CA3102988A1 - Forced solvent cycling in oil recovery - Google Patents

Abstract

ABSTRACT
Processes are provided for operating a well pair in a heavy oil reservoir to facilitate productive solvent cycling in distinct operational phases that ameliorate the occurrence of unproductive solvent short circuiting between injection and production wells.
In a first phase, solvent is injected so as to raise a bottom hole pressure in the recovery chamber to a threshold value, while production of solvent-derived casing gas is minimized. On transition to the alternative phase, injection of solvent is minimized and production of solvent-derived casing gas is permitted, up to a threshold value that then triggers a reversion to first phase operations.
Date Recue/Date Received 2020-12-18

Description

FORCED SOLVENT CYCLING IN OIL RECOVERY
TECHNICAL FIELD
[0001] The present disclosure relates to in situ methods for recovering hydrocarbons from subterranean reservoirs. In particular, the present disclosure relates to solvent-aided or solvent driven processes that ameliorate the unproductive short circuiting of injected solvent between an injection well and a production well, thereby driving a productive solvent cycling process.
BACKGROUND

[0002] Hydrocarbons in some subterranean deposits of viscous hydrocarbons, can be extracted in situ by lowering the viscosity of the hydrocarbons to mobilize them so that they can be moved to, and recovered from, a production well. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbons, heavy oil, bitumen, or oil sands. In situ processes for recovering oil from oil sands typically involve the use of multiple wells drilled into the reservoir, .. and are assisted or aided by thermal and/or solvent based recovery techniques, such as injecting a heated fluid, typically steam, solvent or a combination thereof, into the reservoir from an injection well. Steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are representative thermal-recovery processes that use steam to mobilize hydrocarbons in situ.
Solvent-aided processes (SAP) and solvent-driven processes (SDP) are representative thermal-.. recovery processes that use both steam and solvent to mobilize hydrocarbons in situ.

[0003] Atypical SAGD process is disclosed in Canadian Patent No.
1,130,201 issued on 24 August 1982, in which the functional unit involves two wells that are drilled into the deposit, one for injection of steam and one for production of oil and water. Steam is injected via the injection well to heat the formation. The steam condenses and gives up its latent heat to the formation, heating a layer of viscous hydrocarbons. The viscous hydrocarbons are thereby mobilized, and drain by gravity toward the production well with an aqueous condensate. In this way, the injected steam initially mobilizes the in-place hydrocarbons to create a steam or production chamber in the reservoir around and above the horizontal segment of the injection and production wells.

[0004] Some thermal recovery processes employ injection fluids that include solvent, optionally in combination with steam, as for example disclosed in Canadian Patent Publication Date Recue/Date Received 2020-12-18 2,956,771. Solvent-aided processes (SAP) are one such category. In the context of the present disclosure, SAP injection fluids comprise less than about 50% solvent and greater than about 50% steam on a mass basis. Solvent-driven processes (SDP) are another such category. In the context of the present disclosure, SDP injection fluids comprise greater than about 50% solvent and less than about 50% steam on a mass basis. SAP and SDP processes can each be implemented in a variety of ways, such that each of these categories comprise a plurality of more specific embodiments. For example, the terms "solvent aided process" and "SAP"
incorporate more specific embodiments that employ injection fluids comprising less than about 50 % solvent and greater than about 50 % steam on a mass basis, such as so called "Expanding solvent SAGD" or "ES-SAGD".

[0005] Solvent-driven processes are not widely employed on commercial scale but, when they are, they are typically employed as one phase in a broader recovery profile. For example, a well may be transitioned through: (i) a start-up phase during which hydraulic communication is established between an injection well and a production well; (ii) a SAGD phase during which a production chamber expands primarily in a vertical direction from the injection well and mobilized hydrocarbons are recovered from the production well along with condensed steam;
(iii) a SDP phase during which the production chamber expands primarily in a horizontal and/or lateral direction and mobilized hydrocarbons are recovered along with condensed solvent; and (iv) a blow-down phase during which non-condensable gas is injected to recover residual hydrocarbons and solvent.

[0006] The terms "steam chamber" or "production chamber" or "recovery chamber"
accordingly refer to the volume of the reservoir which is saturated with injected fluids and from which mobilized oil has at least partially drained. Mobilized viscous hydrocarbons are typically recovered continuously through one or more production wells. The conditions of mobilizing fluid injection and of hydrocarbon production may be modulated to control the growth of the production chamber, for example to maximize oil production at the production well. There are, however, circumstances in which maximum oil production may not be the paramount commercial operational imperative.
SUMMARY

[0007] Methods are disclosed for operating a well pair in a heavy oil reservoir to facilitate recovery of hydrocarbons, where the production well includes one or more segments that are Date Recue/Date Received 2020-12-18 spaced apart from corresponding segments of the injection well by interwell zones that include mobile fluids. In this circumstance, there is a risk of an injection fluid short circuiting from the injection well to the production well. This is particularly problematic when the injection fluids include a volatile solvent, because it is difficult or impossible to determine whether any solvent produced through the production well, typically as a casing gas, is the result of solvent short circuiting or, more productively, merely the production of solvent that had dissolved in, and hence mobilized, the heavy oil that is being produced, before being released as a gas from the production fluids.

[0008] In view of the foregoing challenge, the present methods provide a system in which the risk of short circuiting solvent is ameliorated. This is accomplished by taking steps to segregate the injection of solvent from the production of solvent-derived casing gas. This segregation is implemented by adopting distinct phases of operation, a "solvent-filling" phase and a "bitumen-draining" phase. In the solvent-filling phase, solvent is injected, for example so as to raise a bottom hole pressure (BHP) in the recovery chamber to a solvent-filling-phase upper BHP threshold value, but production of solvent-derived casing gas is minimized. In contrast, in the bitumen-draining phase, injection of solvent is minimized and production of solvent-derived casing gas is permitted, for example up to a bitumen-draining-phase maximum casing gas production threshold.

[0009] In the solvent-filling phase, the production of fluids is throttled-down, for example by adjusting the speed of a production pump, so as to minimize production of gaseous solvent.
This approach to production fluid management guards against the short circuiting of the injected solvent through the interwell mobile fluid zone directly to the production well. In the bitumen-draining phase, the production of fluids may be throttled-up, with the attendant production of an operationally acceptable amount of gaseous solvent, but because the injection of solvent is reduced during the bitumen-draining phase, the produced casing gas is necessarily attributable to solvent entrained in the mobilized bitumen, and cannot be attributable to solvent short circuiting through the interwell zone.

[0010] The well pair in the subterranean heavy oil reservoir is emplaced so as to service a recovery chamber. In a typical well pattern, analogous to a SAGD well pair, a production well accessing the heavy oil reservoir is provided, typically comprising a production well surface facility in fluid communication with a generally horizontal longitudinal production well segment within a heavy oil zone in the reservoir. The production well may include a fluid-permeable production well casing, through which production fluids are collected. The fluid-permeable Date Recue/Date Received 2020-12-18 collection segments of the production well may be spaced apart from one or more corresponding segments of an injection well, with an interwell zone between these segments of the production and injection wells. This interwell zone provides an avenue for fluid flow that potentially permits solvent short circuiting.

[0011] The injection well accessing the heavy oil reservoir may similarly comprise an injection well surface facility in fluid communication with a generally horizontal longitudinal injection well segment within the heavy oil zone in the reservoir. The longitudinal injection well segment typically being generally parallel to and vertically spaced apart above the longitudinal production well segment.

[0012] In the solvent-filling phase, a mobilizing fluid that includes a solvent is injected into the recovery chamber through the injection. This may for example take place at a constant or variable solvent-filling-phase injection rate, so as to increase a bottom hole pressure (BHP) in the recovery chamber. In conjunction with injection of mobilizing fluids, the production of mobilized fluids from the production well may be modulated, for example so as to limit the amount of production well casing gas production below a solvent-filling-phase maximum casing gas production threshold. In this way, an increase the BHP may be achieved, for example to a solvent-filling-phase upper BHP threshold value.

[0013] In the bitumen-draining phase, decreasing the solvent injection rate, for example to below an average, or minimum, of the solvent-filling-phase injection rates, may be implemented so as to decrease the BHP in the recovery chamber. In conjunction with this, the production of mobilized fluids from the production well may be modulated so as to permit the amount of casing gas produced to rise, for example to a bitumen-draining-phase maximum casing gas production threshold.

[0014] The transition between solvent-filling and bitumen-draining phases may be triggered by select operating parameters. For example, when the bitumen-draining-phase maximum casing gas production threshold is reached, operations may be returned to the solvent-filling phase. In typical implementations, the solvent-filling-phase maximum casing gas production threshold is much less than the value of the bitumen-draining-phase maximum casing gas production threshold, for example at or less than about 50%, about 40%, about 30%, about 20%, about 10%, about 5%, or about 1% of the bitumen-draining-phase maximum casing gas production threshold. This reflects the fact that casing gas production may be permitted in the bitumen-draining phase, when solvent injection is reduced, because the produced casing gas is derived in large part from solvent that has previously dissolved in the mobilized bitumen, Date Recue/Date Received 2020-12-18 representing the intended productive use of the solvent rather than an unproductive short circuiting of solvent.

[0015] In select embodiments, the present disclosure relates to a method of recovering hydrocarbons from a subterranean heavy oil reservoir, comprising:
providing a well pair servicing a recovery chamber, the well pair comprising:
a production well accessing the heavy oil reservoir; and, spaced apart from the production well by an interwell zone, an injection well accessing the heavy oil reservoir;
in a solvent-filling phase, injecting a mobilizing fluid comprising a solvent through the injection well at a constant or variable solvent-filling-phase injection rate so as to increase a bottom hole pressure (BHP) in the recovery chamber while modulating production of mobilized fluids from the production well so as to limit the amount of production well casing gas production below a solvent-filling-phase maximum casing gas production threshold, so as to increase the BHP to a solvent-filling-phase upper BHP
threshold value;
in a bitumen-draining phase, decreasing the solvent injection rate, so as to decrease the BHP in the recovery chamber while modulating production of mobilized fluids from the production well so as to permit the amount of casing gas produced to rise to a bitumen-draining phase maximum casing gas production threshold; and, when the bitumen-draining-phase maximum casing gas production threshold is reached, returning to the solvent-filling phase, wherein the solvent-filling-phase maximum casing gas production threshold is at or less than 50% of the value of the bitumen-draining-phase maximum casing gas production threshold.

[0016] In select embodiments of the present disclosure, the bitumen-draining-phase maximum casing gas production threshold is at least about 10 T/d, about 11 T/d, about 12 T/d, about 13 T/d, about 14 T/d, about 15 T/d, about 16 T/d, about 17 T/d, about 18 T/d, about 19 T/d or about 20 T/d; or, is an at least about 10%, about 20%, about 30%, about 40%, about 50%, about 60% about 70%, about 80%, about 90%, about 100%, about 110%, about 120%, about 130%, about 140%, about 150%, about 160%, about 170%, about 180%, about 190%, or about 200% increase of casing gas production rate within a bitumen-draining-phase maximum casing gas monitoring period of from about 1 hour to about 1 week.

[0017] In select embodiments of the present disclosure, the solvent-filling-phase maximum casing gas production threshold is between about 0 T/d and about 10 T/d; or, is an at least Date Recue/Date Received 2020-12-18 about 10%, about 20%, about 30%, about 40%, about 50%, about 60% about 70%, about 80%, about 90%, about 100%, about 110%, about 120%, about 130%, about 140%, about 150%, about 160%, about 170%, about 180%, about 190%, or about 200% increase of casing gas production rate within a solvent-filling-phase maximum casing gas monitoring period of from about 1 hour to about 1 week.

[0018] In select embodiments of the present disclosure, the solvent-filling-phase maximum casing gas production threshold is at or less than about 40%, about 30%, about 20%, about 10%, about 5% or about 1% of the value of the bitumen-draining-phase maximum casing gas production threshold.

[0019] In select embodiments of the present disclosure, the solvent-filling-phase upper BHP
threshold value is at least about 3175 kPa, about 3200 kPa, about 3225 kPa or 3250 kPa.

[0020] In select embodiments of the present disclosure, the BHP is generally maintained within a BHP constraint range at or below the solvent-filling-phase upper BHP
threshold value and at or above a minimum BHP constraint value.

[0021] In select embodiments of the present disclosure, in the bitumen-draining phase, the solvent injection rate is decreased to below an average of the solvent-filling-phase injection rates, so as to decrease the BHP in the recovery chamber.

[0022] In select embodiments of the present disclosure, in the bitumen-draining phase, the solvent injection rate is decreased to below a minimum value of the solvent-filling-phase .. injection rates, so as to decrease the BHP in the recovery chamber.

[0023] In select embodiments of the present disclosure, the solvent-filling phase and the bitumen-draining phase are repeated in a plurality of cycles, and in the plurality of cycles one or more of the following parameters changes from one cycle to another cycle: the bitumen-draining-phase maximum casing gas production threshold; the solvent-filling-phase maximum casing gas production threshold; and/or, the solvent-filling-phase upper BHP
threshold value.

[0024] In select embodiments of the present disclosure, the solvent comprises C2 to C10 linear, branched, or cyclic alkanes, alkenes, or alkynes, substituted or unsubstituted.

[0025] In select embodiments of the present disclosure, the solvent predominantly comprises one or more n-alkane.

[0026] In select embodiments of the present disclosure, the n-alkane is propane, butane or pentane.

Date Recue/Date Received 2020-12-18

[0027] In select embodiments of the present disclosure, the solvent comprises propane and/or butane.

[0028] In select embodiments of the present disclosure, the mobilizing fluid comprises steam.

[0029] In select embodiments of the present disclosure, the mobilizing fluid comprises at least about 50%, about 60%, about 70%, about 80% or 90% solvent.

[0030] In select embodiments of the present disclosure, the production well accessing the heavy oil reservoir comprises a production well surface facility in fluid communication with a generally horizontal longitudinal production well segment within a heavy oil zone in the reservoir, the production well comprising a fluid-permeable production well casing.

[0031] In select embodiments of the present disclosure, the injection well accessing the heavy oil reservoir comprises an injection well surface facility in fluid communication with a generally horizontal longitudinal injection well segment within the heavy oil zone in the reservoir, the longitudinal injection well segment being generally parallel to and vertically spaced apart above the longitudinal production well segment.

[0032] In select embodiments of the present disclosure, the method further comprises a transition period between: (i) the solvent-filling phase and the bitumen-draining phase; and/or (ii) the bitumen-draining phase and the solvent-filling phase.
BRIEF DESCRIPTION OF THE DRAWINGS

[0033] Figure 1 includes two graphs, schematically illustrating the synchronous adjustment of the BHP and the fluid production rate in alternating "solvent-filling" and "bitumen-draining"
phases of a heavy oil production process.
DETAILED DESCRIPTION

[0034] Cyclic processes are disclosed for managing the efficient use of solvent in the recovery of mobilized hydrocarbons from heavy oil reservoirs, including process that involve the co-injection of steam and solvent, particularly solvent-aided (SAP) or solvent-driven processes (SDP). These cyclic processes include conditionally recurrent steps of increasing and decreasing the injection rate of a mobilizing injection fluid and the production rate of a mobilized Date Recue/Date Received 2020-12-18 production fluid, in alternating phases. Specifically, each cycle has two phases, which may be referred to as a "solvent-filling" phase and "bitumen-draining" phase.

[0035] In the solvent-filling phase, an injection fluid, typically a mixture of solvent and steam is injected into the formation, typically at a relatively high injection rate, so that the bottom hole pressure (BHP) in the recovery chamber increases. During this phase, the production rate is typically maintained at a relatively low, or minimum, production rate, which is selected so as to minimize or prevent casing gas flow. This phase is a "filling" phase, in the sense that in this phase: (i) the recovery chamber is being filled with injected mobilizing fluid, typically steam and solvent, and (ii) the bottom portion of the recovery chamber fills with drained mobilized hydrocarbon liquids, so the mobilized liquid level above the production well rises (the injection rate is high and production rate is low). Operating conditions may accordingly be arranged so that little or no solvent gas is produced through the production casing in this solvent-filling phase, so that there can inherently be little or no short circuiting of solvent from the injection well directly to the production well through the interwell zone.

[0036] In select implementations, the solvent-filling phase ends, and the process transitions to the bitumen-draining phase, when the BHP reaches a preselected maximum value. In the transition period, the injection rate may be relatively quickly decreased, for example so as to decrease the BHP to a preselected minimum. In conjunction with this, the production rate may be increased. Then, for example when the minimum BHP pressure is reached, the injection rate is maintained at a relatively low level, for example so as to maintain the BHP
at the selected minimum BHP, and the production rate is correspondingly increased, for example up to a maximum production rate. In this bitumen-draining phase, casing gas is produced and some solvent may be produced through the casing gas. The solvent produced in the casing gas, however, is not attributable to short circuiting because the solvent injection rate has been throttled-down. This phase is a "draining" phase in the sense that in this phase, the liquid level above the production well will be lowered due to the reduced injection rate and increased production rate, and the amount of steam/solvent in the chamber also decreases.

[0037] As the mobilized liquid level above the production well falls during the bitumen-draining phase, the casing gas flow rate will generally increase. The casing gas flow rate may accordingly be monitored, and when the casing gas flow rate reaches a preselected maximum threshold value or rate (for example when there is a sharp increase in the casing gas production rate), the bitumen-draining phase may be concluded, and the process can be made to transition back to a solvent-filling phase to initiate the next cycle. In this way, productive solvent cycling in Date Recue/Date Received 2020-12-18 the recovery chamber is prioritized over unproductive short circuiting of solvent. The process accordingly cyclically alternates between the solvent-filling phase and the bitumen-draining phase, and the triggering condition for transitioning from the solvent-filling phase to the bitumen-draining phase is the attainment of a maximum BHP, while the triggering condition for transitioning from the bitumen-draining phase to the solvent-filling phase is the onset of a maximum casing gas threshold, being a maximum casing gas flow rate or a maximum rate-change increase.

[0038] In select implementations, the methods of the present disclosure may comprise a transition period between: (i) the solvent-filling phase and the bitumen-draining phase; and/or (ii) the bitumen-draining phase and the solvent-filling phase. The duration and operations associated with the transition period may be modulated to achieve particular production and/or reservoir parameters as will be appreciated by those skilled in the art who have benefitted from the teachings of the present disclosure,

[0039] The processes disclosed herein overcome the challenge that it is difficult or impossible to tell whether a solvent present in produced casing gas is short circuiting unproductively, or if it is productively migrating to the casing via the liquid drained next to the producer. In addition, in a typical SAGD process, relatively large quantities of emulsion are produced, and in the emulsion effectively forms a physical buffer around the production well.
However, in a recovery process involving the use of significant amounts of solvent, where water is limited (as there is less steam), the mobilized oil is thicker, and larger quantities of gas are typically produced in the absence of a similar physical buffer around the production well. These characteristics of solvent-based recovery processes exacerbate the challenges associated with short circuiting of solvent. The present processes are accordingly particularly advantageous in a high-gas, low-water recovery environment, conditions typical of SAP and SDP
processes.

[0040] In effect, the present processes provide methods for adjusting solvent production in a hydrocarbon recovery process, typically where steam and solvent are co-injected. The mobilizing fluid is injected at an injection rate into the reservoir, so as to assist hydrocarbon production, and a reservoir fluid comprising hydrocarbons is produced at a production rate. The methods involve conditionally recurrent transitioning between a solvent-filling phase and a bitumen-draining. In the solvent-filling phase, the injection rate and the production rate are adjusted to increase a bottom hole pressure in the reservoir, and the production rate is set at a reduced production rate selected so as to reduce production of the solvent in the gas phase from the reservoir. In the bitumen-draining phase, the injection rate and the production rate are Date Recue/Date Received 2020-12-18 adjusted to maintain the bottom hole pressure in the recovery chamber, for example at a preselected minimum pressure, and the production rate is increased, for example to a maximum production rate, to increase production of the solvent in the gas phase at an increased gas production rate. The triggering condition for transitioning from the solvent-filling phase to the bitumen-draining phase is the attainment of a preselected maximum BHP; and the triggering condition for transitioning from the bitumen-draining phase to the solvent-filling phase is the onset of a gas production rate, or rate change, that reaches a maximum value.

[0041] The present processes are accordingly cyclic processes, imposing forced solvent cycling, for managing production of solvent in a process of recovering oil/petroleum/hydrocarbons from a reservoir/formation containing bitumen/heavy oil/heavy hydrocarbons, for example by co-injection of steam and solvent. The cyclic process includes conditionally recurrent steps of increasing and decreasing of the production rate and the injection rate of fluids, and the cycling of the bottom hole pressure between a maximum and a minimum. The synchronized adjustment of the bottom hole pressure and the production rate is arranged such that the production rate is low while the bottom hole pressure is increasing or high, and the production rate is high while the bottom hole pressure is decreasing or low. The synchronized adjustment of the injection rate and production rate is arranged such that the production rate is low while the injection rate is high, and the production rate is high while the injection rate is low. The process may involve monitoring casing gas flow during production, and triggering transition from a "bitumen-draining" phase (low injection/high production) to a "solvent-filling" phase (high injection/low production) when the casing gas flow rate, or change in casing gas flow rate, reaches a selected maximum threshold.

[0042] In the context of the present application, various terms are used in accordance with what is understood to be the ordinary meaning of those terms. For example, "petroleum" is a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid or solid phase. In the context of the present application, the words "petroleum"
and "hydrocarbon"
are used to refer to mixtures of widely varying composition. The production of petroleum from a reservoir necessarily involves the production of hydrocarbons, but is not limited to hydrocarbon production and may include, for example, trace quantities of metals (e.g. Fe, Ni, Cu, V).
Similarly, processes that produce hydrocarbons from a well will generally also produce petroleum fluids that are not hydrocarbons. In accordance with this usage, a process for producing petroleum or hydrocarbons is not necessarily a process that produces exclusively petroleum or hydrocarbons, respectively. "Fluids", such as petroleum fluids, include both liquids Date Recue/Date Received 2020-12-18 and gases. Natural gas is the portion of petroleum that exists either in the gaseous phase or in solution in crude oil in natural underground reservoirs, and which is gaseous at atmospheric conditions of pressure and temperature. Natural gas may include amounts of non-hydrocarbons.
The abbreviation POIP stands for "producible oil in place" and in the context of the methods disclosed herein is generally defined as the exploitable or producible oil located above the production well elevation.

[0043] It is common practice to segregate petroleum substances of high viscosity and density into two categories, "heavy oil" and "bitumen". For example, some sources define "heavy oil" as a petroleum that has a mass density of greater than about 900 kg/m3. Bitumen is sometimes described as that portion of petroleum that exists in the semi-solid or solid phase in natural deposits, with a mass density greater than about 1,000 kg/m3 and a viscosity greater than 10,000 centipoise (cP; or 10 Pa-s) measured at original temperature in the deposit and atmospheric pressure, on a gas-free basis. Although these terms are in common use, references to heavy oil and bitumen represent categories of convenience and there is a continuum of properties between heavy oil and bitumen. Accordingly, references to heavy oil and/or bitumen herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the two substances. In particular, the term "heavy oil" includes within its scope all "bitumen"
including hydrocarbons that are present in semi-solid or solid form.

[0044] A "reservoir" is a subsurface formation containing one or more natural accumulations of moveable petroleum, which are generally confined by relatively impermeable rock. An "oil sand" or "oil sands" reservoir is generally comprised of strata of sand or sandstone containing petroleum. A "zone" in a reservoir is an arbitrarily defined volume of the reservoir, typically characterized by some distinctive property. Zones may exist in a reservoir within or across strata or facies, and may extend into adjoining strata or facies. In some cases, reservoirs containing zones having a preponderance of heavy oil are associated with zones containing a preponderance of natural gas. This "associated gas" is gas that is in pressure communication with the heavy oil within the reservoir, either directly or indirectly, for example through a connecting water zone. A pay zone is a reservoir volume having hydrocarbons that can be recovered economically.

[0045] "Thermal recovery" or "thermal stimulation" refers to enhanced oil recovery techniques that involve delivering thermal energy to a petroleum resource, for example to a heavy oil reservoir. There are a significant number of thermal recovery techniques other than Date Recue/Date Received 2020-12-18 SAGD, such as cyclic steam stimulation (CSS), in-situ combustion, hot water flooding, steam flooding, and electrical heating. In general, thermal energy is provided to reduce the viscosity of the petroleum to facilitate production.

[0046] A "chamber" within a reservoir or formation is a region that is in fluid/pressure communication with a particular well or wells, such as an injection or production well. For example, in a SAGD process, a steam chamber is the region of the reservoir in fluid communication with a steam injection well, which is also the region that is subject to depletion of hydrocarbons, often by gravity drainage, into a production well.

[0047] As used herein, the term "about", in the context of a numerically definable parameter, refers to an approximately +/-10% variation from a given value. Where numerical values are recited herein and these values are necessarily an approximation, for example to a given decimal point, it is to be understood that the recital of the values imputes the exercise of approximation.

[0048] A wide variety of alternative configurations of injection and production wells may be adapted for alternative implementations of forced solvent cycling processes, for example involving production wells that are infill wells, which may in turn be wedgewells, and where steam or production chambers served by particular injection and/or production wells are distinct or have merged.

[0049] Reservoirs containing heavy hydrocarbons are typically below an overburden, which may also be referred to as a cap layer or cap rock. The overburden may be formed of a layer of impermeable material such as clay or shale. Under natural conditions (e.g.
prior to the application of a recovery process), the reservoir is typically at a relatively low temperature, such as about 12 C, and the formation pressure may be from about 0.1 to about 4 MPa (1 MPa =
1,000 Pa), depending on the location and other characteristics of the reservoir. A pair of wells, including an injection well and a production well, are drilled into and extend substantially horizontally in the reservoir for producing hydrocarbons from the reservoir.
The well pair is typically positioned away from the top of the reservoir, which is defined by the lower edge of the overburden, and positioned near the bottom of a pay zone or geological stratum in the reservoir.

[0050] As is typical of such well pair configurations, the injection well may be vertically spaced from the production well, such as at a distance between about 1 m to about 15 m, and more typically of about 5 m. The distance between the injection well and the production well in a well pair may vary and may be selected to optimize forced solvent cycling operations. In select Date Recue/Date Received 2020-12-18 embodiments, the horizontal sections of the injection well and the production well may be between about 800 m and about 2000 m in length. In other embodiments, these lengths may be varied and the overall pattern of well pairs may vary widely. The injection well and the production well may each be configured and completed according to a wide variety of suitable techniques available in the art. The injection well and the production well may also be referred to as the "injector" and "producer", respectively.

[0051] The injection well and the production well are typically connected to respective corresponding surface facilities, which typically include an injection surface facility and a production surface facility. The injection surface facility may be configured and operated to supply injection fluids, such as steam, solvent or combinations thereof into the injection well.
The production surface facility is configured and operated to produce fluids collected in the production well to the surface. In select embodiments, co-injected fluids or materials may be pre-mixed before injection. In other embodiments, co-injected fluids may be separately supplied into the injection well. In particular, the injection surface facility may be used to supply steam into the injection well in a first phase, and a mixture of steam and solvent into the injection well in a second phase. In the second phase, the solvent may be pre-mixed with steam at surface before co-injection. Alternatively, the solvent and steam may be separately fed into the injection well for injection into the reservoir. Optionally, the injection surface facility may include a heating facility (not separately shown) for pre-heating the solvent before injection.

[0052] The injection well typically has an injector casing and the production well has a production casing. An injector tubing is typically positioned in the injector casing. The injector casing may include a slotted liner along the horizontal section of well for injecting fluids into the reservoir. Production casing may also be completed with a slotted liner, a wire wrap or a precise punched slot screen (PPS), along the horizontal section of well for collecting fluids drained from the reservoir by gravity (i.e. in a gravity-dominated process). In select embodiments, the production well may be configured and completed similarly to the injection well. In select embodiments, each of the injection well and the production well may be configured and completed for both injection and production.

[0053] The reservoir may be subjected to an initial phase, for example as part of a SAGD
process, referred to as the "start-up" phase or stage. Typically, start-up involves establishing fluid communication between the injection well and the production well. To permit drainage of mobilized hydrocarbons and condensate to the production well, fluid communication between the injection well and the production well must be established in the interwell zone. Fluid Date Recue/Date Received 2020-12-18 communication in this context refers to fluid flow between the injection and production wells.
Establishment of such fluid communication typically involves mobilizing viscous hydrocarbons in the reservoir to form a mobilized reservoir fluid and removing the mobilized reservoir fluid to create a porous pathway between the wells. Viscous hydrocarbons may be mobilized by heating such as by injecting or circulating pressurized steam or hot water through the injection well or the production well. In some cases, steam may be injected into, or circulated in, both the injection well and the production well for faster start-up. A pressure differential may be applied between the injection well and the production well to promote steam/hot water penetration into the porous geological formation that lies between the wells of the well pair.
The pressure differential promotes fluid flow and convective heat transfer to facilitate communication between the wells.

[0054] Additionally or alternatively, other techniques may be employed during the start-up stage. For example, to facilitate fluid communication, a solvent may be injected into the reservoir region around and between the injection well and the production well. The region may be soaked with a solvent before or after steam injection. An example of start-up using solvent injection is disclosed in CA 2,698,898. In further examples, the start-up phase may include one or more start-up processes or techniques disclosed in CA 2,886,934, CA
2,757,125, or CA
2,831,928.

[0055] Once fluid communication between the injection well and the production well has been achieved, oil production or recovery may commence, employing one or more iterations of forced solvent cycling. As a result of depletion of the heavy hydrocarbons, a porous region is formed in the reservoir, which is referred to as a vapor or production or recovery chamber. The mobilized hydrocarbons drained towards the production well and collected in the production well are then produced (transferred to the surface), such as by gas lifting or through pumping.

[0056] The solvent for use in the present processes may be selected based on a number of considerations and factors, for example as set out in CA2,956,771. The solvent may be injectable as a vapor, and may be selected on the basis of being suitable for dissolving at least one of the heavy hydrocarbons to be recovered from the reservoir. The solvent may be a viscosity-reducing solvent, which reduces the viscosity of the heavy hydrocarbons in the reservoir. Suitable solvents may include C2 to C10 linear, branched, or cyclic alkanes, alkenes, or alkynes, in substituted or unsubstituted form, or other aliphatic or aromatic compounds.
Select embodiments may for example use an n-alkane as the dominant solvent, for example propane, butane, pentane or mixtures thereof. For a given selected solvent, the corresponding Date Recue/Date Received 2020-12-18 operating parameters during co-injection of the solvent with steam may also be selected or determined in view the properties and characteristics of the selected solvent.
The mass fraction of the solvent may for example be greater than 20% and enough steam may be added to ensure that the injected solvent is substantially in the vapor phase. In a given application, the solvent may be selected based on its volatility and solubility in the reservoir fluid.

[0057] The solvent may be heated to vaporize the solvent. For example, when the solvent is propane, it may be heated with hot water at a selected temperature such as, for example, about 100 C. Additionally or alternatively, solvent may be mixed or co-injected with steam to heat the solvent to vaporize it and to maintain the solvent in vapor phase. Depending on whether the solvent is pre-heated at surface, the weight ratio of steam in the injection stream should be high enough to provide sufficient heat to the co-injected solvent to maintain the injected solvent in the vapor phase. If the feed solvent from surface is in the liquid phase, more steam may be required to both vaporize the solvent and maintain the solvent in the vapor phase as the solvent travels through the vapor chamber 260. For example, where the selected solvent is propane, a solvent-steam mixture containing about 90% propane and about 10% steam on a mass basis may be injected at a suitable temperature, such as about 75 C to about 100 C. For example, the enthalpy per unit mass of the aforementioned steam-propane mixture may be about 557 kJ/kg.

[0058] In the context of the present disclosure, at various times, the produced-fluid stream may have an oil:water ratio of from about 60:40 to about 90:10, or for example alternatively about 75:25 to about 90:10, depending on the amount of solvent injected. The use of solvent accordingly gives rise to a bitumen-concentrating effect in the mobilized fluid zone at the bottom of the production chamber, compared to thermal recovery mediated by steam alone.

[0059] Although various embodiments of the invention are disclosed herein, many adaptations and modifications may be made within the scope of the invention in accordance with the common general knowledge of those skilled in this art. Such modifications include the substitution of known equivalents for any aspect of the invention in order to achieve the same result in substantially the same way. Terms such as "exemplary" or "exemplified" are used herein to mean "serving as an example, instance, or illustration." Any implementation described herein as "exemplary" or "exemplified" is accordingly not to be construed as necessarily preferred or advantageous over other implementations, all such implementations being independent embodiments. Unless otherwise stated, numeric ranges are inclusive of the numbers defining the range, and numbers are necessarily approximations to the given decimal.
The word "comprising" is used herein as an open-ended term, substantially equivalent to the Date Recue/Date Received 2020-12-18 phrase "including, but not limited to", and the word "comprises" has a corresponding meaning.
As used herein, the singular forms "a", "an" and "the" include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to "a thing" includes more than one such thing. Citation of references herein is not an admission that such references are prior art to the present invention. Any priority document(s) and all publications, including but not limited to patents and patent applications, cited in this specification, and all documents cited in such documents and publications, are hereby incorporated herein by reference as if each individual publication were specifically and individually indicated to be incorporated by reference herein and as though fully set forth herein. The invention includes all embodiments and variations substantially as hereinbefore described and with reference to the examples and drawings.

Date Recue/Date Received 2020-12-18

Claims (18)

1. A method of recovering hydrocarbons from a subterranean heavy oil reservoir, comprising:
providing a well pair servicing a recovery chamber, the well pair comprising:
a production well accessing the heavy oil reservoir; and, spaced apart from the production well by an interwell zone, an injection well accessing the heavy oil reservoir;
in a solvent-filling phase, injecting a mobilizing fluid comprising a solvent through the injection well at a constant or variable solvent-filling-phase injection rate so as to increase a bottom hole pressure (BHP) in the recovery chamber while modulating production of mobilized fluids from the production well so as to limit the amount of production well casing gas production below a solvent-filling-phase maximum casing gas production threshold, so as to increase the BHP to a solvent-filling-phase upper BHP
threshold value;
in a bitumen-draining phase, decreasing the solvent injection rate, so as to decrease the BHP in the recovery chamber while modulating production of mobilized fluids from the production well so as to permit the amount of casing gas produced to rise to a bitumen-draining phase maximum casing gas production threshold; and, when the bitumen-draining-phase maximum casing gas production threshold is reached, returning to the solvent-filling phase, wherein the solvent-filling-phase maximum casing gas production threshold is at or less than 50% of the value of the bitumen-draining-phase maximum casing gas production threshold.

2. The method of claim 1, wherein the bitumen-draining-phase maximum casing gas production threshold is at least about 10 T/d, about 11 T/d, about 12 T/d, about 13 T/d, about 14 T/d, about 15 T/d, about 16 T/d, about 17 T/d, about 18 T/d, about 19 T/d or about 20 T/d; or, is an at least about 10%, about 20%, about 30%, about 40%, about 50%, about 60% about 70%, about 80%, about 90%, about 100%, about 110%, about 120%, about 130%, about 140%, about 150%, about 160%, about 170%, about 180%, about Date Recue/Date Received 2020-12-18 190%, or about 200% increase of casing gas production rate within a bitumen-draining-phase maximum casing gas monitoring period of from about 1 hour to about 1 week.

3. The method of claim 1 or 2, wherein the solvent-filling-phase maximum casing gas production threshold is between about 0 T/d and about 10 T/d; or, is an at least about 10%, about 20%, about 30%, about 40%, about 50%, about 60% about 70%, about 80%, about 90%, about 100%, about 110%, about 120%, about 130%, about 140%, about 150%, about 160%, about 170%, about 180%, about 190%, or about 200% increase of casing gas production rate within a solvent-filling-phase maximum casing gas monitoring period of from about 1 hour to about 1 week.

4. The method of any one of claims 1 to 3, wherein the solvent-filling-phase maximum casing gas production threshold is at or less than about 40%, about 30%, about 20%, about 10%, about 5% or about 1% of the value of the bitumen-draining-phase maximum casing gas production threshold.

5. The method of any one of claims 1 to 4, wherein the solvent-filling-phase upper BHP
threshold value is at least about 3175 kPa, about 3200 kPa, about 3225 kPa or 3250 kPa.

6. The method of any one of claims 1 to 5, wherein the BHP is generally maintained within a BHP constraint range at or below the solvent-filling-phase upper BHP threshold value and at or above a minimum BHP constraint value.

7. The method of any one of claims 1 to 6, wherein, in the bitumen-draining phase, the solvent injection rate is decreased to below an average of the solvent-filling-phase injection rates, so as to decrease the BHP in the recovery chamber.

Date Recue/Date Received 2020-12-18

8. The method of any one of claims 1 to 7, wherein, in the bitumen-draining phase, the solvent injection rate is decreased to below a minimum value of the solvent-filling-phase injection rates, so as to decrease the BHP in the recovery chamber.

9. The method of any one of claims 1 to 8, wherein the solvent-filling phase and the bitumen-draining phase are repeated in a plurality of cycles, and in the plurality of cycles one or more of the following parameters changes from one cycle to another cycle: the bitumen-draining-phase maximum casing gas production threshold; the solvent-filling-phase maximum casing gas production threshold; and/or, the solvent-filling-phase upper BHP
threshold value.

10. The method of any one of claims 1 to 9, wherein the solvent comprises C2 to C10 linear, branched, or cyclic alkanes, alkenes, or alkynes, substituted or unsubstituted.

11. The method of any one of claims 1 to 10, wherein the solvent predominantly comprises one or more n-alkane.

12. The method of claim 11, wherein the n-alkane is propane, butane or pentane.

13. The method of any one of claims 1 to 9, wherein the solvent comprises propane and/or butane.

14. The method of any one of claims 1 to 13, wherein the mobilizing fluid comprises steam.

15. The method of any one of claims 1 to 14, wherein the mobilizing fluid comprises at least about 50%, about 60%, about 70%, about 80% or 90% solvent.

16. The method of any one of claims 1 to 15, wherein the production well accessing the heavy oil reservoir comprises a production well surface facility in fluid communication with a Date Recue/Date Received 2020-12-18 generally horizontal longitudinal production well segment within a heavy oil zone in the reservoir, the production well comprising a fluid-permeable production well casing.

17. The method of claim 16, wherein the injection well accessing the heavy oil reservoir comprises an injection well surface facility in fluid communication with a generally horizontal longitudinal injection well segment within the heavy oil zone in the reservoir, the longitudinal injection well segment being generally parallel to and vertically spaced apart above the longitudinal production well segment.

18. The method of any one of claims 1 to 17, wherein the method further comprises a transition period between: (i) the solvent-filling phase and the bitumen-draining phase;
and/or (ii) the bitumen-draining phase and the solvent-filling phase.
Date Recue/Date Received 2020-12-18