CA3018858A1

CA3018858A1 - Method for producing hydrocarbons from subterranean reservoir with solvent and controlled heating

Info

Publication number: CA3018858A1
Application number: CA3018858A
Authority: CA
Inventors: Prince Azom; Amos Ben-Zvi; Brent Donald Seib
Original assignee: Cenovus Energy Inc
Current assignee: Cenovus Energy Inc
Priority date: 2017-09-29
Filing date: 2018-09-27
Publication date: 2019-03-29

Abstract

A method of producing hydrocarbons from a subterranean reservoir comprises producing a liquid mixture from the reservoir, the liquid mixture comprising an injected solvent, hydrocarbons mobilized by the injected solvent, and asphaltenes; and heating the liquid mixture in a production zone, before the liquid mixture is produced, to reduce asphaltene precipitation and deposition in the production zone or to limit growth of an asphaltene-rich phase in the liquid mixture, at a temperature below a bubble point temperature of the solvent in the liquid mixture under a reservoir pressure.

Description

METHOD FOR PRODUCING HYDROCARBONS FROM SUBTERRANEAN
RESERVOIR WITH SOLVENT AND CONTROLLED HEATING
TECHNICAL FIELD
[001] This disclosure relates generally to solvent-based methods for in situ (in-situ) hydrocarbon production and more particularly to solvent-based methods which utilize one or more downhole heaters.
BACKGROUND

[002] Recovery of viscous hydrocarbons from subterranean reservoirs can be aided by injection of a selected solvent into the reservoir. The solvent can function as a diluent for viscous hydrocarbons. When the solvent is heated, it may also, to a limited extent, transfer heat to the hydrocarbons or the reservoir. Both effects can reduce the viscosity of viscous hydrocarbons and increase their mobility.

[003] A solvent may be used to aid a steam-assisted recovery process, in a so-called solvent-aided process (SAP). SAPs include both steam driven solvent processes, where the amount of steam added is greater than the amount of solvent added, and solvent driven processes, where the amount of steam added is less than the amount of solvent added. To further reduce steam use, a solvent may be injected without steam in a production stage of a recovery process (processes including such a production stage are referred to herein as solvent-based recovery processes).

[004] In a solvent-based recovery process known as Vapor Extraction (VAPEX) process, a vaporized solvent is injected into the reservoir (formation) via an injection well situated above a production well. The injected solvent mobilizes viscous hydrocarbons in the formation, and the mobilized hydrocarbons drain downward and are collected in the production well and produced to surface. Drainage of the mobilized hydrocarbons leaves a hydrocarbon-depleted porous volume in the formation, through which the solvent vapor and other fluids can more easily travel, and this porous volume can be referred to as a "vapor chamber", similar to a "steam chamber" in a steam-assisted gravity drainage (SAGD) process. In fact, the well arrangement in a VAPEX
process may be configured similarly to a SAGD well-pair arrangement, as can be understood by those skilled in the art.

[005] Compared with steam-assisted recovery processes such as SAGD
processes, a solvent-based recovery process may require less heating energy and less use of water, and reduce emission of greenhouse gases. However, existing solvent-based recovery processes face their own challenges. For example, the oil production rate is typically lower in a solvent-based recovery process than in a SAGD
process or a SAP when solvent injection is limited to keep the solvent to oil ratio (SolOR) within practical limits.

[006] CA2299790, published 23 August 2001 proposed a method of enhanced oil recovery, where a heated and vaporized solvent is injected under pressure into the formation and condensed in the formation to release heat of condensation to the formation. A liquid blend of the solvent and mobilized heavy oil is then extracted from the formation. However, this proposed technique requires injection of a relatively high volume of heated solvent, which increases production costs due to both increased heating cost and increased material cost.

[007] CA 2281276, published 28 January 2001 proposed a method of in-situ recovery of viscous petroleum hydrocarbons from an underground formation, where vaporized solvents are injected into the formation and the injected solvents are boiled off by indirect heating in the formation (termed as "reboil") to recycle the solvents in the reservoir.

[008] WO 2013/007297, published 17 January 2013 proposed a process for recovery of viscous hydrocarbons, where steam and/or one or more solvents are injected into an upper injection well, and the lower production well is electrically heated to re-vaporize (reflux) the steam and/or one or more solvents.

[009] However, commercial applications of solvent-based recovery processes have been limited to date. Challenges remain in providing solvent-based recovery processes for efficient and effective commercial application.
SUMMARY

[010] In one aspect, the present disclosure relates to a method of producing hydrocarbons from a subterranean reservoir. The method comprises producing a liquid mixture from the reservoir, the liquid mixture comprising an injected solvent, hydrocarbons mobilized by the injected solvent, and asphaltenes; and heating the liquid mixture in a production zone, before the liquid mixture is produced, to reduce asphaltene precipitation and deposition in the production zone, at a temperature below a bubble point temperature of the solvent in the liquid mixture under a reservoir pressure.

[011] In another aspect, the present disclosure relates to a method of producing hydrocarbons from a subterranean reservoir, comprising: producing a liquid mixture from the reservoir, the liquid mixture comprising an injected solvent, hydrocarbons mobilized by the injected solvent, and asphaltenes; and heating the liquid mixture in a production zone, before the liquid mixture is produced, to limit growth of an asphaltene-rich phase in the liquid mixture, at a heating temperature below a bubble point temperature of the solvent in the liquid mixture under a reservoir pressure.

[012] In an embodiment of a method described herein, the liquid mixture may be produced through a production well, and the production zone may be heated with a downhole heater in the production well. The downhole heater may comprise an electric heater. The electric heater may have an operating frequency in the range of 1 Hz to 30 kHz, or may be operable in the direct current mode. The heating temperature may be above 50 C. The heating temperature may be at least 5 C below the bubble point temperature, such as at least 15 C below the bubble point temperature. The heating temperature may be between 50 C and 70 C. In a particular embodiment, the solvent may comprise propane. The solvent may comprise a non-polar solvent. The non-polar solvent may comprise a C4-C15alkane, such as a C4-C7alkane. The non-polar solvent may comprise n-butane, iso-butane, or pentane. The produced liquid mixture may comprise 1 to 30 wt% of asphaltenes. The method may comprise injecting the solvent into the reservoir. The solvent may be injected as a vapor into the reservoir.
The heating may comprise intermittent heating using electrical power, wherein the heating is reduced during a period of peak-demand for electrical power. The solvent may be injected into the reservoir through an injection well and the production well may comprise a well positioned below the injection well. The injection well may comprise a generally horizontal wellbore and a branched wellbore extending upwards, or laterally, from the horizontal wellbore. The production well may comprise a branched wellbore.
The production well may comprise an infill well positioned in a bypassed region between first and second pairs of injection and production wells.

[013] 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

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

[015] FIG. 1 is a schematic perspective section view of a well system for use in an embodiment of the present disclosure.

[016] FIG. 2 is a schematic side section view of the injection well of FIG.
1.

[017] FIG. 3 is a schematic side section view of the production well of FIG. 1.

[018] FIG. 4 is a flow diagram for an exemplary solvent-based recovery process, illustrative of an embodiment of the present disclosure.

[019] FIG. 5 is a schematic cross-sectional view of the reservoir and wells of FIG. 1 during operation.

[020] FIG. 6A is data graph showing representative experimental and simulation results of viscosity as a function of temperature for different sample materials.

[021] FIGS. 6B and 6C are 3D data graphs showing representative simulation results of mobility as a function of temperature and pressure for propane and butane aided recovery of bitumen, respectively.

[022] FIG. 7A is a line graph comparing calculated solvent to oil (SolOR) ratios in an embodiment of the present disclosure (with heating of the production well during production) and a comparison solvent-based recovery process (without heating the production well during production).

[023] FIG. 7B is a schematic diagram illustrating a reservoir model used for simulation of production performances in different recovery processes and for the results shown in FIG. 7A.

[024] FIG. 7C is a line graph comparing simulation results of cumulative heater energy intensity (El) for different heating strategies.

[025] FIGS. 8A, 8B, 8C, 8D, 8E and 8F are schematic views of different branched well configurations.

[026] FIG. 9A is a schematic cross-sectional view of two well pairs and a bypassed region.

[027] FIG. 9B is a schematic cross-sectional view of the well pairs and the bypassed region of FIG. 9A, and an infill well penetrating the bypassed region.

[028] FIG. 10 is a line graph illustrating corresponding profiles of electricity usage in a power supply system and electricity usage for intermittent heating of the production zone in an embodiment of the present disclosure.

[029] FIG. 11 is a line graph of the oil production rate as a function of the relative density of the produced oil.

[030] FIG. 12 is a comparison of the energy intensity (El) at 70% recovery factor (RF) between a SAGD process (cSOR=3.2) and a propane-based recovery process (cSOR=0.2), with a reduction in El by 16 times (cSOR = cumulative solvent to oil ratio).

[031] FIG. 13 shows the relative changes of temperature, oil saturation in the formation (So %), and solvent saturation (propane concentration %) over time in a propane-based recovery process at temperatures below 100 C.

[032] FIG. 14 shows comparison data with respect to FIG. 13 from a comparison process with co-injection of steam and propane at temperatures up to about 240 C.
DETAILED DESCRIPTION

[033] In brief overview, the present inventors have recognized that the effectiveness and efficiency of solvent-based hydrocarbon recovery from a subterranean reservoir can be improved by controlled heating of a production zone through which mobilized hydrocarbons are produced. For this purpose, a heater (e.g. a downhole heater) may be disposed in, or along a portion of, a production well in the production zone to heat a liquid mixture to be produced as the liquid mixture flows through the production zone.

[034] The production zone is a zone around the production well through which a liquid mixture to be produced passes before being produced to surface. The liquid mixture may include mobilized hydrocarbons and an injected fluid. The production zone may include the volume occupied by the production well and a region around or near a perforated section of the production well.

[035] The heating of the production zone may be controlled to keep the temperature in the production zone (including the production well) above a lower threshold and below an upper threshold. For example, the lower threshold may be selected to manage and control asphaltene phase equilibria such as precipitation, flocculation, and agglomeration, in order to limit the formation or growth of an asphaltene-rich bitumen (ARB) phase in the liquid mixture to be produced, and to limit the extent of asphaltene deposition within the production zone. The upper threshold may be selected to prevent excessive re-vaporization of the solvent in the reservoir, since the heating required for solvent re-vaporization in the reservoir may be non-productive or inefficient for increasing the mobility of the hydrocarbons to be produced and the hydrocarbon production rate.

[036] Conveniently, when formation or growth of the ARB phase in the liquid mixture is controlled by controlling the temperature in the production zone, the oil production rate may be increased more efficiently. For example, the present inventors have recognized that a comparable production rate may be achieved more efficiently at a relatively lower solvent injection temperature, as compared to a process in which the solvent is injected at a relatively higher temperature without separate controlled heating of the production zone.

[037] Without being limited to any particular theory, the formation and growth of the ARB phase is more likely to occur below a threshold temperature, which is dependent on the reservoir pressure and the composition of the liquid mixture including any solvent content and hydrocarbon content therein. It is expected that the formation and growth of the ARB phase in the production zone may lead to reduction of the oil production rate for a number of reasons.

[038] For example, the liquid mixture in the production zone may include an ARB phase or a solvent-rich bitumen (SRB) phase. An ARB phase is typically denser than a SRB phase, and tends to be preferentially produced. Production of substantial amounts of the ARB phase tends to reduce oil production due to the longer residence times of the SRB phase within the reservoir and lower temperatures associated with the ARB phase (as compared to the SRB phase). Moreover, excessive formation of the ARB phase increases the risk of asphaltene deposition within the production zone which tends to reduce the fluid flow rates by clogging/plug pores and fluid paths in the reservoir, particularly in the production zone in or near the production well.
Therefore, keeping the temperature in the production zone high enough (i.e., above a threshold temperature) to limit the formation and growth of the ARB phase, or to limit the precipitation and deposition of asphaltenes, is expected to improve the oil production rate.

[039] It has also been recognized by the present inventors that when the solvent is excessively heated such that it is vaporized in the production zone, the mobility of the SRB phase in the production zone can decrease. A reason for decreased mobility is that the viscosity of the hydrocarbons in the SRB phase may increase when less diluent (solvent) is present in the liquid mixture due to removal of the solvent by vaporization. Further, vaporization of the solvent in the production zone requires heat energy. Heating the solvent to vaporize the solvent in the production zone may not be efficient or economical for increasing the oil production rate.
Keeping the temperature in the production zone below the bubble point temperature of the solvent in the liquid mixture can effectively limit or prevent substantial solvent vaporization in the production zone, thus increasing oil production efficiency.

[040] An illustrative embodiment will be described next with reference to the figures.

[041] FIG. 1 shows a reservoir 100 having a pay zone 102 under a cap layer 103. In the particular embodiment illustrated in FIG. 1, an injection well 120 and a production well 140 are provided, which penetrate the pay zone 102 of the reservoir 100.

[042] The reservoir 100 is a subterranean or underground reservoir containing recoverable viscous hydrocarbons. At least some of the viscous hydrocarbons are immobile under natural or original reservoir conditions (i.e. before the reservoir 100 is subjected to heating or before a treatment material has been injected into the reservoir to mobilize the hydrocarbons). Immobile materials include materials that are not mobile or not mobile enough to drain under gravity without further treatment. In the reservoir 100, fluids such as gases and water may also have limited mobility due to a relatively high degree of viscous hydrocarbon saturation. In some typical bitumen reservoirs found in Alberta, Canada, the natural or original temperature in the reservoir may be between about 7 C and about 12 C, and the natural or original pressure in the reservoir may be between about 1 MPa and about 5 MPa. In different reservoirs, the original temperature and pressure may be different.

[043] Broadly, viscous hydrocarbons in the reservoir 100 may have a viscosity higher than about 1,000 centipoise (cP), 10,000 cP, 100,000 cP, or 1,000,000 cP. The viscous hydrocarbons in the reservoir 100 may be a mixture of various materials. A
variety of hydrocarbons in the reservoir 100 may exist, as viscous liquids, or in semi-solid or solid forms at native reservoir conditions. For example, the viscous hydrocarbons in reservoir 100 may exist in the form of bitumen, heavy oil, extra heavy oil, bituminous sands (also referred to as oil sands), or combinations thereof. In bituminous sands, at least some viscous or immobile hydrocarbons are disposed between, or attached to, sands. In the reservoir 100, hydrocarbons may exist in mixtures of varying compositions comprising hydrocarbons in the gaseous, liquid or solid states, which may also be in combination with other fluids (liquids and gases) that are not hydrocarbons. Bitumen is generally non-mobile under typical native reservoir conditions. The reservoir 100 also includes asphaltenes in the pay zone, which may co-exist or be mixed with the viscous hydrocarbons. As will be understood by those skilled in the art, asphaltenes are typical components of crude oil or petroleum which are insoluble in light paraffinic hydrocarbons, but at least partially soluble in benzene, chloroform, or carbon disulfide. Asphaltenes may include polycyclic aromatic compounds, which may contain carbon, hydrogen, oxygen, sulfur, nitrogen, or a combination thereof. In some hydrocarbon reservoirs, the initial asphaltene content in a pay zone may be from about 10 wt% to about 30 wt%, or about 15wt% to about 30wt%, of the hydrocarbon content in the same pay zone.

[044] Each of the wells 120 and 140 has a horizontal section with a perforated section. The horizontal sections of the wells 120 and 140 are substantially parallel to one another and are vertically spaced by a distance, which may be about 5 to about 8 m, with the production well 140 positioned below the injection well 120. The horizontal sections of the wells 120 and 140 may be about 800 m in length. The injection well 120 is connected to an injection surface facility 220 (not shown in detail), and the production well 140 is connected to a production surface facility 240 (not shown in detail). Further details of the wells 120 and 140 are provided below with reference to FIGS. 2 and 3.

[045] The injection surface facility 220 is configured to supply an injection fluid, which includes a solvent, to the injection well 120 for injection into the pay zone 102 of the reservoir 100. The injection surface facility 220 may have a supply line (not shown) connected to an injection fluid source (not shown) for supplying the injection fluid.

[046] The production surface facility 240 and the production well 140 are configured to produce a fluid from the reservoir 100 to surface through production well 140. The produced fluid may include a liquid mixture of the injected solvent, mobilized hydrocarbons, and asphaltenes. The production surface facility 240 may include a fluid transport pipeline (not shown) for conveying the produced fluid to a downstream facility (not shown) for processing or treatment.

[047] The injection surface facility 220 includes equipment for supplying the injection fluid to the injection well 120, and the production surface facility 240 includes equipment for producing the produced fluid from the production well 140, as can be understood by those skilled in the art.

[048] The wells 120 and 140 may be configured and completed in a similar manner as the horizontal wells used in a steam-assisted gravity drainage (SAGD) process, with suitable modifications to inject a solvent instead of, or in addition to, steam, and to heat the production zone as will be further explained below.

[049] For example, FIG. 2 schematically illustrates an embodiment of the injection well 120. The injection well 120 is provided with a coiled tubing 122 for injecting the solvent (and other possible injected fluids or materials), a casing 124, a liner assembly 126, and a liner hanger 128. The liner assembly 126 is slotted to allow injected fluids to pass through. The coiled tubing 122 may be connected to a control system (not shown) at the surface for controlling the injection operation, as can be understood by those skilled in the art. One or more downhole heaters 132 may be provided in the injection well 120, which may include a wire or rod coiled around the coiled tubing 122 along a length of the horizontal section of the injection well 120. The heater 132 may be an electric heater. An electric heater may be operated in the direct-current (DC) mode or in an alternating-current (AC) mode, and maybe operated at an operating frequency in the range of 1 Hz to 30 kHz. A temperature sensor 134 may be provided in or on the coiled tubing 122. The temperature sensor 134 may include a distributed temperature sensing (DTS) device, and may include thermocouples.
Temperatures at multiple points along the well 120, such as 4 to 6 points or more, may be monitored during operation. Electrical signal and power lines (not separately shown) for the temperature sensors 134 and the heater 132 may be connected to the surface control system to provide temperature signals from the sensors 134 to the control system and to control operation of the heater 132. The power and signal lines may be attached to the coiled tubing 122 or a tubing string (not shown in FIG. 2).
Additional necessary or optional components, tools, or equipment may be installed in the injection well 120, but they are not shown in FIG. 2 as they are not particularly relevant for the purpose of the present disclosure. For example, as is typical for steam- or solvent-aided or -assisted processes, sensors and devices (not shown) for measuring downhole temperature (T) and pressure (P) may be provided in the well 120, such as at a heel portion of the well 120.

[050] In a specific embodiment, an injection well may have a true vertical well depth (TVD) of about 390 m, and a total depth (TD) of 1,500 mKB. This particular well is provided with a dual-heater string, four thermocouples (TC), and a DTS
fibre in the coiled tubing.

[051] FIG. 3 illustrates an embodiment of the production well 140, which is similarly constructed as injection well 120. In particular, the production well 140 also includes a coiled tubing 142, a casing 144, a slotted liner assembly 146, a liner hanger 148, a heater 152, and a temperature sensor 154, which may be similarly constructed and configured as their counterparts in the injection well 120. The production well 140 also additionally includes a pump 156 and a production tubing 158 for producing fluids entering the well 140 through the slotted liner assembly 146 to the surface.
As in the injection well 120, signal and power lines (not shown) for the heater 152 and temperature sensor 154 may be provided and connected to the surface control system.
As in the injection well 120, additional necessary or optional components, tools, or equipment may be installed in the production well 140, but they are not shown in FIG. 3 as they are not particularly relevant for the purpose of the present disclosure.
However, it is noted that a pressure sensor may be optionally omitted in the production well 140 in some embodiments.

[052] In a specific embodiment, a production well may have a TVD of about m, and a TD of 1,500 mKB. This well may also be provided with a dual-heater string, four or more TCs, and a DTS fibre in the coiled tubing. The production tubing may be landed at the heel of the well, with a TD of 595 mKB.

[053] During operation, an example recovery process S400 for producing hydrocarbons form the reservoir 100 using the well pair of wells 120 and 140 may include the stages illustrated in FIG. 4.

[054] As listed in FIG. 4, the process S400 includes a start-up stage, which may include a Start-up I sub-stage S402 and a Startup ll sub-stage S404, a production stage S406, and a blowdown stage S408. The process S400 is discussed below with references to FIGS. 4 and 5.

[055] In the sub-stage S402 (which may be referred to as preheating), the heaters 132 and 152 may be powered to heat an inter-well zone (or inter-well region) 104 to soften the viscous hydrocarbons therein. The heating in the sub-stage may be provided at a selected power for a period of sufficient time to prepare the reservoir formation for the sub-stage S404, such as for about 1 month to about months at a heating power/well length of up to 10,000 Winn, such as from about 500 to 5,000 W/m. As can be appreciated by those skilled in the art, heating the materials in the reservoir 100, particularly in the inter-well region 104, can soften, or increase the mobility of, viscous hydrocarbons within the inter-well zone 104, which can facilitate distribution and dispersion of the injected solvent in the inter-well region 104. At the end of the sub-stage S402, the temperature in the inter-well zone 104 is increased as compared to its native temperature, so that the viscous hydrocarbons in the inter-well region 104 are at least partially softened and mobilized. For example, the average temperature of the inter-well zone 104 may be about 95 C at the end of the sub-stage S402. The average temperature may vary from about 80 C to about 290 C for propane at the operating pressure of about 3 MPa.

[056] In the sub-stage S404, an injection fluid 160 including a selected solvent is injected into the inter-well zone 104 from both the injection well 120 and the production well 140 at a selected pressure to establish fluid communication between the injection well 120 and the production well 140. The solvent may be selected as discussed below. The injection pressure and injection temperature may also be selected as further discussed below. In a particular embodiment, the selected solvent is propane. When the solvent is propane, the injection temperature may be about 80 C to about 100 C, and the injection pressure may be about 3 MPa to about 3.5 MPa.
The propane is thus injected as a vapor at these selected temperatures and pressures. The injected solvent vapor will disperse into the pay zone 102 particularly the inter-well region 104, and will condense in the cooler regions as the solvent travels away from the wells 120 and 140. The latent heat transferred from the solvent to the pay zone 102 further mobilizes the hydrocarbons therein. The condensed solvent liquid can also dilute the hydrocarbons it contacts, thus further softening or mobilizing the hydrocarbons in the inter-well region 104. During the sub-stage S404, heaters 132 and 152 may both be activated to heat the inter-well region 104 to assist heating of the hydrocarbons therein.

[057] At some point in the sub-stage S404, a pressure differential between the injection well 120 and the production well 140 may be established to drive fluid flow from the injection well 120 towards the production well 140. For example, injection of solvent into the production well 140 may be terminated at a selected time, and the pump 156 may be operated to produce fluids in the well 140 to the surface, while injection of the solvent into the injection well 120 is maintained. As can be appreciated, a higher injection pressure or higher pressure differential between the wells can drive the solvent into the reservoir 100, or the fluid flow in the reservoir 100, more quickly.
Eventually, a fluid path between the wells 120 and 140 will be formed and fluid communication between the wells is established. In some applications, it may take about 3 months or more to establish fluid communication between the wells in the well pair. The sub-stage S404 may continue after initial fluid communication between the wells in the well pair to provide improved communication there between. For example, it may be desirable to have generally uniform communication along the length of the horizontal sections of the wells 120 and 140.

[058] After fluid communication between the wells 120 and 140 is established, the production stage S406 may commence. At the beginning of the production stage S406, there may be a ramp-up phase (not shown in FIG. 4), in which the production rate is gradually increased, or increased in steps.

[059] At this point, some softened or mobilized hydrocarbons will have drained downward, leaving behind a porous volume, referred to as the vapor chamber 106, in the pay zone 102. The vapor chamber 106 is analogous to the "steam chamber" in SAGD processes. The concept of a "steam chamber" is well known and understood by those skilled in the art. A solvent vapor can travel more easily and quickly in the vapor chamber 106 as compared to the original, much less porous, pay zone 102. In the ramp-up phase, the vapor chamber may grow and develop upwards above the injection well 120, as the heated solvent vapor tends to rise in the vapor chamber 106.
The temperature in the central region of the vapor chamber 106 near the injection well 120 is higher than the temperature at the edges (sometimes referred to as the "interface region" or the "chamber front") of the vapor chamber 106. The interface region is indicated in FIG. 5 by the dashed line. For example, the temperature of the central region of the vapor chamber 106 may be close to the injection temperature, at about 80 to about 100 C in the above discussed example. The temperature at the interface region may vary from about 70 C to about 20 C, for example, if the temperature in regions outside the vapor chamber 106 is about 15 C.

[060] During the production stage S406, the selected solvent, propane in this particular example, is injected into the pay zone 102 of the reservoir 100 through the injection well 120 only. The injection pressure may be about 3 MPa at this stage. The injection temperature may be about 75 C to about 100 C, such as about 80 C
to about 90 C at this stage. The solvent, propane in this example, enters the reservoir 100 mainly in the vapor form. The solvent may be vaporized at surface and supplied to the injection well 120 in the vapor phase, or provided as a liquid to the injection well 120 and vaporized in the injection well 120 before entering the pay zone 102.
Alternatively, the solvent may be supplied to the injection well 120 as a liquid-vapor mixture. The ratio of liquid:vapor in the liquid-vapor mixture may be selected such that the liquid portion of the mixture at least mostly vaporizes at reservoir conditions (e.g., due to the pressure differential between the injection well 120 and the production well 140 and/or in the presence of the heater) to generate the vapor chamber.

[061] The heater 132 in the injection well 120 may be used to control the injection temperature of the solvent, which may be at about 80 C to about 90 C for propane, such that the propane is injected substantially in the vapor phase.

[062] The heated solvent vapor will initially travel generally upwards in the vapor chamber 106, as indicated by arrows 160 in FIG. 5. The solvent vapor will condense at the interface region due to the cooler temperature in the interface region.
The solvent liquid will mix with the mobilized hydrocarbons to form a liquid mixture 170 and drain generally downward as indicated by arrows 170.

[063] Eventually, the liquid mixture 170 drains into the production zone around the production well 140, and is produced to the surface through the production well 140.

[064] It should be understood that a liquid mixture may contain some limited gaseous contents. For example, in the formation a solvent may be partially in the liquid phase and partially in the vapor phase, such as with up to 80 wt% of the solvent in the liquid phase. A liquid in the liquid mixture, such as a liquid solvent, may also be vaporized in the production well when being produced to surface. Some other gases such as methane, CO2, HS, or a combination thereof may also be produced with the liquid mixture.

[065] During production, the heater 152 in the production well 140 is used to heat the production zone 108. The heating may be controlled by the surface control system (not shown) based on the temperature signal detected by the temperature sensor 154, to maintain the temperature in the production zone 108 to be within a selected temperature range. The factors considered for selecting this range will be discussed in detail below. For injection of propane as the solvent in a particular type of reservoir formation, the lower threshold of the temperature range may be about 50 C, and the upper threshold may be about 70 C, when the injection pressure is about 3 MPa. The lower threshold temperature is selected in this case based on the data shown in FIG. 6A. Because the propane dew point temperature is about 77 C at the given operating pressure, the bubble point temperature of propane in the fluid mixture 170 is also close to 77 C. Thus, the lower and upper thresholds are about 27 C and about 7 C below the bubble point temperature of the liquid mixture at the given reservoir conditions, respectively. As the temperature in the production zone 108 is maintained below the bubble point temperature of the liquid mixture 170, the propane in the liquid mixture 170 will not be significantly re-vaporized, or refluxed, in the production zone 108.

[066] Further, as the reservoir 100 contains asphaltenes, which may be mixed with the hydrocarbons, the liquid mixture 170 in the production zone 108 may include the condensed solvent, mobilized hydrocarbons, and asphaltenes. Depending on the amount of the asphaltenes and the sizes of the asphaltene particles in the liquid mixture 170, the liquid mixture 170 may contain the ARB phase. Conveniently, when the temperature in the production zone 108 is higher than about 50 C, the growth of the ARB phase may be limited or controlled. Thus, the rate of hydrocarbon production is expected to be high, as compared to a comparison solvent based process in which the production zone or the production well is not separately heated with a heater. When the production zone is not heated with a heater, and the temperature in the production zone is relatively low, the hydrocarbon production rate may be relatively low because the liquid mixture 170 may have an increased ARB phase.

[067] For example, with controlled heating of the production zone 108, the asphaltene content in the produced fluid mixture may be limited to between about 1 wt% and about 30 wt%, such as about 1 wt% to about 20 wt%.

[068] Hydrocarbon production may continue until the amount of the hydrocarbons in the pay zone has been reduced to a level that is no longer economical.
At S408, the blowdown stage may start as can be understood by those skilled in the art. During the blowdown stage S408, injection of the solvent is terminated.
The residual hydrocarbons and solvent may still be produced for a period of time.
A non-condensable gas (NCG) such as methane may be injected into the vapor chamber to assist recovery of the residual solvent and the remaining hydrocarbons. The injected NCG may keep the pressure in the vapor chamber at a relatively high level.
During the blowdown stage S408, the production zone 108 may be heated with the heater 152 to keep the temperature in the production zone 108 between the lower and upper thresholds so that the hydrocarbon production is still efficient.

[069] In different embodiments solvents other than propane may be selected and used, and the operating conditions may also vary depending on the selected solvent and the native reservoir conditions. To improve the efficiency of hydrocarbon production, the solvent and the injection and heating conditions may be selected or determined based on a number of factors including those disclosed herein.

[070] In theory, a higher injection pressure is more desirable for increasing the hydrocarbon production rate. A higher injection pressure would drive the fluid flow faster. A higher pressure also allows the solvent to be injected at a higher rate and to condense at a higher temperature, both of which would increase the rate of mobilizing the viscous hydrocarbons. As can be appreciated, a hotter solvent liquid is more efficient for mobilizing hydrocarbons. Simulation tests have confirmed that the production rate increases as the injection pressure increases at the tested conditions.
However, in practical applications, the injection pressure is typically limited by technical, safety, environmental, or other concerns and may be regulated by local authorities. Within the practical limitations, the injection pressure may be selected to be as high as is permitted.

[071] Given the possible injection pressure range, a suitable solvent may be selected so that the solvent can be injected as a vapor at the given injection pressure and at the possible temperature range, such as from about 50 to about 250 C
and can condense at the expected temperature at the interface region of the vapor chamber.
The selected solvent should also be effective for mobilizing the viscous hydrocarbons solvent at the reservoir conditions. Among the possible solvents, the solvents that would provide a similar recovery rate at relatively lower temperatures may be selected as heating a solvent and the pay zone to a lower temperature requires less energy and less cost. Other factors such as chemical compatibility, availability, pre-and post-injection treatment requirements, costs, or the like may also be considered when selecting the solvent. As can be appreciated, a solvent may be injected as a vapor at temperatures above the critical point of the solvent. In this regard, the critical point data are:
- Propane: 96 C, 4.26 MPa - Butane: 152 C, 3.8 MPa - Pentane: 197 C, 3.4 MPa - Hexane: 235 C, 3.02 MPa

[072] In this regard, known data including simulation data may be utilized for selecting the solvent. For example, FIG. 6A shows experimental and simulation results of the viscosity of sample materials or mixtures at different temperatures, at a selected pressure of 2.89 MPa. It can be seen that the bitumen viscosities generally decrease as the temperature increases. For practical production, the viscosity of the softened bitumen should be lower than about 50 - 100 cP, such as from about 1 to about 20 cP, although bitumen with even lower viscosity is generally easier to produce. The data in FIG. 6A indicates that propane, butane and pentane are all effective for lowering the bitumen viscosity to below about 10 cP, at temperatures from about 50 to about C. In particular, propane is still effective for viscosity reduction in the temperature range of about 50 to about 100 C. Thus, on balance of consideration of other factors, propane may be selected as the solvent at the given pressure range.

[073] For a given solvent, the injection temperature may be selected based on factors known to those skilled in the art. For example, the injection temperature should be high enough to vaporize the solvent at the injection temperature and allow the solvent to travel through the vapor chamber in mainly the vapor phase.
However, the injection temperature may be lower than the injection temperature for the same solvent in a conventional solvent-aided process, as additional heat is provided by at least heater 152 in the production well 140. As a result of the additional heating in the production zone 108, it is not necessary for the solvent to be injected at a very high temperature in order to carry enough sensible heat for heating the entire vapor chamber and maintain a sufficiently high temperature in the production zone.

[074] The heating temperature or the threshold temperatures for heating the production zone 108 may then be selected as discussed earlier. For the given solvent and a selected solvent injection rate, the asphaltene content in the fluid mixture collected in the production zone 108, and how the ARB and SRB phases would change at different temperatures may be assessed, such as by conducting experimental tests, or simulation tests, or both. The lower temperature threshold for heating the production zone 108 may be selected so that the ARB phase formation is controlled and limited to allow efficient hydrocarbon production. For example, based on simulation and laboratory tests, it is expected that for propane and the tested type of bitumen, the ARB
phase formation is limited at temperatures above about 50 C at about 3 MPa when propane is used as the solvent. The temperature 50 C can thus be selected as the lower threshold temperature in this instance. The bubble point temperature in the liquid mixture of propane and the tested bitumen is about 77 C at the pressure of about 3.5MPa. Thus, the upper threshold temperature may be selected to be a temperature below the bubble point temperature of 77 C to prevent reflux of the solvent (re-vaporization) in the production zone 108. For example, the upper threshold temperature may be selected to be 70 C. The heating temperature may be at least 5 C below the bubble point temperature of the solvent in the liquid mixture in the production zone, or at least 15 C below the bubble point temperature. For propane, the heating temperature may be between 50 C and 70 C.

[075] For selecting solvents and injection and heating conditions, data plots such as shown in FIGS. 6B and 6C may be helpful. FIG. 6B shows mobility dependence on pressure and temperature for propane, and FIG. 6C shows similar data for butane. For comparison purposes, the typical mobility of bitumen obtained in a conventional SAGD process at typical temperatures of 250 C or higher is about 0.1 cp-1. For propane and butane, similar bitumen mobility may be obtained at much lower temperatures at pressures higher than 3 MPa. From FIG. 6C, it can be seen that the bitumen mobility can be higher than 0.1 cp-1 at temperatures lower than about and pressures of lower than 4 MPa. Thus, it can be expected that butane may also be a suitable solvent for a solvent-aided process as described herein.

[076] The actual temperature control may be carried out by controlling the heater 152 to maintain a set temperature point or range based on the detected temperature from the temperature sensor 154.

[077] It is noted that in FIG. 6A, the viscosity data for different materials or mixtures are plotted. The materials include the following:
- "Saturated C3 Expt." = dead oil bitumen saturated with propane liquid (experiment) - "Liq-Liq C3-Bitumen Expt." = two liquid phase: a bitumen rich phase and a propane (C3 alkane) rich phase, at equilibrium (experiment) - "Saturated C4 Expt." = dead oil bitumen saturated with butane liquid (experiment) - "Bitumen" (experiment) - "Bitumen saturated with methane" (simulation) - "Bitumen saturated with propane" (simulation) - "Bitumen saturated with butane" (simulation) - "Bitumen saturated with pentane" (simulation)

[078] It is worth noting that the data in FIGS. 6A, 6B and 6C indicate that the viscosity of certain alkane-saturated bitumen can decrease as the temperature is reduced. In other words, the mobility of such materials increases at lower temperatures. In comparison, as can be seen in FIG. 6A, the viscosity of the bitumen material or a mixture of bitumen and methane increases as the temperature decreases, and their mobility correspondingly decreases. From the mobility data alone, it might be concluded that the lower the production temperature (i.e. the temperature in the production zone), the higher the production rate due to increased mobility when propane or butane is used to aid the production process. However, as noted above, when the production temperature is too low, formation or excess growth of the ARB
phase in the production zone can negatively affect the production rate. Thus, the lower threshold for the production temperature should take this effect into account.

[079] Known analysis tools and methods may be used to aid the selection of the solvent and operating conditions. For example, a known oil production analysis method is the SARA (Saturates, Aromatics, Resins, and Asphaltenes) analysis.
The SARA analysis method is described in, for example, US 5,424,959, the entire contents of which are incorporated herein by reference.

[080] In some embodiments, propane may be selected as a suitable candidate solvent for a number of reasons relating to thermo-physical characteristics of propane and propane-bitumen mixtures under the particular reservoir conditions. First, propane has a moderate dew point temperature (and the corresponding bubble point temperature in a propane-bitumen mixture is also moderate), and thus it can be readily vaporized at a moderate temperature for injection through the injection well 120 and the propane vapor can be readily condensed at the interface region of the vapor chamber 106. Second, the viscosity of the propane-bitumen mixture decreases with decreased temperature at the temperature range of 50 to 70 C, which is just below the propane bubble point in the mixture at the given pressure of about 3MPa. The shaded oval region in FIG. 6A indicates a region for effective bitumen production. Based on this indicated region, a production temperature for propane may be indicated as from about 50 C to about 105 C. For example, a preliminary lower temperature threshold may be selected based on this region, and selecting the lower temperature threshold of about 50 C may provide a minimum acceptable viscosity level. From the preliminary threshold, lab or field tests can be conducted to determine an optimal or actual lower threshold. The lower threshold may then be increased or decreased based on the test results or production performance during operation, such as to mitigate against excess formation of an undesirable ARB phase in the production zone 108.

[081] While the initial upper temperature threshold may be selected to limit solvent reflux or "reboil" in the production zone 108, the data such as shown in FIGS.
6A, 6B or 6C may also be considered, and can be adjusted based on actual test or performance results. Limiting re-vaporization of the solvent in the production zone 108 can reduce inefficient heating of the solvent and the production zone 108. For example, the upper temperature threshold may be set at 70 C, which is about 7 C below the propane dew point temperature under the stated reservoir conditions.

[082] For clarity, it is noted that an embodiment of a solvent-based recovery process may include injection of steam at different stages (such as the start-up stage) other than the oil production stage, where a solvent is injected in the production stage without steam. Embodiments of the present disclosure also include recovery processes in which a solvent is injected in an oil production stage to drive oil production, but steam is not co-injected with the solvent as a primary heating source to maintain or control the temperature in the production zone of the reservoir during the production stage.

[083] Conveniently, an embodiment of the solvent-based recovery process as described herein may provide effective and efficient hydrocarbon production at reduced energy and solvent consumption and lower costs.

[084] For example, FIG. 7A compares the achievable solvent to oil ratios (SolOR) in two different processes based on simulation results for propane.
The lower lighter curve in FIG. 7A represents the SolOR for a process as described herein where the production zone is heated with a downhole heater in the production well at the heating temperature of 65 C (for subcool of about 10 C below the bubble point temperature of the produced fluid mixture containing propane). The upper darker line in FIG. 7A represents the SolOR for a comparison process, which is similar in other aspects but without using a downhole heater in the production well to heat the production zone to control the temperature in the production zone. The solvent injection pressure and injection temperature are the same in both cases. The idealized half symmetry reservoir model used to generate the simulation results shown in FIG.
7A is illustrated in FIG. 7B. The model was used to compare effects of production using a downhole heater in the production well to maintain the heating temperature in the production well at 65 C, against production without directly heating the production well and the production zone with a heater in the production well to control the temperature in the production zone. The simulated reservoir was assumed to be homogenous.
The overall SolOR of the comparison process without separate heating of the production zone was higher as compared to the process with controlled heating of the production zone.

[085] As illustrated in FIG. 7B, the simulated reservoir had a reservoir pay zone 700 and contained a shale barrier 702, which may alternatively be a baffle.
The pay zone 700 was positioned below an overburden 704 and above an underburden 706.
In the simulation model, the shale barrier 702 was positioned so that it would be in the region of the vapor chamber developed due to injection of the solvent.
Additional reservoir properties of the simulation model are listed in Table I.

Table I. Simulated Reservoir Properties PROPERTY VALUE
Formation Material McMurray Sand Initial Reservoir Temperature 1500 Initial Reservoir Pressure 3 MPa Operating (Injection) Pressure 3.2 MPa Injection Temperature 74 C
Initial Methane Fraction in Oil 20 mol%
Solvent Concentration in the Injection Fluid 100 wt%
Solvent C3H8 Electric Heater Temperature (Circulation) 260 C
Electric Heater Temperature (Normal Operation) 65 C

[086] It can be appreciated that fluid flow through or around the shale barrier 702 is slower than fluid flow through the same region without the barrier, so the fluid path through the shale barrier is an inefficient fluid path. When an inefficient fluid path exists in the pay zone, more energy or heat is required to overcome the barrier. One possible way to meet such increased heat demand is to inject more solvent than otherwise needed. However, because the latent heat of solvents is relatively low compared to steam, utilizing more solvent to provide the required heat energy is not efficient. Utilizing a heater in the production well to separately heat the production zone and control the temperature in the production zone may provide more efficient heating.

[087] The representative simulation results shown in FIG. 7A indicate that the use of the heater to heat the production zone during oil production increased production efficiency by about 7%. It is expected that a further increase of production efficiency may be obtained in actual reservoirs where the formation is significantly more heterogeneous and has more shale barriers/baffles than in the simulated reservoir shown in Fig. 7B.

[088] The present inventors have further recognized that it is less efficient to heat the solvent in the production zone to a temperature above the bubble point of the solvent in the fluid mixture to be produced, as compared to subcool heating where the heating temperature is maintained below the bubble point temperature. FIG. 7C
shows the cumulative heater energy intensities for different heating strategies or regimes, including subcool heating to a subcool temperature of 65 C (i.e. 10 C below the bubble point of propane), and overheating to temperatures of 85 C (i.e. 10 C
above the bubble point of propane) and 155 C (i.e. 80 C above the bubble point of propane), based on unit oil production. At the heating temperature of 85 C, propane in the production well and the production zone is partially re-vaporized. At the heating temperature of 155 C, propane in the production well and the production zone is completely or nearly completely re-vaporized. FIG. 7C shows that for the same amount of oil production, overheating requires more heat energy than subcool heating.
Even when propane (the solvent) is only partially re-vaporized at 85 C, the required heat energy is about double (twice of) the heat energy required for subcool heating at 65 C
where there is no or little re-vaporization. Heating to 155 C (complete re-vaporization) requires more than 3 times the heat energy, compared to subcool heating at 65 C to produce the same amount of oil. These simulation results indicate that overheating is not as efficient as subcool heating the solvent in the production zone during oil production. This effect may be understandable in view of FIG. 6B, as in the case of partial re-vaporization of the solvent, the oil mobility may be increased due to both temperature increase and solvent diluting effects (some liquid solvent is still dissolved in the fluid mixture in the formation), but in the case of complete re-vaporization, the oil mobility increase comes mainly from temperature increase.

[089] The data shown in FIGS. 6A to 6C and FIGS. 7A and 7C were generated using solvent partition coefficients (k values) in bitumen, solvent and bitumen viscosities as functions of temperature and pressure, and a log-linear mixing rule for bitumen saturated viscosities (with solvent). The simulation algorithm was configured to calculate expected bitumen viscosity at the given temperature and pressure.

[090] In a different embodiment, butane may be selected as the solvent, and the operation parameters and conditions may be selected based on the approach described above with regard to propane, and in view of the data shown in FIG.
6C.

[091] In view of the foregoing description of example embodiments, a skilled person will appreciate the working principles of the present disclosure, which is in no way bound to the example embodiments set out above or below. The foregoing description will now be supplemented to elucidate other aspects and embodiments of the present disclosure.

[092] For instance, in different embodiments, different solvents may be used as a solvent in one or more selected stages of the recovery process. Example candidates for suitable solvents may include, for example, the following materials, and may be selected based on factors including the factors discussed below.

[093] Some factors to be considered for selecting the solvent include the reservoir pressure, maximum operating pressure (may be dictated by local regulatory requirement), solvent solubility, solvent cost and availability, solvent-rock interaction properties, capital expenditure (capex) constraints, possible solvent losses, and other factors.

[094] Generally, an operator may not be able to change the reservoir pressure and the maximum permissible operating pressure, and may need to work within these constraints. For example, in a shallow reservoir with a regulatory constraint that the operating pressure should not be significantly above the initial reservoir pressure, lighter hydrocarbon solvents such as propane may be used.

[095] As an illustrative example, assume that the initial reservoir pressure is 0.6 MPa and the upper limit on operating pressure is 1.0 MPa, from Fig. 6B, it can be expected that propane may not be a viable solvent due to low production performance at these conditions when propane is used as the solvent in a solvent-based recovery process. However, if butane is used as the solvent, reasonable production rates can still be expected at the pressure of 1 MPa or even less (see FIG. 6C).

[096] At a given operating pressure, the solvent injection temperature may be selected to match the highest mobility point in curves such as those shown in Fig. 6B
and 6C, for propane and butane, respectively.

[097] Among solvents which can work within the same operating conditions (pressure and temperature), the solvent that provides the highest oil mobility within the reservoir operating ranges may be selected and may be expected to provide better production performance than other solvents in the group. Alternatively, the solvent associated with the lowest operating temperature may be selected, such as when it is desirable to reduce energy consumption or to lower green-house gas (GHG) emissions. For example, at an operating pressure of 3 MPa and based on the data in FIGS. 6B and 6C, selecting butane may provide better oil production rates than propane, while selecting propane may reduce energy requirements and GHG
emissions compared to butane.

[098] A person of skill in the art may also appreciate that objective functions (used in optimization) may be formulated by combining maximizing oil production rates and minimizing energy requirements and GHG emissions, with a selected weight for each objective.

[099] Solvent cost and availability are economic factors that can change and are mainly driven by demand and supply in the market. However, such economic factors should also be considered along with other factors including technical factors.
Economic considerations may be balanced against technical advantages or disadvantages of selecting a particular solvent.

[100] Hydrocarbon solvents, as organic solvents, do not generally interact with the mineral rocks present in the reservoir, and may be used. However, non-hydrocarbon solvents may also be used. When selecting a non-hydrocarbon solvent for use in a recovery process as described herein, one should consider the possible interaction between the particular solvent and the rock matrix in the reservoir. If the particular solvent would interact deleteriously with the rock matrix, it should not be used. For example, carbon dioxide (CO2) may not be a good solvent for carbonate reservoirs, since CO2 can interact with the rock matrix to form calcium carbonate (CaCO3), which can precipitate and potentially block reservoir pores, thus limiting or preventing fluid flow in the reservoir and negatively affecting oil production.

[101] The costs of obtaining and handling solvent should also be considered.
On a balanced approach considering both economic and technical factors, in some cases a technically less optimal solvent (such as according to the type of technical data shown in FIGS. 6B and 6C) may be selected over the technically optimal solvent.

[102] As another example, to reduce solvent residue (trapped solvent) in the reservoir formation (particularly before the blowdown phase or stage), heavier solvents may be selected as they are less likely to be trapped. However, heavier solvents tend to be more expensive. Thus, a detailed analysis may be required to determine the actual overall costs for selecting a heavier solvent over another lighter solvent.

[103] In some embodiments, a mixture of solvents, such as propane and butane, may be injected, which may provide some advantages over using a single solvent. For example, the mixture may be selected to optimize a combined objective function of oil production rate and heater energy intensity. An example of such a combined objective function is the net present value (NPV) for a proposed process, which may take into account the amount of oil produced, the capital and operating costs required for the production, and carbon tax savings from possible GHG
emission reductions.

[104] As a skilled person in the art will appreciate, in a liquid mixture containing multiple solvents, the bubble point condition of the liquid mixture is different from the bubble point condition of a mixture containing only one of the solvents.

[105] The candidate solvent should be suitable for dissolving at least one of the viscous hydrocarbons in the reservoir 100, such that it can function as a diluent for the hydrocarbons. Possible solvents may include non-polar solvents such as C3-C15 hydrocarbons, such as a C3, C4, C5, C6 or C7 alkane. In some embodiments, the solvent may be propane, iso-butane, n-butane, pentane, hexane, heptane, octane or a combination thereof. Cyclohexane, 2,2-dimethylpentane, 2,2,4-trimethylpentane, or combinations thereof may also be suitable solvents alone or in combination with other non-polar solvents. Other possible solvents may include polar solvents. Polar solvents may include one or more of the following functional groups: an ether group, an epoxide group, a carboxylic acid group, an aldehyde group, a ketone group, an anhydride group, an ester group, an alcohol group, an amine group, and the like as disclosed in CA 1,887,405, which is incorporated by reference herein. Other possible solvents may be multi-component solvents such as natural gas liquids (NGLs), gas condensates, naphtha, diesel, other diluents, or combinations thereof.

[106] Not all solvents will work under all conditions, as would be understood by the skilled person. The solvent thus should be carefully selected for given reservoir conditions and for given overall production objectives. Some properties of the solvent may be readily recognized by a person skilled in the art. For example, the skilled person may be able to select a solvent that is vaporizable under given injection conditions (temperature and pressure) such that it can be injected into the reservoir 100 in the gas (vapor) phase and so that it can substantially remain in the vapor phase until it reaches the interface region in the vapor chamber 106. In this regard, heavier solvents, such as C8-C15 hydrocarbons, may not be suitable under some reservoir conditions. If heavier solvents are desirable under such conditions, they may be combined with another lighter solvent to form a solvent mixture. The skilled person may also be able to recognize solvents that are condensable under given temperature and pressure conditions. In this regard, non-condensable solvent gases (under reservoir conditions), such as methane and ethane, are not suitable solvents for embodiments disclosed herein.

[107] In selecting a suitable solvent for use, the skilled person may be guided, by initially determining the pressure and temperature conditions of the particular reservoir. Typically, injection pressures and temperatures are also subject to limitations set by regulatory bodies. The skilled person may select an injection pressure/temperature at a point which is at or near the upper pressure/temperature limit for the particular conditions in order to obtain maximum solvent diffusivity and to broaden the choice of solvents for use. Once the initial temperature and pressure conditions are set, the choice of potential solvents may be determined based on the guidance provided in this disclosure, and may be additionally based on routine calculation, routine experimentation or routine simulation and analysis of solvent behaviour and properties in a given reservoir composition.

[108] In selecting a suitable solvent, the skilled person may also be guided by the solvent-crude hydrocarbon miscibility profiles for the solvents that meet the pressure/temperature requirements set out above. Solvent-crude hydrocarbon miscibility profiles for a wide array of solvents are known, as discussed in H.
Nouroozieh, M Kariznovi and J. Abedi, "Experimental and modeling studies of phase behavior for propane/Athabasca bitumen mixtures," Journal of Fluid Phase Equilibria, 397 (2015) 37-43, the entire contents of which are incorporated by reference herein. In general, the skilled person may select a solvent which has a suitable solvent-crude hydrocarbon mixing coefficient, such that it will serve to mobilize hydrocarbons within the reservoir 100 during the development and expansion of the vapor chamber 106.
For this reason, highly polar solvents may not be appropriate under some reservoir conditions. Likewise, the skilled person may select a solvent which has a suitable solvent-asphaltene miscibility (or precipitation) coefficient. As different solvents have different solvent-asphaltene miscibility coefficients, the choice of the solvent may affect the selection of the lower temperature threshold for the production zone 108.
In order to select an appropriate solvent for a particular set of reservoir conditions, the skilled person may also rely on the teachings in this disclosure, in combination with routine calculation, routine experimentation, or routine simulation related to solvent-crude hydrocarbon miscibility profiles, or solvent-asphaltene miscibility profiles.

[109] In selecting a suitable solvent, the skilled person may be further guided by the solvent bubble point in the fluid mixture in the production zone under the reservoir operating conditions. As noted, to avoid excess heating which is non-productive or less efficient, substantial solvent re-vaporization within the production zone 108 should be prevented. Further, solvent re-vaporization may increase the viscosity of the liquid mixture in which the solvent acts as a diluent.
Solvents which substantially evaporate or remain substantially in the vapor phase at a very low temperature, such as below about 50 to 60 C, may not be suitable, because if such solvents were used, the production zone would need to be maintained at even lower temperatures, and the oil mobility at these lower temperatures would be too low to allow efficient production. At such low temperatures, other potential problems may arise which may negatively affect the production process, such as hydrate formation or the like.

[110] In selecting a suitable solvent, the skilled person may be additionally guided by additional factors such as solvent cost, solvent recoverability, solvent toxicity, and solvent recyclability. A skilled person can weigh these exemplary additional factors when selecting an appropriate solvent without requiring undue experimentation and without requiring inventive ingenuity.

[111] Other variations of the example embodiments are also possible. For instance, selected embodiments of the present disclosure may employ alternative well configurations.

[112] For example, in some embodiments, a branched well may be conveniently used to improve solvent dispersion and more uniform heating of the pay zone. Branched wells may also be helpful in stratified reservoirs where different pay zones or regions are separated by impermissible or semi-impermissible barriers, in low permeability reservoirs, or in reservoirs with a lean pay zone. In such reservoirs, branched wells such as multilateral or uptrack well configurations may increase the extent to which both heat and solvent can be distributed into the reservoir.
Some example branched-well configurations are shown in FIGS. 8A to 8E.

[113] FIG. 8A illustrates a branched well configuration 800 sometimes referred to as "fishbone" wells, which may be particularly useful in a lean pay zone.

[114] The fishbone well configuration 800 may include a plurality of so-called "ribs" 802 (sometimes referred to as side tracks, side wells, or laterals) extending from the so-called main "spine" 804 of the branched well. The main spine 804 may include a generally horizontal wellbore. The ribs 802 may be cased and lined and completed as well 120 or 140, and they may be extending in a horizontal plane or an inclined plane.
The ribs 802 may be evenly spaced along the spine 804 of the branched well 800, and the ribs 802 may be of an equal length or of varied lengths.

[115] FIG. 8B illustrates a branched well configuration 810 with opposing branched wellbores 812.

[116] FIG. 8C illustrates a branched well configuration 820 with stacked wellbores 822, which may be particularly useful in reservoirs having horizontally separated pay zones.

[117] FIG. 8D illustrates a branched well configuration 830 with forked wellbores 832.

[118] FIG. 8E illustrates a branched well configuration 840 with herringbone wellbores 842.

[119] FIG. 8F illustrates a branched well configuration 850, where an injector 852 has an uptrack wellbore 854, and two fishbone wellbores 856; and a producer 858 having a branched wellbore, with two fishbone wellbores 859. The uptrack wellbore 854 extends upwards from a horizontal wellbore section of the injector 852 and passes through a shale barrier 860 to provide the solvent and heat into the pay zone above the shale barrier 860.

[120] Shale barrier 860 may be substantially impermeable to the solvent and other fluids in the reservoir. Such impermeable barriers can limit production of hydrocarbons. For instance, they can limit growth of the vapor chamber in the pay zone(s), particularly at an early stage of vapor chamber development in the lower pay zone as illustrated in FIG. 8F. In order to access the secondary pay zone above the barrier 860, the uptrack well 854 may extend from the injector 852 into to the second pay zone through the shale barrier 860. This wellbore through the barrier 860 can also create a pressure sink through the barrier 860 thus allowing the solvent to diffuse into the secondary pay zone above the barrier 860 and to mobilize viscous hydrocarbons therein. The uptrack wellbore 854 may also provide a pathway for mobilized hydrocarbons in the upper pay zone to drain towards the producer 856 including wellbores 859. A secondary vapor chamber may also be formed above the shale barrier 850.

[121] As illustrated, branched wells may include a single branch point and two or more wellbores, or multiple branch points and any number of wellbores.

[122] When branched wells are provided, each wellbore in the branched wells may be provided with a downhole heater and a temperature sensor. As can be appreciated, the branched wells with down hole heaters may be used to improve heating of the pay zone or the reservoir, such as providing more uniform heating, and providing heating to specifically selected regions in the pay zone or reservoir. Branched wells may also provide better temperature control in the vapor chamber to limit the ARB
phase growth in the entire fluid path in the vapor chamber.

[123] In a branched well configuration, a plurality of heaters and temperature sensors may be provided throughout the various branches of the branched wellbores.

[124] For example, in the fishbone well configuration 800, a plurality of heaters (not shown) may be provided and each rib 802 may include a downhole heater (not separately shown). The main spine 804 may also include a downhole heater.
Likewise, a plurality of temperature sensors may be provided in the ribs 802 and the spine 804.
Each rib 802 or the spine 804 may include a single heater and a single temperature sensor, or multiple heaters or sensors. In such embodiments, the temperature in the production zone may be controlled by applying heat to one or more specifically selected ribs 802 in response to temperature measurement data provided by the temperature sensors. With such well configurations, the temperature of the production zone may be better controlled.

[125] Heaters and temperature sensors may be similarly provided in other branched well configurations.

[126] Branched wells may also be used to reach otherwise bypassed regions between two adjacent pairs of injection and production wells.

[127] Alternatively, an infill well or a well provided using WEDGE WELLTM
technology may be used to produce hydrocarbons in the bypassed region.

[128] For example, FIG. 9A illustrates two adjacent well pairs, 920a/940a and 920b/940b, and a bypassed region 950 between the two pairs of wells after some time of hydrocarbon production where the respective vapor chambers 906a and 906b have merged. It may be difficult to produce hydrocarbons from the bypassed region using production wells 940a and 940b. However, as illustrated in FIG. 9B, if an additional infill well 960 is provided in the bypassed region 950, hydrocarbons in the bypassed region may be more conveniently mobilized and produced. The infill well 960 may be configured and completed similar to production well 140. An infill well may be provided using WEDGE WELLTM technology. For example, example wells are described in CA 2,591,498, the entire contents of which are incorporated herein by reference.

[129] In FIGS. 9A and 9B, injection wells 920a and 920b may be similarly completed and operated as injection well 120; and production wells 940a and940b may be similarly completed and operated as production well 140. The respective associated production zones are indicated with dash lines, and labeled as zones 908a, 908b and 908c respectively.

[130] As can be appreciated, an infill well or WEDGE WELLTM technology may include a single wellbore as depicted in FIG. 9B, or may include branched wellbores.

[131] Selected embodiments of the present disclosure use other alternative well configurations. For example, alternative configurations may include vertical wells, slanted wells or a combination thereof such as those used in bottom-up solvent-aided processes. As used herein, a vertical well is a well that extends downward vertically or substantially vertically. As used herein, a slanted well is one that extends downward at a slanted angle and is neither vertical nor horizontal. Suitable wells may have one or more sections or portions that are vertical or horizontal. Different portions of the wells may also extend at different angles. Vertical wells and slanted wells are further described in Canadian Patent Application No. 2,833,068, the entire contents of which are incorporated herein by reference.

[132] As can be appreciated, the temperatures under original (natural) conditions in different reservoirs may vary. For example, the original temperature may be from about 7 C to about 22 C, from about 9 C to about 15 C, or from about to about 13 C, depending on the location of the reservoirs and the time. The native pressures may also vary in different reservoirs. For example, the native pressure in a reservoir may be from about 0.1 to about 4 MPa, from about 0.5 to about 3.5 MPa, or from about 1 to about 3 MPa. The pressure and temperature profiles in a reservoir may also vary depending on the location and other characteristics of the reservoir.

[133] The types of viscous hydrocarbons within different reservoirs may also vary. Depending on the in-situ density and viscosity of the viscous hydrocarbons, the viscous hydrocarbons may comprise, for example, a combination of heavy oil, extra heavy oil and bitumen. Heavy oil, for example, may be defined as any liquid petroleum hydrocarbon having an American Petroleum Institute (API) Gravity of less than about 200 and a viscosity greater than 1,000 mPa-s. Extra heavy oil, for example, may be defined as having a viscosity of over 10,000 mPa-s and about 10 API Gravity.
The API
Gravity of bitumen ranges from about 12 to about 70 and the viscosity is greater than about 100,000 mPa-s. For example, the bitumen in a reservoir may have an API
of 10 and a viscosity of about 110,000 mPa.s. API Gravity is also referred to as API
for brevity.

[134] The recovery processes described herein are not limited to any particular type of reservoirs or hydrocarbon compositions in the reservoir.

[135] As noted earlier, in selected embodiments, the injection well 120 may be completed with, for example, a perforated or slotted liner along the horizontal section of the well. The production well 140 may also be completed with a slotted liner along the horizontal section of the well. In other embodiments, the wells may be completed differently as described above. For example, the injection or production well may include perforations, slotted liners, screens, oufflow control devices (injection well), inflow control devices (production well), or a combination thereof as known to one skilled in the art.

[136] In selected embodiments, one or both of the wells 120 and 140 may be provided with standard completion devices and equipment used in a typical solvent aided process, or used in wells that are suitable for use in a SAGD process with suitable modifications for solvent injection. Such devices and equipment may include flow control devices (FCDs), temperature measuring devices such as distributed temperature sensing (DTS) devices or fibre optic measurement or control components, or the like.

[137] In selected embodiments, the injection well 120 may be vertically spaced from the production well 140 by a distance within a range of from 3m to 10 m, or from 4 m to 6 m. These distances are exemplary and may be varied to optimize the operation performance. A skilled person could select the well spacing by considering relevant processing parameters such as the temperature and pressure of the reservoir 100 and the mobility of the viscous hydrocarbons present therein. In selected embodiments, the length of the horizontal sections of the wells 120 and 140 may vary.
For example, in some embodiments, the horizontal sections of the wells 120 and may have a length from 200 m to 1400 m, or from 600 m to 1000 m. The injection well 120 and the production well 140 may be configured and completed in any suitable manner so long as the wells are suitable for injection of the selected solvent and production of a fluid from the reservoir as described herein. In some embodiments, the terminal sections of the wells 120 and 140 may be substantially parallel to one another.
A person of skill in the art will appreciate that while there may be some variation in the vertical or lateral trajectory of the wells 120 and 140 (causing increased or decreased separation there between), such wells for the purpose of this application will still be considered substantially horizontal and substantially parallel to one another.

[138] In selected embodiments, the surface facility 220 may have a supply line (not shown) connected to an injection fluid source for supplying the solvent.
In selected embodiments, one or more additional supply lines may be provided for supplying other fluids, additives or the like (not shown) for co-injection with the solvent.
Each supply line may be connected to an appropriate source of supply, which may include, for example, 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 the injection well 120.

[139] In selected embodiments, the surface facility 240 may include a fluid transport pipeline (not shown) for conveying the produced fluids to a downstream facility (not shown) for processing or treatment. The surface facility 240 may also include additional optional equipment for producing a fluid from the production well 140, as can be understood by one skilled in the art.

[140] In selected embodiments, other necessary or optional surface facilities (not shown) may also be provided, as can be understood by one skilled in the art. For example, the surface facilities 220 and 240 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 solvent recycling facility, and a control or data processing system for controlling production / operation or for processing collected operational data.

[141] Example heaters disclosed in CA 2,304,938 may be used as downhole heaters in selected embodiments as described herein.

[142] The heaters 132 and 152 may include an electric heater. An electric heater may include an insulated conductor. The conductor may be elongated, such as in the form of a wire or a rod, and may be coiled. The conductor may be disposed and enclosed in a conduit.

[143] A heater may also include a suitable heating system.

[144] For example, a heating system may generate heat by burning a fuel external to or in a formation. The heating system may also include surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors. In selected embodiments, heat provided to or generated in one or more heaters may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer medium that directly or indirectly heats the formation. It is to be understood that one or more heaters that are applying heat to a formation may use different sources of energy.
Thus, for example, for a given formation some heaters may supply heat from electric heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources (for example, chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A
chemical reaction may include an exothermic reaction (for example, an oxidation reaction). A
heater may also include a heater that provides heat to a zone proximate to or surrounding a heating location such as a heater well. The selection of an appropriate heater is within the purview of those skilled in the art. Such a selection is typically made having regard to, i.e., the output, efficiency, durability, control and configuration of the heater. The heater may be selected based on how far into the reservoir heat from the heater is expected to penetrate.

[145] In some selected embodiments, one or more of the heaters 132 and 152 may be powered to provide continuous desired or optimal heating. In other selected embodiments, one or more of the heaters 132 and 152 may be operated to provide heating intermittently. Intermittent heating involves a first period of heating at a lower level, and a second period of heating at a higher level. The first and second heating levels may alternate and cyclically repeated. The first time period may correspond to a period of peak usage in the power grid that supplies heating power to the heaters, and the second time period may correspond to an off-peak period in the power grid.
Thus the cycle of intermittent heating of the production zone may correspond to the cycle of peak and off-peak usage in the power grid.

[146] For example, heating may be reduced during a period of peak-demand for electrical power as illustrated in FIG. 10, which shows a schematic representation of the power usage profiles of the heaters and the power grid. In general, the heating power applied in the heater 152 may have a profile that tracks or matches the peak and off-peak usage in the power source (a power grid in this example). Such intermittent heating may be more economical and, if scheduled appropriately, may not negatively affect the production performance significantly. The process may be, for example operated intermittently so as to reduce or minimize the operating expenses (OPEX) associated with electricity usage for heating the production zone. For example, the electricity cost to the operator of the recovery process may be substantially reduced during the off-peak period, as compared to the peak period. However, cyclically alternating between increased heating and reduced heating at 24 hour cycles may not significantly affect the average temperature in the production zone or the pay zone in general. That is, the temperature fluctuation in the reservoir, particularly in the production zone, may be limited and may not exceed or fall outside the selected temperature range (e.g. the selected lower and upper threshold temperatures).
Thus, factors for selecting the varied heating powers may include the electricity costs at different time periods during a day or different days of the week. The reservoir pressure, reservoir temperature, injection rates, and production rates may also influence the optimizing of field operations, and may be included in the consideration.
The heater(s) may be powered in any suitable manner to maintain the temperature in the production zone 108 between the upper threshold and the lower threshold.

[147] In various embodiments, the start-up sub-stage S402 may last for a period of about 1 to about 12 months, or about 3 to about 9 months.

[148] In selected embodiments, other preheating measures may be employed in the start-up sub-stage S402. Such measures may include, for example, the application of geo-mechanical techniques or the use of one or more microorganisms to increase overall fluid mobility in a near-wellbore region.

[149] In selected embodiments, the time period for the start-up sub-stage may vary. For example, the sub-stage S404 may last for a period of about 1 to about 6 months, or about 2 to about 4 months.

[150] Instead of or in addition to solvents, other suitable injection fluids such as steam, diesel, natural gas liquids, gas condensate, C3-C15 hydrocarbons, non-condensable gases (NCGs), or combinations thereof may be injected during the start-up stage S402 or S404, or both sub-stages. While not all of these fluids solvents will work under all conditions, a suitable fluid for use in the start-up stages S402 or S404 may be selected by a person skilled in the art having regard to the particular reservoir conditions (e.g. temperature, pressure, composition), in view of the guidance provided in this disclosure. NCGs include, but are not limited to air, nitrogen, carbon dioxide, methane, natural gas, other light hydrocarbons, or a combination thereof. The NCG
may facilitate maintaining at least a portion of the solvent in the vapor phase due to a partial pressure effect, allowing the solvent to travel further before completely condensing.

[151] The injection temperature and injection pressure for any given injection fluid in the start-up stages may also vary. Possible injection temperatures may be, for example, from the ambient temperature to about 250 C or about 290 C.
Possible injection pressures may be from about 2 MPa to about 7 MPa.

[152] In selected embodiments, the time period of the production stage S406 may vary. For example, it may last for a period of about 1 year to about 10 years.
Likewise, the injection temperature and injection pressure during the production stage S406 may vary over time and may vary in different applications. The injection temperatures may be, for example, from the ambient temperature to about 250 C
or about 290 C, depending on the solvent selected and the reservoir conditions.
The injection pressures may be from about 2 MPa to about 7 MPa.

[153] The wells 120 and 140 may be positioned towards the bottom of the pay zone 102, which may be more efficient as the heated solvent vapor may tend to rise up in the vapor chamber 106. The heater 132 may be configured and operated to provide more heating power, as it may be used to heat a larger volume of the pay zone than the heater 152. For example, the power ratio between the heaters 132 and may be 60:40, 70:30, or 80:20.

[154] In select embodiments, the heater 152 may include a plurality of heaters positioned in various configurations throughout the horizontal section of the production well 140. For example, two or more heaters may be positioned at equal spacing along the horizontal sectional section of the production well 140, and the two or more heaters may be independently controlled. In such a configuration, heat may be applied to a first region of the production well 140, while a second region of the production well 140 is not heated. This location specific heating may be applied to account for, for example, heterogeneity in the production zone 108.

[155] In select embodiments, the upper temperature threshold and the lower temperature threshold of the production zone 108 may vary during the production stage S406. The lower threshold may be selected to manage and control asphaltene phase equilibria such as precipitation, flocculation, and agglomeration, in order to limit the formation or growth of an asphaltene-rich bitumen (ARB) phase in the liquid mixture to be produced, and to limit the extent of asphaltene deposition in the production zone.
The skilled person may select the lower threshold based on the teachings of this specification, routine calculations, routine experimentation and routine simulation. The upper threshold may be selected to prevent excessive re-vaporization of the solvent in the liquid mixture, since solvent re-vaporization may reduce the mobility of the liquid mixture. The skilled person may select the upper threshold based on the teachings of this specification, routine calculations, routine experimentation and routine simulation.

[156] In selected embodiments, the time period of the blowdown stage S408 may vary. For example, the blowdown stage S408 may last for a period of about month to about 12 months. In selected embodiments, the injected fluid, injection temperature and pressure used during the blown-down stage S408 may vary.
Possible fluids for blowdown may include methane, ethane, propane, N2, CO2 or the like.

Possible blowdown pressures may range from 2 MPa to 7 MPa, and possible blowdown temperatures may range from ambient temperature to about 250 C or about 290 C.

[157] As discussed earlier with respect to FIG. 5, the temperatures of the various regions of the reservoir 100 generally decrease as the distance from the injection well 120 and the production well 140 becomes longer, towards the interface regions of the vapor chamber 106. In the interface region, the temperature may decrease quickly, and the temperature just outside the vapor chamber may be close to or at the reservoir native temperature. Thus, the temperature of the injected solvent may be the highest at the injection well 120, and may drop modestly as the solvent travels through the central region of the vapor chamber 106. In select embodiments, the injection temperature may be between 50 C and 150 C, and the injected solvent may cool down to a temperature between about 45 C and to about 145 C is it passes through the vapor chamber 106. As the solvent vapor contacts materials within the cooler interface region its temperature may decrease more quickly, and the solvent may condense and mix with hydrocarbons in the interface region to form a liquid mixture containing the solvent, mobilized hydrocarbons and asphaltenes. In select embodiments the temperature at the interface region may be between 25 C and oc.

[158] In different embodiments, the process parameters may be selected to improve overall process efficiency, with an aim to recover the maximum amount of oil from the reservoir. The process may also be designed to reduce the amount of the solvent used, or to recapture injected solvent quickly. Convenient recycling and re-use of the solvent may be a factor, but reducing or avoiding solvent recycling may be beneficial in some embodiments as recycling a solvent may not be as efficient as for recycling steam, since the gravity is not as efficient for driving solvent drainage as compared to driving steam drainage.

[159] Another factor to consider is overall reduced energy usage. Such factor may be assessed using a net energy intensity (El). The El for a given process may be assessed by a person skilled in the art based on known methods and tools.

[160] For example, some analysis has shown that substantial energy savings can be obtained for a given recovery factor (RF) (such as at 70% RF) with an embodiment of the present disclosure in a homogenous reservoir, as compared to other processes. In particular, using the El of a typical SAGD process as the base line, using propane according to the present disclosure may reduce the El by as much as 75%, and using butane may reduce the El by as much as 45%, at 3 MPa. In other words, propane may reduce the El to about 1/14 of the SAGD value, butane may reduce the El to about 1/8 of the SAGD value. Pentane may reduce the El to about 1/4 of the SAGD value. The reduced effect of butane as compared to propane is expected to be largely due to the higher heating temperature permitted in the butane process (see FIGS. 6B and 6C).

[161] The process parameters may be selected to reduce or minimize the amount or volume of injected solvent without sacrificing the production rate, production efficiency, or recovery factor.

[162] It is also noted that to upgrade bitumen in situ, some asphaltene precipitation will occur. Generally, the more asphaltenes precipitate, the more the bitumen is upgraded. Asphaltenes can plug up reservoir pores and wellbore liners, so it may be desirable to control asphaltene production in a solvent driven process.

Controlled heating of the production zone as disclosed herein provides a control mechanism to control asphaltene precipitation and production. In an ideal situation, the optimal heating temperature set for a heater in the production well would provide maximum upgrading of the produced oil without, or with only minimal, deleterious asphaltene precipitation in the production zone.

[163] In practice, the oil production rate may be monitored in real time as a function of the asphaltene content in the produced oil, or as a function of the API of the produced oil (API value is indicative of the degree of oil upgrading), while lowering the temperature in the production well, and the heating temperature may be selected as the temperature at which the oil production rate is maximized or an overall production performance metric is optimized. Normally, it is desirable to increase both the oil production rate and the API of the produced oil, which may result from limited and controlled asphaltene precipitation. However, when the oil production rate starts to decrease while the API of the produced oil is still increasing, the asphaltene precipitation in the production zone may be considered to have become deleterious, as the asphaltene precipitation may have possibly led to plugging of the pores or wellbore liners.

[164] Fig. 11 illustrates an example correlation between the oil production rate (Oil Rate) and the API of the produced oil (Oil API). The Oil API increases as the heating temperature in the production well is increased. As can be seen, the oil production rate initially increases as the Oil API increases and then starts to fall at an inflexion point. The corresponding heating temperature at the inflexion point may represent an optimal operating condition (temperature) for controlling the heater(s) in the production well. The asphaltene content in the produced oil may be measured in a laboratory using the SARA analysis. The Oil API may be determined by measuring the density of the produced oil, as can be understood by those skilled in the art.

[165] Tests were performed which indicated that using propane and butane as the solvent, the produced oil could be upgraded by about 30%.

[166] An oil extraction lab test involving soaking an oil core (used as a reservoir model) with butane (no steam) at a temperature of 138 C and a pressure of 3.172 MPa over a period of about 30 h indicated that percent oil saturation (So) in the core was reduced from 88% to 16%. In comparison, soaking an oil core with de-ionized (DI) water at a temperature of 236 C and a pressure of 3.137 MPa over the same time period of about 30 h resulted in So in the core only being reduced from 88% to 67%.
Likewise, oil recovery of 83.63% of the original oil in place (00IP) was significantly higher with butane-only extraction compared to DI water, which yielded an oil recovery of just 24.03% of 00IP. Relevant data for this test is listed in Table II.

Table II. Solvent (Butane) Oil Extraction Results Butane DI Water Solvent:Steam Ratio 100:0 0:100 Core Weight (g) 121.4 120.36 Oil in Core (g) 18.22 18.05 Initial So (%) 88 88 Pressure of Operation (MPa) 3.172 3.137 Temperature of Operation ( C) 138 236 Mass Solvent Added (g) 115 0 Mass Water Added (g) 2 115 Oil Extracted (g) 15.23 4.34 Oil Recovery (% 00IP) 83.63 24.03 Final So (13/0) 16 67 Time (h) 30 30

[167] FIG. 12 compares the energy intensity (El) at 70% recovery factor (RE) between a SAGD process (cSOR=3.2) and a propane-based recovery process (cSOR=0.2), with a reduction in El by 16 times (cSOR = cumulative solvent to oil ratio).
The comparison is for a homogeneous reservoir.

[168] FIG. 13 shows the relative changes of temperature, oil saturation in the formation (So %), and solvent saturation (propane concentration %) over time in a propane-based recovery process at temperatures below 100 C. FIG. 14 shows comparison data with respect to FIG. 13 from a comparison process with co-injection of steam and propane at temperatures up to about 240 C.

[169] CONCLUDING REMARKS

[170] 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.

[171] 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.

[172] 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.

[173] 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.

[174] 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 producing hydrocarbons from a subterranean reservoir, comprising:
producing a liquid mixture from the reservoir, the liquid mixture comprising an injected solvent, hydrocarbons mobilized by the injected solvent, and asphaltenes; and heating the liquid mixture in a production zone, before the liquid mixture is produced, to reduce asphaltene precipitation and deposition in the production zone, at a temperature below a bubble point temperature of the solvent in the liquid mixture under a reservoir pressure.

2. A method of producing hydrocarbons from a subterranean reservoir, comprising:
producing a liquid mixture from the reservoir, the liquid mixture comprising an injected solvent, hydrocarbons mobilized by the injected solvent, and asphaltenes; and heating the liquid mixture in a production zone, before the liquid mixture is produced, to limit growth of an asphaltene-rich phase in the liquid mixture, at a heating temperature below a bubble point temperature of the solvent in the liquid mixture under a reservoir pressure.

3. The method of claim 1 or claim 2, wherein the liquid mixture is produced through a production well, and the production zone is heated with a downhole heater in the production well.

4. The method of claim 3, wherein the downhole heater comprises an electric heater.

5. The method of claim 4, wherein the electric heater has an operating frequency in the range of 1 Hz to 30 kHz, or is operable in a direct-current mode.

6. The method of any one of claims 3 to 5, wherein the solvent is injected into the reservoir through an injection well and the production well comprises a well positioned below the injection well.

7. The method of claim 6, wherein the injection well comprises a generally horizontal wellbore and a branched wellbore extending upwards from the horizontal wellbore.

8. The method of any one of claims 3 to 7, wherein the production well comprises a branched wellbore.

9. The method of any one of claims 3 to 8, wherein the production well comprises an infill well positioned in a bypassed region between first and second pairs of injection and production wells.

10.The method of any one of claims 1 to 9, wherein the heating temperature is above 50 °C.

11.The method of any one of claims 1 to 10, wherein the heating temperature is at least 5 °C below the bubble point temperature.

12. The method of claim 11, wherein the heating temperature is at least 15 °C
below the bubble point temperature.

13.The method of any one of claims 1 to 12, wherein the heating temperature is between 50 °C and 70 °C.

14.The method of any one of claims 1 to 13, wherein the solvent comprises propane.

15.The method of any one of claims 1 to 14, wherein the solvent comprises a non-polar solvent.

16. The method of claim 15, wherein the non-polar solvent comprises a C4-C15 alkane.

17. The method of claim 15, wherein the non-polar solvent comprises n-butane, isobutane, or pentane.

18.The method of any one of claims 1 to 17, wherein the produced liquid mixture comprises 1 to 30 wt% of asphaltenes.

19.The method of any one of claims 1 to 18, comprising injecting the solvent into the reservoir.

20.The method of claim 19, wherein the solvent is injected as a vapor into the reservoir.

21.The method of any one of claims 1 to 20, wherein the heating comprises intermittent heating using electrical power, wherein the heating is reduced during a period of peak-demand for electrical power.