B is another example of a process flow of an in situ hydrocarbon recovery operation.

[0073] Fig 2C is an example of a process flow of an in situ hydrocarbon recovery operation for a plurality of well pairs in two well pads.

[0074] Fig 3A is a side view schematic of a completion assembly in an injection well according to another implementation.

[0075] Fig 3B is a cross-sectional view of the completion assembly of Fig 3A.

[0076] Fig 4A is a side view schematic of a completion assembly in an injection well according to another implementation.

[0077] Fig 4B is a cross-sectional view of the completion assembly of Fig 4A.

[0078] Fig 5A is a side view schematic of a completion assembly in an injection well of a well pair.

[0079] Fig 5B is a cross-sectional view of the completion assembly of Fig 5A.
Date recue / Date received 2021-12-03

[0080] Fig 6 is a side view schematic of a well pair during the startup phase, including a completion assembly in both wellbores.

[0081] Fig 7 is a side view schematic of a well pair during the production phase, including a completion assembly according to another implementation in the injection well.

[0082] Fig 8A is a side view schematic of a completion assembly according to another implementation in an injection well.

[0083] Fig 8B is a cross-sectional view of the completion assembly in Fig 8A.
DETAILED DESCRIPTION

[0084] Techniques described herein relate to processes for mobilizing hydrocarbons, such as heavy hydrocarbons which can include bitumen or heavy oil, present in a hydrocarbon-containing reservoir, in the context of in situ hydrocarbon recovery operations using a well assembly. The well assembly can be a well pair that includes an injection well and a production well. Various aspects of the process can be used as part of a startup phase, as well as during subsequent stages of hydrocarbon recovery operations such as during the production phase where mobilized hydrocarbons are recovered to the surface. While implementations of the process will be discussed mainly in association with bitumen recovery, it is noted that various hydrocarbons can be recovered using techniques described herein.

[0085] The process involves the use of an integrated heating system that is configured to heat a circulating fluid and a mobilizing fluid. The techniques can be applied to in situ hydrocarbon recovery operations that use various well arrangements, such as well pairs that each includes an injection well and a production well or single wells that each operates as an injection and production well.

[0086] The integrated heating system can utilize a heating unit provided at surface to heat a circulation fluid to be introduced into at least one of the injection and production wells during a startup phase of a recovery process (i.e., warm up of the injection well and/or production well to mobilize the bitumen surrounding the injection and/or production well) and to heat a mobilizing fluid, such as a solvent, prior to injection into Date recue / Date received 2021-12-03 the hydrocarbon-containing reservoir during a conditioning phase and/or a production phase.

[0087] The integrated heating system can include an at-surface heating unit and a well completion assembly to perform dual actions during the startup and production phases. The well completion assembly can include, for instance, a circulation system that can be a closed-loop system, an open-loop system, and/or a heating system operable in a dual mode, i.e., in an open-loop configuration and in a closed-loop configuration.

[0088] The at-surface heating unit is configured to heat a circulation fluid to produce a heated circulation fluid, such as steam, that can be circulated in the injection well and/or the production well, via the circulation system that can include, for instance, a closed-loop system. At some point during the startup phase or once the startup phase is completed (i.e., when the surrounding bitumen is mobilized to a desired degree), the heated circulation fluid returned to the surface can be used to heat or superheat an injection fluid, such as a solvent, to produce a pre-heated injection fluid.
In some implementations, the heating unit can include a heat exchanger that can heat the injection fluid using heat transferred from the heated circulation fluid. The heated injection fluid can then be introduced into the injection well to further mobilize and dissolve bitumen surrounding the injection well. In addition, in some implementations, the injection fluid can be indirectly heated within the injection well with the circulation system. Once injected into the hydrocarbon-containing reservoir, the heated injection fluid dissolves and mobilizes bitumen to produce mobilized bitumen, which can then drain via gravity to the production well and be recovered to the surface via the production well as a production fluid.

[0089] Heat requirements can vary throughout a production lifecycle of a well pair. For instance, heat requirements can be higher during a startup phase when a circulation fluid is heated to be circulated in the injection well and/or the production well and during a production phase when a mobilizing fluid is heated prior to being introduced in the injection well for injection into the hydrocarbon-containing reservoir, compared to a latter part of the production phase when progressively less mobilizing fluid is introduced into Date recue / Date received 2021-12-03 the injection well. Thus, a heat requirement of a well pair can vary through time as the lifecycle of the recovery operation progresses.

[0090] Accordingly, in some implementations, the integrated heating system can be utilized for more than one well pair, either simultaneously or sequentially, depending on the heat requirements of the well pairs at a given time in their lifecycles.
Management strategies can also be implemented to enhance the generation and distribution of heat by the integrated heating system between multiple well pairs depending on the heat requirements of each well and the heating capacity of the heating unit, for instance. In some implementations, the integrated heating system can be used to provide heat to multiple well pairs, including well pairs on multiple well pads. In such implementations, the integrated heating system can be provided as part of a well pad and configured to provide heat to adjacent well pads in a hub and spoke design. Alternatively, the heating unit can be located at a central processing facility and provide heat to multiple well pads.
In situ recovery process

[0091] The processes described herein can contribute to enhancing utilization of at-surface heating unit used to heat various fluids involved in the startup and production phases of an in situ bitumen recovery process. Examples of the in situ bitumen recovery process will be described in further detail below.

[0092] An in situ bitumen recovery process generally includes various stages, including a startup phase, optionally followed by a conditioning phase and then a recovery phase or production phase, which can then optionally be followed by blowdown and/or winddown phases. The startup process is generally aimed at mobilizing hydrocarbons in an interwell region of the well pair (i.e., the area of the reservoir surrounding the injection well and/or production well, including the area of the reservoir located between the injection well and the production well), and establish fluid communication between the injection well and the production well of the well pair. The winddown or blowdown stages typically occur once the production stage of the bitumen recovery process has been in operation for a certain period of time and the recovery rate of the hydrocarbon production has started to decrease to uneconomical levels.
Once bitumen has been mobilized during the startup process, mobilized bitumen can be Date recue / Date received 2021-12-03 produced as a production fluid from the bitumen-containing reservoir during recovery operations that follow the startup phase.

[0093] It should be understood that, in the context of the present description, an in situ bitumen recovery process can refer to any suitable in situ bitumen recovery process adapted to produce mobilized bitumen from a bitumen-containing reservoir using injection fluid introduction via an injection well. Such suitable in situ bitumen recovery processes can include, for instance, a solvent-assisted gravity drainage operation that generally uses a solvent as a mobilizing fluid, with or without steam, for introduction as an injection fluid into the bitumen-containing reservoir. Other suitable in situ bitumen recovery processes can include a Steam-Assisted Gravity Drainage (SAGD) process. A
SAGD process conventionally uses steam alone as the mobilizing fluid; however, SAGD
can also use some other compounds that can be co-injected with the steam (e.g., small amounts of hydrocarbon solvent as in ES-SAGD, surfactants, non-condensable gas, water wetting agents, among others).
Startup phase of the in situ recovery process

[0094] During the startup phase, a heated circulation fluid can be used to heat and mobilize the bitumen surrounding the injection and/or production wells. As used herein, the expression "circulation fluid" refers to a fluid that is circulated into the well, i.e., that travels downhole into the well and then returns back uphole and remains within the circulation system if a closed-loop system is used or may contact the near wellbore region of the reservoir if an open-loop system is used, in contrast to an injection fluid that is introduced into a well and penetrates into the area surrounding the well, for instance under the action of pressure.

[0095] For instance, a closed-loop system can be used to circulate a heated circulation fluid in a circulation circuit deployed in the injection well and/or the production well. The closed-loop system can be in fluid communication with an integrated heating system provided at surface that heats the circulation fluid prior to circulation in the injection well and/or the production well, and that subsequently heats the circulation fluid returning back to the surface. The closed-loop system can be part of a completion assembly that includes an injection tubing string that can remain in the injection well during the production phase. In some implementations, an additional completion Date recue / Date received 2021-12-03 assembly, which can include a closed-loop system, can be provided in the production well to heat and mobilize the bitumen surrounding the production well during the startup phase.

[0096] Referring now to Figs 1A, 1B and 2A, an example of an in situ recovery system 10 is shown. The recovery system 10 includes a heating unit 18 provided at surface. The heating unit 18 includes a circulation fluid heater 19 that is configured to heat a circulation fluid 20 and produce a heated circulation fluid 24 that can be used for circulation at least during the startup phase in one or more well pairs, and to heat an injection fluid 26, such as a solvent, during the production stage of one or more well pairs. For ease of reference, in Fig 2A, streams related to the circulation of the circulation fluid in the injection well and production well are illustrated as dark lines, and streams related to the injection of the injection fluid in the injection well are illustrated as dotted lines.

[0097] In some implementations, the heating unit 18 can include a steam generator such as a once-through steam generator (OTSG), a direct contact steam generator (DCSG), a direct-fired steam generator (DFSG), or a drum boiler, for example, as the circulation fluid heater 19. Any other heating unit that can be configured to produce a heated circulation fluid 24, such as steam, can also be suitable. In some implementations, the heating unit 18 can be part of an exiting surface facility that also includes water treatment equipment to produce boiler feed water, particularly when the heating unit 18 includes a OTSG or a drum boiler.

[0098] In the implementation shown in Figs 1A, 1B and 2A, the well pair includes an injection well 12 overlying a production well 14. Fig 1A is an example of a configuration of a well pair that can be used during a startup phase, whereas Fig 1B
illustrates an example of a configuration of a well pair that can be used during a production phase. As mentioned above, the heating unit 18, e.g., the circulation fluid heater 19, is configured to provide heat to a circulation fluid 20 to produce a heated circulation fluid 24. The heated circulation fluid 24 can be circulated in the injection well 12 and/or the production well 14, as shown in Figs 1A, 1B and 2A. In the implementation shown in Figs 1A and 2A, the heated circulation fluid 24 is circulated in the injection well 12 via a closed-loop system 16 located in the injection well 12, and in the production well 14 via an additional Date recue / Date received 2021-12-03 closed-loop system 16 located in the production well 14, thereby heating and mobilizing the surrounding bitumen during the startup phase. In some implementations, the closed-loop systems 16 can extend close to the toe portion of each wellbore 38 and provide heat along the entire length of the wellbores 38, as shown in Fig 1A. Fig 1B
illustrates the closed-loop system 16 remaining in the injection well 12 during the production phase, while the additional closed-loop system 16 has been removed from the production well 14.

[0099]
Circulation fluids that can be used for circulation in the closed-loop system can include steam, hot water, a heat transfer fluid such as a glycol-based liquid, an organic fluid such as oil, and the like. Referring to Figs 1A and 2A, the heated circulation fluid 24 is circulated in the closed-loop system 16 provided in the injection well 12, and optionally circulated in the additional closed-loop system 16 provided in the production well 14, during the startup phase. As the heated circulation fluid 24 travels downhole in the closed-loop system 16, heat radiates from the closed-loop system 16 and heats the area in the reservoir that surrounds the well(s) into which the closed-loop system 16 is deployed. The circulation fluid 24 then returns uphole to the surface as a return circulation fluid 20a. Depending on the circulation fluid 24 used, the return circulation fluid 20a can be in liquid form, in vapour form, or can be multiphase.

[00100] The return circulation fluid 20a is then supplied back to the circulation fluid heater 19 of the heating unit 18 to be re-heated and, optionally, re-circulated. The circulation fluid 20 can be circulated and re-circulated through the closed-loop system 16 continuously or intermittently, for instance until the startup phase is completed (i.e., until the bitumen is mobilized to a desired fluidity in the reservoir surrounding the well). In some implementations, circulation of the circulation fluid 20 can continued in the injection well 12 during the production phase, or can be ended prior to completing the startup phase, depending on the recovery process design.

[00101] Still referring to Figs 1A and 2A, the return circulation fluid 20a is returned back to the circulation fluid heater 19 of the heating unit 18 to be re-heated, and once re-heated, can then be used as a heat exchange fluid in a heat exchanger 30 configured to pre-heat an injection fluid 26 that can subsequently be used during a production phase.
In some implementations, the return circulation fluid 20a can be a subcooled circulation Date recue / Date received 2021-12-03 fluid. In implementations where the circulation fluid 20 is steam, the return circulation fluid 20a can be hot or warm water. Toward the end of the startup phase when the reservoir has been heated, the return circulation fluid 20a can be a two-phase fluid, such as a mixture of liquid water and steam. In some implementations, if the composition of the return circulation fluid 20a has sufficient latent heat to pre-heat the injection fluid 26, the return circulation fluid 20a can be directed to the heat exchanger 30 to be used as a heat exchange fluid.

[00102] Referring more particularly to Fig 2A, in implementations where the heated circulation fluid 24 continues to be circulated in at least one of the injection well 12 and the production well 14 concomitantly with the injection fluid 26 is being pre-heated, a portion of heated circulation fluid 24a can be routed to the heat exchanger 30 to act as the heat exchange fluid to heat the injection fluid 26. Alternatively, in implementations where the heated circulation fluid 24 is no longer circulated in at least one of the injection well 12 and the production well 14 when the injection fluid 26 is being pre-heated, substantially all the heated circulation fluid 24 can be routed to the heat exchanger 30 as a heat exchange fluid to heat the injection fluid 26, or a portion of heated circulation fluid 24a can be routed to the heat exchanger 30 to act as the heat exchange fluid to heat the injection fluid 26 while the remaining portion of the heated circulation fluid 24a can be routed to one or more additional wells 25 as a circulation fluid or as a heat exchange fluid to heat an injection fluid.

[00103] In some implementations, when circulation of the circulation fluid 20 continues during part of the production phase, the closed-loop system 16 can contribute to providing heat to the pre-heated injection fluid 32 travelling downhole along a length of the injection well 12. In such implementations, during the production phase, the return circulation fluid 20a can be re-heated at surface using the circulation fluid heater 19 and then used as a heat exchange fluid to heat the injection fluid 26 prior to introduction into the injection well 12.

[00104] Furthermore, as shown in Fig 2A, heat transfer from the heated circulation fluid 24 or the portion of the heated circulation fluid 24a to the injection fluid 26 that occurs in the heat exchanger 30 produces a cooled portion of circulation fluid 31. Thus, in implementations where the heated circulation fluid 24 continues to be circulated in at Date recue / Date received 2021-12-03 least one of the injection well 12 and the production well 14 during part of the production phase, the cooled portion of circulation fluid 31 can be combined with the return circulation fluid 20a and returned back to the circulation fluid heater 19 as a combined stream 23.

[00105] Referring back to Fig 1A, the heating unit 18 located at surface is in fluid communication with a circulation fluid source 22 and with the closed-loop system 16.
The circulation fluid source 22 can be for instance a water source, when the intended heated circulation fluid is steam. Alternatively, the circulation fluid source 22 can be from a closed-loop system located in another well pair. In other words, the circulation fluid 20 that is present in the closed-loop system 16 of any adjacent well can be provided to the circulation fluid heater 19 as a return circulation fluid 20a and a source of circulation fluid 20. It is to be understood that, in a closed-loop configuration, the circulation fluid 20 is the same fluid as the return circulation fluid 20a shown in Figs 1A, 1B and 2A
although travelling in a different direction, i.e., downhole and uphole respectively, and having a different temperature. Thus, when using the expression "return circulation fluid", it is meant that the return circulation fluid 20a has circulated in the closed-loop system 16 at least once and is supplied back to the circulation fluid heater 19 to be re-heated. The circulation fluid heater 19 heats the circulation fluid 20 or return circulation fluid 20a, such that a heated circulation fluid 24 can be circulated in the closed-loop system 16 located in the injection well 12 and/or the production well 14. In some implementations, a make-up circulation fluid 21 can be supplied to the closed-loop system 16 to account for any fluid loss.

[00106] The closed-loop system 16 can have various configurations to enable circulation of a circulation fluid therein. For instance, the closed-loop system 16 can include an introduction tubing string for introducing the heated circulation fluid 24 downhole into the well, and a return tubing string for returning the circulation fluid 20, i.e., the return circulation fluid 20a, uphole to the circulation fluid heater 19. In the implementation shown in Figs 1A and 1B, the introduction tubing string corresponds to an inner tubing string 42, while the return tubing string corresponds to an outer tubing string 44. The inner tubing string 42 and the outer tubing 44 are provided in a concentric configuration, with the inner tubing string 42 extending within the outer tubing string 44, thereby defining an inner annulus 46 between the outer surface of the inner tubing string Date recue / Date received 2021-12-03 42 and the inner surface of the outer tubing string 44. In accordance with this configuration of the inner tubing string 42 and the outer tubing string 44, the return circulation fluid 20a can travel uphole in the inner annulus 46 to return to the circulation fluid heater 19.

[00107] The heated circulation fluid 24 is circulated through the closed-loop system 16, to heat the area surrounding the well in which the closed-loop system 16 is deployed. As heat transfers from the outer tubing string 44 of the closed-loop system 16 to the area surrounding the well, the heated circulation fluid 24 can condense, and the circulation fluid 20 is supplied back to the circulation fluid heater 19 as a return circulation fluid 20a.
The circulation fluid heater 19 can then reheat the return circulation fluid 20a to produce a heated circulation fluid 24 again, which can be subsequently recirculated in the well.

[00108] Fig 6 illustrates an example of a configuration of an injection well 12 and a production well 14 during a startup phase, with a closed-loop system 16 being provided in each of the injection well 12 and the production well 14. Heat 94 radiates from the closed-loop system 16 and heats the area surrounding the injection well 12 and the production well 14. The startup phase is transitioned to a conditioning phase or a production phase, for instance when the bitumen present in the interwell region has been mobilized to a certain degree, the closed-loop system 16 can be removed from the production well 14.

[00109] Fig 2B will now be described as an example of an implementation of an in situ recovery system 200 that uses steam 224 as a heated circulation fluid, and a solvent 226 as an injection fluid. For ease of reference, in Fig 2B, streams related to the circulation of steam 224 in the injection well 12 and production well 14 are illustrated as full lines, and streams related to the injection of the solvent 226 in the injection well 12 are illustrated as dotted lines.

[00110] In this implementation, water can thus be considered as the circulation fluid.
The water 220 can be obtained from a water source 222, for instance a water source located at the CPF, can be condensate 252, i.e., water condensate, from a closed-loop system located in another well pair and/or from the closed-loop system 216 of the injection well 12 and/or the production well 14. When the water is condensate 252 from a Date recue / Date received 2021-12-03 closed-loop system, water 220 from the water source 222 can be used as make-up water.

[00111] In Fig 2B, the condensate 252 is supplied to a cooler 240 to be cooled, and then the cooled water is supplied to a boiler feed water (BFW) heater 242 to produce boiler feed water 244. The boiler feed water 244 is then supplied to a drum boiler 246 that includes a direct-fired steam generator 248 configured to produce steam 224, and that also includes a boiler separator 250 to separate steam 224 from boiler blowdown water. In this implementation, the heating unit can thus be considered to include the drum boiler 246 described above as a circulation fluid heater. It is to be understood that in other implementations, condensate 252 and/or water 220 from the water source 222 can be supplied directly to the direct-fired steam generator 248. In some implementations, when the heated circulation fluid comprises steam 224, the steam 224 can be superheated steam, such as steam superheated to a temperature ranging from about 150 C to about 350 C, or from about 200 C to about 300 C, or up to about 370 C.
In some implementations, the heating unit, i.e., the drum boiler 246 in Fig 2B, can be configured to superheat the water 220 under a gauge pressure of up to 7800 kPag and to a temperature of up to about 294 C. Other combinations of temperatures and pressures can also be implemented in accordance with the capacity of the heating unit.

[00112] The steam 224 produced by the drum boiler 246 is then supplied to the injection well 12 and the production well 14 during a startup phase of the process, and optionally to additional wells 225, to be circulated. Circulation of the steam 224 in the injection well 12 and/or the production well 14 produces a circulation fluid condensate as a return circulation fluid, which corresponds to the condensate 252 described above, optionally with circulation fluid condensate from other wells. The condensate 252 is supplied back to the BFW heater 242 to be heated again in the drum boiler 246.
As described above, the condensate 252 can substantially be subcooled water, or can be a two-phase fluid comprising steam and liquid water. The composition of the condensate 252 can be dependent on the stage of production of the well pair. For example, during an initial stage of the startup phase, a majority of the latent heat of the steam 224 is released, thus heating the reservoir and producing a condensate 252 that comprises subcooled water. Toward the end of the startup phase, when the reservoir has been Date recue / Date received 2021-12-03 heated, the condensate 252 may retain some latent heat, such that the condensate can be a two-phase fluid comprising steam and liquid water.

[00113] When the recovery process transitions to a phase that involves injecting the solvent 226 in the reservoir via the injection well, such as during a production phase, the solvent 226 from a solvent supply 227 is supplied to a heat exchanger 254 that uses at least a portion 256 of the steam 224 produced by the drum boiler 246 as a heat exchange fluid to produce a pre-heated solvent 258. The pre-heated solvent 258 can be supplied to the injection well 12, and optionally to one or more additional wells 225. The portion 256 of the steam 224 that is used as the heat exchange fluid transfers heat to the solvent 226 and cools down to produce a heat exchange fluid condensate 260 that can be combined with the circulation fluid condensate 252 to be supplied back to the drum boiler 246.

[00114] The production well 14 produces a production fluid 296 that can be subjected to separation in a conditioning fluid vessel 229 to recover a conditioning fluid therefrom and produce a bitumen emulsion 233. In some implementations, the recovered conditioning fluid 231 can be combined with the solvent 226 from the solvent source 227 to be used as part of the injection fluid.

[00115] The configuration of the in situ recovery system 200 described above can be implemented for instance when circulation of the steam 224 in the injection well 12 is continued as the pre-heated solvent 258 is introduced in the injection well 12 to be injected in the reservoir. In implementations where circulation of the steam 224 into the injection well 12 is not performed as the pre-heated solvent 258 is introduced in the injection well 12 to be injected in the reservoir, the portion 256 of the steam 224 produced by the drum boiler 246 can be supplied to one or more wells located on the same well pad or on another well pad. Alternatively, substantially all the steam 224 can be supplied to the heat exchanger 254 to be used as the heat exchange fluid.
Conditioning phase of the in situ recovery process

[00116] In some implementations, a conditioning phase can be performed following the startup phase, and prior to debuting the production phase. In the conditioning phase, a conditioning fluid, such as a non-deasphalting solvent (e.g., an aromatic solvent Date recue / Date received 2021-12-03 comprising toluene, diesel, xylene, etc.), can be introduced into the injection well and/or the production well. In such implementations, the non-deasphalting solvent can be heated prior to introduction in the injection well and/or the production well, for example, by using the heated circulation fluid 24 as a heat exchange fluid for use in the heat exchanger 30. Alternatively, the conditioning fluid can be introduced in the injection well and/or the production well without having been previously pre-heated. In implementations where the conditioning phase is performed and the conditioning fluid is not pre-heated prior to being introduced in the injection well and/or the production well, e.g., when the conditioning fluid is introduced in liquid phase, circulation of the heated circulation fluid 24 can be ceased in the injection well and production well.
In other implementations, circulation of the heated circulation fluid 24 can continue concomitantly with the injection of the conditioning fluid.
Solvent-based production phase of the in situ recovery process

[00117] During the production phase, as shown in Fig 1B, an injection fluid 26 is supplied to the heating unit 18 from an injection fluid source 28. The heating unit 18 can be used to heat the injection fluid 26. Thus, in addition to providing heat to the circulation fluid to produce a heated circulation fluid that can be circulated in the injection and/or the production well during a startup phase, the heating unit 18 located at surface is further configured to heat an injection fluid used during a production phase of the recovery process. In such implementations, the heating unit 18 can further include a heat exchanger 30, and the heated circulation fluid 24 can be used to pre-heat the injection fluid 26 via the heat exchanger 30. The heat exchanger 30 can be any suitable type of heat exchanger, such as a shell-and-tube heat exchanger, a plate heat exchanger, a double-pipe heat exchanger, etc. By using the heating unit 18 to heat the circulation fluid 20 and the injection fluid 26, the heating unit 18 can provide heat during the startup phase and the production phase (i.e., to heat both the circulation fluid 20 and the injection fluid 26), thus reducing the need for multiple heating units and streamlining the at-surface equipment.

[00118] When the heated circulation fluid 24 is used to pre-heat the injection fluid 26, the circulation fluid heater 19 can first be used to heat the circulation fluid 20 that has condensed and that has been supplied back to the circulation fluid heater 19 from the Date recue / Date received 2021-12-03 closed-loop system 16 (i.e., return circulation fluid 20a), or a circulation fluid 20 received from the circulation fluid source 22, to produce the heated circulation fluid 24. For example, water lines can provide water to a steam generator, and the steam generator can produce steam for circulation in the closed-loop system and to pre-heat the injection fluid 26 via the heat exchanger 30. Alternatively, the heated circulation fluid 24 used to heat the injection fluid 26 can be received from a central processing facility or from another source. In some implementations, the heating unit 18 can directly pre-heat the injection fluid 26, i.e., without the use of the heated circulation fluid 24.

[00119] Fluids that can be used as the injection fluid 26 can include aromatic solvents, such as toluene, xylene and diesel as well as higher carbon number solvents or other refining products, paraffinic solvents, such as propane, butane, or pentane, which are also referred to as alkanes (C3 to C6 paraffin solvents), condensates, dimethyl ether (DME), methyl ethyl ketone (MEK), or other ethers and ketones, air, surfactants, and non-condensable gas, among others.

[00120] The injection fluid 26 can have various properties depending on the process design. In some implementations, the injection fluid 26 can be in vapour phase, liquid phase or multiphase. In some implementations, the injection fluid 26 can be superheated to produce a vaporized pre-heated injection fluid 32. The injection fluid 26 can have a composition that is modified over time.

[00121] Referring to Figs 1B, and 3A-8B, the injection fluid 26 can be introduced into the injection well 12 via an injection tubing string 34 as a pre-heated injection fluid 32. In the implementations shown in Figs 1B and 3A-8B, the inner surface of the injection tubing string 34 and the outer surface of the outer tubing string 44 define an intermediate annulus 50 into which the pre-heated injection fluid 32 can flow downhole. The pre-heated injection fluid 32 introduced into the injection tubing string 34 exits the injection tubing 34, i.e., the intermediate annulus 50, through openings 48 that are defined in the injection tubing string 34, and enters the reservoir. The pre-heated injection fluid 32 introduced into the reservoir forms, over time, an extraction chamber that eventually extends upwardly and outwardly from the injection well within the reservoir as the mobilized hydrocarbons flow toward the production well, mainly due to viscous forces and gravity forces.
Date recue / Date received 2021-12-03

[00122] In some implementations, heat can dissipate from the pre-heated injection fluid 32 as the pre-heated injection fluid 32 travels downhole. As a result, the pre-heated injection fluid 32 may progressively cool down as it travels along the length of the injection well 12. An additional source of heat can be used to provide heat to the pre-heated injection fluid 32 as it travels downhole. For example, the closed-loop system 16 can remain in place during the production phase and in proximity of the injection tubing string 34 to provide heat to the pre-heated injection fluid 32 throughout a portion or the entire length of the injection well 12. An electric resistance heater can also be deployed in the injection well 12 to heat the pre-heated injection fluid 32 as it travels downhole.
The electric heating can also be performed prior to, during and/or after the closed-loop circulation. An electric resistance heater can be left int the well for the duration of the startup and production stages, or can be deployed and then removed. Other heating methods can also be used. For example, electromagnetic (EM) radiation can be used by providing an EM device downhole. Fluid injection and soaking can also be used at different times (e.g., steam or solvent bullheading, solvent injection and soaking) which may be after closed-loop circulation and before injection of the mobilizing fluid for the production stage. Thus, other startup and heating methods can be employed in combination with the closed-loop circulation methods described herein.

[00123] When the closed-loop system 16 is used to provide constant or intermittent heat to the pre-heated injection fluid 32 as the pre-heated injection fluid 32 travels downhole, the heated circulation fluid 24 can be circulated through a closed-loop system 16 that is located adjacent or proximal to the injection tubing string 34.
With such a configuration, the heated circulation fluid 24 can be circulated to provide heat to the pre-heated injection fluid 32 along at least a portion of the length of the wellbore 38. The heated circulation fluid 24 can be simultaneously injected with the pre-heated injection fluid 32, or the heated circulation fluid 24 can be circulated intermittently during introducing of the pre-heated injection fluid 32 into the injection well 12.
Providing constant or intermittent heat to the closed-loop system 16 while introducing the pre-heated injection fluid 32 in the injection well 12 can facilitate achieving more consistent operating conditions throughout the length of the injection well 12.

[00124] Referring to Fig 7, during a production phase, the pre-heated injection fluid 32 can be introduced into the injection well 12 via the injection tubing string 34. The pre-Date recue / Date received 2021-12-03 heated injection fluid 32 flows out of the injection tubing string 34 via openings defined in the slotted liner 52 and into the area surrounding the injection well 12. The heated circulation fluid 24 can be circulated through the closed-loop system 16 simultaneously as the pre-heated injection fluid 32 is introduced in the injection well 12, providing indirect heat 94 to the surrounding area and to the pre-heated injection fluid 32. The pre-heated injection fluid 32 dissolves and mobilizes the bitumen producing a production fluid 96 that includes mobilized bitumen and condensed mobilizing fluid that flows via gravity into the production well 14.

[00125] Referring back to Fig 2C, an in situ recovery operation can include several well pads 68 connected to a central processing facility (CPF) 70 that includes a heating unit 18. When the circulation fluid is steam, steam supply pipelines 72 provide steam to the well pads 68. Each well pad 68 can include multiple well pairs 76 that extend down into the reservoir. In some implementations, an array of parallel well pairs 76 can extend from each well pad 68.

[00126] During the startup phase, the heated circulation fluid, which can be steam, can be circulated through a closed-loop system 16 and returned to the heating unit 18 via a circulation fluid line 80. In some implementations, the heating unit 18 located at the CPF
70 can provide a heated circulation fluid, such as steam, to multiple adjacent well pads 68 in a hub and spoke design.

[00127] During the production phase, the heated circulation fluid, which can be steam 72, can be used to pre-heat a mobilizing fluid, which can be a solvent XX, that is subsequently introduced into one or more injection wells of a plurality of well pairs 76.
The CPF 70 can provide the pre-heated mobilizing fluid to the well pads 68 via mobilizing fluid pipelines 82. In some implementations, the heated circulation fluid can be provided to the injection well(s) of the well pairs 76 simultaneously with the pre-heated mobilizing fluid. The pre-heated mobilizing fluid dissolves and mobilizes the bitumen, which drains by gravity to the production well. The CPF 70 is provided with production fluid pipelines 74 that transport the production fluid recovered from the production well of each well pair 76 for processing at the CPF 70.
Completion assembly implementations for the injection well of a well pair Date recue / Date received 2021-12-03

[00128] In addition to the at-surface heating unit 18 that can perform dual actions during the startup and production phases, the integrated heating system includes at least one completion assembly as described above. The completion assembly can include a circulation system configured as a closed-loop system as described above, or a closed-loop system that is configured differently than the closed-loop system 16 described above. Alternatively, the circulation system can include an open-loop system or a dual mode circulation system, or the circulation system can include any combination of a closed-loop system, an open-loop system and a dual mode circulation system. The completion assembly can further include a mobilizing fluid injection system provided in a concentric or adjacent relation with respect to the circulation system.
Alternatively, there can be a first completion assembly that includes a circulation system, and a second completion assembly that includes the mobilizing fluid injection system. The first completion assembly can be deployed in selected wells during a startup phase of the recovery process, then removed from the selected wells following the startup phase, and the second completion can subsequently be deployed in selected wells following the startup phase to introduce an injection fluid into the reservoir to dissolve and mobilize the bitumen. When a first completion assembly and a second completion assembly are used, the timing of the use of each can change depending on the design of the recovery process.

[00129] Example implementations of completion assemblies that can be used in an injection well will now be described.

[00130] Referring now to Figs 3A and 3B, a completion assembly 110 that can be deployed in the injection well 12 can include an inner tubing string 42 and an outer tubing string 44. The inner tubing string 42 can have an open end, and can be provided within the outer tubing string 44 that has a closed end, such that the inner tubing string 42 is in fluid communication with the outer tubing string 44. This configuration of the inner tubing string 42 and the outer tubing string 44 together define a closed-loop system. In the implementation shown, the closed-loop system is provided inside an injection tubing string 34. A heated circulation fluid 24 can be introduced into the inner tubing string 42, flowing out the open end and into an inner annulus 46 defined between the outer surface of the inner tubing string 42 and the inner surface of the outer tubing string 44. When the heated circulation fluid 24 is introduced into the inner tubing string Date recue / Date received 2021-12-03 42, the inner tubing string 42 corresponds to the introduction tubing string.
At least a portion of the heated circulation fluid 24 can condense within the inner tubing string 42 after having transferred a sufficient portion of its heat, for example, to the reservoir during the startup phase or to the pre-heated injection fluid 32 during the production phase. Thus, the fluid entering the inner annulus 46 is a return circulation fluid 20a.
Therefore, in this implementation, the outer tubing string 44 is configured to route a return circulation fluid 20a that can have various levels of condensate back to surface and to the heating unit 18. In this example, the outer tubing string 44 is the return tubing string.

[00131] Referring to Figs 4A and 4B, a completion assembly 120 that can be deployed in the injection well 12 can include an inner tubing string 42 an outer tubing string 44.
The inner tubing string 42 and the outer tubing string 44 define a closed-loop system.
The closed-loop system can be provided inside an injection tubing string 34. A
heated circulation fluid 24 can be introduced into an inner annulus 46 defined between the outer surface of the inner tubing string 42 and the inner surface of the outer tubing string 44.
The heated circulation fluid 24 can flow out the end of the inner annulus 46 and into the inner tubing string 42. Thus, in such implementations, the inner tubing string 42 is configured to route a return circulation fluid 20a that can have various levels of condensate back to surface and to the heating unit 18. In this example, the inner tubing string 42 is the return tubing string.

[00132] Still referring to Figs 4A and 4B, in the implementation shown, the inner tubing string 42 is provided with a fluid inflow control device 54 at its far downhole end, or proximate thereto, to control the rate at which the heated circulation fluid 24 is returned to the heating unit 18 as a return circulation fluid 20a. In addition, when the completion assembly extends within an injection tubing string 34, the fluid inflow control device 54 can contribute to improving heating efficiency of the mobilizing fluid via heating by the circulation fluid. In this implementation, the fluid inflow control device 54 can be embodied by an autonomous inflow control device (AICD) configured to act as a steam trap and ensure that the mobilizing fluid is condensed within the inner annulus 46 prior to entering the inner tubing string 42 (or prior to entering the inner annulus 46 when the heated circulation fluid 24 is introduced into the inner tubing string 42).
The AICD can enable at least partial automatization of the system by allowing the return circulation fluid Date recue / Date received 2021-12-03 20a (e.g., steam condensate) to enter the inner tubing string 42 to be routed back up to the surface. It is to be understood that the fluid inflow control device 54 can be used with any implementation of completion assembly and is for controlling the rate at which a heated circulation fluid 24 enters a return tubing string.

[00133] Referring now to Figs 5A and 5B, a completion assembly 130 for use in an injection well 12 is shown. The heated circulation fluid 24 can be introduced into the closed-loop system 16 via an inner tubing string 42. The closed-loop system 16 can further include an outer tubing string 44 surrounding the inner tubing string 42, thereby defining an inner annulus 46 between the outer surface of the inner tuning string 42 and the inner surface of the outer tubing string 44 by which the circulation fluid 20 can be returned to the surface as a return circulation fluid 20a. The closed-loop system 16 is provided inside the injection tubing string 34 in a concentric configuration, the inner surface of the injection tubing string 34 defining an intermediate annulus with the outer surface of the outer tubing string 44, i.e., of the return tubing string.
During the production phase, a pre-heated injection fluid 32 can be introduced into the intermediate annulus 50 and flow into the reservoir through openings 48 defined in the injection tubing 34.

[00134] In the implementations shown in Figs 3A to 5B, the flow of the heated circulation fluid 24 can thus be considered as being substantially annular, particularly when the inner tubing string 42 and the outer tubing string 44 are provided in a concentric or coaxial configuration relative to each other.

[00135] In some implementations, such as in Figs 8A and 8B, the closed-loop system 16 can be a looped tube system that includes an introduction tubing string 86 for introducing the heated circulation fluid 24 into the injection well 12 and a return tubing string 86 for returning the circulation fluid 20 to the surface as a return circulation fluid 20a, the introduction tubing string 86 and the return tubing string 84 being in fluid communication with each other via a U-shaped end portion 85. In such implementations, the introduction tubing string 84 and the return tubing string 86 can thus be a single tube that loops at a toe region of the wellbore 38.

[00136] Still referring to Figs 8A and 8B, in some implementations, the introduction tubing string 84 and the return tubing string 86 can be provided within an outer tubing Date recue / Date received 2021-12-03 string 90. When the closed-loop system 16 is used in an injection well 12, the outer tubing string 90 can be provided within the injection tubing string 34. In such implementations, an annulus 92 is defined between the outer surface of the outer tubing string 90 and the inner surface of the injection tubing string 34, and the pre-heated injection fluid 32 can be introduced into the injection well via the annulus 92.

[00137] It is to be understood that the closed-loop systems described herein can be utilized in an injection well and/or a production well for heating and mobilizing bitumen surrounding the wells. The closed-loops systems described herein can also be utilized in an injection well with an injection tubing string 34 to provide additional heat to the pre-heated injection fluid 32 that is injected into the injection tubing string 34. When the closed-loop system 16 is implemented with the injection tubing string 34, the closed-loop system 16 can be located adjacent to or proximal to the injection tubing string 34 in a manner such as to facilitate a transfer of heat from the closed-loop system to the pre-heated injection fluid 32 in the injection tubing string 34. For example, in some implementations, heat can be transferred from the closed-loop system (i.e., from the inner tubing string 42 and the outer tubing string 44 or from the introduction tubing string 84 and the return tubing string 86) to the pre-heated injection fluid 32 via heat radiating from the closed-loop system (i.e., from the wall of the outer tubing string 44 or 90).

[00138] In some implementations, heat insulation can be provided along one or more of the tubing strings described herein. For example, when the heated circulation fluid 24 is introduced into the inner annulus 46 of the closed-loop system 16, the inner tubing string 42 can be insulated to reduce counter-current heat transfer from the heated circulation fluid 24 to the return circulation fluid 20a returning uphole in the inner tubing string 42. In some implementations, the heat insulation can be provided around the outside of the tubing string for which heat insulation has been determined to be desirable. In some implementations, vacuum insulated tubing can be used for tubing strings for which heat insulation has been determined to be desirable.

[00139] During the production phase, as heat dissipates from the heated circulation fluid 24, the pre-heated injection fluid 32 can be further heated or maintained at a desired temperature through heat radiating through the outer wall of the closed-loop system 16, such as the outer tubing string 44. Accordingly, it can be desirable that the Date recue / Date received 2021-12-03 interface between the closed-loop system 16 and the injection fluid being introduced into the injection well has heat transfer properties that can facilitate heating of the pre-heated injection fluid 32.

[00140] In some implementations, during the production phase, the pre-heated injection fluid 32 can be introduced into the intermediate annulus 50 defined between the injection tubing string 34 and the outer tubing string 44 of the closed-loop system 16 deployed in the injection well 12. As shown in Figs 1B, 3A and 3B, the injection tubing string 34 defines an outer annulus 40 with the wellbore or the slotted liner 52. When the outer annulus 40 is present, the pre-heated injection fluid 32 can flow out of the injection tubing string 34 and into the outer annulus prior to entering the reservoir.

[00141] In some implementations, such as shown in Fig 4A and 4B, the injection tubing string 34 can have a portion that is defined by the slotted liner 52. In such implementations, the pre-heated injection fluid 32 can be considered to flow in the outer annulus 40 since the intermediate annulus 50 defined between the outer surface of the outer tubing string 44 and the inner surface of the injection tubing string 34 is absent for the portion of the injection tubing string 34 that is defined by the slotted liner 52, e.g., along the horizontal portion of the injection well 12. It is to be noted that in some implementations, the intermediate annulus 50 can be present and defined along a portion of the well uphole of the horizontal portion of the injection well 12.
For example, the pre-heated injection fluid 32 can flow through the intermediate annulus 50 downhole from the surface and out the end of the injection tubing string 34 that is located in a horizontal portion of the injection well 12 and into the outer annulus 40 defined between the outer tubing string 44 and the slotted liner 52.

[00142] During the production phase, the pre-heated injection fluid 32 that is introduced into the injection tubing string 34 can flow out of the injection tubing string 34 and into the area surrounding the injection well 12. In order to do so, the injection tubing string 34 can be include openings 48 along a length thereof for injecting the pre-heated injection fluid 32 at multiple locations along the injection well. In some implementations, the openings 48 can include nozzles 48. The nozzles 48 can be provided in groups at given locations along the well, or can be provided in other ways. The nozzles 48 can take the form of simple openings or outlets in the wall thickness of the injection tubing Date recue / Date received 2021-12-03 string 34, or can have certain structural features. The outlets or nozzles 48 enable the pre-heated injection fluid 32 to flow from the intermediate annulus 50, outer annulus 40, or annulus 92 into the reservoir at different points along the length of the injection well 12, thus facilitating control of the distribution of the pre-heated along the length of the injection well 12. The nozzles can include various types of splitters and/or outflow control devices. In the implementation shown in Figs 4A and 4B, the openings 48 are provided along the outer liner 52 to enable the pre-heated injection fluid 32 to flow along the outer annulus 40 to be injected into the surrounding reservoir.

[00143] As mentioned above, an electric resistance heater (not shown), such as a heat-tracing cable, can be provided in the injection well 12 and/or the production well 14 during the startup phase, or in the injection well 12 during the production phase. The electric resistance heaters can be used in combination with a closed-loop system as described herein. For example, one or more electric resistance heaters can be provided in the injection well 12 and/or the production well 14. The electric resistance heater can transfer heat to the injection well 12 and/or the production well 14 during startup, in addition to the heat provided by the closed-loop system. Alternatively, the electric resistive heater can be used before or after the circulation of the circulation fluid in the closed-loop system. When deployed in the production well during startup, the electric resistance heaters can be removed from the production well 14 once the startup phase is complete.

[00144] Additionally, the electric resistance heater can be used during the production phase to superheat the pre-heated injection fluid 32 as it travels downhole.
Furthermore, the resistance heater can be provided adjacent or proximal to (e.g., wrapped around) the injection tubing string 34 such that the resistance heater can provide constant or intermittent heat to the injection tubing string 34 to maintain a desired temperature of the pre-heated injection fluid 32. In some implementations, the electric resistance heater can provide heat to the injection tubing string 34 along the entire length of the horizontal portion of the injection well 12, or along a portion of the of the horizontal portion of the injection well 12.
Implementations related to enhanced heat generation Date recue / Date received 2021-12-03

[00145] Use of the heating unit 18 can vary through time, as the lifecycle of the recovery operations progresses in given well pairs or well pads. In some implementations, the heating unit 18 can be utilized for more than one well pair depending on the stage of the production lifecycle of a given one of the well pairs, a heat requirement of a given well of the well pairs, and/or the heating capacity of the heating unit 18. For instance, in some implementations, once the startup phase is completed for a given one of the well pairs, the heating unit 18 may have more capacity to provide heat to another one of the well pairs. Similarly, as the production phase progresses through time for a given well pair, the rate of injection of pre-heated injection fluid 32 may be decreased, such that the heating unit 18 can have an additional capacity to provide heat to another one of the well pairs.

[00146] In some implementations, various variables can be monitored to enhance distribution of heat from the heating unit to one or more well pairs. Such variables can include a heat requirement of an injection well and/or a production well of one or more well pairs (for example, by monitoring the requirement for heated circulation fluid or pre-heated injection fluid in the wells), a stage of production of an injection well and/or a production well of one or more well pairs, and/or a heating capacity of the heating unit.

[00147] For example, during the startup phase, a high heat requirement may be desirable to heat and mobilize bitumen surrounding the injection well and the production well, compared for instance to a later stage in the production phase. Once the startup phase is determined to be completed, the heating unit can receive instructions to cease circulation of the heated circulation fluid in the completion assembly and to supply the circulation fluid back to the heating unit. At this point, the heating unit can re-heat the circulation fluid, or a portion thereof, for use in another well pair or for continuing circulation of the heated circulation fluid during the production phase, and also pre-heat the injection fluid that is intended to be used during the production phase.
Then, as the production stage progresses through time, the rate of injection of pre-heated injection fluid can decline, such that the heating unit can be used to provide heat to other ones of the well pairs.

[00148] In some implementations, the heating unit described herein can include one or more units that can be used to provide heat to one or more well pairs.
Date recue / Date received 2021-12-03

[00149] The heating unit can be located on a well pad that includes one or more well pairs. In some implementations, the heating unit can be located on a given well pad and be configured to provide heat to adjacent well pads, e.g., in a hub and spoke design.

[00150] When the heating unit is located on a well pad, circulation fluid lines can provide the circulation fluid in liquid phase to the heating unit from a circulation fluid source or from the return circulation fluid that has condensed. This approach can be desirable to avoid maintaining the circulation fluid at a certain temperature during transportation to the well pad. In other words, when the circulation fluid comprises water, water can be supplied to the well pad via the circulation fluid lines, instead of having to transport steam over long distances to the well pad. Heated circulation fluid lines are also provided to transport the heated circulation fluid produced by the heating unit to the one or more well pairs of the well pad. Furthermore, injection fluid lines are provided to transport the pre-heated injection fluid produced by the heating unit, e.g., the heat exchanger, to the one or more well pairs of the well pad.

[00151] In other implementations, the heating unit can be located at a CPF, as described above with reference to Fig 2C. In such implementations, the heating unit can be designed and operated to provide a heated circulation fluid to a determined number of well pairs a single well pad, or to a determined number of well pairs distributed over multiple well pads.

[00152] When the heating unit is located at the CPF, heated circulation fluid lines can provide the heated circulation fluid from the heating unit to a determined number of well pairs a single well pad, or to a determined number of well pairs distributed over multiple well pads. Return circulation fluid lines are provided to supply the return circulation fluid from the well pairs back to the heating unit. Injection fluid lines are provided to transport the pre-heated injection fluid produced by the heating unit, e.g., the heat exchanger, to the injection wells of the well pairs.
Process implementation using completion assemblies

[00153] Referring now to Figs 6 and 7, an example of a process for mobilizing bitumen implemented using an integrated heating system configured to provide heat to various fluids such as a circulation fluid and an injection fluid will be described.
Date recue / Date received 2021-12-03

[00154] Fig 6 shows a well pair during a startup phase of the process. The well pair includes an injection well 12 and a production well 14. A completion assembly is deployed in the injection well 12, the completion assembly including an injection tubing string 34 and a closed-loop system 16 that includes an inner tubing string 42 and an outer tubing string 44. Another completion assembly is deployed in the production well 14, the completion assembly 14 including a closed-loop system 16.

[00155] Fig 7 shows the well pair of Fig 6 during a production phase of the process. In Fig 7, the completion assembly deployed in the injection well 12 during the production phase is the same as the completion assembly deployed in the injection well 12 during the startup phase, i.e., the completion assembly remains in the injection well 12 when the process transitions from the startup phase to the production phase. The production well 14 of Fig 7 shows the closed-loop system 16 removed therefrom.

[00156] In the illustrated implementation and similarly to what is described above, the injection well 12 includes a surface casing 56 in its vertical well section, and a liner 52 along the length of the horizontal portion of the injection well 12. The slotted liner 52 terminates near the toe end of the wellbore 38 in the injection well 12. The slotted liner 52 can include openings that enable the pre-heated injection fluid 32 to flow therethrough and into a surrounding area of the horizontal portion of the injection well 12. In other implementations, the slotted liner 52 can be omitted, such that the injection tubing string 34 extends within the wellbore 38, thereby allowing the pre-heated injection fluid 32 to be discharged within the wellbore 38 and directly contact bitumen contained in a surrounding area of the horizontal portion of the injection well 12. The horizontal portion of the injection well 12 includes a heel region 98 and a toe region 102, with a horizontal mid-region extending therebetween.

[00157] In the implementation shown in Fig 6, i.e., during the startup phase, the injection tubing string 34 extends within the liner 52 and along the horizontal portion of the injection well 12 down to the toe region 102, with the discharge end being in the toe region 102. The pre-heated injection fluid 32 flows through an intermediate annulus 50 defined between the outer surface of the outer tubing string 44 and the inner surface of the injection tubing string 34, and exits the slotted liner 52 to enter the area surrounding the injection well 12. In Fig 7, i.e., during the production phase, the configuration of the Date recue / Date received 2021-12-03 injection string 34 deployed in the injection well 12 remains the same as during the startup phase.

[00158] During the startup phase, as shown in Fig 6, a heated circulation fluid 24 produced by the heating unit located at surface can be introduced into the closed-loop system 16, resulting in heat 94 radiating from the closed-loop system 16 and into the area surrounding the injection well 12 and/or the production well 14. The heat 94 heats and mobilizes the bitumen in the area surrounding the wells. Once the bitumen in the area surrounding the production well 14 is mobilized, the closed-loop system 16 can be removed from the production well.

[00159] During the production phase, as shown in Fig 7, the heated circulation fluid 24 produced by the heating unit 18 can be used to pre-heat the injection fluid prior to introduction into the injection well 12. For example, the heated circulation fluid 24 can heat the injection fluid 26 received from an injection fluid source via a heat exchanger that is part of the heating unit 18 to produce a pre-heated injection fluid 32.

[00160] The pre-heated injection fluid 32 is injected into the injection well 12 through the injection tubing string 34. In some implementations, the heated circulation fluid 24 can be simultaneously or intermittently circulated through the closed-loop system 16 with the pre-heated injection fluid 32 to provide further heat to the pre-heated injection fluid 32. The pre-heated injection fluid 32 flows out openings defined in the injection tubing string 34, through the slotted liner 52, and into the area surrounding the injection well 12.
The pre-heated injection fluid 32 dissolves and mobilizes the bitumen, which produces a solvent-diluted bitumen or production fluid 96 that flows via gravity into the production well 14. The production fluid 96 can be pumped to the surface for processing.

[00161] It is noted that various implementations and features described herein can be combined together in various ways and used in various applications for recovering hydrocarbons or other materials from subterranean formations.

[00162] Several alternative implementations and examples have been described and illustrated herein. The implementations of the technology described above are intended to be exemplary only. A person of ordinary skill in the art would appreciate the features of the individual implementations, and the possible combinations and variations of the Date recue / Date received 2021-12-03 components. A person of ordinary skill in the art would further appreciate that any of the implementations could be provided in any combination with the other implementations disclosed herein. It is understood that the technology may be embodied in other specific forms without departing from the central characteristics thereof. The present implementations and examples, therefore, are to be considered in all respects as illustrative and not restrictive, and the technology is not to be limited to the details given herein. Accordingly, while the specific implementations have been illustrated and described, numerous modifications come to mind.
Date recue / Date received 2021-12-03

Claims (61)

37

1. A process for recovering hydrocarbons from a hydrocarbon-containing reservoir using a well pair comprising an injection well overlying a production well, the process comprising:
heating a circulation fluid using a heating unit located at surface to produce a heated circulation fluid;
circulating the heated circulation fluid via a circulation system deployed in at least one of the injection well and the production well to heat the hydrocarbons surrounding the at least one of the injection well and the production well;
pre-heating an injection fluid using the heating unit to produce a pre-heated injection fluid;
introducing the pre-heated injection fluid into the hydrocarbon-containing reservoir via an injection tubing string provided in the injection well to dissolve and mobilize the bitumen; and recovering a production fluid comprising diluted hydrocarbons via the production well.

2. The process of claim 1, wherein circulating the heated circulation fluid into the at least one of the injection well and the production well comprises:
introducing the heated circulation fluid into the circulation system;
circulating the heated circulation fluid in the circulation system; and supplying a return circulation fluid back to the heating unit.

3. The process of claim 2, further comprising heating the return circulation fluid to produce a heated return circulation fluid, the heated return circulation fluid corresponding to the heated circulation fluid.

4. The process of claim 2 or 3, wherein pre-heating the injection fluid using the heating unit comprises supplying the heated circulation fluid and the injection fluid to a heat exchanger to produce the pre-heated injection fluid.

5. The process of claim 2 or 3, wherein pre-heating the injection fluid using the heating unit comprises supplying the injection fluid and a portion of the heated circulation fluid to a heat exchanger to produce the pre-heated injection fluid.

6. The process of claim 2 or 3, wherein pre-heating the injection fluid using the heating unit comprises supplying the injection fluid and substantially all of the heated circulation fluid to a heat exchanger to produce the pre-heated injection fluid.

7. The process of any one of claims 1 to 6, wherein the circulation system comprises a closed-loop system.

8. The process of any one of claims 1 to 6, wherein the circulation system comprises an open-loop system.

9. The process of any one of claims 1 to 6, wherein the circulation system comprises a dual mode circulation system operable in a closed-loop mode and an open-loop mode.

10. The process of any one of claims 1 to 9, wherein circulating the heated circulation fluid is performed in the injection well.

11. The process of claim 10, further comprising heating the pre-heated injection fluid travelling downhole in the injection well while the heated circulation fluid is being circulated in the injection well to further heat the pre-heated injection fluid.

12. The process of any one of claims 1 to 11, wherein the heating unit is provided at a well pad.

13. The process of any one of claims 1 to 11, wherein the heating unit is provided at a central processing facility.

14. The process of claim 12 or 13, wherein the heating unit is configured to supply heat to the well pair and to at least one additional well pair of the well pad.

15. The process of claim 12 or 13, wherein the heating unit is configured to supply heat to the well pair and to at least one additional well pair of an additional well pad.

16. The process of claim 14 or 15, further comprising introducing the heated circulation fluid into the at least one additional well pair.

17. The process of claim 16, further comprising monitoring respective heat requirements for the well pairs and the at least one additional well pair, and adjusting an injection rate of the pre-heated injection fluid into a corresponding injection well of the well pair and the at least one additional well pair based on the respective heat requirements.

18. The process of claim 16, further comprising monitoring a corresponding stage of production for each of the well pair and the at least one additional well pair, and adjusting an injection rate of the pre-heated injection fluid into a corresponding injection well of the well pair and the at least one additional well pair based on the corresponding stage of production.

19. The process of any one of claims 16 to 18, further comprising monitoring an available heating capacity of the heating unit, wherein the circulation fluid is heated and circulated in a corresponding injection well of the well pair and the at least one additional well pair based on the available capacity of the heating unit.

20. The process of any one of claims 16 to 19, further comprising adjusting at least one of heating the circulation fluid, circulating the heated circulation fluid, pre-heating the injection fluid, and injecting the pre-heated injection fluid based on the monitoring.

21. The process of any one of claims 1 to 20, wherein the at least one of the injection well and the production well is the injection well and the production well, and the process further comprises removing the circulation system from the production well following completion of a startup phase.

22. The process of any one of claims 1 to 21, wherein the heated circulation fluid comprises steam.

23. The process of claim 22, wherein the heating unit comprises a steam generator.

24. The process of claim 23, wherein the steam generator comprises at least one of a once-through steam generator (OTSG), a drum boiler, and a direct-fired steam generator (DFSG).

25. The process of any one of claims 22 to 24, further comprising supplying water to the heating unit for producing the steam.

26. The process of any one of claims 1 to 25, wherein the injection fluid comprises a solvent.

27. The process of claim 26, wherein the solvent comprises a paraffinic solvent.

28. The process of claim 27, wherein the solvent comprises pentane.

29. The process of claim 27, wherein the solvent comprises butane.

30. The process of claim 27, wherein the solvent comprises propane.

31. The process of any one of claims 1 to 30, wherein the hydrocarbons comprise bitumen, heavy oil, or a combination thereof.

32. A process for recovering hydrocarbons from a hydrocarbon-containing reservoir using a well pair comprising an injection well overlying a production well, the process comprising:
heating a circulation fluid using a heating unit located at a surface to produce a heated circulation fluid;
circulating the heated circulation fluid in a closed-loop system provided in at least one of the injection well and the production well to heat the hydrocarbons surrounding the at least one of the injection well and the production well;

supplying a return circulation fluid from the closed-loop system back to the heating unit for re-heating to produce the heated circulation fluid;
pre-heating an injection fluid using the heated circulation fluid to produce a pre-heated injection fluid;
injecting the pre-heated injection fluid into the hydrocarbon-containing reservoir through the injection well to dissolve and mobilize the hydrocarbons;
and recovering a production fluid comprising diluted hydrocarbons via the production well.

33. The process of claim 32, wherein the closed-loop system is provided in the injection well.

34. The process of claim 32 or 33, wherein the heated circulation fluid is further circulated in an additional closed-loop system provided in the production well.

35. The process of claim 34, further comprising removing the additional closed-loop system from the production well after the return circulation fluid has been supplied back to the heating unit following completion of a startup phase.

36. The process of any one of claims 32 to 35, wherein pre-heating the injection fluid using the heating unit comprises supplying the heated circulation fluid and the injection fluid to a heat exchanger to produce the pre-heated injection fluid.

37. The process of any one of claims 32 to 36, further comprising heating the pre-heated injection fluid travelling downhole in the injection well while the heated circulation fluid is being circulated in the injection well to further heat the pre-heated injection fluid.

38. The process of any one of claims 32 to 37, wherein the heated circulation fluid comprises steam.

39. The process of claim 38, wherein the heating unit comprises a steam generator.

40. The process of claim 39, wherein the steam generator comprises at least one of a once-through steam generator (OTSG), a drum boiler, and a direct-fired steam generator (DFSG).

41. The process of any one of claims 32 to 40, wherein the injection fluid comprises a solvent.

42. The process of any one of claims 32 to 41, wherein the hydrocarbons comprise bitumen, heavy oil, or a combination thereof.

43. An integrated heating system for recovering hydrocarbons from a hydrocarbon-containing reservoir using a well pair comprising an injection well overlying a production well, the integrated heating system comprising:
a heating unit located at surface and configured to heat a circulation fluid to produce a heated circulation fluid and to pre-heat an injection fluid to produce a pre-heated injection fluid;
a closed-loop system in fluid communication with the heating unit and positionable in at least one of the injection well and the production well to heat hydrocarbons surrounding the at least one of the injection well and the production well, the closed-loop system comprising an introduction tubing string and a return tubing string in fluid communication with each other; and an injection tubing string in fluid communication with the heating unit and positionable along at least a portion of the injection well, the injection tubing string being configured for injecting the pre-heated injection fluid into the hydrocarbon--containing reservoir to dissolve and mobilize hydrocarbons.

44. The integrated heating system of claim 43, wherein the heating unit comprises a heat exchanger configured to transfer heat from at least a portion of the heated circulation fluid to the injection fluid.

45. The integrated heating system of claim 43 or 44, wherein the introduction tubing string is arranged within the return tubing string and an inner annulus is defined between the introduction tubing string and the return tubing string, and wherein the introduction tubing string comprises an open end near a toe of the at least one well and the return tubing comprises a closed end near the toe of the at least one of the injection well and the production well.

46. The integrated heating system of claim 43 or 44, wherein the return tubing string is arranged within the introduction tubing string and an inner annulus is defined between the introduction tubing string and the return tubing string, and wherein the return tubing string comprises an open end near a toe of the at least one well and the introduction tubing comprises a closed end near the toe of the at least one of the injection well and the production well.

47. The integrated heating system of claim 45 or 46, further comprising a fluid inflow control device positioned proximate to the open end to control a rate at which the heated circulation fluid is introduced into the inner annulus.

48. The integrated heating system of any one of claims 43 to 47, wherein the closed-loop system further comprises an outer tubing string, wherein the introduction tubing string and the return tubing string are arranged inside the outer tubing string.

49. The integrated heating system of any one of claims 43 to 48, further comprising insulation disposed around at least one of the introduction tubing string and the return tubing string.

50. The integrated heating system of claim 49, wherein the at least one of the introduction tubing string and the return tubing string comprises a vacuum insulated tubing.

51. The integrated heating system of any one of claims 43 to 50, wherein the closed-loop system is positioned in the injection well adjacent to at least a portion of the injection tubing string and is configured to provide indirect heat to the pre-heated injection fluid.

52. The integrated heating system of claim 51, wherein the closed-loop system is provided inside the injection tubing string, thereby forming an intermediate annulus between an outer surface of the closed-loop system and the injection tubing string.

53. The integrated heating system of any one of claims 43 to 52, wherein the injection tubing string comprises outlets along a length thereof for injecting the pre-heated injection fluid at multiple locations along the injection well.

54. The integrated heating system of claim 53, wherein the outlets comprise nozzles.

55. The integrated heating system of any one of claims 43 to 54, wherein the heating unit further comprises a steam generator to produce steam as the heated circulation fluid.

56. The integrated heating system of claim 54, wherein the steam generator comprises at least one of a once-through steam generator (OTSG), a drum boiler, and a direct-fired steam generator (DFSG).

57. The integrated heating system of any one of claims 43 to 56, wherein the hydrocarbons comprise bitumen, heavy oil, or a combination thereof.

58. An integrated heating system for mobilizing hydrocarbons in a hydrocarbon-containing reservoir using a well pair comprising an injection well overlying a production well, the system comprising:
a heating unit located at surface, the heating unit comprising:
a circulation fluid heater configured to heat a circulation fluid to produce a heated circulation fluid; and a heat exchanger configured to receive the heated circulation fluid as a heat exchange fluid to heat an injection fluid via transfer of heat from the heated circulation fluid to the injection fluid to produce a pre-heated injection fluid;
an injection tubing string positionable along at least a portion of the injection well and configured to be in fluid communication with the heat exchanger for injecting the pre-heated injection fluid into the hydrocarbon-containing reservoir; and a closed-loop system positionable proximal to the injection tubing string in the injection well, the closed-loop system comprising an introduction tubing string and a return tubing string in fluid communication with each other, the introduction tubing string being configured to be in fluid communication with the circulation fluid heater to receive the heated circulation fluid and the return tubing string being configured to be in fluid communication with the circulation fluid heater to supply a return circulation fluid thereto.

59. The integrated heating system of claim 58, further comprising an additional closed-loop system comprising an additional introduction tubing string and an additional return tubing string, wherein the additional closed-loop system is configured to be arranged in the production well and the additional introduction tubing string is in fluid communication with the heating unit to receive the heated circulation fluid and the additional return tubing string is in fluid communication with the heating unit to supply the return circulation fluid to the heating unit.

60. The integrated heating system of claim 58 or 59, wherein the closed-loop system is arranged within the injection tubing string and an outer wall of the closed-loop system defines an outer annulus with the injection tubing string and wherein the outer annulus is configured to receive the pre-heated injection fluid.

61. The integrated heating system of any one of claims 58 to 60, wherein the hydrocarbons comprise bitumen, heavy oil, or a combination thereof.