CA3101890C - Solvent dominated in situ recovery process with intermittent steam slug co-injection - Google Patents

Abstract

Processes and related systems for recovering heavy hydrocarbons from a subsurface reservoir, including injecting solvent in vapour phase via an injection well/conduit into the reservoir to dissolve and mobilize heavy hydrocarbons to define solvent dominated injection cycles; in between solvent dominated injection cycles, co-injecting steam along with the solvent via the injection well in the form of steam slugs defining slug cycles, and producing mobilized heavy hydrocarbons and condensed fluid via a production well/conduit. The amount of steam that is injected in the reservoir is such that the injection remains solvent dominated throughout the recovery operation.

Description

SOLVENT DOMINATED IN SITU RECOVERY PROCESS WITH INTERMITTENT
STEAM SLUG CO-INJECTION
TECHNICAL FIELD
[001] The technical field generally relates to in situ recovery of heavy hydrocarbons from underground reservoirs, and more particularly to a solvent dominated process that includes intermittent co-injection of steam slugs.
BACKGROUND

[002] Various in situ recovery processes use the injection of a fluid, such as steam, solvent, non-condensable gas, to enhance mobilization and recovery of heavy hydrocarbons, such as bitumen.

[003] Steam assisted gravity drainage (SAGD) is a conventional process that involves the injection of steam via an injection well that overlies a production well to form a steam chamber and promote gravity drainage of fluids toward the production well.
Other in situ recovery processes, such as expanding solvent SAGD (ES-SAGD), use steam and solvent co-injection. Still other in situ recovery processes involve the injection of relatively pure solvent in vapour phase to heat and dissolve bitumen to promote recovery.
In addition, steam injection, solvent injection or steam-solvent co-injection can be performed cyclically with injection and production cycles via the same well.

[004] There remain a number of challenges in terms of the efficient and economical recovery of heavy hydrocarbons, such as bitumen, from subsurface reservoirs.
SUMMARY

[005] In one aspect, there is provided a process for recovering bitumen from a subsurface reservoir via a well pair comprising a production well underlying an injection well. The process includes:
injecting substantially only solvent in vapour phase via the injection well into the reservoir to dissolve and mobilize bitumen in the reservoir;
intermittently co-injecting steam along with the solvent via the injection well in the form of steam slugs defining slug cycles; and Date Recue/Date Received 2020-12-08 producing mobilized bitumen and condensed fluid via the production well.

[006] Optionally, the solvent can include a paraffinic solvent. Further optionally, the solvent can include a C3 to C6 paraffin. For example, the solvent can be pentane. In another example, the solvent can be butane. In another example, the solvent can be propane. In another example, the solvent can include dimethyl ether.

[007] In some implementations, the process can include generating steam and solvent in vapour phase separately before injection thereof via the injection well.

[008] In some implementations of the process, the slug cycles can be each performed for a same duration. In other implementations of the process, at least some of the slug cycles can be performed for different durations compared to each other. For example, the duration of each slug cycle can increase from one slug cycle to a next slug cycle.

[009] In some implementations, the process can include controlling initiation and duration of each slug cycle to reduce or minimize a solvent-to-oil ratio of the process.
Optionally, the process can include initiating a slug cycle upon monitoring an increase of the solvent-to-oil ratio.

[010] In some implementations, the process can further include controlling initiation and duration of each slug cycle to reduce or minimize a steam-to-oil ratio of the process.

[011] In some implementations, the process can include controlling initiation and duration of each slug cycle to maintain solvent dominated process conditions.

[012] In some implementations of the process, co-injection of the steam slugs according to the slug cycles can be initiated after a start-up stage and ceased prior to mature operation of the well pair.

[013] In some implementations, the process can include starting co-injecting solvent and a steam slug as a first slug cycle when a production stage of the well pair is reached.

[014] In some implementations of the process, at least 15 slug cycles can be performed.

[015] In some implementations of the process, for each slug cycle, the steam and the solvent can be combined at surface to form a co-injection mobilizing fluid which is then introduced down the injection well. In other implementations of the process, for each slug Date Recue/Date Received 2020-12-08 cycle, the steam and the solvent can be combined down the injection well for form a co-injection mobilizing fluid within the injection well. Optionally, the co-injection mobilizing fluid can include about 5 mol% to about 70 mol% steam. Further optionally, the co-injection mobilizing fluid can consist essentially of the solvent and the steam.

[016] In some implementations of the process, at least one of the slug cycles can include injecting the co-injection mobilizing fluid with an additional fluid.
Optionally, the additional fluid can include a non-condensable gas. Further optionally, the additional fluid can include exhaust gases from combustion of a fuel.

[017] In some implementations, the process can further include varying the composition of the co-injection mobilizing fluid during a given slug cycle. Optionally, the process can include varying the composition of the co-injection mobilizing fluid for each slug cycle.

[018] In some implementations, the process can further include selecting a steam content of the co-injection mobilizing fluid for each slug cycle based on monitoring of the solvent-to-oil ratio. Optionally, the process can include increasing the steam content during a given slug cycle in response to an increase in the solvent-to-oil ratio.

[019] In some implementations, the process can include generating superheated steam before being combined with the solvent in vapor phase for co-injection.

[020] In some implementations, the process can include heating the solvent to at least a saturation temperature thereof at a reservoir operation pressure.

[021] In some implementations of the process, the solvent and the steam can be injected at an injection pressure between 500 and 1100 kPa. Optionally, the injection pressure can be between 50 kPa and 200 kPa higher than an operation pressure of the reservoir.

[022] In some implementations of the process, the solvent can be a single solvent compound that is purified at surface before injection. Optionally, the solvent that is injected can be at least 98% pure. Further optionally, the solvent that is injected can be at least 99% pure. Further optionally, the solvent that is injected can be at least 99.5% pure.

[023] In some implementations of the process, the solvent is injected into the reservoir to produce an extraction chamber at a temperature that can be between about 40 C and about 80 C.

Date Recue/Date Received 2020-12-08

[024] In some implementations of the process, the solvent can be recovered in a Central Processing Facility (CPF) which receives the mobilized bitumen and condensed fluids recovered via the production well and for separation thereof to produce the recovered solvent that is reused for injection.

[025] In some implementations of the process, the steam can be generated from process water recovered in a Central Processing Facility (CPF) which receives the mobilized bitumen and condensed fluids recovered via the production well and for separation thereof to produce the process water.

[026] In some implementations of the process, the solvent and the steam can be in vapour phase prior to supplying into the injection well. Optionally, the steam can be generated by a direct-contact steam generator (DCSG). Further optionally, the steam can be generated by a once-through steam generator (OTSG). For example, the process can include generating the steam using a portable steam generator located proximate to the well pair.

[027] In other implementations of the process, the solvent can be vaporized within the injection well prior to injection into the reservoir. Optionally, the steam can be generated within the injection well prior to injection into the reservoir. For example, the injection well can include a heater that heats the injection well to a temperature between 200 C and 280 C. The heater can include an electric resistance heater, or include a closed-loop fluid heater for circulating a heating fluid therein.

[028] In some implementations of the process, the well pair can be part of an oilfield with multiple well pairs. Optionally, the process can further include supplying steam to a first set of the well pairs for a corresponding first slug cycle, and then ceasing steam supply to the first set of the well pairs and supplying steam to a second set of the well pairs for a corresponding second slug cycle that is off-set with respect to the first slug cycle.

[029] In some implementations, the process can be operated to obtain a cumulative solvent-to-oil recovery at least 20% lower than for bitumen recovery with continuous injection of the solvent only.

Date Recue/Date Received 2020-12-08

[030] In some implementations, the process can be operated such that cumulative solvent requirements are higher than cumulative steam requirements over cyclic operation of the process.

[031] In another aspect, there is provided a process for recovering heavy hydrocarbons from a subsurface reservoir. The process includes:
injecting solvent in vapour phase in the absence of steam via an injection well into the reservoir to dissolve and mobilize heavy hydrocarbons in the reservoir;
intermittently injecting fluid slugs concomitantly with the solvent via the injection well, the fluid slugs comprising a mobilizing vapour having a higher latent heat capacity compared to the solvent; and producing mobilized heavy hydrocarbons and condensed fluid via a production well underlying the injection well.

[032] In some implementations of the process, the mobilizing vapour can include steam.

[033] In some implementations of the process, the mobilization vapour can include at least one compound having a latent heat capacity of at least 2% greater than the solvent.

[034] In some implementations of the process, the heavy hydrocarbons can include bitumen.

[035] The process can further include any features defined in relation to the first aspect of the process above.

[036] In another aspect, there is provided a system for recovering heavy hydrocarbons from a subsurface reservoir. The process includes:
a well pair comprising:
an injection well; and a production well underlying the injection well in the reservoir;
a fluid supply assembly at surface and in fluid communication with the injection well, the fluid supply assembly comprising:
Date Recue/Date Received 2020-12-08 a solvent supply line, and a steam supply line; and a control assembly coupled to the fluid supply assembly and configured to:
continuously feed only solvent from the solvent supply line into the injection well to inject the solvent in vapour phase into the reservoir to dissolve and mobilize heavy hydrocarbons in the reservoir; and intermittently co-feed steam from the steam supply line into the injection well in the form of steam slugs that enter the reservoir with the solvent.

[037] In some implementations, the system can further include a heating assembly to heat water to at least a saturation temperature thereof at an operation pressure of the reservoir to produce at least a portion of the steam. Optionally, the heating assembly can include a modular steam generator located at surface to generate steam prior to passing into the injection well. For example, the modular steam generator can be a direct-contact steam generator (DCSG). In another example, the modular steam generator can be a once-through steam generator (OTSG).

[038] In some implementations of the system, the heating assembly can further heat solvent to at least a saturation temperature thereof at an operation pressure of the reservoir to produce at least a portion of the solvent in vapour phase.

[039] Optionally, the heating assembly can include at least one heater located downhole to generate steam upon passing into the injection well. Further optionally, the heating assembly can include at least one heater located downhole to generate solvent vapour upon passing into the injection well. For example, the at least one heater can be configured to heat a near wellbore region surrounding the injection well to a temperature between 200 C and 280 C.

[040] In some implementations of the system, at least one of the steam supply line and solvent supply line can be in fluid communication with a Central Processing Facility (CPF) separating solvent and/or water from a condensed fluid recovered by the production well.

Date Recue/Date Received 2020-12-08

[041] In some implementations of the system, the heavy hydrocarbons can include bitumen.

[042] In another aspect, there is provided a process for recovering bitumen from a subsurface reservoir via a single well comprising a production section adjacent to an injection section. The process includes:
injecting substantially only solvent in vapour phase via the injection section into the reservoir to dissolve and mobilize bitumen in the reservoir;
intermittently co-injecting steam along with the solvent via the injection section in the form of steam slugs; and producing mobilized bitumen and condensed fluid via the production section.

[043] In some implementations of the process, the single well can further include multiple injection sections and multiple production sections distributed along and within an annulus of the single well, the production sections being staggered with respect to the injection sections and being axially separated therefrom, and the process comprising:
injecting the solvent in vapour phase from the multiple injection sections into the reservoir, intermittently co-injecting the steam slugs from the multiple injection sections into the reservoir; and producing the mobilized bitumen and the condensed fluid from the multiple production sections.

[044] In another aspect, there is provided a process for recovering bitumen from a subsurface reservoir via a well pair comprising a production well underlying an injection well. The process includes:
injecting a solvent dominated fluid in vapour phase via the injection well into the reservoir to dissolve and mobilize bitumen in the reservoir, to define a solvent dominated injection cycle;

Date Recue/Date Received 2020-12-08 in between solvent dominated injection cycles, co-injecting steam along with the solvent via the injection well in the form of steam slugs defining slug cycles, wherein a steam content during the slug cycles is greater than a steam content of the solvent dominated fluid during the solvent dominated injection cycles; and producing mobilized bitumen and condensed fluid via the production well.

[045] In some implementations of the process, the solvent dominated fluid can include steam. Optionally, the solvent dominated fluid can include 1 mol% to 10 mol%
steam.

[046] In some implementations of the process, the steam content during each slug cycle can be at least double the steam content during the corresponding previous solvent dominated injection cycle.

[047] In some implementations of the process, the solvent can include a paraffinic solvent. Optionally, the solvent can be butane. Further optionally, the solvent can be propane. Further optionally, the solvent can include dimethyl ether.

[048] In some implementations of the process, the duration of each slug cycle increases from one slug cycle to a next slug cycle.

[049] In some implementations of the process, at least 15 slug cycles can be performed.

[050] In some implementations of the process, for each slug cycle, the steam and the solvent can be combined at surface to form a co-injection mobilizing fluid which is then introduced down the injection well. In other implementations of the process, for each slug cycle, the steam and the solvent can be combined down the injection well for form a co-injection mobilizing fluid within the injection well. Optionally, the co-injection mobilizing fluid can include about 5 mol% to about 70 mol% steam. Further optionally, the co-injection mobilizing fluid can include about 20 mol% to about 50 mol% steam. Further optionally, the co-injection mobilizing fluid can consist essentially of the solvent and the steam.

[051] In some implementations of the process, at least one of the slug cycles can include injecting the co-injection mobilizing fluid with an additional fluid.
Optionally, the additional fluid can include a non-condensable gas. Further optionally, the additional fluid can include exhaust gases from combustion of a fuel.

Date Recue/Date Received 2020-12-08

[052] In some implementations, the process can include varying the composition of the co-injection mobilizing fluid during a given slug cycle. Optionally, the process can include varying the composition of the co-injection mobilizing fluid for each slug cycle.

[053] In some implementations, the process can include selecting the steam content of the co-injection mobilizing fluid for each slug cycle based on monitoring of the solvent-to-oil ratio. Optionally, the process can include increasing the steam content during a given slug cycle in response to an increase in the solvent-to-oil ratio.

[054] In some implementations, the process can include generating superheated steam before being combined with the solvent in vapor phase for co-injection.

[055] In some implementations, the process can include heating the solvent to at least a saturation temperature thereof at a reservoir operation pressure.

[056] In some implementations of the process, the solvent and the steam can be injected at an injection pressure between 500 and 1100 kPa.

[057] In some implementations of the process, the solvent can be a single solvent compound that is purified at surface before injection.

[058] In some implementations of the process, the solvent that is injected can be at least 98% pure.

[059] In some implementations of the process, the solvent can be injected into the reservoir to produce an extraction chamber at a temperature between about 40 C
and about 80 C.
BRIEF DESCRIPTION OF THE DRAWINGS

[060] Figure 1 is a cross-sectional view schematic of a well assembly including a well pair extending within a bitumen-containing reservoir.

[061] Figure 2 is a top perspective view schematic of a well assembly including a well pair extending within a bitumen-containing reservoir showing expansion of an extraction chamber.

Date Recue/Date Received 2020-12-08

[062] Figure 3 is a cross-sectional view schematic of an injection well, containing separate steam supply line and solvent supply line, extending within a bitumen-containing reservoir.

[063] Figure 4 is a cross-sectional view schematic of a well assembly including a single well extending within a bitumen-containing reservoir.

[064] Figure 5 is a schematic process flow diagram illustrating an implementation of the solvent dominated process.

[065] Figure 6 is a schematic process flow diagram illustrating another implementation of the solvent dominated process.

[066] Figure 7 is a graph of oil recovery rate (in m3/day) versus time (in years) when injecting pentane and co-injecting steam according to the present solvent dominated process in comparison to pentane injection only.

[067] Figure 8 is a graph of cumulative solvent injection (in m3) versus time (in years) when injecting pentane and co-injecting steam according to the present solvent dominated process in comparison to pentane injection only.

[068] Figure 9 is a graph of cumulative solvent to oil recovery (CSvOR) versus time (in years) when injecting pentane and co-injecting steam according to the present solvent dominated process in comparison to pentane injection only.

[069] Figure 10 is a graph of CSvOR versus time (in years) when injecting pentane and co-injecting 10 mol% steam according to the present solvent dominated process in comparison to continuously co-injecting pentane and 10 mol% steam.

[070] Figure 11 is a graph of cumulative oil recovery (in m3) versus time (in years) when injecting pentane and co-injecting steam according to the present solvent dominated process in comparison to pentane injection only.

[071] Figure 12 is a graph of oil recovery rate (in m3/day) versus time (in years) when injecting butane and co-injecting steam according to the present solvent dominated process in comparison to butane injection only.
Date Recue/Date Received 2020-12-08

[072] Figure 13 is a graph of CSvOR versus time (in years) when injecting butane and co-injecting steam according to the present solvent dominated process in comparison to butane injection only.

[073] Figure 14 is a graph of CSvOR versus time (in years) when injecting butane and co-injecting 10 mol% steam according to the present solvent dominated process in comparison to continuously co-injecting butane and 10 mol% steam.

[074] Figure 15 is a graph of cumulative oil recovery (in m3) versus time (in years) when injecting butane and co-injecting steam according to the present solvent dominated process in comparison to butane injection only.

[075] Figure 16 is a graph of cumulative oil recovery (in m3) versus time (in years) when injecting butane or pentane and co-injecting steam according to the present solvent dominated process.
DETAILED DESCRIPTION

[076] The present description relates to techniques for recovering heavy hydrocarbons, such as bitumen, using a solvent dominated process including intermittent co-injection of steam. The steam being co-injected over a given period of time with the solvent can be generally referred to as a steam slug. It is noted that the process is qualified as solvent dominated because solvent is continuously injected while steam slugs are intermittently co-injected to provide additional energy input, while not transitioning to a steam dominated process. The cumulative solvent injection is higher than the cumulative steam injection during operation of the process such that the process remains solvent dominated.

[077] The main recovery mechanism is thus solvent driven due to diffusion and dissolution of the solvent into the heavy hydrocarbons, such as bitumen, that reduces viscosity and mobilize the heavy hydrocarbons. Heat can be additionally provided for a given period of time to the mobilizing mixture by co-injecting intermittently steam (steam slug) to maximize the performance of the recovery while minimizing the overall solvent-to-oil ratio. Indeed, the intermittent nature of steam co-injection facilitates a reduction of the steam requirements in comparison to conventional steam-based recovery processes (e.g., SAGD) and steam/solvent-based recovery processes (e.g., ES-SAGD), for a similar Date Recue/Date Received 2020-12-08 oil recovery. In addition, it has been found that the overall solvent-to-oil ratio can be lower compared to conventional solvent-based recovery processes for a similar oil recovery.
Well assembly implementations

[078] The solvent dominated process can be implemented in various well assemblies adapted for in situ recovery of heavy hydrocarbons. Referring to Figures 1 and 4, these well assemblies 2 include a well pair (Figures 1 to 3) or a single well (Figure 4).

[079] In some implementations, the process can be performed in a well pair, as shown in Figure 1, that includes an injection well 4 overlying a production well 6 for gravity-based recovery. Both of the wells 4 and 6 have a section horizontally extending within the reservoir 10. An injection tubing string 8 can extend along and within the injection well 4 so as to provide at least one mobilizing fluid within the injection well 4 for injection into the reservoir 10. A production tubing string 12 can extend along and within the production well 6 to recover a production fluid that includes mobilized heavy hydrocarbons and condensed mobilizing fluid.

[080] It is also noted that various well completions can be used for the injection and production wells, depending on various factors. For example, additional equipment to what is described herein or illustrated in Figure 1 can be included in a dual-well completion, such as casing, liner, packing elements, instrumental lines, and so on. The implementation illustrated in Figure 1 shows delivery of the mobilizing fluid via an open end of the tubing string 8 at a toe of the injection well 4. However, it is noted that the number, positioning and configuration of the injection tubing strings can be modified to change the injection pattern of the mobilizing fluids. For example, tubing strings can be arranged to release the mobilizing fluid into the annulus at different points along the injection well 4, e.g., near the heel and the toe, in order to enhance conformance along the well.

[081] In other implementations, the process could also be operated in a single well, such as the well shown in Figure 4. The single well 200 can include an injection conduit 80 extending concentrically along and within a production conduit 120. The mobilizing fluid is injected from the injection conduit 80 into the reservoir via injection sections 202 of the well 200. Mobilized and condensed fluids are produced from the reservoir 10 via the production conduit 120 from production sections 204 of the well 200. Thus, the mobilizing fluid is injected via the injection sections 202 into corresponding injection regions of the Date Recue/Date Received 2020-12-08 reservoir, and mobilized fluids then flow from adjacent regions of the reservoir into the production sections 204 and then into the production conduit 120 for recovery to the surface. The injection sections 202 can be separated from production sections 204 with packing modules 206. The single well can be configured and operated similarly to the well as described in CA 2.965.633 and CA 3.022.710, using solvent and slug cycles, as will be further described herein. In the case of single-well operation, techniques described herein with respect to the injection well or the production well of a well pair can be applied or readily adapted to the injection conduit and section or the production conduit and section of the single well.

[082] It is noted that the well assemblies shown in Figures 1 to 4 are for illustrative purposes. Other well assemblies including vertical wells, infill wells, step-out wells, multilateral wells, slanted wells, and so on, are also contemplated and could be used in the context of the solvent dominated process with steam slugs as described herein. The techniques that are described herein in relation to dual-well assemblies can be used in or adapted to any of the other above-mentioned well configurations.
Cyclic operation implementations

[083] Conventional solvent-assisted processes were developed in part to reduce water requirements of steam based processes, such as SAGD, and thus reduce energy costs related to heating water to make steam. However, in solvent-based processes, the total oil recovery and/or the oil recovery rate can be lower than with SAGD. In addition, since the solvent is a more expensive fluid than water, solvent processes have other challenges in terms of solvent-to-oil ratio and solvent usage. The solvent dominated process proposed herein includes intermittently injecting steam while continuously injecting solvent during a production stage of an in situ recovery operation, which can facilitate reducing solvent requirements while benefiting from the energy of the injected steam as well as leveraging the benefits of solvent dominated operation.

[084] The solvent dominated process includes continuous injection of solvent and intermittent injection of steam which is operated periodically, thereby defining a solvent-domintaed operation. More specifically, the recovery process is operated for given periods of time during which solvent is injected in vapour phase into the reservoir, and other periods of time during which solvent in vapour phase and steam are co-injected into the Date Recue/Date Received 2020-12-08 reservoir. The period of time during which only solvent is injected into the reservoir is referred to herein as a solvent-dominated period or cycle, and the period of time during which both solvent and steam are injected into the reservoir is referred to as a slug period or cycle. Therefore, in the context of the present techniques, steam is used as a supplemental mobilizing fluid and is not injected alone (i.e. in absence of solvent) during a production phase of the recovery.

[085] The well assembly can operate under gravity based mechanisms where the injected mobilizing fluid or mixture rises within an extraction chamber, condenses on the bitumen to mobilize the bitumen, and facilitates drainage toward an underlying production region in fluid communication with the production well or conduit.

[086] Referring to the well assembly 2 illustrated in Figure 1, the solvent-dominated operation of the process can begin with injection of pure solvent that is supplied within the injection well 4, e.g., via the injection tubing string 8 serving as a solvent supply line, for injection of the solvent as vapour from the injection well 4 into the reservoir 10. Solvent-only injection can be maintained for a period of time sufficient to establish solvent dominated process conditions in the reservoir.

[087] Referring to Figure 2, the solvent dominated process conditions are established via the injection of the pure solvent as vapour within the injection well 4, the solvent vapour passing into the reservoir 10 from the injection well 4 and forming over time an extraction chamber 14 in which the solvent vapour rises and condenses at the cool surface of the extraction chamber 14, thus warming and dissolving bitumen from the reservoir 10. The solvent can be injected such that the extraction chamber 14 is at a temperature between about 40 C and about 80 C, for example, although other operating conditions are possible and can depend on the type of solvent used for the process. The resulting mobilized bitumen then drains by gravity to the production well 6 along with a portion of the condensed solvent.

[088] The solvent dominated process can further include a slug cycle that is initiated once the solvent dominated process conditions are established. In one implementation, the slug cycle includes the addition of steam to the stream of injected solvent, so that steam and solvent vapour are co-injected into the reservoir during the slug cycle. The mixture of co-injected steam and solvent can be referred to herein as a co-injection Date Recue/Date Received 2020-12-08 mobilizing fluid. It is still noted that injection of solvent as vapour is maintained during and the whole operation of the process, including during slug cycles. Steam can thus be added during each slug cycle, such that steam slugs are injected intermittently during the cyclic operation of the process to provide latent energy surges. The bitumen is thus further heated to reduce its viscosity while also helping to retain solvent in the extraction chamber.

[089] In some implementations, each slug cycle can involve adding only steam to the pure solvent, such that the resulting co-injection mobilizing fluid is essentially only two components, with at most 2 mol% or at most 1 mol% of other compounds for example.

[090] Referring to Figure 1, the steam can be added at surface into the injection tubing string 8 line via a steam supply line 14 while solvent is provided via a solvent supply line 16, so that a mixture of steam and solvent vapour is introduced into the injection well 4 and then into the extraction chamber. The steam and solvent supply lines can be joined at a simple T-junction or at a dedicated vessel that is in fluid communication with the injection well 4. In this implementation, the steam-solvent mixture is fed to the wellhead via a single pipeline for introduction down the injection well.

[091] Alternatively, the steam and solvent can be supplied to the injection well 4 separately and then mixed together within the injection well. In one example, the steam and solvent supply lines can both feed into the wellhead such that the two fluids are combined in an up-hole region of the injection well, e.g., in the vertical section or near the heel. In another example referring to Figure 3, the steam supply line 14 can be a tubing string extending along and within at least a portion of the horizontal section of the injection well 4, and separate from the solvent supply line 16, so as to feed steam down the injection well 4. Steam and solvent vapour are thereby mixed downhole, e.g., within the annulus of the injection well 4, and then enter the extraction chamber (not shown) as the co-injection mobilizing fluid.

[092] It is noted that the system design can vary from what is illustrated in Figure 1, e.g., with the solvent supply line and steam supply line connecting further upstream of the injection well. For example, solvent vapor and steam can be mixed at the well pad or proximate to or within a Central Processing Facility (CPF) where produced fluids are processed to separate and recover bitumen, water and solvent.
Date Recue/Date Received 2020-12-08

[093] It should be noted that the cyclic operation of the solvent dominated process could be started with a first slug cycle instead of solvent-only injection as described above.
However, it has been shown that starting the cyclic operation of the process by establishing the extraction chamber with solvent vapour can reduce the overall number of cycles during which steam slugs need to be co-injected to achieve a same oil recovery.
Slug cycles can be performed right away after a start-up stage and until blow-down and/or wind-down operations near the end of the productive life of the well. It can however be appreciated that the intermittent slug cycles can be used during a narrower period of time over the lifespan of the wells.

[094] The process is cyclically operated according to the slug cycles. The cumulative solvent requirements remain higher than the cumulative steam requirements during operation of the process such that the process remains solvent dominated. The term "cumulative" is used to refer to a total injected solvent or steam over the lifetime of the well. It should be noted that intermittent steam co-injection can allow the cumulative solvent requirements of the solvent dominated process to be lower than for other solvent processes for a similar oil recovery rate, while not requiring significant surface steam capacity given the intermittent nature of steam injection. Indeed, cumulative steam requirements of the solvent dominated process have also been found to be notably lower than for recovery processes involving continuous co-injection of solvent and steam.

[095] The process can further include performing slug cycles for a same or different duration (also referred to as cycle time period or cycle duration). For example, short slug cycles can be performed to not only aid the process but also to assess the performance of the slug cycles in order to tailor the timing and duration of the steam slug injection.
Timing and duration of each slug cycle can also be tailored to minimize or reduce solvent-to-oil ratio and/or steam-to-oil ratio. For example, the duration of each slug cycle can be several days up to several months, as long as solvent dominated process conditions are maintained.

[096] Operating conditions can be varied and optimized depending on the reservoir conditions and well configurations. Operating conditions include solvent type, composition of the co-injection mobilizing fluid, injection temperature, injection pressure, duration of each slug cycle, timing of each slug cycle, and number of slug cycles.

Date Recue/Date Received 2020-12-08

[097] It should be noted that there are various ways to adjust the timing of a slug cycle.
In some implementations, the duration of each slug cycle can increase from one slug cycle to a next slug cycle. In another example, if the solvent-to-oil ratio is observed to increase up to an undesired level during solvent dominated operation, a slug cycle can be initiated and maintained until combined solvent-to-oil ratio and steam-to-oil ratio are satisfactory.

[098] In some implementations, the process can include varying a composition of the co-injection mobilizing fluid during a slug cycle, and/or for each or some slug cycles. Thus, the steam content and the solvent content can be the same or different for each slug cycle and/or within each slug cycle. In some implementations, the steam molar content of the co-injection mobilizing fluid can be from 5 mol% to 70 mol%. In addition, when the process is to be transitioned from a solvent cycle to a slug cycle, the process can include adjusting injected quantities of steam and solvent so as to reach a desired molar ratio, while maintaining the same injection pressure and downhole pressure through the cycles.
Solvent injection is thus maintained from one slug cycle to another, but the solvent injection rate is reduced during a slug cycle, due to the presence of steam which replaces part of the solvent. It should be noted that the injection pressure is dependent on the reservoir conditions and is selected at least slightly higher than the reservoir operating pressure.

[099] In some other implementations, the process can include selecting a steam content of the co-injection mobilizing fluid for each slug cycle based on monitoring of the process.
For instance, if the solvent-to-oil ratio of the process is detected to be increasing undesirably, a slug cycle can be initiated with a steam content determined based on the monitored solvent-to-oil ratio increase. For example, a solvent-to-oil ratio threshold can be pre-determined and the solvent injection and composition of the production fluid can be monitored so as to determine whether the threshold is reached. If the threshold is reached or if it is being approached quickly, a slug of steam can be injected and maintained for a duration based on the solvent-to-oil ratio characteristics.

[0100] Other properties of the process can be monitored and used to initiate or control the cycles. For example, if too much condensed solvent is being produced back with the production fluid, a slug cycle can be initiated to increase the energy in the extraction chamber to thereby increase in situ vaporization of the solvent within the reservoir. Any indicator of an uneconomical solvent-to-oil ratio can be used as a trigger for a slug cycle.

Date Recue/Date Received 2020-12-08

[0101] In one example scenario, the characteristics of one or more slug cycles are determined based on properties pursuant to one or more previous slug cycles.
For example, a first slug cycle or series of slug cycles can be performed, and certain parameters are measured such as the solvent-to-oil ratio, solvent content in the production fluid, temperature in the well or near wellbore region, and so on. If the measurements indicate that the slug cycle enabled a slight reduction in the solvent-to-oil ratio, a subsequent slug cycle can be operated with higher steam input (e.g., higher steam content for a same slug cycle duration, same steam content for a longer slug cycle duration, or a combination thereof) and further measurements are obtained to determine the impact of that slug cycle on, for example, the solvent-to-oil ratio. As subsequent slug cycles are performed, the operating conditions (e.g., steam input) can be adjusted in order to reach an optimal solvent-to-oil ratio while maintaining solvent dominated conditions and desired oil recovery rates.

[0102] It is also noted that the operating parameters of a given slug cycle can be provided based not only on characteristics of one or more previous slug cycles, but also on determined characteristics of the progress of the process such as the volume of the extraction chamber. Since the extraction chamber grows over time and the volume of the chamber is a factor that influences fluid injection and energy that may be required, the subsequent slug cycle can be adapted by increasing the steam input in accordance with the increased size of the extraction chamber.

[0103] It should be noted that the process can include controlling the number and duration of the slug cycles, and also the steam content of the co-injection mobilizing fluid, so as to keep the recovery process under solvent dominated gravity drainage mechanisms rather than steam dominated mechanisms. For example, it can be possible to provide the co-injection mobilizing fluid with relatively high steam content as long as the slug cycle duration is relatively short in order to maintain solvent dominated conditions in the extraction chamber during the slug cycle and upon returning to solvent-only injection. In some example, the total steam quantity for injection can remain the same for certain slug cycles, but the duration and steam content change between different slug cycles. Of course, it is also possible to change the total steam injection volume from a slug cycle to another slug cycle.

Date Recue/Date Received 2020-12-08

[0104] It should be further noted that, depending on the reservoir conditions and design of the process facilities, some steam could be co-injected with solvent such that the process remains solvent dominated, and the slug cycle could then be performed at a higher steam-to-solvent ratio. In other words, it is possible to operate the process with at least one slug cycle injecting solvent with a small quantity of steam (e.g., 5 mol% or below), and other slug cycles injecting solvent with a step-change higher quantity of steam (e.g., mol% or above). The steam content during a solvent dominated cycle can be selected so that the steam-solvent mixture is at or near the azeotrope at the injected reservoir conditions, for example. In some implementations, the solvent dominated injection cycles involve the injection of a fluid that includes no steam, up to 1 mol% steam, up to 2 mol%
steam, up to 3 mol% steam, up to 4 mol% steam, up to 5 mol% steam, up to 10 mol%
steam, at the azeotrope, or within plus or minus 5% of the azeotrope at the conditions of the reservoir into which the fluid is injected. The solvent dominated injection cycles can involve the injection of a fluid that is over 90 mol% solvent with the remainder being a secondary injection compound, such as steam or another species.

[0105] It can also be appreciated that, prior to the cyclic phase of the in-situ recovery process, the well pair can undergo a startup stage in which the wells are put into hydraulic communication with each other. The startup stage can include various methods, such as steam circulation, steam bullheading, electric resistive heating, electromagnetic heating, solvent circulation or injection, and various combinations of such methods.
Fluid circulation or injection can occur in one or both of the wells.
Mobilizing fluid implementations

[0106] In some implementations, the solvent used as the dominant mobilizing fluid is a solvent that has properties facilitating injection in vapour phase at the reservoir conditions, and condensation thereof within the extraction chamber that is formed in the reservoir to dissolve and heat the bitumen. In some implementations, the solvent can be a paraffinic solvent, such as propane, butane, pentane or hexane or a mixture thereof. The solvent can be a deasphalting solvent which is used in operating conditions to cause in situ precipitation of asphaltenes that deposit and may remain in the reservoir while deasphalted bitumen is received as part of the production fluid. Various levels of deasphalting can be performed depending on the operating conditions. For example, the solvent can be Dimethyl Ether (DME).

Date Recue/Date Received 2020-12-08

[0107] It is noted that the process can be adapted to injection of any mobilizing solvents, as single solvent or mixture of solvents.

[0108] It is noted that the solvent can be injected in relatively pure form during solvent dominated operation. At the surface, the solvent can be purified up to a certain target concentration for reinjection downhole. The solvent that is injected can be at least 98%, 99% or 99.5% pure. For example, the solvent can be purified so that there is no more than 1 mol% of lighter hydrocarbon vapours in the injected solvent, or no more than 0.5 mol%, 0.2 mol% or 0.1 mol% of lighter hydrocarbon vapours. Lighter vapours, such as methane, can increase the risk of accumulating downhole in the extraction chamber which could reduce the efficiency of the process. Referring to Figure 5, the solvent can be for example separated from the production fluid 32 that is recovered to the surface and further treated in the CPF 30.

[0109] The solvent can be removed from the production fluid, or a stream derived therefrom, using various process configurations and separation units in order to produce a purified liquid solvent which can be transformed into a vapour at surface and reinjected downhole. The solvent purity particularly refers to its purity relative to lighter hydrocarbon species, such as methane. For example, if propane is the main solvent species, then there may be some quantities of butane and pentane depending on the surface purification system design, but the solvent would not include methane in quantities above 1 mol%. In another example, if butane is the main solvent species, then there may be some quantities of pentane and hexane and some quantities of propane as well, but the solvent would not include methane in quantities above 1 mol%. Nevertheless, there may be some process benefits to purifying the solvent to produce a single-species solvent for injection with very low quantities of lighter and heavier hydrocarbon species.

[0110] It is noted that the solvent can be selected depending on the reservoir properties and the overall process design. The temperature of the solvent to be injected corresponds to at least the saturation temperature of the solvent for being vapour phase at the reservoir pressure conditions. The solvent can be selected to minimize the energy required to heat the solvent to its saturation temperature at reservoir conditions. For example, if butane is injected as pure solvent, the process can include heating butane to at least 60 C to ensure vaporization under downhole pressure conditions of about 600 kPa. Heavier solvents could also be used, but heavier solvents would require higher energy input to be heated Date Recue/Date Received 2020-12-08 to at least their saturation temperature. In addition, lighter C3 to C5 solvents, such as propane, butane and pentane, can benefit more from combined steam slugs since the energy of such heated lighter solvents is lower than heavier solvents and thus the high latent energy of steam can provide a notable energy boost to the system.

[0111] Steam is to be understood herein as being saturated or superheated steam with a temperature to enter the reservoir in vapour phase, although some condensation in the injection wellbore is possible. It is nevertheless noted that additional elements and impurities, e.g. gases other than steam, can be found in steam in small or trace amounts.
The process can include heating water to at least a saturation temperature to produce steam at reservoir pressure. Depending of the downhole operating pressure, water is heated minimally to the temperature allowing to reach saturation conditions.
Optionally, steam can be superheated such that water remains in vapor phase when mixed with solvent vapour at a lower saturation temperature.

[0112] It is noted that the process can include separately heating the solvent and water so that solvent and water are vaporized prior to introduction into the injection well or after passing into the injection well.

[0113] In some implementations, the solvent can be heated at surface such that solvent vapor is directly fed to the injection tubing string at the wellhead. For example, solvent vapour can be directly generated after recovery from the production fluid at the CPF, and then fed to the well pad via a dedicated pipeline from the CPF. In another example, referring to Figure 5, solvent can be sourced from the CPF 30 where solvent is recovered from the production fluid 32 exiting the well pad 26, and then sent to a solvent vapour generator 34 located near or at one or more well pad 26. An additional solvent tank 36 can be provided as a source for a make-up solvent stream 38. Pumps or compressors 40a and 40b allow solvent from the CPF 30 or solvent tank 32 to flow into the solvent vapour generator 34, and pump or compressor 40c is configured to provide the solvent vapour to the well pad 26 at an adequate or desired injection pressure.
Solvent vapour can be provided from the well pad 26 into the injection well 4 via a tubing string (e.g., 8 or 16) as illustrated in Figure 1 or Figure 3. The solvent vapour can also be preheated prior to injection into the reservoir, using a preheater at surface and/or using a downhole heater (e.g., closed loop heater, electric resistance heater) disposed in the injection well.

Date Recue/Date Received 2020-12-08

[0114] In some implementations, heating of the water to produce steam can be performed at surface. For example, steam can be generated directly at the well pad, which may be done using a specifically designed heating device, such as a portable or relocatable steam generator. Indeed, the steam requirements of the solvent dominated process are sufficiently low to enable production of steam via smaller sized steam generators that can be designed to be moveable from one well pad to another. Referring to Figure 5, water can be sourced from a water tank 20 and fed to the portable steam generator 22 via a first pump 24a. The steam generator 22 is locatable proximate to at least one well pad 26 and once generated, steam is fed to the well pad 26 via a second pump 24h.

[0115] Alternatively, steam can be fed to the well pad via a dedicated pipeline from the CPF where steam is generated from treated process water. Steam can be provided into the injection well 4 at the well pad 26 via a tubing string (e.g., 8 or 14), which is the same or different than for solvent, as illustrated in Figure 1 or Figure 3.

[0116] Steam generators contemplated herein include Once Through Steam Generators (OTSGs), drum boilers, and Direct-Contact Steam Generators (DCSGs). DCSGs can contribute to lower the overall energy cost of the process. However, when using a DCSG, the process can include further purification of the steam to remove at least a portion of compounds than result from the combustion, such as CO2. Other steam sources, such as excess steam from a SAGD operation, could also be used to lower the energy cost of the process while leveraging existing steam generation infrastructure and meeting steam requirements of the slug cycles.

[0117] It can be appreciated that other equipment, additional to those illustrated in the figures, would be used as well, depending on the selected heating techniques and location of the heating devices.

[0118] In other implementations, solvent vapor and/or steam can be generated downhole upon passing into the injection well from the injection tubing string.
Downhole heating techniques can include electric resistive heating, electromagnetic heating, radio-frequency (RF) heating, fluid circulation heating, closed-loop circulation heating and any other heating techniques for reaching at least the saturation temperature of water at reservoir conditions. For example, there can be provided a heater that heats a near wellbore region surrounding the injection well to a temperature between 200 C and 280 C. In another Date Recue/Date Received 2020-12-08 example, solvent vapour can be generated at surface, while steam is being generated downhole during each slug cycle.

[0119] Although steam is described herein as the co-injected fluid during each slug cycle, other fluids providing additional energy through their higher latent heat capacity could be used in combination with the main solvent. Ideally, the fluid should have properties similar or analogous to steam so as to provide high latent heat in comparison to the quantity to be injected and having a higher latent heat capacity compared to the main solvent in order to provide a surge or energy in the reservoir.
()Meld implementations and steam use

[0120] One benefit that can be derived from the solvent dominated process described herein is that notably less steam infrastructure can be required for an oilfield compared to SAGD or steam-solvent continuous co-injection processes. For instance, the steam slugs can be timed so that only some wells receive steam while the others are receiving solvent only, thereby offsetting slug cycles for different sets of wells in the oilfield. The oilfield can be divided into two, three, four or more sets of wells or well pairs and the slug cycles can be timed so that one of the sets of wells are supplied with steam for a slug cycle while the other sets of wells are operated in continuous solvent injection mode. The overall steam requirements would thus be a fraction of those for a conventional steam-solvent co-injection operation.

[0121] In some implementations, the process can include offsetting cyclic operation of multiple wells to minimize the scale of the steam generation facilities.
Referring to Figure 6, a portable steam generator 22 can service at least two well pads 26 and 27.
Steam generated by the steam generator 22 can be fed to the first well pad 26 via a first steam supply line 42a during a slug cycle, while first and second well pads 26 and 27 are continuously fed solvent via respective first and second solvent supply lines 44a and 44b.
As the second well pad 27 is offset in terms of cyclic operation with respect to the first well pad 26, the same steam generator 22 can be used to feed steam to the second well pad 27 via supply line 42b, when the first well pad 26 initiates a solvent-only injection and the second well pad 27 therefore starts a slug cycle. Valves 46 and 48 in fluid communication with respective steam generator 22 and solvent source from the CPF 30 are controlled in accordance with the cyclic operation of each well pad 26 and 27. It should be noted that Date Recue/Date Received 2020-12-08 the valves 46 and 48 can be equipped to control a flowrate or pressure of steam and solvent flowing in the supply lines 42a, 42b, 44a and 44h. Indeed, even if solvent is continuously injected (i.e., during the whole solvent dominated operation, including the slug cycles) at a constant injection pressure, the amount of solvent to be sent to the well pad decreases for each slug cycle in accordance with the co-injected steam.
The valves 46 and 48 can also be controlled to adjust the flowrate of steam during co-injection so as meet a given steam molar ratio for the co-injection mobilizing fluid.

[0122] It should further be noted that production and surface equipment can be designed to handle a variable amount of solvent condensate and liquid water in the production fluid that will report back therewith. For instance, the production fluid can include minimal water when receiving fluids that are derived from solvent-only injection, but the production fluid can then include slightly higher water content due to a slug cycle. Thus, the surface equipment (e.g., at the CPF) can include a water separation unit that is appropriately designed to handle the highest water content the production could have. The design of the water separation unit can include sizing a water separator to be appropriately large and/or providing multiple water separators so that additional separator can come online when water content is higher.

Date Recue/Date Received 2020-12-08 EXPERIMENTAL SIMULATION FINDINGS

[0123] A series of homogenous 2D numerical simulations were conducted to evaluate the potential of the presently described solvent dominated recovery techniques using STARS, from Computer Modeling Group Ltd.

[0124] A "Solvent Base Case" was used to serve as a reference simulation scenario resulting from the injection of pure hot solvent (butane or pentane) at an injection pressure of 700kPa and at an injection temperature corresponding its saturation temperature (at 600kPa). Using the same solvent (butane or pentane), several simulation scenarios were tested using the solvent dominated principles contemplated herein (referred to as solvent dominated scenarios). In these solvent dominated scenarios, a slug of steam volume was periodically co-injected with the selected solvent (Ca or Cs) for a period of 20 days and at different steam molar fractions (10 mol%, 25 mol%, and 50 mol%), while the selected solvent was injected continuously at a constant injection pressure of 600kPa.
In each solvent dominated scenario, a total of 23 slugs of steam were injected during the first three years of operation, and solvent was continuously injected during the entire process until the end of the well life. Another simulation scenario, referred to as the continuous scenario, was run to test continuous co-injection of solvent (Ca or Cs) and steam until the end of the well life. Oil recovery, cumulative solvent requirements, and cumulative solvent-to-oil ratio (CSvOR) resulting from the solvent dominated scenarios were compared to the Solvent Base Case (Ca or Cs) or the continuous scenario as illustrated in Figures 7 to 16.
Pentane case

[0125] Figure 7 illustrates the oil recovery rate in m3 per day over more than five years when using pentane in the above simulation scenarios and Solvent Base Case (pure solvent injection only). The results indicate that oil recovery rate remained quite similar for all solvent dominated scenarios and Solvent Base Case. Nevertheless, referring to Figure 9, one can see that the CSvOR can be reduced by up to about 36% (when using 50 mol%
steam in the co-injection mobilizing fluid during each slug cycle) in comparison with the Solvent Base Case (Cs). Referring to Figure 8, the lower CSvOR resulting from the solvent dominated scenarios can be explained by the reduction of the cumulative solvent requirement (up to 38% less) for a substantially same oil production.
Date Recue/Date Received 2020-12-08

[0126] The simulation scenario was run for continuous co-injection of pentane and steam (10% steam mole fraction). Performance of such continuous scenario was compared to the performance of cyclic co-injection of pentane and steam (10% steam mole fraction), over the same period of time. Figure 10 shows that almost the same cumulative solvent-to-oil ratio CSvOR was obtained for both continuous and solvent dominated scenarios, while approximately 35% less cumulative steam injection was required for the solvent dominated scenario to obtain almost the same oil production (Figure 11).
Butane case

[0127] In order to investigate the performance of different solvents, the same simulation scenarios were repeated with identical operation conditions using butane (C4) as solvent.
Figures 12 and 13 show simulation results having similar trends as for the pentane case.
Oil recovery rates shown in Figure 12 remained quite similar for all solvent dominated scenarios and Solvent Base Case. Referring to Figure 13, the CSvOR can be reduced by up to about 37% (when using 50 mol% steam in the co-injection mobilizing fluid during each slug cycle) in comparison with the Solvent Base Case (C4). When comparing solvent dominated and continuous scenarios, Figure 14 shows again that almost the same CSvOR was obtained for both continuous and solvent dominated scenarios.
However, Figure 15 shows about 25% reduction in cumulative steam injection volume to obtain almost the same volume of produced oil.
Pentane versus Butane

[0128] Referring to Figure 16, cumulative oil recovery was compared for butane and pentane, when running a solvent dominated scenario with co-injection of 10 mol% steam and solvent. Based on this comparison, it was observed that better oil production performance can be obtained using a heavier solvent (e.g., pentane) compared to a lighter solvent (e.g., butane) for these conditions.

Date Recue/Date Received 2020-12-08

Claims (99)

1. A process for recovering bitumen from a subsurface reservoir via a well pair comprising a production well underlying an injection well, the process comprising:
injecting substantially only solvent in vapour phase via the injection well into the reservoir to dissolve and mobilize bitumen in the reservoir;
intermittently co-injecting steam along with the solvent via the injection well in the form of steam slugs defining slug cycles; and producing mobilized bitumen and condensed fluid via the production well.

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

3. The process of claim 2, wherein the solvent comprises a C3 tO C6 paraffin.

4. The process of claim 3, wherein the solvent is pentane.

5. The process of claim 3, wherein the solvent is butane.

6. The process of claim 3, wherein the solvent is propane.

7. The process of claim 1, wherein the solvent comprises dimethyl ether.

8. The process of any one of claims 1 to 7, comprising generating steam and solvent in vapour phase separately before injection thereof via the injection well.

9. The process of any one of claims 1 to 8, wherein the slug cycles are each performed for a same duration.

10. The process of any one of claims 1 to 8, wherein at least some of the slug cycles are performed for different durations compared to each other.

11. The process of claim 10, wherein the duration of each slug cycle increases from one slug cycle to a next slug cycle.

Date Recue/Date Received 2020-12-08

12. The process of any one of claims 1 to 11, further comprising controlling initiation and duration of each slug cycle to reduce or minimize a solvent-to-oil ratio of the process.

13. The process of claim 12, further comprising initiating a slug cycle upon monitoring an increase of the solvent-to-oil ratio.

14. The process of any one of claims 1 to 13, further comprising controlling initiation and duration of each slug cycle to reduce or minimize a steam-to-oil ratio of the process.

15. The process of any one of claims 1 to 14, further comprising controlling initiation and duration of each slug cycle to maintain solvent dominated process conditions.

16. The process of any one of claims 1 to 15, wherein co-injection of the steam slugs according to the slug cycles is initiated after a start-up stage and ceased prior to mature operation of the well pair.

17. The process of any one of claims 1 to 16, comprising starting co-injecting solvent and a steam slug as a first slug cycle when a production stage of the well pair is reached.

18. The process of any one of claims 1 to 17, wherein at least 15 slug cycles are performed.

19. The process of any one of claims 1 to 18, wherein, for each slug cycle, the steam and the solvent are combined at surface to form a co-injection mobilizing fluid which is then introduced down the injection well.

20. The process of any one of claims 1 to 18, wherein, for each slug cycle, the steam and the solvent are combined down the injection well for form a co-injection mobilizing fluid within the injection well.

21. The process of claim 19 or 20, wherein the co-injection mobilizing fluid comprises about 5 mol% to about 70 mol% steam.

22. The process of any one of claims 19 to 21, wherein the co-injection mobilizing fluid consists essentially of the solvent and the steam.

Date Recue/Date Received 2020-12-08

23. The process of any one of claims 19 to 22, wherein at least one of the slug cycles comprises injecting the co-injection mobilizing fluid with an additional fluid.

24. The process of claim 23, wherein the additional fluid comprises a non-condensable gas.

25. The process of claim 23 or 24, wherein the additional fluid comprises exhaust gases from combustion of a fuel.

26. The process of any one of claims 19 to 25, further comprising varying the composition of the co-injection mobilizing fluid during a given slug cycle.

27. The process of any one of claims 19 to 26, further comprising varying the composition of the co-injection mobilizing fluid for each slug cycle.

28. The process of any one of claims 19 to 27, further comprising selecting a steam content of the co-injection mobilizing fluid for each slug cycle based on monitoring of the solvent-to-oil ratio.

29. The process of claim 28, comprising increasing the steam content during a given slug cycle in response to an increase in the solvent-to-oil ratio.

30. The process of any one of claims 1 to 29, comprising generating superheated steam before being combined with the solvent in vapor phase for co-injection.

31. The process of any one of claims 1 to 30, comprising heating the solvent to at least a saturation temperature thereof at a reservoir operation pressure.

32. The process of any one of claims 1 to 31, wherein the solvent and the steam are injected at an injection pressure between 500 and 1100 kPa.

33. The process of claim 32, wherein the injection pressure is between 50 kPa and 200 kPa higher than an operation pressure of the reservoir.

34. The process of any one of claims 1 to 33, wherein the solvent is a single solvent compound that is purified at surface before injection.

Date Recue/Date Received 2020-12-08

35. The process of any one of claims 1 to 34, wherein the solvent that is injected is at least 98% pure.

36. The process of any one of claims 1 to 35, wherein the solvent that is injected is at least 99% pure.

37. The process of any one of claims 1 to 36, wherein the solvent that is injected is at least 99.5% pure.

38. The process of any one of claims 1 to 37, wherein the solvent is injected into the reservoir to produce an extraction chamber at a temperature between about 40 C

and about 80 C.

39. The process of any one of claims 1 to 38, wherein the solvent is recovered in a Central Processing Facility (CPF) which receives the mobilized bitumen and condensed fluids recovered via the production well and for separation thereof to produce the recovered solvent that is reused for injection.

40. The process of any one of claims 1 to 39, wherein the steam is generated from process water recovered in a Central Processing Facility (CPF) which receives the mobilized bitumen and condensed fluids recovered via the production well and for separation thereof to produce the process water.

41. The process of any one of claims 1 to 40, wherein the solvent and the steam are in vapour phase prior to supplying into the injection well.

42. The process of claim 41, wherein the steam is generated by a direct-contact steam generator (DCSG).

43. The process of claim 41, wherein the steam is generated by a once-through steam generator (OTSG).

44. The process of any one of claims 41 to 43, further comprising generating the steam using a portable steam generator located proximate to the well pair.

45. The process of any one of claims 1 to 40, wherein the solvent is vaporized within the injection well prior to injection into the reservoir.
Date Recue/Date Received 2020-12-08

46. The process of any one of claims 1 to 40, wherein the steam is generated within the injection well prior to injection into the reservoir.

47. The process of claim 46, wherein the injection well comprises a heater that heats the injection well to a temperature between 200 C and 280 C.

48. The process of claim 47, wherein the heater comprises an electric resistance heater.

49. The process of claim 47, wherein the heater comprises a closed-loop fluid heater for circulating a heating fluid therein.

50. The process of any one of claims 1 to 49, wherein the well pair is part of an oilfield with multiple well pairs.

51. The process of claim 50, further comprising:
supplying steam to a first set of the well pairs for a corresponding first slug cycle, and then ceasing steam supply to the first set of the well pairs and supplying steam to a second set of the well pairs for a corresponding second slug cycle that is off-set with respect to the first slug cycle.

52. The process of any one of claims 1 to 51, wherein the process is operated to obtain a cumulative solvent-to-oil recovery at least 20% lower than for bitumen recovery with continuous injection of the solvent only.

53. The process of any one of claims 1 to 52, wherein the process is operated such that cumulative solvent requirements are higher than cumulative steam requirements over cyclic operation of the process.

54. A process for recovering heavy hydrocarbons from a subsurface reservoir, comprising:
injecting solvent in vapour phase in the absence of steam via an injection well into the reservoir to dissolve and mobilize heavy hydrocarbons in the reservoir;

Date Recue/Date Received 2020-12-08 intermittently injecting fluid slugs concomitantly with the solvent via the injection well, the fluid slugs comprising a mobilizing vapour having a higher latent heat capacity compared to the solvent; and producing mobilized heavy hydrocarbons and condensed fluid via a production well underlying the injection well.

55. The process of claim 54, wherein the mobilizing vapour comprises steam.

56. The process of claim 54 or 55, wherein the mobilization vapour comprises at least one compound having a latent heat capacity of at least 2% greater than the solvent.

57. The process of any one of claims 54 to 56, wherein the heavy hydrocarbons comprise bitumen.

58. The process of any one of claims 54 to 57, further comprising one or more features as defined in any one of claims 1 to 53.

59. A system for recovering heavy hydrocarbons from a subsurface reservoir, comprising:
a well pair comprising:
an injection well; and a production well underlying the injection well in the reservoir;
a fluid supply assembly at surface and in fluid communication with the injection well, the fluid supply assembly comprising:
a solvent supply line, and a steam supply line; and a control assembly coupled to the fluid supply assembly and configured to:
continuously feed only solvent from the solvent supply line into the injection well to inject the solvent in vapour phase into the reservoir to dissolve and mobilize heavy hydrocarbons in the reservoir; and Date Recue/Date Received 2020-12-08 intermittently co-feed steam from the steam supply line into the injection well in the form of steam slugs that enter the reservoir with the solvent.

60. The system of claim 59, further comprising a heating assembly to heat water to at least a saturation temperature thereof at an operation pressure of the reservoir to produce at least a portion of the steam.

61. The system of claim 60, wherein the heating assembly comprises a modular steam generator located at surface to generate steam prior to passing into the injection well.

62. The system of claim 61, wherein the modular steam generator is a direct-contact steam generator (DCSG).

63. The system of claim 61, wherein the modular steam generator is a once-through steam generator (OTSG).

64. The system of claim 60, wherein the heating assembly further heats solvent to at least a saturation temperature thereof at an operation pressure of the reservoir to produce at least a portion of the solvent in vapour phase.

65. The system of claim 60, wherein the heating assembly comprises at least one heater located downhole to generate steam upon passing into the injection well.

66. The system of claim 64, wherein the heating assembly comprises at least one heater located downhole to generate solvent vapour upon passing into the injection well.

67. The system of claim 65 or 66, wherein the at least one heater is configured to heat a near wellbore region surrounding the injection well to a temperature between 200 C and 280 C.

68. The system of claim 59, wherein at least one of the steam supply line and solvent supply line is in fluid communication with a Central Processing Facility (CPF) separating solvent and/or water from a condensed fluid recovered by the production well.

Date Recue/Date Received 2020-12-08

69. The system of any one of claims 59 to 68, wherein the heavy hydrocarbons comprise bitumen.

70. A process for recovering bitumen from a subsurface reservoir via a single well comprising a production section adjacent to an injection section, the process comprising:
injecting substantially only solvent in vapour phase via the injection section into the reservoir to dissolve and mobilize bitumen in the reservoir;
intermittently co-injecting steam along with the solvent via the injection section in the form of steam slugs; and producing mobilized bitumen and condensed fluid via the production section.

71. The process of claim 70, wherein the single well further comprises multiple injection sections and multiple production sections distributed along and within an annulus of the single well, the production sections being staggered with respect to the injection sections and being axially separated therefrom, and the process comprising:
injecting the solvent in vapour phase from the multiple injection sections into the reservoir, intermittently co-injecting the steam slugs from the multiple injection sections into the reservoir; and producing the mobilized bitumen and the condensed fluid from the multiple production sections.

72. A process for recovering bitumen from a subsurface reservoir via a well pair comprising a production well underlying an injection well, the process comprising:
injecting a solvent dominated fluid in vapour phase via the injection well into the reservoir to dissolve and mobilize bitumen in the reservoir, to define a solvent dominated injection cycle;

Date Recue/Date Received 2020-12-08 in between solvent dominated injection cycles, co-injecting steam along with the solvent via the injection well in the form of steam slugs defining slug cycles, wherein a steam content during the slug cycles is greater than a steam content of the solvent dominated fluid during the solvent dominated injection cycles; and producing mobilized bitumen and condensed fluid via the production well.

73. The process of claim 72, wherein the solvent dominated fluid comprises steam.

74. The process of claim 73, wherein the solvent dominated fluid comprises 1 mol%
to 10 mol% steam.

75. The process of any one of claims 72 to 74, wherein the steam content during each slug cycle is at least double the steam content during the corresponding previous solvent dominated injection cycle.

76. The process of any one of claims 72 to 75, wherein the solvent comprises a paraffinic solvent.

77. The process of claim 76, wherein the solvent is butane.

78. The process of claim 76, wherein the solvent is propane.

79. The process of claim 76, wherein the solvent comprises dimethyl ether.

80. The process of any one of claims 72 to 79, wherein the duration of each slug cycle increases from one slug cycle to a next slug cycle.

81. The process of any one of claims 72 to 80, wherein at least 15 slug cycles are performed.

82. The process of any one of claims 72 to 81, wherein, for each slug cycle, the steam and the solvent are combined at surface to form a co-injection mobilizing fluid which is then introduced down the injection well.
Date Recue/Date Received 2020-12-08

83. The process of any one of claims 72 to 81, wherein, for each slug cycle, the steam and the solvent are combined down the injection well for form a co-injection mobilizing fluid within the injection well.

84. The process of claim 82 or 83, wherein the co-injection mobilizing fluid comprises about 5 mol% to about 70 mol% steam.

85. The process of claim 82 or 83, wherein the co-injection mobilizing fluid comprises about 20 mol% to about 50 mol% steam.

86. The process of claim 82 or 83, wherein the co-injection mobilizing fluid consists essentially of the solvent and the steam.

87. The process of any one of claims 82 to 86, wherein at least one of the slug cycles comprises injecting the co-injection mobilizing fluid with an additional fluid.

88. The process of claim 87, wherein the additional fluid comprises a non-condensable gas.

89. The process of claim 87, wherein the additional fluid comprises exhaust gases from combustion of a fuel.

90. The process of any one of claims 82 to 89, further comprising varying the composition of the co-injection mobilizing fluid during a given slug cycle.

91. The process of any one of claims 82 to 90, further comprising varying the composition of the co-injection mobilizing fluid for each slug cycle.

92. The process of any one of claims 82 to 91, further comprising selecting the steam content of the co-injection mobilizing fluid for each slug cycle based on monitoring of the solvent-to-oil ratio.

93. The process of claim 92, comprising increasing the steam content during a given slug cycle in response to an increase in the solvent-to-oil ratio.

94. The process of any one of claims 72 to 93, comprising generating superheated steam before being combined with the solvent in vapor phase for co-injection.

Date Recue/Date Received 2020-12-08

95. The process of any one of claims 72 to 94, comprising heating the solvent to at least a saturation temperature thereof at a reservoir operation pressure.

96. The process of any one of claims 72 to 95, wherein the solvent and the steam are injected at an injection pressure between 500 and 1100 kPa.

97. The process of any one of claims 72 to 96, wherein the solvent is a single solvent compound that is purified at surface before injection.

98. The process of any one of claims 72 to 97, wherein the solvent that is injected is at least 98% pure.

99. The process of any one of claims 72 to 98, wherein the solvent is injected into the reservoir to produce an extraction chamber at a temperature between about 40 C

and about 80 C.

Date Recue/Date Received 2020-12-08