CA2956771A1

CA2956771A1 - Methods of recovering heavy hydrocarbons by hybrid steam-solvent processes

Info

Publication number: CA2956771A1
Application number: CA2956771A
Authority: CA
Inventors: Alexander Eli Filstein
Original assignee: Cenovus Energy Inc
Current assignee: Cenovus Energy Inc
Priority date: 2016-02-01
Filing date: 2017-01-31
Publication date: 2017-08-01
Anticipated expiration: 2037-01-31
Also published as: CA2956771C

Abstract

Heavy hydrocarbons are recovered from a subterranean reservoir by a hybrid recovery process including steam-dominant and solvent-dominant processes. The process includes injecting steam into the reservoir to assist recovery of hydrocarbons from the reservoir by the steam-dominant process until a peak process threshold has been reached. A vapor chamber is developed in the reservoir by steam injection and a dominant vapor in the vapor chamber during the steam-dominant process is steam. Upon determination that the peak process threshold has been reached, a solvent and steam are co-injected into the vapor chamber to assist further recovery of hydrocarbons from the reservoir by the solvent-dominant process, such that the vapor chamber is further expanded and the dominant vapor in the expanded vapor chamber is a vapor of the injected solvent. A fluid comprising the solvent and hydrocarbons is recovered from the reservoir.

Description

METHODS OF RECOVERING HEAVY HYDROCARBONS
BY HYBRID STEAM-SOLVENT PROCESSES
TECHNICAL FIELD
[001] This invention relates generally to in situ processes for recovering hydrocarbons from reservoirs of heavy hydrocarbons, and more particularly to hybrid steam-solvent-assisted in situ recovery processes.
BACKGROUND

[002] Some subterranean deposits of heavy hydrocarbons can be extracted in situ (in-situ) by increasing the mobility of the heavy hydrocarbons so that they can be moved to, and recovered from, a production well penetrating a formation of the hydrocarbons. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbons, heavy oil, bitumen, tar sands, bituminous sands, or oil sands.
For example, such reservoirs include deposits as may be found in Canada's Athabasca oil sands.

[003] The in situ processes for recovering oil from heavy hydrocarbon reservoirs typically involve the use of multiple wells drilled into the reservoir, and are assisted or aided by injecting a heated fluid such as steam into the reservoir formation from an injection well.

[004] For example, a known process for recovering viscous hydrocarbons is the steam-assisted gravity drainage (SAGD) process. A typical (conventional) SAGD
process utilizes one or more pairs of vertically spaced horizontal wells. For example, various embodiments of the SAGD process are described in Canadian Patent No.
1,304,287 and corresponding U.S. Patent No. 4,344,485. In a SAGD process, steam is pumped through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well vertically spaced proximate to the injection well. The injection and production wells are typically located near, but some distance above, the bottom of a pay zone in the hydrocarbon deposit. The injected steam initially heats and mobilizes the in-situ hydrocarbons in the reservoir around the injection well. Mobilized hydrocarbons will drain downward due to gravity, leaving a volume of the formation at least partially depleted of the hydrocarbons. The pores in the depleted volume of the formation, from which mobilized oil has at least partially drained, are then filled with mainly injected steam, and the deleted volume is thus commonly referred to as the "steam chamber".
As steam injection and gravity drainage continue, the steam chamber will continue to grow, expanding both upwardly and laterally from the injection well. As the steam chamber expands upwardly and laterally from the injection well, more and more viscous hydrocarbons in the reservoir are gradually heated and mobilized, especially at the margins of the steam chamber where the steam condenses and heats a layer of viscous hydrocarbons by thermal conduction. The mobilized hydrocarbons (and aqueous condensate) drain under the effects of gravity towards the bottom of the steam chamber, where the production well is located. The mobilized hydrocarbons are collected and produced from the production well.

[005] Alternative processes aided by fluids other than steam have also been proposed. For example, solvent-aided processes (SAP) and a process known as the vapor-extraction (VAPEX) process have been proposed. In SAP, both steam and a solvent may be used to aid recovery. VAPEX utilizes a solvent vapor, instead of steam, to reduce the viscosity of viscous hydrocarbons. In a proposed VAPEX
process, a solvent, such as propane, is injected into the reservoir in the vapor phase, to form a vapor-filled chamber within the reservoir. The solvent vapor dissolves in the oil around the vapor chamber and the resulting solution drains, driven by gravity, to a horizontal production well placed low in the formation. The solvent vapor, at or near its dew point, is injected simultaneously with hot water from a horizontal well located at the top of the reservoir. The temperature and flow rate of the water are chosen so that the reservoir temperature is raised to the range of only 40 C to 80 C. See, Butler et al., "A New Process (VAPEX) for Recovering Heavy Oils Using Hot Water and Hydrocarbon Vapour", Journal of Canadian Petroleum Technology, 1991, vol. 30, issue 1, pages 97-106.

[006] US 6,662,872 to Gutek et al. discloses a combined steam and vapor extraction process (SAVEX), where steam is injected until an upper surface of the steam chamber has progressed to 25 to 75 percent of the distance from the bottom of the injection well to the top of the reservoir, or until the recovery rate of hydrocarbons is about 25 to 75 percent of the peak predicted recovery rate using SAGD. When the condition is met, steam injection is suspended and replaced with solvent vapor injection (the VAPEX process). The cross over in injection from steam to vaporized solvent should occur about 4 to 6 months after the initiation of SAGD operations for a typical SAGD well pair in Athabasca. One of the goals in modifying existing SAGD and other steam-assisted processes is to reduce the steam to oil ratio (SOR) or the cumulative SOR (CSOR), as the SOR or CSOR is commonly considered an important metric for assessing the performance and efficiency of a steam-assisted recovery process.

Replacing steam with solvent vapor and hot water as in the VAPEX or SAVEX
process is expected to reduce CSOR. However, another important measure of the performance of an oil recovery process is the oil production rate, which indicates how fast oil can be produced from the reservoir. The proposed VAPEX or SAVEX processes are expected to result in significant reduction in peak oil production rate.

[007] Instead of a well pair, one or more single horizontal or vertical wells may be utilized for injection and production in in-situ hydrocarbon recovery processes such as, but not limited to, SAGD, cyclic steam stimulation (CSS), or SAP. For example, Canadian patent application number 2,844,345 to Gittins et al. discloses a single vertical or inclined well thermal recovery process. Canadian patent application number 2,868,560 to Sood et aL discloses a single horizontal well for injection and production in thermal or solvent recovery processes. These single well processes may be preceded by start-up acceleration techniques to establish communication in the formation between openings in the single well that have been configured to allow for both injection and production. An assembly for coupling a high-pressure steam pipeline, a produced hydrocarbon emulsion pipeline, and a produced gas pipeline to a single well may be employed for facilitating injection and production.
SUMMARY

[008] In one aspect, there is provided a method of recovering heavy hydrocarbons from a subterranean reservoir by a steam-dominant recovery process and a solvent-dominant recovery process, comprising: injecting steam into the reservoir to assist recovery of hydrocarbons from the reservoir by the steam-dominant recovery process until a peak process threshold has been reached, wherein a vapor chamber is developed in the reservoir by steam injection and a dominant vapor in the vapor chamber during the steam-dominant recovery process is steam; upon determination that the peak process threshold has been reached, co-injecting a solvent and steam into the vapor chamber to assist further recovery of hydrocarbons from the reservoir by the solvent-dominant recovery process, such that the vapor chamber is further expanded and the dominant vapor in the expanded vapor chamber is a vapor of the injected solvent; and recovering a fluid comprising the solvent and hydrocarbons from the reservoir.

[009] The steam-dominant recovery process may comprise a steam-assisted gravity drainage (SAGD) recovery process. The method may comprise selecting a solvent for the solvent- dominant process, wherein the solvent is injectable as a vapor and dissolves at least one of the hydrocarbons for increasing a mobility of the heavy hydrocarbons. The solvent may be heated and vaporized by the co-injected steam. The solvent-dominant recovery process may comprise co-injecting steam and the vapor of the solvent into the vapor chamber to further expand the vapor chamber laterally, wherein the volume of steam injected into the reservoir formation provides sufficient heat to the injected solvent to maintain the injected solvent in a vapor phase, and wherein the weight ratio of co-injected solvent vapor to co-injected steam is higher than 3/2. The method may comprise selecting a transition condition for transitioning from the steam-dominant recovery process to the solvent-dominant recovery process, wherein the transition condition occurs after the peak process threshold has been reached, determining when the condition has been met, and upon determination that the condition has been met, transitioning from the steam-dominant recovery process to the solvent-dominant recovery process. The reservoir may have an overburden above a formation of the reservoir that contains heavy hydrocarbons, the steam-dominant process may create a vapor chamber in the formation below the overburden, and the transition condition may be that the injected steam has reached the overburden. The reservoir may have an overburden above a formation of the reservoir that contains heavy hydrocarbons, the SAGD process may form a vapor chamber in the formation below the overburden, and the transition condition may be that vertical growth of the vapor chamber has reached a limit such that further vapor chamber growth will be substantially lateral. The transition condition may be that a peak hydrocarbon production rate has been reached in the SAGD process. The transition condition may be that the reservoir has been subjected to the steam-dominant recovery process for at least two years. The transition condition may be that the hydrocarbon production rate has reached a peak value and then decreased by less than about 20 percent of the peak value, such as decreased by about 10% of the peak production rate, in the steam-dominant recovery process. The transition condition may be that hydrocarbon production in the steam-dominant recovery process has declined for a selected period of time. The transition condition may be that a current cumulative steam to oil ratio (CSOR) is higher than a previous CSOR in the steam-dominant recovery process.
The reservoir may have an overburden above a formation of the reservoir that contains heavy hydrocarbons, and steam injection in the steam-dominant recovery process may cause a temperature at an interface region between the overburden and the formation to increase, and the transition condition may be that the temperature has increased to at least 20 C due to heating by steam injection. The solvent may comprise at least one of propane, butane, pentane, hexane, heptane, and octane. The solvent may comprise a C3 to C5 hydrocarbon. The solvent may comprise propane. The solvent-dominant process may comprise co-injecting a mixture of steam and the solvent, the mixture comprising less than 40 wt% of steam. The solvent may comprise propane and the solvent-dominant process may comprise co-injecting a mixture of steam and the solvent, the mixture comprising about 10 wt% of steam and about 90 wt% of the solvent. The solvent may comprise propane, and steam and the solvent may be co-injected at a temperature of about 75 C to about 100 C in the solvent-dominant process. Steam may be injected at a pressure of about 3 MPa in the steam-dominant recovery process, and steam and the solvent may be co-injected at a pressure of about 2 MPa to about 3.5 MPa in the solvent-dominant process. The co-injection of a solvent and steam into the vapor chamber may comprise gradually increasing the weight ratio of the solvent in the co-injected solvent and steam, and gradually decreasing the weight ratio of steam in the co-injected solvent and steam. The method may further comprise gradually decreasing a solvent content in the co-injected solvent and steam, and gradually increasing a steam content in the co-injected solvent and steam.
The solvent-dominant process may comprise co-injecting a mixture of about 20 wt%
of steam and about 80 wt% of propane. Steam injection may be reduced from about wt% to about 20 wt% of the injected fluid (mixture) over a period of about three weeks.
In the solvent-dominant process, the steam and solvent may be co-injected as a mixture at a selected temperature, and a ratio of steam to solvent in the mixture and the temperature may be selected so that the mixture has sufficient enthalpy to allow the solvent to be in the gas phase at the selected temperature. In the steam-dominant recovery process, steam may be injected at a temperature sufficient to heat the solvent such that the injected solvent has a temperature of between about 50 C and about 350 C within the vapor chamber.

[010] Other aspects and features will become apparent to those of ordinary skill in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS

[011] Selected illustrative embodiments are described in detail below, with reference to the following drawings.

[012] FIG. 1 is a schematic side view of a hydrocarbon reservoir and a pair of wells penetrating the reservoir for recovery of hydrocarbons.

[013] FIG. 2 is a schematic partial end view of the reservoir and wells of FIG. 1.

[014] FIG. 3 is a schematic perspective view of the reservoir and wells of FIG. 1 during operation after a vapor chamber has formed in the reservoir.

[015] FIG. 4 is a flowchart illustrating a process for recovery of hydrocarbons from the reservoir of FIG. 1, illustrative of an embodiment.

[016] FIG. 5 is a simulated two-dimensional phase diagram for selected solvents.

[017] FIG. 6 is a schematic partial end view of the reservoir and wells of FIG. 3 where the vapor chamber has expanded upward to reach the overburden above the wells.

[018] FIG. 7 is a schematic partial end view of the reservoir and wells of FIG. 3 where the vapor chamber has ceased upward vertical expansion and has further expanded laterally.

[019] FIGS. 8, 9, 10 and 11 are line graphs illustrating expected change in oil production rate over time in a SAGD process and possible transition times.

[020] FIG. 12 is a line graph illustrating time dependency of the cumulative steam to oil ratio in a SAGD process.

[021] FIG. 13 is a data graph of representative expected temperature changes at an interface region between a pay zone formation and an overburden in the reservoir of FIG. 1 over time during a SAGD process.

[022] FIG. 14 is a line graph showing representative expected heavy hydrocarbon recovery factors for selected solvents at various injection temperatures.

[023] FIG. 15 is a data graph showing representative expected oil production rates for a hybrid steam-solvent process as compared to a conventional SAGD
process.

[024] FIG. 16 is a data graph comparing expected production rates for a hybrid process and a comparison SAGD process, illustrating the effects of the solvent-dominant process at later stages of oil production.

[025] FIG. 17 shows a screen capture of a computer display illustrating representative simulation results of vapor chamber development in the process of FIG. 4.

[026] FIG. 18 is a line graph showing cumulative oil production over time in different simulated recovery processes.

[027] FIG. 19 is a line graph showing oil production rate over time in different simulated processes.

[028] FIG. 20 is a line graph showing cumulative solvent injection over time in different simulated recovery processes.
DETAILED DESCRIPTION

[029] In overview, it has been recognized by the Applicant that effective and efficient recovery of heavy hydrocarbons from a subterranean hydrocarbon reservoir can be provided by a hybrid recovery process where a steam-dominant recovery process (steam-dominant process) is followed by a solvent-dominant recovery process (solvent-dominant process) after the steam-dominant recovery process has reached a peak production threshold. The Applicant has found that the peak production threshold may be reached when the steam chamber has ceased substantial vertical growth or expansion (e.g. has reached the overburden above the steam chamber), when the oil production rate by the steam-dominant process has peaked, when the cumulative steam to oil ratio (CSOR) has started to increase, or when the temperature in the interface region between the reservoir formation and the overburden has started to significantly increase. It is expected that an embodiment of such a hybrid recovery process can significantly accelerate hydrocarbon recovery, reduce the overall CSOR, and still achieve satisfactory peak oil production rate, or satisfactory overall average oil production rate over the entire recovery period.

[030] In the steam-dominant recovery process, the injected steam plays the dominant role for the vertical vapor chamber development in the reservoir. The vapor chamber developed in the steam-dominant process is a steam chamber, as the dominant vapor in the vapor chamber is steam. In selected embodiments, the steam-dominant recovery process may be a steam-assisted gravity drainage (SAGD) process.
In a SAGD process, pure steam may be injected to assist hydrocarbon recovery.
In a modified SAGD process, one or more additives may be co-injected with steam, or separately injected, but the weight ratio of the additive to steam in the injection fluid is relatively small, such as less than about 20 to 30 wt%.

[031] In the solvent-dominant recovery process, the injected solvent plays the dominant role for further expansion, particularly lateral or horizontal expansion of the vapor chamber in the reservoir. While the vapor chamber is initially dominated by steam, after a period of operation under the solvent-dominant process, the dominant vapor in the vapor chamber becomes the solvent vapor, as the dominant component in the injection fluid is now the solvent. In selected embodiments, the solvent may be co-injected with a small amount of steam in the solvent-dominant process. In such a case, the amount of the injected steam is selected to be sufficient to heat and vaporize the injected solvent, and maintain the solvent in the vapor phase in the vapor chamber to allow the solvent to travel to the chamber front (edges or margins of the vapor chamber). However, the weight ratio of co-injected steam to co-injected solvent is relatively small, such as less than about 20 to 30 wt%, so that steam plays only a minor role in further expansion the vapor chamber and further oil production. The amount of injected steam is thus substantially reduced or minimized in the solvent-dominant process, as compared to steam use in the steam-dominant process.

[032] As can be appreciated, the solvent used in the solvent-dominant process is vaporizable at the operational pressure and temperature near the injection well and in the central region of the vapor chamber, which has been heated by steam to an elevated temperature, so that the solvent can enter the reservoir in the vapor phase and can remain in the vapor phase until the solvent vapor reaches the vapor chamber front. The solvent is also substantially condensable at the edges, margins or boundaries of the vapor chamber, where the local temperature is significantly lower than the temperature in the central region of the vapor chamber. The condensed solvent is capable of dissolving hydrocarbons such that the condensed solvent (liquid solvent) can reduce the viscosity of the hydrocarbons, or increase the mobility of the hydrocarbons, which will assist to improve the hydrocarbon drainage rate and therefore hydrocarbon production rate. There are a number of underlying mechanisms for increasing mobility of hydrocarbons in the reservoir formation as can be understood by those skilled in the art. A suitable solvent may be selected to assist drainage of hydrocarbons based on any of these mechanisms or a combination of such mechanisms.

[033] For example, a solvent may be selected based on its ability to reduce the viscosity of hydrocarbons, to dissolve in the reservoir fluid, or to reduce surface and interfacial tension between hydrocarbons and sands or other solid or liquid materials present in the reservoir formation. The solvent may act as a wetting agent or surfactant.
When oil attachment to sand or other immobile solid materials in the reservoir is reduced, the oil mobility can be increased. The solvent may function as an emulsifier for forming hydrocarbon-water emulsions, which may help to improve oil mobility with water in the reservoir. Suitable solvents may include volatile hydrocarbon solvents such as butane or propane, as will be further described below.

[034] In the hybrid steam-solvent process described herein, the timing for the transition from the steam-dominant process to the solvent-dominant process is selected to maintain satisfactory production performance while significantly reducing the overall CSOR. One factor for considering if a recovery process has satisfactory production performance is if the overall recovery process is practical and economically viable. The factors to be considered include the overall production time (to reach a given recovery factor), the overall production cost, the overall (amount of) oil recovery for a given reservoir, the potential environmental impact, and the like. It is generally desirable to minimize production cost while increasing production yield and production rate, and shortening recovery time. If the transition from the steam-dominant process to the solvent-dominant process occurs too early, such as before the oil production rate by steam injection has reached the peak rate, the overall production performance will be negatively affected. Transition after a properly selected peak production threshold, such as the peak oil production rate, has been reached is expected provide a balanced result, i.e., reducing the overall CSOR while maintaining satisfactory overall production performance.

[035] In some embodiments, a solvent-dominant process is introduced to improve production performance of an existing SAGD operation, particularly after the SAGD operation has continued for at least two years, or after the SAGD
production rate has peaked and is declining or after the CSOR of the SAGD operation has reached a minimum and is increasing with continued steam injection. At such later 'stages of the SAGD operation, replacing steam with solvent vapor as the dominant fluid for vapor chamber development and for hydrocarbon mobilization can conveniently have a number of benefits, some of which will be discussed below. As can be appreciated, in some applications, the transition from a steam-dominant process to a solvent-dominant process may occur earlier than two years from initial SAGD
production, or may be later than two years.

[036] Without being limited to any particular theory, it is expected that steam is more efficient or effective for vertical growth of the vapor chamber and a suitable solvent may be more efficient or effective for lateral growth of the vapor chamber. Thus, transitioning from a steam-dominant process to a solvent-dominant process after the vapor chamber has reached the overburden (or vertical expansion limit) and thus ceased vertical growth may provide better overall efficiency and more cost-effective recovery of hydrocarbons from the reservoir, as compared to a conventional SAGD
process or a conventional SAVEX process. The residual heat and aqueous condensate in the vapor chamber after steam injection can also help the injected solvent to remain in the vapor phase and to disperse through the vapor chamber, which will improve the effectiveness and efficiency of the solvent recovery process. The improvement or synergistic effect may be particularly significant for hydrocarbon recovery from a reservoir formation which has a pay zone depth that requires, for example, many months to two years for the vapor chamber to fully develop vertically by the steam-dominant recovery process.

[037] Also without being limited to any particular theory, it is further expected that steam utilization may become less efficient or effective after the vapor chamber (steam chamber) has reached the overburden due to significant heat loss through the overburden by thermal conduction. As a solvent vapor may be injected at a substantially lower temperature as compared to steam, further production operation at the lower temperature can reduce inefficiency due to heat loss.

[038] Selected illustrative embodiments are described in more detail below with reference to the drawings.

[039] FIG. 1 schematically illustrates a typical SAGD well pair in a hydrocarbon reservoir, which can be operated to implement an embodiment of the hybrid process.

[040] As illustrated, a reservoir formation 100 containing heavy hydrocarbons is below an overburden 110. Under natural conditions, reservoir formation 100 is 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 = 106 Pa), depending on the location and other characteristics of the reservoir.

[041] A pair of SAGD wells, including an injection well 120 and a production well 130, is drilled into and extends substantially horizontally in reservoir formation 100, for producing hydrocarbons from reservoir formation 100. The well pair is typically positioned away from the top of the reservoir formation 100, which as depicted in FIG.
1 is defined by the lower edge of overburden 110, and positioned near the bottom of a pay zone or geological stratum in formation 100, as can be appreciated by those skilled in the art.

[042] As is typical, injection well 120 may be vertically spaced from production well 130, such as at a distance of about 5 m. The distance between the injection well and the production well in a SAGD well pair may vary and may be selected to optimize the SAGD operation performance, as can be understood by those skilled in the art. In some embodiments, the horizontal sections of wells 120 and 130 may have a length of about 800 m. In other embodiments, the length may be varied as can be understood and selected by those skilled in the art. Wells 120 and 130 may be configured and completed according to any suitable techniques for configuring and completing horizontal in-situ wells known to those skilled in the art. Injection well 120 and production well 130 may also be referred to as the "injector" and "producer", respectively.

[043] As depicted, formation 100 underlies overburden 110, which may also be referred to as a cap layer or cap rock. Overburden 110 is formed of a layer of impermeable material such as clay or shale. A region in the formation 100 just below and near overburden 110 may be considered as an interface region 115.

[044] As illustrated, wells 120 and 130 are connected to respective corresponding surface facilities, which typically include an injection surface facility 140 and a production surface facility 150. Surface facility 140 is configured and operated to supply injection fluids, such as steam and solvent, into injection well 120.
Surface facility 150 is configured and operated to produce fluids collected in production well 130 to the surface. Each of surface facilities 140, 150 includes one or more fluid pipes or tubing for fluid communication with the respective well 120 or 130. As depicted for illustration, surface facility 140 may have a supply line connected to a steam generation plant for supplying steam for injection, and a supply connected to a solvent source for supplying the solvent for injection. Optionally, one or more additional supply lines may be provided for supplying other fluids, additives or the like for co-injection with steam or the solvent. Each supply line may be connected to an appropriate source of supply, which may include, for example, a steam generation plant, a boiler, a fluid mixing plant, a fluid treatment plant, a truck, a fluid tank, or the like. In some embodiments, co-injected fluids or materials may be pre-mixed before injection. In other embodiments, co-injected fluids may be separately supplied into injection well 120. In particular, surface facility 140 is used to supply steam and a selected solvent into injection well 120. The solvent may be pre-mixed with steam at surface before co-injection.
Alternatively, the solvent and steam may be separately fed into injection well 120 for injection into formation 100. Optionally, surface facility 140 may include a heating facility (not separately shown) for pre-heating the solvent before injection.

[045] As illustrated, surface facility 150 includes a fluid transport pipeline for conveying produced fluids to a downstream facility (not shown) for processing or treatment. Surface facility 150 includes necessary and optional equipment for producing fluids from production well 130, as can be understood by those skilled in the art.

[046] Other necessary or optional surface facilities 160 may also be provided, as can be understood by those skilled in the art. For example, surface facilities 160 may include one or more of a pre-injection treatment facility for treating a material to be injected into the formation, a post-production treatment facility for treating a produced material, a control or data processing system for controlling the production operation or for processing collected operational data.

[047] Injection well 120 and production well 130 may be configured and completed in any suitable manner as can be understood or is known to those skilled in the art, so long as the wells are compatible with injection and recovery of the selectable solvent to be used in the solvent-dominant process as will be disclosed below.

[048] FIG. 2 shows a schematic cross-sectional view of wells 120, 130 in formation 100, and FIG. 3 is a schematic perspective view of wells 120, 130 in formation 100 during a recovery process where a vapor chamber has formed.

[049] As illustrated, injection well 120 and production well 130, each have a casing 220, 230 (respectively). An injector tubing 225 is positioned in injector casing 220, the use of which can be understood by those skilled in the art and will be described below. For simplicity, other necessary or optional components, tools or equipment that are installed in the wells are not shown in the drawings as they are not particularly relevant to the present disclosure.

[050] As depicted in FIG. 3, injector casing 220 includes a slotted liner along the horizontal section of well 120 for injecting fluids into reservoir formation 100.

[051] Production casing 230 is also completed with a slotted liner along the horizontal section of well 130 for collecting fluids drained from reservoir formation 100 by gravity. In some embodiments, production well 130 may be configured and completed similarly to injection well 120.

[052] In some embodiments, each well 120, 130 may be configured and completed for both injection and production, which can be useful in some applications as can be understood by those skilled in the art.

[053] In operation according to an embodiment of the hybrid process, wells and 130 may be initially operated to produce hydrocarbons from reservoir formation 100 according to a conventional SAGD process, or a suitable variation thereof, as can be understood by those skilled in the art. In this initial process, steam is the only or the dominant injection fluid.

[054] FIG. 4 illustrates an example hybrid process.

[055] At S400, reservoir formation 100 is subjected to an initial phase of the SAGD process, referred to as the "start-up" phase or stage, in which fluid communication between wells 120 and 130 is established. To permit drainage of mobilized hydrocarbons and condensate to production well 130, fluid communication between wells 120, 130 must be established. Fluid communication 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 reservoir fluid and removing the 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 injection well 120 or production well 130. In some cases, steam may be injected into, or circulated in, both injection well 120 and production well 130 for faster start-up. For example, the start-up phase may include circulation of steam or hot water by way of injector casing 220 and injector tubing 225 in combination. A pressure differential may be applied between injection well 120 and production well 130 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.

[056] Additionally or alternatively, other techniques may be employed during the start-up phase. For example, to facilitate fluid communication, a solvent may be injected into the reservoir region around and between the injection and production wells 120, 130. The region may be soaked with a solvent before or after steam injection. An example of start-up using solvent injection is disclosed in CA2,698,898. In further examples, the start-up phase may include one or more start-up processes or techniques disclosed in CA2,886,934, CA2,757,125, or CA2,831,928.

[057] Once fluid communication between injection well 120 and production well 130 has been achieved, oil production or recovery may commence, at S410. As the oil production rate is typically low initially and will increase as the vapor chamber develops, the early production phase is known as the "ramp-up" phase or stage.
During the ramp-up phase, steam is typically injected continuously into injection well 120, at constant or varying injection pressure and temperature. At the same time, mobilized heavy hydrocarbons and aqueous condensate are continuously removed from production well 130. During ramp-up, the zone of communication between injection well 120 and production well 130 may continue to expand axially along the full length of the horizontal portions of wells 120, 130.

[058] As injected steam heats up formation 100, heavy hydrocarbons in the heated region are softened, resulting in reduced viscosity. Further, as heat is transferred from steam to formation 100, steam condenses. The aqueous condensate and mobilized hydrocarbons will drain downward due to gravity. As a result of depletion of the heavy hydrocarbons, a porous region 360 is formed in formation 100, which is referred to as the "vapor chamber." When the vapor chamber is filled with mainly steam, it is commonly referred to as the "steam chamber." The aqueous condensate and hydrocarbons drained towards production well 130 and collected in production well 130 are then produced (transferred to the surface), such as by gas lifting or through pumping as is known to those skilled in the art.

[059] As alluded to above, vapor chamber 360 is formed and expands due to depletion of hydrocarbons and other in situ materials from regions of formation 100 above the injection well 120. Injected steam tends to rise up to reach the top of vapor chamber 360 before it condenses, and steam can also spread laterally as it travels upward. Therefore, during early stages of chamber development, vapor chamber expands upwardly and laterally from injection well 120. During the ramp-up phase and the early conventional SAGD production phase, vapor chamber 360 can grow vertically towards overburden 110.

[060] Depending on the size of formation 100 and the pay therein and the distance between injection well 120 and overburden 110, it can take a long time, such as many months and up to two years, for vapor chamber 360 to reach overburden 110, when the pay zone is relative thick as is typically found in some operating oil sands reservoirs. However, it will be appreciated that in a thinner pay zone, the vapor chamber can reach the overburden sooner. The time to reach the vertical expansion limit can also be longer in cases where the pay zone is higher or highly heterogeneous, or the formation has complex overburden geologies such as with inclined heterolithic stratification (HIS), top water, top gas, or the like.

[061] At S420, reservoir formation 100 is subject to a conventional SAGD
production process, where the oil production rate is sufficiently high for economic recovery of hydrocarbons and the CSOR continues to decrease or remain relatively stable.

[062] During SAGD production or a similar but modified steam-dominant recovery process, one or more chemical additives may be added to steam or co-injected with steam to enhance hydrocarbon recovery. For example, a surfactant, which lowers the surface tension of a liquid, the interfacial tension (IFT) between two liquids, or the IFT between a liquid and a solid, may be added. The surfactant may act, for example, as a detergent, wetting agent, emulsifier, foaming agent, or dispersant, to facilitate the drainage of the softened hydrocarbons to the production well.
An organic solvent, such as an alkane or alkene, may also be added to dilute the mobilized hydrocarbons so as to increase the mobility and flow of the diluted hydrocarbon fluid to production well 130 for improved recovery. Other materials in liquid or gas form may also be added to enhance recovery performance. However, steam still plays the dominant role in chamber development during such modified SAGD processes and the weight ratio of such other agents or additives in the injection stream is relatively low. In some embodiments, the injection stream may include a mixture of steam and another vapor, where the partial pressure of the other vapor is about 0.25% to about 20% of the total pressure.

[063] When vapor chamber 360 grows vertically, oil production rate normally continue to increase, and the CSOR normally continue to decrease. Steam utilization during such chamber growth is efficient. However, when the top front of vapor chamber 360 approaches or reaches overburden 110 or transition region 115 near overburden 110, vertical growth of vapor chamber 360 will slow down and eventually stop.
While vapor chamber 360 may continue to grow or expand laterally, which may be at a slower pace, steam utilization during slow lateral growth is less efficient. As a result, oil production rate may reach a peak value or plateau, and then starts to decline.
The CSOR may bottom out and start to increase.

[064] Thus, such changes in chamber growth, oil production rate and CSOR
may be used as a production threshold for transitioning from the steam-dominant process to the solvent-dominant process. Without being limited to any particular theory, it is expected that a suitable solvent can be more effective or more efficient than steam for growing a vapor chamber laterally.

[065] The start-up, ramp-up, and SAGD production phases may be conducted according to any suitable conventional techniques known to those skilled in the art, and will therefore not be detailed herein for brevity.

[066] As an example, during conventional SAGD production, or at the end of the SAGD production process in the hybrid process, the formation temperature in the vapor chamber can reach about 235 C and the pressure in the vapor chamber may be about 3 MPa. Of course, depending on the reservoir and the application, the chamber temperature and pressure may vary in different embodiments. For example, in various embodiments, steam may be injected at a temperature from about 152 C to about C and a pressure from about 0.1 MPa to about 12.5 MPa. In some embodiments, the highest temperature in the vapor chamber may be from about 152 C to about 286 C
and the pressure in the vapor chamber may be from about 0.1 MPa to about 7 MPa.

[067] In further embodiments, it may also be possible that in the solvent-dominant process, steam is injected at a temperature sufficient to heat the solvent such that the injected solvent has a maximum temperature of between about 50 C and about 350 C within the vapor chamber.

[068] It should be noted that the temperature in a vapor chamber varies from the injection well towards the front of the vapor chamber, and the temperature at the chamber edges (also referred to as the "steam front") is still relatively low, such as about 15 C to about 25 C. The reservoir temperature can also vary from about to the highest chamber temperature discussed above.

[069] As production continues in conventional SAGD after the oil production rate has peaked, the rate of oil production will eventually decrease. When the oil production rate drops below a certain production performance threshold, continued operation under the SAGD production process becomes less economic, which is expected to occur during the later stages of a conventional SAGD production process, as compared to the earlier full production stage.

[070] It is expected that replacing the SAGD production process with a suitable solvent-dominant recovery process can improve production efficiency or performance and improve the economic outcome of the operation.

[071] To this end, at S430 a suitable solvent and transition condition are selected according to the various factors and considerations discussed herein, and as can be understood by those skilled in the art, at S440 and S450 respectively.
As can be appreciated, the selection at S440 and S450 may be performed at any time prior to solvent injection, and may be performed in any order depending on the particular situation and application.

[072] At S440, the solvent for use in the solvent-dominant process is selected or determined. A suitable solvent may be selected based on a number of considerations and factors as discussed herein. The solvent should be injectable as a vapor, and can dissolve at least one of the heavy hydrocarbons to be recovered from reservoir formation 100 in the solvent-dominant process for increasing mobility of the heavy hydrocarbons. The solvent may be a viscosity-reducing solvent, which reduces the viscosity of the heavy hydrocarbons in formation 100.

[073] At S450, a transition condition for transitioning to the solvent-dominant process is selected or determined. Transition conditions may be selected based on a number of considerations and factors as discussed herein. Transition conditions may be selected such as to, for example, achieve a desirable balance between various factors and considerations including engineering trade-offs and economic considerations, such as vapor chamber growth, production performance, costs, and environmental factors. The transition condition may be selected to ensure that the performance or production threshold discussed earlier has been reached. The transition condition may be selected based on operational experience in similar projects at other well pads, or projections according to modeling or simulation calculations, or a combination thereof. The transition condition may also be adjusted or selected based on the market conditions including production costs, material costs, and the market values of produced or recovered materials including market oil prices and solvent prices.

[074] Transitioning to the solvent-dominant process at an early stage in the SAGD process may be possible in some cases, but such early transition before the vapor chamber has fully developed vertically may limit the overall chamber growth or slow down the initial chamber growth. Further, when the transition occurs too early, the reservoir formation contains less heat transferred from steam and the heated region in the formation is relatively small. Without being limited to any specific theory, when the vapor chamber is fully developed vertically, the amount of heat transferred to the reservoir formation and the large region of heated area can be quite beneficial to the subsequent solvent-dominant process. The heat, or higher formation temperature in a large region in the formation, can help to maintain the solvent in the vapor phase and assist dispersion of the solvent to the chamber front or edges. The heat from steam can also by itself assist reduction of viscosity of the hydrocarbons. Thus, an improved synergistic effect can be achieved in an embodiment as described herein.

[075] At S460, it is determined whether the transition condition selected at S450 has been met. This determination may be made based on a pre-set timing or based on measured and predicted operational parameters and current reservoir conditions. The determination may involve monitoring certain selected parameters, for example, monitoring of injection, production, downhole parameters, or parameters of the geological formation. For example, parameters such as CSOR, temperatures, pressures or the like may be monitored such as, for example, at injection well 120 or production well 130. Additionally or alternatively, determining a transition condition has been met may involve prediction based on indirect indicators that the condition has been met, such as based on assumptions derived from a model and informed by the aforementioned monitoring.

[076] When the transition condition has been met, the steam-dominant SAGD
process is terminated and the solvent-dominant process is started at S470. The solvent-dominant process involves injection of the selected solvent in vapor form into formation 100 through injection well 120. The solvent is injected into reservoir formation 100 in a vapor phase. Injection of the solvent in a vapor phase allows the solvent vapor to rise in vapor chamber 360 and condense at a region away from injection well 120.
Allowing solvent to rise in vapor chamber 360 before condensing may achieve beneficial effects. For example, when vapor of the solvent is delivered to vapor chamber 360 and then allowed to condense and disperse in the vapor chamber 360 particularly near the edges of vapor chamber 360, oil production performance, such as indicated by one or more of oil production rate, cumulative steam to oil ratio (CSOR), and overall efficiency, can be improved. Injection of solvent in the gaseous phase, rather than a liquid phase, may allow vapor to rise in vapor chamber 360 before condensing so that condensation occurs away from injection well 120. It is noted that injecting solvent vapor into the vapor chamber does not necessarily require solvent be fed into the injection well in vapor form. The solvent may be heated downhole and vaporized in the injection well in some embodiments.

[077] The total injection pressure for solvent and steam co-injection may be the same or different than the injection pressure during the SAGD production process. For example, the injection pressure may be maintained at between 2 MPa and 3.5 MPa, or up to 4 MPa. In another example, steam may be injected at a pressure of about 3 MPa in the SAGD process, while steam and solvent are co-injected at a pressure of about 2 MPa to about 3.5 MPa in the solvent-dominant process.

[078] 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 360. For example, where the selected solvent is propane, a solvent-steam mixture containing about 90 wt% propane and about 10 wt% steam may be injected at a suitable temperature, such as about 75 C to about 100 C.
Such a suitable steam temperature may be determined, for example, through techniques as known to persons of skill in the art based on parameters of the mixture components.
For example, the enthalpy per unit mass of the aforementioned steam-propane mixture may be about 557 kJ/kg.

[079] The total volume of the solvent injected during the solvent-dominant process may be lower than the total volume of steam injected during SAGD.

[080] In different embodiments, co-injection of steam and the solvent may be carried out in a number of different ways or manners as can be understood by those skilled in the art. For example, co-injection of the solvent and steam into the vapor chamber may include gradually increasing the weight ratio of the solvent in the co-injected solvent and steam, and gradually decreasing the weight ratio of steam in the co-injected solvent and steam. At a later stage, the solvent content in the co-injected solvent and steam may be gradually decreased, and the steam content in the co-injected solvent and steam may be gradually increased. For example, depending on market factors, the cost of solvent may change over the life of a hybrid steam-solvent process. During or after the solvent-dominant process, it may be of economic benefit to gradually decrease the solvent content and gradually increase the steam content.

[081] Solvent injection is expected to result in increased mobility of at least some of the heavy hydrocarbons of reservoir formation 100. For example, solvent injection may tend to achieve a heavy hydrocarbon mobility increase by solubility or diffusion of solvent into hydrocarbons, or by both solubility and diffusion.
The term "mobility" is used herein in a broad sense to refer to the ability of a substance to move about, and is not limited to the flow rate or permeability of the substance in the reservoir. For example, the mobility of heavy hydrocarbons may be increased when the heavy hydrocarbons become easier to detach from the sand to which they are attached, or when the heavy hydrocarbons become mobile, even if the viscosity or flow rate remains the same. The mobility of heavy hydrocarbons may also be increased by decreasing the viscosity of the heavy hydrocarbons, or when the effective permeability, such as through bituminous sands, is increased. Additionally or alternatively, increasing heavy hydrocarbon mobility may be achieved by heat transfer from solvent to heavy hydrocarbons.

[082] Additionally or alternatively, solvent may otherwise accelerate production.
For example, a non-condensable gas, such as methane, may propel a solvent, such as propane, downwards thereby enhancing lateral growth of the vapor chamber. For example, such propulsion may be part of, or additionally or alternatively in addition to, a blowdown phase.

[083] Conveniently, a solvent-dominant process where solvent is co-injected with steam requires less steam as compared to the SAGD production phase.
Injection of less steam may reduce water and water treatment costs required for production.
Injection of less steam may also reduce the need or costs for steam generation for an oil production project. Steam may be produced at a steam generation plant using boilers. Boilers may heat water into steam via combustion of hydrocarbons such as natural gas. A reduction in steam generation requirement may also reduce combustion of hydrocarbons, with reduced emission of greenhouse gases such as, for example, carbon dioxide.

[084] Once the oil production process is completed, the operation may enter an ending or winding down phase, at S480, with a process known as the "blowdown"
process. The "blowdown" phase may be performed in a similar manner as in a conventional SAGD process. During the blowdown phase, a non-condensable gas may be injected into the reservoir to replace steam or the solvent. For example, the non-condensable gas may be methane. In addition, methane may enhance hydrocarbon production, for example by about 10% within 1 year, by pushing the already injected solvent through the chamber.

[085] Alternatively, in an embodiment, the solvent used for injection in the solvent-dominant process may be continuously utilized through a blowdown phase, in which case it is possible to eliminate or reduce injection of methane during blowdown.
In particular, it is not necessary to implement a conventional blowdown phase with injected methane gas, when a significant portion of the injected solvent can be readily recycled and reused. In some embodiments, as alluded to above, during or at the end of the blowdown phase, methane or another non-condensable gas (NCG) may be used to enhance solvent recovery, where the injected methane or other non-condensable gas may increase solvent condensation and thus improve solvent recovery. For example, injected methane or other NCG may mobilize gaseous solvent in the chamber to facilitate removal of the solvent.

[086] During the blowdown phase, oil recovery or production may continue with production operations being maintained. When methane is used for blowdown, oil production performance will decline over time as the growth of the vapor front in vapor chamber 360 slows under methane gas injection.

[087] In an embodiment of the hybrid process, at the end of the production operation, the injection wells may be shut in but solvent (and some oil) recovery may be continued, followed by methane injection to enhance solvent recovery. The formation fluid may be produced until further recovery of fluids from the reservoir is no longer economical, e.g. when the recovered oil no longer justifies the cost for continued production, including the cost for solvent recycling and re-injection.

[088] In some embodiments, before, during or after the blowdown phase, production of fluids from the reservoir through production well 130 may continue.

[089] In some embodiments, a limited steam-dominant process may be started again after the solvent-dominant process but before the blowdown phase.

[090] The solvent for injection during the solvent-dominant process may be selected based on a number of selection criteria. As discussed above, the solvent should be injectable as a vapor, and can dissolve at least one of the heavy hydrocarbons to be recovered from reservoir formation 100 in the solvent-dominant process for increasing mobility of the heavy hydrocarbons.

[091] Conveniently, increased hydrocarbon mobility can enhance drainage of the reservoir fluid toward and into production well 130. In a given application, the solvent may be selected based on its volatility and solubility in the reservoir fluid. For example, in the case of a reservoir with a thinner pay zone (e.g., the pay zone thickness is less than about 8 m), or a reservoir having a top gas zone or water zone, the solvent may be injected in a liquid phase in the solvent-dominant process.

[092] Suitable solvents may include C3 to C5 hydrocarbons such as, propane, butane, or pentane. Additionally or alternatively, a C6 hydrocarbon such as hexane could be employed.

[093] For selecting a suitable solvent, the properties and characteristics of various candidate solvents may be considered and compared. For a given selected solvent, the corresponding operating parameters during co-injection of the solvent with steam should also be selected or determined in view the properties and characteristics of the selected solvent.

[094] For example, the phase diagrams of the solvents may be helpful for such selection. FIG. 5 shows 2-dimensional (2D) pressure-temperature phase diagrams of propane, butane, pentane, hexane, heptane, and octane. As can be seen, at a given pressure, the boiling points of different solvents are different, and at a given temperature the saturation vapor pressures of different solvents are different. Thus, suitable operating temperatures and pressures may be selected for a given solvent in view of such phase diagrams. In particular, the injection temperature should be sufficiently high and the injection pressure should be sufficiently low to ensure most of the solvent will be injected in the vapor phase into the vapor chamber. In this context, injection temperature and injection pressure refer to injection into the injection well.
Injection temperature, injection pressure, or both, may be selected to ensure that the solvent is in the gas phase upon injection from the injection well into the vapor chamber.

[095] Solvents may be selected having regard to reservoir characteristics such as, the size and nature of the pay zone in the reservoir, properties of fluids involved in the process, and characteristics of the formation within and around the reservoir. For example, a relatively light hydrocarbon solvent may be suitable for a reservoir with a relatively thick pay zone, as a lighter hydrocarbon solvent in the vapor phase is typically more mobile within the heated vapor chamber. For example, propane may be selected.

[096] Additionally or alternatively, a lighter hydrocarbon solvent such as, for example, propane may dissolve in higher and more challenging areas of the heterogeneous reservoirs as compared to a solvent including heavier hydrocarbons.

[097] Additionally or alternatively, solvents including heavier hydrocarbons such as, for example, pentane or hexane, may be more appropriate in a thinner pay reservoir environment. Heavier solvents, even if injected in a liquid phase or condensed quickly after injection as a vapor, may serve to drive out (wash) remaining heavy oil in a reservoir environment, towards the production well. Further, solvent existence in the vapor phase may be less beneficial in a thinner pay reservoir as compared to a thicker pay reservoir. For example, in a CSS process, where the initial pressure in a 5-meter pay zone is about 0.3 MPa, a heavier solvent, such as, for example, liquid hexane may be appropriate for use as the solvent. In comparison, in a hybrid process as described herein where the reservoir has a 3 MPa initial pressure and a 30-meter pay zone, lighter solvents, such as propane in the vapor phase, may be more suitable.

[098] Additionally or alternatively, solvent selection may include consideration of the economics of heating a selected particular solvent to a desired injection temperature. For example, following a 3 MPa initial pressure SAGD operation, propane will have to be heated to about 80 C whereas pentane will have to heated to about 190 C so it can be injected in the vapor phase.

[099] As can be appreciated by those skilled in the art, solvents referenced in FIG. 5, such as propane and butane, can be efficiently injected in the vapor phase at relatively low temperatures at a given injection pressure such as about 3 MPa.
In comparison, efficient pure steam injection in a SAGD process typically requires a much higher injection temperature, such as about steam 200 9C or higher.

[100] For example, at an injection pressure of about 3 MPa, the injection temperature for propane may be about 75 C to about 100 C.

[101] Different solvents or solvent mixtures may be suitable candidates as may be known to those skilled in the art. For example, the solvent may be propane, butane, or pentane. A mixture of propane and butane may also be used in an appropriate application. It is also possible that a selected solvent mixture may include heavier hydrocarbons in proportions that are, for example, low enough that the mixture still satisfies the above described criteria for selecting solvents.

[102] Conveniently the hybrid process may reduce overall production costs while improving production performance, as compared to conventional SAGD
processes or combined SAGD and solvent processes. As the overall CSOR is reduced, the hybrid process may also result in reduced emission of greenhouse gases, such as carbon dioxide due to reduced need for steam generation and water treatment.

[103] The transition condition may be selected to optimize the overall performance or maximize the above noted benefits. Different techniques for determining the optimal transition condition have been proposed.

[104] In an embodiment, the vertical growth of vapor chamber 360 is directly monitored or estimated based on available data.

[105] FIG. 6 illustrates the stage at which the top front of vapor chamber has just reached the interface region 115 at the lower edge of overburden 110 due to vertical growth as indicated by the arrows. Such a condition may be detected by monitoring a temperature in the interface region 115 change via instrumentation such as, for example, using distributed temperature sensing (DTS) (not shown). The temperature change is significant if it can indicate that steam has reached or is near the interface region. A pre-selected temperature or rate of temperature change may be used as a threshold for determining if the temperature has changed significantly. This threshold may be selected based on a methodology known to those skilled in the art.
Additionally or alternatively, this condition may be inferred such as, for example, when production monitoring indicates that the oil production rate change over time exhibits a generally "parabolic" curve. After this stage, overburden 110 will limit further upward vertical growth of vapor chamber 360. However, as illustrated in FIG. 7, vapor chamber 360 may still grow laterally, as indicated by the arrows. A peak production threshold may therefore be reached around this time. Thus, the transition time may be selected to be some time after this point. In particular, one technique is to monitor or predict vertical growth of vapor chamber 360 and select the transition condition to be the cessation of upward vertical growth of vapor chamber 360. Another possible transition condition is a significant increase in lateral growth of vapor chamber 360.
Such a condition may be detected by monitoring temperature changes in different locations in the formation, such as by DTS. In different embodiments, it is also possible to determine the appropriate transition condition by monitoring the change in oil production rate or the cumulative steam to oil ratio in the SAGD process.

[106] For example, FIG. 8 shows a curve 800 representing hypothetical expected change in oil production rate over time in a conventional SAGD
process. As illustrated, it is assumed that curve 800 initially increases and will reach a peak value 810 at the time denoted as T. In an embodiment, the transition condition (or transition time, TT) may be selected be Tp, or sometime thereafter. A delay after Tp may be desirable to ascertain that the oil production rate has peaked and is declining.

[107] Notably, curve 800 may not reflect the oil production rate after transition to the solvent-dominant process, as curve 800 represents predicted oil production rate for the SAGD process.

[108] Transition time TT may be selected to occur after some period of time elapses following initial steam injection in the SAGD process as illustrated in FIG. 9.
Time TT may be selected based on a variety of relevant factors. For example, the transition time may be selected based on an a priori determination of when SAGD
production or the reservoir formation development thereunder is expected to have reached peak production, or when the vertical growth of the vapor chamber from the injector to overburden is achieved. The time period from initial steam injection may vary depending on the thickness of the pay zone. Considerations may also be given to the optimal transition time to achieve an optimal economic or cost-effect result.

[109] As an example, for a reservoir with a 20 m thick pay zone and assuming the pressure in the formation is 3 MPa, TT may be about 2 years. For a reservoir with a different pay zone thickness or reservoir pressure condition, the time period may be different. For example, if the pay zone is thinner or the reservoir pressure is higher, the time period may be shortened. For example, for a reservoir with a 5 m thick pay zone, TT may be about 6 months.

[110] Time TT may also be selected to be at the time when the oil production rate has peaked, and in some embodiments, has then declined by about 10%, and no more than 20%, of the peak production rate, as illustrated in FIG. 10.

[111] As illustrated in FIG. 11, Time TT may also be selected to be at the time after a selected period of time, denoted as AT, has elapsed after Tp (i.e. the time of reaching peak production rate). That is, TT = Tp + T. The transition condition is thus that the reservoir formation has continued to be subjected to the SAGD process for a time period of AT after reaching peak production. The time period AT may be selected based on one or more of a variety of relevant factors. For example, reservoir characteristics in a heterogeneous environment such as variations in overburden height may be a factor to be considered. The selection may be based on simulation prediction.
Process economics may also be a factor to be considered. The time period AT
may be selected to ensure that the oil production rate has indeed peaked. As the oil production rate may fluctuate due to various reasons, to ensure the oil production rate has peaked, the oil production rate may be monitored until continued and consistent decline of the oil production rate has been observed over the time period AT, such as until the oil production rate has consistently declined by about 10% of the peak production rate.

[112] A further possible transition condition is that the CSOR has started to increase, which tends to indicate that production performance has started to decline after a peak production threshold has been reached. A hypothetical expected CSOR
curve for a SAGD production process is illustrated in FIG. 12.

[113] As known to skilled persons, CSOR will vary during a SAGD process as discussed above. Decreases in CSOR are expected during early SAGD production stages. An increase in CSOR can indicate that steam utilization has become less efficient or effective.

[114] As depicted by the CSOR curve 1200 in FIG. 12, the CSOR may decrease initially until reaching a minimum value (bottom) indicated by dashed line 1210. The CSOR may then begin to increase, reaching a higher CSOR value as indicated by dashed line 1220. A transition condition may be selected to be that the CSOR has decreased and then increased. For example, the transition condition may be that the CSOR has increased by a threshold value, ACSOR. The time to meet this condition is indicated as TT in FIG. 12.

[115] In some embodiments, ACSOR may be calculated as a function of the measured CSOR or based on theoretical predictions.

[116] In a further embodiment, the transition condition may be selected based on an indicator that can be used to predict or indicate that vapor chamber 360 has reached overburden 110, or reached the interface region 115. For example, the temperature change in interface region 115, which may be detected, for example, by DTS, can be a useful indicator in this regard.

[117] FIG. 13 illustrates expected temperature change at interface region over time during a conventional SAGD process. The curve 1300 in FIG. 13 represents the expected temperature variation over time in interface region 115, which is the interface region between overburden 110 and formation 100. As depicted, the initial (natural, prior to a treatment being applied to the reservoir) temperature in interface region 115 is assumed to be about 11 C to about 12 C as is typical in many oil sands or bitumen reservoirs. The temperature in interface region 115 may gradually increase due to steam injection and can reach about 25 C when the steam chamber 360 reaches interface region 115. As such, the transition condition for transitioning from the SAGD process to the solvent-dominant process may be selected as when the temperature in interface region 115 is at a pre-selected value, such as about 20 C to about 25 C. For example, the transition condition may be selected for a temperature of about 20 C as shown by stippled line 1310. The time to meet this condition is indicated as TT in FIG. 13. Expressed differently, the transition condition may be that the temperature at interface region 115 has increased by about 11 C to about 12 C, or the temperature as measured in degree Celsius has doubled.

[118] The aforementioned example transition conditions are in no way limiting and instead serve to exemplify transition conditions that may be suitable in some embodiments.

[119] In some embodiments, it may be appropriate that more than one transition conditions be met before the transition takes place. For example, the conditions that need to be satisfied before the transition may include a combination of two or more of the transition conditions described herein. In some embodiments, transition may take place as long as one of the selected transition conditions has been satisfied. Alternatively, in some embodiments, transition may take place only after all selected transition conditions have been satisfied, or a sub-combination of transition conditions have all been satisfied.

[120] Examples

[121] Computer simulations have been conducted to predict expected recovery performance and vapor chamber development in a hybrid steam-solvent process as described herein. Representative simulation results are discussed next.

[122] Example I. Computer Simulation of Solvent Recovery Process

[123] The performance and results for hydrocarbon recovery under solvent injection were studied based on two-dimensional (2D) computer simulation. The study was conducted for temperatures 100 C and 150 C to compare potential performance of propane, butane, pentane, and hexane in enhancing heavy hydrocarbon recovery.

[124] As can be appreciated, each of the studied solvents requires less energy to vaporize and to inject at the temperatures of 100 C or 150 C, as compared to the energy required to heat water to generate steam at a temperature above 200 C.

[125] FIG. 14 shows representative expected heavy hydrocarbon recovery factors for selected solvents at different injection temperatures in an example reservoir having a relatively thin pay, in this case of 10 m.

[126] As can be seen from FIG. 14, propane provided the best recovery performance, as injection of propane resulted in the highest recovery factor in a thin pay reservoir at both injection temperatures of 100 C and 150 C.

[127] Example II. Phase Diagram Simulation

[128] Computer simulation was also conducted to provide 2D pressure-temperature phase diagrams for co-injection of selected solvents with steam.
The operating pressure in the simulation was near the initial injection pressure of 3 MPa.

[129] A representative simulated 2D phase diagram is shown in FIG. 5.

[130] The injection temperature was selected to ensure that the solvent is injected in the vapor (gas) phase, based on enthalpy calculations. That is, there would be sufficient energy (enthalpy) available in the mixture to keep the solvent in the vapor phase. For example, for injecting propane at 3MPa, the enthalpy calculation showed that the injection temperature should be about 75 C to about 100 Co. For heavier solvents, a higher injection temperature would be required so the heavier solvent could be injected in the vapor phase. The solvent may be delivered to the injection well at a higher temperature than required to achieve a gaseous phase so as to offset possible heat losses that may occur in the injection well as the solvent travels to the reservoir.

[131] It is expected that for reservoirs with a typical pay zone height of, for example, about 20 m, the solvent would need to be injected as a vapor for effective recovery.

[132] Example III. Computer Simulation of Hybrid Steam-Solvent Recovery Process, and Comparison SAGD Process

[133] The performance of a hybrid steam-solvent process was compared to a conventional SAGD process based on computer simulation and computer modelling.

[134] The computer simulations modelled components of water, bitumen, methane, and a selected solvent, which was selected from C3 to C6 hydrocarbons. The simulated reservoirs had dimensions of 800 m long, 50 m wide, and 10 m or 20 m high.
A hot fluid communication zone was introduced between the injector and producer wells at 200 C and with water saturation of 60% to improve mobility. The reservoir conditions were simulated as follows: Temperature (T) =12 C, Pressure (P) = 3 MPa, Water Saturation (Sw) = 20%, and Oil Saturation (So) = 80%. The permeability in the x, y, and z directions were 6, 6, and 5 Darcy, respectively, and the reservoir porosity was assumed to be 33%. Methane content in the oleic phase was assumed to be 16 wt%.

[135] The injection tubing had the following flow control device (FCD) configuration:
Location: injection tubing section 3, Opening diameter in meters: 20.00e-3;
Discharge coefficient: 0.7;
Location: injection tubing section 7, Opening diameter in meters: 28.28e-3;
Discharge coefficient: 0.73;
Location: injection tubing section 11, Opening diameter in meters: 40.00e-3;
Discharge coefficient: 0.81;
Location: injection tubing section 15, Opening diameter in meters: 56.57e-3;
Discharge coefficient: 0.95.

[136] As noted before, molecularly heavier solvents require higher temperatures for injection in the gaseous phase at a selected temperature.
Injection in the gaseous phase may be necessary depending on the pay height of a reservoir.
For example, solvent injection in the gaseous phase, rather than a liquid phase, would be necessary if the pay height in the reservoir formation is approximately 20 metres in order for the solvent to reach the top of the vapor chamber.

[137] From the operational perspective, injection was controlled at a pressure of 3.1 MPa for steam injection, and production was controlled according to a gas constraint of 10 tonnes per day (t/d).

[138] FIG. 15 shows representative simulation results for the cumulative oil production in a hybrid steam-solvent process, as compared to a SAGD base (baseline) case.

[139] For the results shown in FIG. 15, the injected solvent was propane.
The simulation results showed that the cumulative oil production reached the level of 65% 3 years earlier with the hybrid steam-solvent process than with the SAGD base case.
This accelerated recovery is a significant improvement in production performance, as a shortened recovery operation can provide various benefits including both technical and economic advantages.

[140] FIG. 16 compares the predicted oil production rates in a hybrid process (labeled as "hybrid") as compared to a baseline SAGD process (labeled as "SAGD"), based on half-symmetry simulation. In the simulated solvent-dominant process of the hybrid process, propane was injected at about 48 t/d, and the transition from steam injection to propane injection was selected to take place at about 1200 days after production. In the simulation results, the hybrid steam-solvent recovery process using propane increased the oil production rate to 140 t/d after 3.5 years of operation, up from 50 t/d in the SAGD base case, for the full simulated reservoir.

[141] The simulation study also considered other solvents. In particular, in the simulations injection of selected condensate (see below) and pentane did not outperform the SAGD base case at an injection rate of 48 t/d, even when the selected condensate or pentane (solvent) was injected in the vapor phase. As will be understood by a person of skill in the art, "condensate" in this context is a mixture of hydrocarbons, for example including C3-C30 hydrocarbons or C4-C20 hydrocarbons. "Condensate"
is sometimes referred to as diluent. Condensate may primarily include a smaller range of hydrocarbons, for example, C3-C6 hydrocarbons. If relatively heavier hydrocarbons, for example, C9-C30 hydrocarbons, or a relatively heavier hydrocarbon, for example, octane being relatively heavier than heptane, are utilized, a lower quantity of the relatively heavier hydrocarbon(s) may be required compared to when relatively lighter hydrocarbon(s), for example, propane, are utilized. Simulation suggested that butane slightly outperformed the SAGD base case initially but its overall performance was not as good as that of propane in the solvent-dominant process. Additionally, simulation indicated that the transition timing is important for achieving improved performance. For example, simulation results for transitioning to propane injection immediately after the start-up stage (i.e. essentially without any steam-dominant oil production process) did not achieve good or improved performance. Instead, the best simulation results were obtained when the transition to propane injection took place after 700, 1000, or 1200 days of production.

[142] Oil saturation distribution and vapor distribution in the vapor chamber were also studied by computer simulation. Representative results are shown in FIG. 17, which shows a screen shot of a computer display showing simulation results.

[143] FIG. 17 shows three displayed windows 1710, 1720, and 1730.

[144] Window 1710 shows oil saturation ("SO") within the simulated reservoir in a SAGD process where no solvent was injected, which was used as the base case.

The darker (cooler) areas indicate oil depleted areas and the lighter (hotter) areas indicate oil saturated areas. As can be appreciated, in the vapor chamber oil was substantially depleted, and the regions of the reservoir outside the vapor chamber were still saturated with oil.

[145] Window 1720 shows oil saturation ("SO") within the simulated reservoir in a hybrid process where a solvent was injected after pure steam injection during the steam-dominant process. The darker (cooler) areas indicate oil depleted areas and the lighter (hotter) areas indicate oil saturated areas. As can be appreciated, in the vapor chamber oil was substantially depleted, and the regions of the reservoir outside the vapor chamber were still saturated with oil. Window 1730 shows propane distribution in the oleic phase at a point of vapor chamber development corresponding to that of window 1720. In window 1730, the lighter area indicates higher solvent concentration in the oleic phase and the darker areas indicate areas where propane is still in the gaseous phase. It can be seen that the injection of propane resulted in significant lateral growth of the vapor chamber, particularly at the lower portions of the reservoir.
Indeed, the computer simulation results of FIG. 17, when considered together, illustrate to a skilled person interpreting the results that propane, even though a lighter and therefore more buoyant solvent than heavier solvents, such as butane, in the simulated reservoir, would still be expected to condense at the bottom of the vapor chamber and thus serve to advance oil towards production.

[146] From the simulation results as represented in FIG. 17, it may also be expected that both heat transfer and diffusion of dissolved solvent in the hydrocarbons contribute to the enhanced oil recovery. In comparison, with steam injection, heat transfer is helpful for increasing mobility of hydrocarbons but steam does not dissolve in the oil phase.

[147] EXAMPLE IV. Simulation Study of Effects of Well Pair Spacing on Vertical Steam Chamber Development

[148] A simulation study was conducted to evaluate effects of well pair spacing on vertical steam chamber development and the optimal timing for initiating a solvent-dominant process.

[149] In the study, the formation was modeled with horizontally spaced well pairs, where the spacing between adjacent pairs of SAGD wells was 50 m, 60 m, m, or 150 m. A hybrid recovery process as described herein was simulated from the modeled formation. The temperatures within the steam chambers and the temperatures within the volume between the two adjacent well pairs outside the respective steam chambers were monitored during a simulated steam-dominant process for each of the four well spacing distances. The simulation results showed that the steam chamber development was substantially affected by the presence and the spacing of an adjacent well pair. With more closely spaced adjacent well pairs, the vertical development of the steam chambers was more rapid and reached the vertical expansion limit or peak production more quickly. For example, in a tested embodiment, the vertical expansion of the steam chamber during the steam-dominant process reached its limit within about 250 days at 50 m spacing, about 300 days at 60 m spacing, about 750 days at 100 m spacing, and about 4000 days at 150 m spacing. In accordance with an embodiment of the present disclosure, the solvent-dominant process may be initiated after the steam chamber has reached its vertical expansion limit or peak production of oil.

[150] While reducing the spacing between the SAGD well pairs might reduce the time to reach the vertical expansion limit of the steam chamber, shortened spacing also requires more wells to be drilled and more steam injection, both of which result in higher costs and potentially higher green-house gas emissions. It is expected that spacing at about 100 m may provide a practical and balanced result when the well pairs have configurations and completions typically found in conventional SAGD

operations.

[151] EXAMPLE V. Simulation Study of Effects of Transition Timing From Steam-Dominant Recovery Process to Solvent-Dominant Recovery Process

[152] This simulation study focused on the transition timing from the steam-dominant process to the solvent-dominant process.

[153] Four different simulations were conducted, and representative simulation results are shown in FIGS. 18, 19 and 20.

[154] The results labelled as "SAGD base" were obtained from a reference case with simulation of pure steam injection without any solvent injection.
The results labelled as "immediate" were obtained by simulating an immediate transition at days from the commencement of pure steam injection, when the production rate was already on a decline curve, to co-injection of 80 wt% of propane and 20 wt% of steam at once. The results labelled as "15 d interval" were obtained from simulation of a stepped transition, in which the proportions of steam and propane in the injection mixture were adjusted as shown in Table 1. The results labelled as "20 d interval" were obtained from simulation of a stepped transition as shown in Table 2. In the "15 d interval" and "20 d interval" cases, the first transition step was a 10 wt%
change from 100 wt% steam to 90 wt% steam and 10 wt% propane, the second transition step was a 10 wt% change from 90 wt% steam and 10 wt% propane to 80 wt% steam and 20 wt% propane, and the subsequent transition steps were 20 wt%
decreases/increases for steam/propane, as shown in Tables 1 and 2, respectively.

[155] The estimated enthalpy per kilogram of the injection mixture with 20 wt%
steam and 80 wt% propane is 528 kJ/kg, which allows injection of gaseous propane at a temperature between 75 C and 100 C.
Table 1. "15 d interval" Transition from Steam-Dominant Process to Solvent-Dominant Process Day Steam (wt%) Propane (wt%) Enthalpy/mass (kJ/kg) Table 2. "20 d interval" Transition from Steam-Dominant Process to Solvent-Dominant Process = Day Steam (wt%) Propane (wt%) Enthalpy/mass (kJ/kg)

[156] As can be seen from FIG. 18, the transition methodology had little effect on the overall amount of oil produced (cumulative oil production).

[157] For selecting a suitable injection mixture in the solvent-dominant process, the respective percentages of steam and solvent, or a ratio of steam to solvent, may be selected based on a selected (desired) injection temperature or pressure and the enthalpy that is needed to allow the solvent to be in the gas (vapor) phase during injection at the selected injection temperature or pressure. As an example for obtaining a suitable mixture for injection in the solvent-dominant process, with a gaseous phase temperature of propane between about 75 C and about 100 C, about 15-20 t/d of steam may be utilized to mix with and heat about 50-75 t/d of propane, resulting in an injection mixture containing between about 75 wt% and about 85 wt% of steam and about 25 wt% to about 15 wt% of propane in the inject stream.

[158] Without being limited to a particular theory, a desired temperature of the solvent may be attained at a certain enthalpy per mass of the mixture of steam and solvent. For example, to inject propane at about 75 C and about 3 MPa in the solvent-dominant process, about 5.07e5 J/kg of enthalpy/mass (based on the weight of the mixture of steam and propane) may need to be in the mixture for the propane to be in the gaseous phase (see e.g. Fig. 5). Based on simulation results, it is expected that the corresponding rates of injection are about 15 t/d of steam and about 60 t/d of propane for a co-injected mixture of about 20 wt% of steam and about 80 wt% of propane.

[159] At a lower pressure, an injection mixture may contain about 15 t/d of steam and about 50 t/d of propane, which would yield a co-injected mixture of about 23 wt% of steam and about 77 wt% of propane.

[160] As a further example, for an injection mixture with about 92 wt% of propane and about 8 wt% of steam, about 5.28e5 J/kg of enthalpy per unit mass may need to be in the mixture for the propane to be in the gaseous phase.

[161] Depending on the solvent selected, a range of enthalpies per unit mass of about 4e5 J/kg to about 7e5 J/kg may be applicable to achieve a solvent temperature such that the solvent is in the gaseous phase. Solvents other than propane may have different enthalpy requirements to achieve temperatures suitable for the solvent-dominant process. For example, butane may have higher enthalpy requirements to achieve temperatures at which butane is in the gaseous phase.

[162] As can be seen from FIG. 19, which shows the change in oil production rate (t/d) over time (days), within the short period of time during the transition from the steam-dominant process to the solvent-dominant process, there was a temporary decrease in the oil production rate during the switch, followed by a substantial increase.
In the case of "immediate" transition, the decline in the oil production rate was more instantaneous, but the following increase was also earlier as compared to the two "interval" cases. In both the "interval" cases, both the decline and following recovery of the oil production rate were less sharp than the "immediate" case. After the transition to the solvent-dominant process the oil production rate in all cases appeared to be steady with low fluctuation and low variance among the different cases.

[163] Given the above results, transitioning with stepped steam reduction and propane increase may be selected in some embodiments to reduce risks that may result from rapid temperature change in the injection mixture. For example, from a thermal shock perspective, a fast change in the temperature of the injection mixture could cause rapid cooling in the injection well and in the steam chamber.
There is a potential risk that rapid cooling could cause possible cracking in carbon steel pipes and injection skid equipment in the injection well. An "interval" transition may reduce such risks.

[164] FIG. 20 shows cumulative solvent injection over time. The result shown suggests that the "immediate" transition required more propane injection.
Given that overall oil production may not be significantly improved by a faster transition, selecting a longer transition time frame, such as from about 20 days (or three weeks) to up to about 75 days, may be more economical.

[165] EXAMPLE VI. Simulation Study of Batch Solvent Injection

[166] A simulation study was conducted to evaluate the effects of batch injection of the solvent during either the steam-dominant process or the solvent-dominant process. In batch injection, the solvent would be injected in separate "batches." For example, each batch might be equivalent to the load of a shipping truck for transporting the solvent.

[167] Unlike continuous solvent injection, batch injection allows quick offloading of the solvent into the wellbore of the injection well, or into the piping where the solvent is mixed with steam to be injected into the formation.

[168] The study results showed that both continuous and batch injection processes produced similar amounts of oil. For example, both batch and continuous injections produced about 140 t/d of oil after 980 days. Batch injection did not lead to a drop in the oil production rate that would render batch injection impractical.
Thus, it is expected that batch injection would be a feasible alternative to continuous injection.
The pressure in the steam chamber also did not differ significantly between batch and continuous injection. In both cases, the average pressure was about 2700 kPa.

[169] As can expected, there was more fluctuation in the oil production rate and chamber pressure with batch injection, but such fluctuation was within acceptable measurement errors for field measurements.

[170] It is expected that batch injection could be utilized as an alternative to continuous injection.

[171] ALTERNATIVES AND VARIATIONS

[172] In some embodiments, injection pressure may be controlled using the same means in SAGD and in the solvent-dominant process. Alternatively, different or additional means may be used for injection pressure control during either SAGD
or the solvent-dominant process.

[173] In some embodiments, the solvent may be heated at the surface before injection. Additionally or alternatively, the solvent may be heated by co-injection with steam. For example, in an embodiment, the injection fluid may include about 90 wt% of solvent and about 10 wt% of steam, such as when propane is used as the solvent. In another embodiment, the injection fluid may include about 80 wt% of solvent and about 20 wt% of steam, such as when butane is used as the solvent. The steam may be present in a sufficient amount and temperature to heat the mixture, including propane, to about 100 C. Additionally or alternatively, the solvent may be heated at surface or downhole, such as by way of a heater. In additional embodiments, the relative amount of the solvent in the injection fluid may also be higher or lower than the ranges previously mentioned. For example, in an embodiment, the injection mixture may contain about 95 wt % of propane and about 5 wt% of steam, with or without additional heating using a heating device.

[174] As discussed above, the solvent is delivered relatively hot to the reservoir formation. However, the solvent may be fed into the injection well with or without pre-heating at the surface.

[175] In some embodiments, the solvent condensed in the reservoir will be recovered (produced) in the oleic phase. Additionally or alternatively, vapor solvent could remain in the reservoir formation, and may also be recovered with a reservoir fluid in the gaseous phase.

[176] In some embodiments, an additive or chemical such as toluene may be injected during the SAGD production process, during the solvent-dominant process, or during a post-production phase. Injection of toluene may help to reduce asphaltene precipitation. About 5 wt% of toluene may be co-injected with steam or a solvent.

[177] In some embodiments, fluids recovered at the surface may be separated from produced solvent to undergo recycling.

[178] In the above discussed and other embodiments, the injected solvent may not be recycled, or the injected solvent may be recovered and recycled.

[179] In some embodiments, a further steam-dominant recovery process may be performed after the conclusion of the solvent-dominant process. For example, the reservoir may be subjected to the steam-dominant process after the solvent-dominant process. For example, the steam-dominant process may be similar to conventional SAGD. Such a switch may be made after a prolonged period of solvent-dominant process production.

[180] In some embodiments, a separate vertical well may be introduced into the reservoir for co-injection of some or all of the steam and solvent mixture.

[181] In some embodiments, a barrier or insulation layer may be formed at the overburden, which may assist in reducing heat loss through the overburden once the vapor chamber has substantially reached full vertical growth. For example, a barrier layer may be formed after this condition is reached. Alternatively, a barrier may be formed at an earlier or later point in time. In another example, a barrier layer may be formed at or about the time that the peak process threshold has been reached and detected. The barrier layer may be formed of an insulation composition such as described in US 201 5/01 59476 to Warren et al. The barrier layer may also be formed from an artificial layer such as those disclosed in US 2011/0186295 or CA
2,729,430 to Kaminski et al..

[182] In some embodiments, non-condensable gases (NCGs) may be generated in the reservoir such as during heating by steam. Additionally or alternatively, an NCG may be injected as an additive in some embodiments.
Conveniently, the presence of NCGs in the formation can enhance lateral dispersion of the solvent vapor to spread the solvent laterally into the reservoir formation. Increased lateral dispersion of the solvent is expected to assist lateral growth of the vapor chamber, and hence enhance oil production.

[183] While in some of the above discussed embodiments a pair of wells is employed for injection and production respectively, it can be appreciated that a hybrid steam-solvent process may be implemented with a single well or unpaired wells.
The single well, or an unpaired well, may be used alternately for injection or production. The single well may have a substantially horizontal or vertical section in fluid communication with the reservoir. The single well may be a well that is configured and completed for use in a cyclic steam stimulation (CSS) recovery process. With the use of a single well for injection and production, a temperature in the reservoir may be about 234 C to about 328 C and a pressure in the reservoir may be from about 0.5 MPa or from about 3.0 MPa to about 12.5 MPa.

[184] There are also alternative methodologies for recognizing or selecting the peak process threshold for transitioning from the steam-dominant process to the solvent-dominant process in homogeneous or heterogeneous hydrocarbon reservoirs.

[185] For example, the amount of propane and oil recovery may be estimated by measuring production rates, composition of the produced fluids, temperature and pressure of the produced emulsion and gas streams. Similarly, the oil production rate may be estimated from analysis of the produced emulsion flow rate and oil cut samples. Instantaneous SOR (ISOR) and CSOR may be estimated using a steam flow meter as well as water cut and total emulsion flow measurements. Compositions of all produced streams may be measured using manual sampling, which may be validated by truck-based large scale samples or by collecting samples from a vessel in which the produced stream is stored. In other words, to provide support for the measurements obtained from the manual samples, a truck mounted tank may be used including an on-demand test separator for additional measurements. One or more of these produced fluid measurements may be helpful in determining when to transition from a steam-dominant process to a solvent-dominant process.

[186] As an example, a SAGD baseline may be established for two to three months before commencement of propane injection. While the oil rates may be used to estimate steam chamber size, 4D seismic data, for example obtained annually, may be used to monitor steam chamber growth.

[187] A post-steam core may be taken within the area swept by the hybrid steam-solvent process. An analysis of the post-steam core may also be used to indicate if the steam-dominant process is complete (that is, if it has reached the peak process threshold, and the timing is suitable for transitioning to a solvent-dominant process). The core may be used to quantify the amount of asphaltenes (if any) that are left in the reservoir. A potential in-situ upgrading benefit of the hybrid steam-solvent process may be realized if the solvent helps to retain asphaltenes in-situ.
This could be monitored by measuring API Gravity at 15 C as well as asphaltene mass % at various time periods during the process. The prospective crude upgrading benefit due to lower asphaltene production may result in lower diluent requirements prior to pipeline transportation and lower refining intensity requirements for separating heavy hydrocarbons from lighter hydrocarbons. Therefore, lower asphaltene production may also contribute to GHG reduction.

[188] Reservoir Saturation Tool (RST) logs may also be obtained for one or more observations wells. For example, an observation well may be located tens of meters, such as about 27 m, from the SAGD well pair of the hybrid steam-solvent process. An RST analysis may be performed at the observation well a few (e.g.
two to three years) before the transition from the steam-dominant process to the solvent-dominant process, and annually shortly before the transition, to monitor relative changes in residual oil saturation and the rise in steam chamber height during the hybrid steam-solvent process. The changes observed from analysis of the RST
logs may be compared to repeat RST logs of other nearby SAGD well pairs.

[189] In some cases, the pay zone in the formation may have an irregular ceiling, i.e., the bottom of the overburden above the reservoir may vary in height. In such cases, the following methods or metrics may be used, alone or in combination, to select and determine the peak process threshold: increase in CSOR; decrease in oil production rate; and statistical information from neighboring wells and pads if the reservoir is highly heterogeneous; 4D seismic data; and temperature information (such as measured by thermal couples).

[190] In some heterogeneous pay zones, the ceiling at some sections of the reservoir formation may be lower, which may allow an earlier transition to the solvent-dominant process.

[191] In some embodiments, it may be beneficial to use a tracer or NCG
during the hybrid process to monitor certain performance or process metrics. For example, in some cases a chemical tracer or NCG may be injected during the steam-dominant process or solvent-dominant process and the production of the tracer is monitored to understand how quickly or how much of the injected fluid is produced (recovered) to surface. The tracer may have a distinctive molecular structure and chain link within the mixture for a complete detection. For example, radioactive tracers, or methyl alcohol or water-based tracers may also be used.

[192] To deliver a selected solvent to the production site and to implement a hybrid steam-solvent process, a modular natural gas liquid (NGL) injection system may be used. Such a modular system may be designed to be relocatable to other well pads.

[193] Solvent, such as propane, may be mixed with steam upstream of a wellhead and the combined stream of steam and solvent may be injected into the reservoir through an injection well. An existing NGL injection module may be modified to allow the steam-solvent injection point to be in close proximity to the wellhead.

[194] In an embodiment, a stand-alone hybrid steam-solvent process skid may be provided. A solvent injection pump driver may be electrically driven with the electrical power supplied.

[195] At the surface, the solvent may be delivered by a pipeline or by trucks. If trucks are used to deliver the solvent, the trucks may offload the solvent, for example propane, to immobile NGL storage bullets, from which the solvent may be injected into the reservoir with one or more pumps. While the solvent may also be injected directly from mobile trucks into the injection well, quick offloading of the solvent from trucks may result in batch injection. Immobile bullets may be used if continuous injection of the solvent is desirable and the solvent is initially provided by trucks. For a medium scale facility, immobile 50-tonne solvent bullets may be used, which may be manufactured and configured specifically for propane storage. Additionally, injection pumps may be manufactured following a standard pump manufacture process, or may be custom-designed and made to manage propane injection from about 40 t/d to about 80 t/d. In practice, the amount of solvent delivered may be determined by measuring the weight of each truck before and after unloading to monitor the weight change. For propane injection at a rate of 50 t/d, two or more trucks may be sufficient.

[196] For maintaining a solvent-dominant process operated with a typical SAGD well pair at a pressure of about 3 MPa, the steam requirement to heat propane to about 75-100 C is expected to be about 10-25 t/d. This steam requirement is much less than the steam requirement for steam injection in a conventional SAGD
process, which requires about 250-300 t/d steam at the in-situ pressure of about 3-3.5 MPa.

[197] In different embodiments, and depending on the desired quality of the injected propane, the quality of the injected steam, and the temperature of the propane in the delivering trucks, the steam injection rate may be between 10% and 30%
of the propane injection rate.

[198] In some embodiments, solvent injection may be measured to avoid risks of short circuiting the solvent and thermal shock. Short circuiting of injected solvent may increase the load on injection and production pump(s) due to increased GOR
(gas to oil ratio). To mitigate this potential problem, solvent injection rate may be increased with careful control and pump performance may be monitored (e.g., through monitoring amperage fluctuations) for anomalies. Rapid cooling at the wellhead and upper reaches of the wellbore due to injection of a cooler injection mixture may cause a thermal shock effect. The wellbore heat capacity may be sufficient to mitigate this effect in some cases. However, to reduce the risk, steam may be provided between 10 wt% and wt% with the solvent, to target 100 C at the wellhead. The amount of steam may be controlled based on a wellhead temperature reading.

[199] In an embodiment, after the initial transition to the solvent-dominant process, a steady injection ratio of 80 wt% propane and 20 wt% steam may be achieved within three weeks. In some cases, 20 wt% steam in the injection mixture may be needed for increasing the enthalpy of the mixture for the solvent to be injected in the gaseous phase and for later condensation of the solvent in the steam chamber.
Co-injection of steam and solvent at a steady ratio of 20 wt% of steam and 80 wt% of solvent may be maintained for about 18 months. It is expected that seasonal environmental temperature changes should not affect the injection process.
Some fluctuation in the wt% of steam, the wt% of solvent, or both, may be observed during the steam-dominant process, the solvent-dominant process, or both, for example, fluctuation of about 10 wt%.

[200] CONCLUDING REMARKS

[201] It will be understood that any range of values herein is intended to specifically include any intermediate value or sub-range within the given range, and all such intermediate values and sub-ranges are individually and specifically disclosed.

[202] It will also be understood that the word "a" or "an" is intended to mean "one or more" or "at least one", and any singular form is intended to include plurals herein.

[203] It will be further understood that the term "comprise", including any variation thereof, is intended to be open-ended and means "include, but not limited to,"
unless otherwise specifically indicated to the contrary.

[204] When a list of items is given herein with an "or" before the last item, any one of the listed items or any suitable combination of two or more of the listed items may be selected and used.

[205] Of course, the above described embodiments are intended to be illustrative only and in no way limiting. The described embodiments are susceptible to many modifications of form, arrangement of parts, details and order of operation. The invention is intended to encompass all such modification within its scope, as defined by the claims.

Claims

WHAT IS CLAIMED IS:

1. A method of recovering heavy hydrocarbons from a subterranean reservoir by a steam-dominant recovery process and a solvent-dominant recovery process, comprising:
injecting steam into the reservoir to assist recovery of hydrocarbons from the reservoir by the steam-dominant recovery process until a peak process threshold has been reached, wherein a vapor chamber is developed in the reservoir by steam injection and a dominant vapor in the vapor chamber during the steam-dominant recovery process is steam;
upon determination that the peak process threshold has been reached, co-injecting a solvent and steam into the vapor chamber to assist further recovery of hydrocarbons from the reservoir by the solvent-dominant recovery process, such that the vapor chamber is further expanded and the dominant vapor in the expanded vapor chamber is a vapor of the injected solvent; and recovering a fluid comprising the solvent and hydrocarbons from the reservoir.

2. The method of claim 1, wherein the steam-dominant recovery process comprises a steam-assisted gravity drainage (SAGD) recovery process.

3. The method of claim 1 or claim 2, comprising selecting a solvent for the solvent-dominant process, wherein the solvent is injectable as a vapor and dissolves at least one of the hydrocarbons for increasing a mobility of the heavy hydrocarbons.

4. The method of any one of claims 1 to 3, wherein the solvent is heated and vaporized by the co-injected steam.

5. The method of any one of claims 1 to 4, wherein the solvent-dominant recovery process comprises co-injecting steam and the vapor of the solvent into the vapor chamber to further expand the vapor chamber laterally, wherein the volume of steam injected into the reservoir formation provides sufficient heat to the injected solvent to maintain the injected solvent in a vapor phase, and wherein the weight ratio of co-injected solvent vapor to co-injected steam is higher than 3/2.

6. The method of any one of claims 1 to 5, comprising:
selecting a transition condition for transitioning from the steam-dominant recovery process to the solvent-dominant recovery process, wherein the transition condition occurs after the peak process threshold has been reached;

and determining when the transition condition has been met, and upon determination that the transition condition has been met, transitioning from the steam-dominant recovery process to the solvent-dominant recovery process.

7. The method of claim 6, wherein the reservoir has an overburden above a formation -of the reservoir that contains heavy hydrocarbons, and the steam-dominant process creates a vapor chamber in the formation below the overburden, and wherein the transition condition is that the injected steam has reached the overburden.

8. The method of claim 6, wherein the reservoir has an overburden above a formation of the reservoir that contains heavy hydrocarbons, and the SAGD process forms the vapor chamber in the formation below the overburden, and wherein the transition condition is that vertical growth of the vapor chamber has reached a limit such that further vapor chamber growth will be substantially lateral.

9. The method of claim 6, wherein the transition condition is that a peak hydrocarbon production rate has been reached in the SAGD process.

10.The method of claim 6, wherein the transition condition is that the reservoir has been subjected to the steam-dominant recovery process for at least two years.

11.The method of claim 6, wherein the transition condition is that the hydrocarbon production rate has reached a peak value and then decreased by less than 20 percent of the peak value in the steam-dominant recovery process.

12.The method of claim 6, wherein the transition condition is that hydrocarbon production in the steam-dominant recovery process has declined for a selected period of time.

13.The method of claim 6, wherein the transition condition is that a current cumulative steam to oil ratio (CSOR) is higher than a previous CSOR in the steam-dominant recovery process.

14.The method of claim 6, wherein the reservoir has an overburden above a formation of the reservoir that contains heavy hydrocarbons, and steam injection in the steam-dominant recovery process causes a temperature at an interface region between the overburden and the formation to increase, and wherein the transition condition is that the temperature has increased to at least 20 C° due to heating by steam injection.

15.The method of any one of claims 1 to 14, wherein the solvent comprises at least one of propane, butane, pentane, hexane, heptane, and octane.

16.The method of any one of claims 1 to 14, wherein the solvent comprises a C3 to C5 hydrocarbon.

17.The method of any one of claims 1 to 16, wherein, in the solvent-dominant process, the steam and solvent are co-injected as a mixture at a selected temperature, and a ratio of steam to solvent in the mixture and the selected temperature are selected so that the mixture has sufficient enthalpy to allow the solvent to be in a gas phase at the selected temperature.

18.The method of any one of claims 1 to 17, wherein the solvent-dominant process comprises co-injecting a mixture of steam and the solvent, the mixture comprising less than 30 wt% of steam.

19.The method of any one of claims 1 to 17, wherein the solvent comprises propane.

20.The method of claim 19, wherein the solvent-dominant process comprises co-injecting a mixture of about 10 wt% of steam and about 90 wt% of the solvent.

21.The method of claim 19, wherein the solvent-dominant process comprises co-injecting a mixture of about 20 wt% of steam and about 80 wt% of propane.

22.The method of claim 21, wherein steam injection is reduced from about 100 wt% to about 20 wt% of the mixture over a period of about three weeks.

23.The method of any one of claims 19 to 22, wherein steam and the solvent are co-injected at a temperature of about 75 °C to about 100°C in the solvent-dominant process.

24.The method of any one of claims 1 to 23, wherein steam is injected at a pressure of about 3 MPa in the steam-dominant recovery process, and wherein steam and the solvent are co-injected at a pressure of about 2 MPa to about 3.5 MPa in the solvent-dominant process.

25.The method of any one of claims 1 to 24, wherein said co-injecting a solvent and steam into the vapor chamber comprises gradually increasing a weight ratio of the solvent in the co-injected solvent and steam and gradually decreasing a weight ratio of the steam in the co-injected solvent and steam.

26.The method of any one of claims 1 to 25, wherein said co-injecting a solvent and steam into the vapor chamber further comprises gradually decreasing a solvent content in the co-injected solvent and steam and gradually increasing a steam content in the co-injected solvent and steam.

27.The method of any one of claims 1 to 26, wherein, in the solvent-dominant recovery process, steam is injected at a temperature sufficient to heat the solvent such that the injected solvent has a temperature of between about 50 °C and about 350°C
within the vapor chamber.