CA3060497A1

CA3060497A1 - Producing hydrocarbons from subterranean reservoir with solvent injection at controlled solvent density

Info

Publication number: CA3060497A1
Application number: CA3060497A
Authority: CA
Inventors: Prince Azom; Amos Ben-Zvi
Original assignee: Cenovus Energy Inc
Current assignee: Cenovus Energy Inc
Priority date: 2018-11-09
Filing date: 2019-10-29
Publication date: 2020-05-09

Abstract

In a hydrocarbon recovery process, a solvent is injected into the reservoir at an injection pressure and an injection temperature selected and matched such that, the solvent has a reduced density of less than 0.5 and a second derivative of the reduced density with respect to temperature is less than 1, at the injection pressure and the injection temperature.

Description

PRODUCING HYDROCARBONS FROM SUBTERRANEAN
RESERVOIR WITH SOLVENT INJECTION AT CONTROLLED
SOLVENT DENSITY
FIELD
[0001] This disclosure relates generally to in situ hydrocarbon production with solvent injection, and particularly to methods for in situ hydrocarbon production with injection of a supercritical solvent or a gas phase solvent.
BACKGROUND

[0002] Recovery of viscous hydrocarbons from subterranean reservoirs can be facilitated by injection of a suitable solvent into the reservoir, such as propane, butane or the like. The solvent can function as a diluent for viscous hydrocarbons.
When the injected solvent is heated, it may also transfer heat to the hydrocarbons or the reservoir. Both effects can reduce the viscosity of viscous hydrocarbons and increase their mobility, thus facilitating or improving production of hydrocarbons from the reservoir.

[0003] In a solvent-based recovery process, the solvent is injected without steam during a production stage of the recovery process. In a solvent-driven recovery process, a solvent is co-injected with steam during the production stage where the amount of injected steam is less than the amount of the injected solvent.

[0004] In known solvent-based recovery processes implemented on a commercial scale, solvents were typically injected in a gas phase. It is generally considered desirable to inject the solvent at higher pressures, as the oil production rate is typically higher at a higher injection pressure. It is expected that a higher injection pressure would drive the reservoir fluid to flow faster in the reservoir. It is also expected that a higher injection pressure would allow the solvent to be injected at a higher rate and allow the solvent to condense at a higher temperature, both of which would increase the rate of mobilizing the viscous hydrocarbons in the reservoir.

[0005] It has also been previously proposed that injecting a solvent in the gas phase at a temperature above, but close to, the boiling point of the solvent at the reservoir conditions would be optimal or desirable as it would reduce energy consumption and achieve efficient production performance, as compared to injecting the solvent in the liquid phase or injecting the solvent in the gas phase but at much higher temperatures.

[0006] lmanbayev et al., in "Supercritical solvent extraction of oil sand bitumen", AIP Conference Proceedings 1879, 0500003 (2017), also disclosed experiments performed in an autoclave reactor for studying supercritical solvent extraction of bitumen from oil sand. Isopropanol and hexane were used as the solvents. For hexane, the test temperature was 255 C and the test pressure was 29.6 atm (-3.0 MPa); for isopropanol, the test temperature was 297 C and the test pressure was 54.8 atm (-5.55 MPa).

[0007] Kharutdinov et al., in "Supercritical Fluid Propane-Butane Extraction Treatment of Oil-Bearing Sands", in Theoretical Foundations of Chemical Engineering, May 2017, Vol. 51, No.3, pp. 288-294, disclosed results of an experimental study using liquid and supercritical fluid extraction to isolate hydrocarbons from oil-bearing sands. A mixture of 75 wt% propane and 25 wt%
butane was used as the extracting agent, in extraction processes carried out at temperatures of 80 C to 140 C and pressures of 5 to 10 MPa in an experimental unit.
The critical point temperature of the mixture was 386 K (-113 C) and the critical point pressure of the mixture was 4.31 MPa.

[0008] CA 2,767,874 to Meyer disclosed a proposed process for extracting and upgrading heavy hydrocarbon mixture by injecting supercritical or near-supercritical CO2 at a temperature of around the critical temperature and a pressure of around the critical pressure. The temperature in the deposit may be between 25 C to 120 C, and the pressure may be 7.4 to 30 MPa. Test results were obtained using a core flooding apparatus or in a closed stainless steel cell.

[0009] It remains desirable to improve overall production efficiency in solvent-based recovery processes and other recovery processes involving solvents, and challenges remain in providing such recovery processes for efficient and effective commercial applications.
SUMMARY

[0010] In an aspect of the present disclosure, there is provided a method of producing hydrocarbons from a subterranean reservoir, comprising injecting a solvent at an injection pressure and an injection temperature into the reservoir to mobilize viscous hydrocarbons in the reservoir, wherein the injection pressure and injection temperature are selected and matched such that, the solvent has a reduced density of less than 0.5 and a second derivative of the reduced density with respect to temperature is less than 1, at the injection pressure and the injection temperature; and producing hydrocarbons mobilized by the solvent from the reservoir.

[0011] In embodiments of the above method, a second derivative of the reduced density with respect to pressure may be less than 0.1. In an embodiment, the solvent is a supercritical solvent at the injection temperature and the injection pressure. The injection pressure may be higher than the critical point pressure of the solvent. The solvent may be propane. The injection pressure may be above 2 MPa, the injection temperature may be less than 200 C, and the density of the solvent at the injection pressure and the injection temperature may be less than 100 kg/m3. In some embodiments, the density of the solvent may be less than 50 kg/m3. The injection pressure may be above 4.3 MPa. The injection pressure may be less than 7 MPa.
The injection temperature may be less than a coking temperature of the hydrocarbons. The injection temperature may be less than 350 C. The injection pressure may be about 2 MPa and the injection temperature may be higher than 150 C. The injection pressure may be about 3 MPa, and the injection temperature may be higher than 200 C.
The injection pressure may be about 4.5 MPa, and the injection temperature may be higher than 250 C. The injection pressure may be about 5 MPa, and the injection temperature may be higher than 300 C. In some embodiments, the solvent may comprise butane, in which case the injection pressure may be above 3.8 MPa and the injection temperature may be above 200 C. The solvent may comprise a natural gas liquid.

[0012] In another aspect of the disclosure, there is disclosed a method of delivering a solvent to an interface region in a reservoir of hydrocarbons through a solvent chamber, comprising injecting the solvent into the solvent chamber in the reservoir at an injection pressure and an injection temperature selected and matched such that, at the injection pressure and the injection temperature the solvent has a reduced density of less than 0.5 in the solvent chamber before the solvent reaches the interface region, and a second derivative of the reduced density with respect to temperature is less than 1.

[0013] In a further aspect, there is provided a method of reducing solvent holdup in a solvent chamber in a reservoir of hydrocarbons, wherein a solvent is injected into the solvent chamber to assist production of hydrocarbons from the reservoir, the method comprising injecting the solvent into the solvent chamber in the reservoir at an injection pressure and an injection temperature selected and matched such that, at the injection pressure and the injection temperature the solvent has a reduced density of less than 0.5 in the solvent chamber before the solvent reaches an interface region between the solvent chamber and the reservoir, and a second derivative of the reduced density with respect to temperature is less than 1.

[0014] Other aspects, features, and embodiments of the present disclosure will become apparent to those of ordinary skill in the art upon review of the following description of specific embodiments in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS

[0015] In the figures, which illustrate, by way of example only, embodiments of the present disclosure:

[0016] FIG. 1 is a schematic side view of a hydrocarbon reservoir and a pair of wells penetrating the reservoir for recovery of hydrocarbons.

[0017] FIG. 2 is a schematic partial end view of the reservoir and wells of FIG. 1.

[0018] FIGS. 3 and 4 are line graphs illustrating density-pressure phase diagrams for propane at various temperatures.

[0019] FIGS. 5-7 are line graphs illustrating propane density dependence on temperature at various pressures.

[0020] FIG. 8 is a line graph illustrating density-pressure phase diagrams for propane at various temperatures.

[0021] FIGS. 9-12 are line graphs illustrating the propane density dependence on pressure at various temperatures.

[0022] FIGS. 13 to 15 are line graphs illustrating density-pressure phase diagrams for propane at various temperatures.

[0023] FIG. 16 is a graph illustrating simulation results of propane density distribution in a solvent chamber.

[0024] FIG. 17 is a line graph showing representative measured solvent density variation during controlled solvent injection.

[0025] FIG. 18 is a data graph illustrating the dependence of the first derivative of the reduced solvent density with respect to the reduced temperature for the data shown in FIG. 17.

DETAILED DESCRIPTION

[0026] In brief overview, the present inventors have recognized that solvent-based, or solvent-driven, hydrocarbon recovery from a subterranean reservoir can be improved by injecting a supercritical solvent at matched injection temperatures and pressures, which are selected and controlled to limit the density of the injected solvent below a selected threshold such that the injected supercritical solvent is more gas-like than liquid-like in the reservoir formation, and to limit the temperature and pressure dependence of the solvent density at the injection conditions so that slight deviation from the selected injection temperature and pressure will cause little or limited changes in the in situ solvent density.

[0027] It has been recognized by the present inventors that injecting solvents with such controlled density behavior can improve production efficiency by reducing the rate or amount of solvent injection, or the solvent-to-oil ratio, as will be further discussed below.

[0028] An illustrative embodiment of the present disclosure is described next with reference to the figures.

[0029] FIG. 1 schematically depicts a reservoir 100 having a pay zone 102 under a cap layer 103. An injection well 120 and a production well 140 are provided, which penetrate the pay zone 102 of the reservoir 100. Injection wells and productions wells are commonly referred to in the art as injectors and producers respectively.

[0030] The reservoir 100 is a subterranean or underground reservoir containing recoverable viscous hydrocarbons. At least some of the viscous hydrocarbons are immobile under native 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 native temperature in the reservoir may be between about and about 12 C, and the native pressure in the reservoir may be between about MPa and about 5 MPa. In different reservoirs, the original temperature and pressure may be different.

[0031] 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 immobile under typical native reservoir conditions.

[0032] 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 distance between the wells and the well lengths may vary in different embodiments. 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 FIG. 2.

[0033] 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.

[0034] 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 and mobilized hydrocarbons. 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.

[0035] 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.

[0036] The wells 120 and 140 may be configured and completed in a similar manner as the horizontal wells used in conventional steam-assisted gravity drainage (SAGD) processes, or vapor extraction (VAPEX) processes, with suitable modifications to inject a supercritical solvent instead of steam, and optionally to heat the production zone as will be further explained below. Wells and well configurations as disclosed in United States Provisional Patent Application Nos. 62/565,816 and 62/609,433 may also be used in an embodiment of the present disclosure. The entire contents of each one of United States Provisional Patent Application Nos.
62/565,816 and 62/609,433 are incorporated herein by reference.

[0037] For example, in selected embodiments, an injection well may be provided with a coiled tubing for injecting the solvent (and other possible injected fluids or materials), a casing, a liner assembly, and a liner hanger (all not shown).
The liner assembly may be slotted to allow injected fluids to pass through. The coiled tubing 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 (not shown) may be provided in the injection well, which may include a wire or rod coiled around the coiled tubing along a length of the horizontal section of the injection well. The heater may be an electric heater, which may be operated in the direct-current (DC) mode or in an alternating-current (AC) mode, and may be operated at an operating frequency in the range of 1 Hz to 30 kHz. A
temperature sensor (not shown) may be provided in or on the coiled tubing. The temperature sensor may include a distributed temperature sensing (DTS) device, and may include thermocouples (TC). Temperatures at multiple points along the production well, 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 and the heater may be connected to the surface control system to provide temperature signals from the sensors to the control system and to control operation of the heater.
The power and signal lines may be attached to the coiled tubing or a tubing string (not shown). Additional necessary or optional components, tools, or equipment may be installed in the injection well 120. Other sensors and devices (not shown) for measuring downhole temperature (T) and pressure (P) may also be provided in the injection well 120, such as at a heel portion of the injection well 120. The detailed constructions of the injection well 120 are not illustrated herein as they are within the knowledge of the skilled person in the art and are not particularly relevant for the purpose of the present disclosure.

[0038] The production well 140 may be similarly constructed as injection well 120, with some modifications or variations for producing a reservoir fluid as can be understood by those skilled in the art. In particular, the production well 140 may also include a coiled tubing, a casing, a slotted liner assembly, a liner hanger, a heater, and a temperature sensor (all not shown), which may be similarly constructed and configured as their counterparts in the injection well 120. The production well 140 also additionally includes a pump and a production tubing (not shown) for producing fluids entering the production well 140 through the slotted liner assembly to the surface. As in the injection well 120, signal and power lines (not shown) for the heater and temperature sensor in the production well 140 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.
However, for example, a pressure sensor may not be necessary in the production well 140 in some embodiments. The production well 140 may also be provided with a dual-heater string, four or more TCs, and a DTS fibre in the coiled tubing (all not shown).
The production tubing may be landed at the heel of the well.

[0039] In operation, a selected solvent is injected through the injection well 120 into the pay zone 102 of the reservoir 100 at selected injection temperature and injection pressure, and hydrocarbons mobilized by the injected solvent are produced from the reservoir 100 through the production well 140. The injected solvent is selected to facilitate mobilization and production of viscous hydrocarbons in the reservoir 100, and the solvent injection temperature and pressure are selected and matched to improve hydrocarbon production efficiency and effectiveness as discussed herein.

[0040] In a particular embodiment, the solvent is injected at supercritical conditions so that when the solvent is injected into the reservoir 100 at the selected injection conditions the injected solvent will be a supercritical solvent after entering into the reservoir formation.

[0041] The injection conditions include the injection temperature and the injection pressure. The "injection temperature" as used herein refers to the temperature of the solvent when the solvent is in the injection well 120 just prior to entering the reservoir 100, unless otherwise specified in a particular context. The "injection pressure" as used herein refers to the pressure in the injection well 120, which is also often referred to as the bottom-hole pressure (BHP) or downhole pressure of the well in the art.

[0042] In comparison and for clarity, the reservoir conditions refer to the temperatures and pressures in the reservoir formation. As can be appreciated, the reservoir conditions are affected and may be controlled by the injection conditions and the injection and production rates, and the local temperatures and pressures within the reservoir can vary as will be further discussed below.

[0043] Prior to oil production, fluid communication between the injection well 120 and the production well 140 may be established with any suitable start-up technique used for a solvent-based or solvent-driven recovery process. This stage of the recovery process is commonly referred to as the start-up stage.

[0044] As illustrated in FIG. 2, in the start-up stage, a heated fluid such as steam or heaters (not shown) or other heating techniques, or a combination of different heating techniques, may be used to heat an inter-well zone 104 between the wells 120, 140 to soften the viscous hydrocarbons in the inter-well zone 104. The inter-well zone 104 may be heated for a period of sufficient time to prepare the reservoir formation, such as for about 1 month to about 7 months at a heating power/well length of up to 10,000 W/m, such as from about 500 W/m to about 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 zone 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 zone 104. After a period of heating, the temperature in the inter-well zone 104 may be increased as compared to the native or initial temperature of the reservoir before heating, so that the viscous hydrocarbons in the inter-well zone 104 are at least partially softened and mobilized. For example, the average temperature in the inter-well zone 104 may be about 95 C after such heating.
In different embodiments, the average temperature at this point may vary from about 80 C to about 290 C if, for example, propane is to be used at the solvent.

[0045] After the inter-well zone 104 is heated to the desired temperature, an injection fluid including the selected solvent may be injected into the inter-well zone 104 from both the injection well 120 and the production well 140 at a selected pressure, such as about 3 MPa, to establish fluid communication between the injection well 120 and the production well 140. The injection pressure and injection temperature at the start-up stage may be selected for efficient and effective establishment of fluid communication, and may be different from the injection temperature and pressure used during the production stage as will be discussed below. In a particular embodiment, the selected solvent is propane, and the injection temperature for the start-up stage may be higher than about 80 C, and the injection pressure may be about 3 MPa to about 3.5 MPa. The solvent such as propane can be injected in a vapor phase at these temperatures and pressures in the start-up stage.
Alternatively, the solvent may be injected at supercritical conditions.

[0046] The injected solvent vapor or supercritical solvent will disperse into the pay zone 102, particularly the inter-well zone 104, and will cool and eventually 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 zone 104. At this point, if heaters (not separately shown) are provided in the wells 120, 140 they may be activated to heat the inter-well zone 104 to assist heating of the hydrocarbons in the inter-well zone 104.

[0047] At some point 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 a pump (not shown) in the production zone may be operated to produce fluids in the production 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 120, 140 will be established. In some applications, it may take about 3 months or more to establish fluid communication between the wells in a typical well pair. Solvent injection may continue after initial fluid communication between the wells 120, 140 to provide improved communication between the wells. For example, it may be desirable to have generally uniform communication along the length of the horizontal sections of the wells 120 and 140, which may take more time to establish.

[0048] After fluid communication between the wells 120 and 140 is established, hydrocarbon production may commence, and the process enters into the production stage. At the beginning of the production stage, there may be a ramp-up phase, in which the oil production rate is gradually increased, or increased in steps.

[0049] After the start-up stage and the ramp-up phase, an initial "solvent chamber"
106 will have been developed as some of the hydrocarbons in the reservoir 100 have been mobilized and drained downward due to gravity, and the pores in the volume of the reservoir 100 originally filled by these hydrocarbons are now filled with the solvent.
The solvent chamber is typically more porous than the initial reservoir formation and allows fluids to travel through the solvent chamber.

[0050] In the production stage, a selected solvent 160, which may be the same or different from the solvent used in the start-up stage, is injected into the reservoir 100 through the injection well 120, and a reservoir fluid 170 is produced from the production well 140. The reservoir fluid 170 includes mobilized hydrocarbons and condensed solvent, as well as other possible components as can be appreciated by those skilled in the art.

[0051] The injected solvent may be propane or butane, or another suitable solvent as will be discussed further below.

[0052] In embodiments disclosed herein, during at least a period of hydrocarbon production, the injection temperature may be selected to be higher than the critical point temperature of the solvent and the injection pressure may be selected to be higher than the critical point pressure of the solvent, so that the injected solvent is supercritical when leaving the injection well 120 and entering the reservoir 100. As will be further discussed below, in selected embodiments, at least one of the temperature and pressure is selected to be significantly different from the critical point value such that the injection condition is not the same or close to the critical point conditions of the solvent, and the reduced density of the injected solvent immediately after entering into the reservoir is less than about 0.5 (e.g. less than about 100 kg/m3 for propane) and the temperature and pressure dependence of the solvent density at the selected injection conditions is relatively weak (see further discussions below). The "reduced density" of the solvent refers to the relative solvent density at a given condition which is normalized to the density of the solvent at the critical point, and can be calculated using Equation (1) discussed below.

[0053] For example, to inject propane as a supercritical solvent, the injection temperature should be higher than the critical point temperature of propane, which is about 96 C, and the injection pressure should be higher than the critical point pressure of propane, which is about 4.23 MPa.

[0054] In another example, when butane is used as the solvent, the injection temperature should be higher than the critical point temperature of butane, which is about 152 C, and the injection pressure should be higher than the critical point pressure of butane, which is about 3.79 MPa.

[0055] In some embodiments, the injection pressure may be below the critical point pressure, provided the matching injection temperature is high enough so that the solvent is injected in the gas phase with a reduced density of less than 0.5.
For example, when propane is used as the solvent, the injection pressure may vary from about 2 MPa to about 7MPa, where the matching injection temperature is higher than 125 C.

[0056] For a given injection pressure selected, the matching injection temperature has a corresponding lower limit to ensure the reduced density of the solvent is controlled as disclosed herein. For example, for reasons to be discussed later, in an embodiment when the injection pressure is about 2 MPa, the matching injection temperature is higher than 150 C; for injection pressure of about 3 MPa, the matching injection temperature is higher than 200 C; for injection pressure of about 4.5 MPa, the matching injection temperature is higher than 250 C; and for injection pressure of about 5 MPa, the matching injection temperature is higher than 300 C.

[0057] As can be appreciated by those skilled in the art, the injection temperature should also be controlled so as not to coke the solvent or the hydrocarbons to be produced in the reservoir 100. For example, in some bitumen reservoirs the coking temperature of the bitumen may be about 350 C. For such reservoirs, the injection temperature should be limited to below 350 C.

[0058] The injection pressure should also be safe and may need to be limited to comply with local regulatory requirements. For example, in some bitumen reservoirs, it is generally safe to inject a fluid into the reservoir at a pressure below about 7 MPa.

[0059] In accordance with an embodiment of the present disclosure, the injection temperature and pressure should also be selected to limit the density of the supercritical solvent so that the supercritical solvent behaves more gas-like than liquid-like in the solvent chamber. In some embodiments, the injection temperature and pressure are selected such that the injected supercritical solvent has a reduced density of less than about 0.5 at the selected injection temperature and injection pressure. For example, when propane is used as the solvent, the density of the injected propane at the injection conditions may be less than 100 kg/m3 (the critical density of propane is about 220 kg/m3 and 0.5 reduced density of propane is about 110 kg/m3). Suitable or optimal injection temperatures and pressures may be selected or determined based computer simulation or laboratory or field test results.

[0060] For ease of illustration, it is assumed that in a specific example embodiment, the solvent is propane, and the injection temperature during production may be from about 150 C to about 350 C, and the injection pressure may be from about 2 MPa to about 7 MPa, and the particular pair of injection pressure and temperature are matched to control the density of the injected solvent as discussed herein.
Detailed procedures for selecting the matching temperature and pressure pairs will be further discussed later below.

[0061] When the injected solvent 160 enters the reservoir 100 and comes into contact with the hydrocarbons and other materials in the reservoir which are at a lower temperature, the solvent 160 can dilute and soften the viscous hydrocarbons to mobilize the hydrocarbons. Some of the softened or mobilized hydrocarbons continue to drain downward due to gravity, leaving behind an increasingly larger porous volume in the pay zone 102. The solvent chamber 106 is in a sense analogous to the "steam chamber" in a conventional SAGD process. The concept of a "steam chamber" is well known and understood by those skilled in the art.

[0062] A solvent can travel more easily and quickly in the solvent chamber 106 as compared to the original pay zone 102 which has a much lower transmissibility under the original conditions before the solvent chamber is formed. In the ramp-up phase, the solvent chamber may grow and develop upwards above the injection well 120, as the injected solvent is gas-like and tends to rise in the solvent chamber 106.
The temperature in the central region of the solvent chamber 106 near the injection well 120 is higher than the temperature at the edges of the solvent chamber 106, which are referred to as the "interface region" 150 (sometimes also referred to as the "chamber front"). For example, the temperature at the central region of the solvent chamber 106 may be close to the injection temperature, and may be from about 150 C to about 350 C in the specific example noted above. The temperature at the interface region may vary, such as from about 70 C to about 20 C, assuming the reservoir temperature in regions outside the pay zone 102 is about 15 C.

[0063] During the production stage, the solvent is injected into the pay zone 102 of the reservoir 100 through the injection well 120 only. The solvent, propane in the specific example, enters the reservoir 100 mainly in the supercritical phase.

[0064] The solvent may be heated and pressurized at surface and supplied to the injection well 120 in the supercritical phase, or provided as a liquid to the injection well 120 and further heated in the injection well 120 to above the supercritical temperature before entering the pay zone 102. Alternatively, the solvent may be supplied to the injection well 120 as a liquid-vapor mixture, and then heated and pressured to above the critical point.

[0065] The solvent may be injected by injecting into the reservoir a fluid consisting essentially of the solvent. The fluid may contain impurities or small amounts of other substances such as water, steam, methane, other solvents, or the like, but the total weight or molar concentration of such impurities and other substances are relatively small, such as below about 1 wt% to about 2 wt%.

[0066] In some embodiments, the injection fluid may include a mixture of two or more selected solvents, in which case the selected solvents are not considered impurities. The injection fluid may also include steam, such as for heating the solvent(s), and improving mobility of the mobilized hydrocarbons in the reservoir as steam can condense in the reservoir and the added water content in the reservoir fluid can improve its flow rate towards the production well.

[0067] A heater in the injection well 120 may be used to control the injection temperature of the solvent.

[0068] The injection pressure or downhole pressure in the injection well 120 may be detected and controlled using any suitable technique including known downhole pressure monitoring techniques such as a bubble tube downhole pressure monitoring system. Using a bubble tube system, the downhole pressure may be automatically and continuously measured.

[0069] The injected solvent will initially travel generally upwards in the solvent chamber 106, as indicated by arrows 160 in FIG. 2. The solvent will cool down and condense at the interface zone 150 or even earlier due to the cooler temperature in the reservoir 100 particularly in interface zone 150. The solvent liquid will dilute the hydrocarbons and mix with the mobilized hydrocarbons to form a liquid mixture, namely, reservoir fluid 170, which drain generally downward.

[0070] Eventually, the reservoir fluid 170 drains into the production zone around the production well 140, and is produced to the surface through the production well 140.

[0071] It should be understood that a liquid mixture may contain some limited gaseous contents. For example, in the reservoir 100, the solvent may be partially in the liquid phase and partially in the vapor phase. A liquid in the liquid mixture, such as a liquid solvent, may also be vaporized in the production well 140 when being produced to surface. Some other gases such as methane, CO2, H25, or a combination thereof may also be produced with the liquid mixture.

[0072] During production, a heater (not shown) may be provided in the production well 140 to heat the production zone 108. The heating may be controlled by a surface control system (not shown) based on the temperature signal detected by a temperature sensor (not shown) provided in the production well 140, to maintain the temperature in the production zone 108 to be within a selected temperature range.
The factors considered for selecting this range have been discussed elsewhere and will not be repeated herein.

[0073] Hydrocarbon production may continue until the amount of the hydrocarbons in the pay zone 102 has been reduced to a level that is no longer economical.

[0074] After the production stage, the process may enter a blowdown stage, as can be understood by those skilled in the art. During the blowdown stage, injection of the solvent may be terminated or substantially reduced. 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 instead into the solvent chamber 106 to assist recovery of the residual solvent and the remaining hydrocarbons. The injected NCG may keep the pressure in the solvent chamber at a relatively high level. During the blowdown stage, the production zone 108 may be heated with a heater but the injection well 120 may not need to be heated any further.

[0075] 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.

[0076] Selecting and matching injection pressure and temperature

[0077] It has been recognized by the present inventors that a problem in some conventional solvent extraction processes is that the injected solvent is not efficiently utilized for extracting hydrocarbons because a large portion of the injected solvent is in, or quickly condenses to, the liquid phase before the solvent reaches the chamber front or the interface region 150 between the solvent chamber 106 and the pay zone 102. A liquid solvent generally travels slower than a gaseous solvent in the solvent chamber 106 or in the reservoir 100. As a result, a significant amount of liquid solvent is held in the reservoir 100, which does not contribute significantly to the production process, and cannot be efficiently recovered through the production well 140.
It has also been discovered that if the density of the injected solvent is lowered and controlled as discussed herein, solvent retention or holdup in the reservoir can be reduced and recovery efficiency can be improved. In particular, it has been recognized that when the injected solvent is either in the gas phase or in the supercritical phase but with a gas-like density, where the reduced density of the injected solvent is less than about 0.5 (see further discussion about reduced density below), and the solvent density dependence on both temperature and pressure is "weak" (see discussion below) at the injection conditions, the injected solvent is less likely to condense prematurely before reaching the chamber front, and solvent "holdup" may be reduced.

As a result, more efficient and more economical hydrocarbon recovery can be achieved, as compared to injecting a liquid solvent, or injecting supercritical solvent with liquid-like densities, or injecting a supercritical solvent at conditions close to the critical point conditions.

[0078] One of the possible reasons for the improved efficiency is that when the solvent is injected at controlled and matched temperatures and pressures as disclosed herein, the injected supercritical solvent can move or travel more quickly through the solvent chamber 106. As a result, it is expected that less solvent will be "held up" in the central portion of the solvent chamber 106. The solvent is thus more efficiently delivered from the injection point to the interface region 150 in the reservoir 100 through the solvent chamber 106. An embodiment described herein can thus reduce solvent holdup in the solvent chamber 106 in a hydrocarbon recover process.

[0079] In comparison, liquid solvents or supercritical solvents having liquid-like densities are more likely "held-up" in the solvent chamber 106. When a large amount of condensed or liquid solvent were present in the central portion of the solvent chamber 106 and its residence time in the solvent chamber 106 were long (i.e., being "held-up"), the utilization of the injected solvent for hydrocarbon recovery is less efficient and less effective. In some conventional techniques, the solvent injection temperature and pressure are optimized to maximize oil yield rate and reduce energy consumption, which result in relatively high solvent density in the solvent chamber 106. As a result, these techniques would require usage of a large amount of solvent to the extent that it would not be economical to implement such techniques on a commercial scale. The usage of solvent in such techniques is also inefficient and ineffective.

[0080] To overcome such inefficiency, in an embodiment of the present disclosure, the solvent injection temperature and pressure are selected and matched to reduce or minimize the solvent residence time in the solvent chamber 106. For example, limiting the solvent density and its dependency on temperature and pressure at the injection conditions can promote faster passage of the solvent through the solvent chamber 106, thus reducing its residence time in the solvent chamber 106, even when the temperature and pressure in the solvent chamber 106 may fluctuate or vary.

[0081] Injecting a supercritical solvent with gas-like density can be more beneficial in some embodiments as the solvent can travel through a longer distance in the reservoir 100 without a phase-change. In comparison, an injected solvent gas may quickly condense into the liquid phase in the solvent chamber due to temperature drops as the solvent moves away from the injection well.

[0082] Therefore, one of the factors to be considered when selecting and matching the injection temperature and pressure is to keep the density of the injected solvent below a certain threshold. The threshold may be expressed in terms of the reduced density of the solvent or the absolute density of the solvent. It is expected that it can be beneficial to inject the solvent at a reduced density of less than about 0.5. Using propane as an example, a reduced density of 0.5 for propane is equivalent to about 111 kg/m3 absolute density, as the critical density of propane is 222 kg/m3.
For butane, the reduced density of 0.5 is equivalent to about 116 kg/m3 absolute density, as the critical density of butane is 232.5 kg/m3.

[0083] It has been recognized by the present inventors that a possible approach to improve solvent efficiency is to modify the operating conditions in the reservoir 100 or in the solvent chamber 106 to reduce or limit solvent "holdup" or solvent residency time in the solvent chamber 106 in the reservoir 100. Without being limited to any specific theory, it is expected that when the density of the solvent is relative low, so the solvent behaves like a gas, the solvent "holdup" can be reduced. Further, to maintain the gas-like behaviour along the way to the interface region, the injection pressure and temperature should be matched so that the density of the solvent is relatively insensitive to pressure and temperature changes within the expected conditions in the centre portion of the solvent chamber. The derivatives of density with respect to temperature and pressure respectively in these zones provide useful and instructive information for selecting the suitable densities and corresponding pressure and temperature of the solvent.

[0084] Simulation tests have shown that by operating at example injection conditions disclosed herein, it is possible to reduce solvent usage and solvent residency time in the solvent chamber 106, while maintain relatively high oil production rates and low energy intensity, resulting in improved process economics.

[0085] To help explain the selection process, reference is first made to FIG. 3, which shows a density-pressure phase diagram for propane, at various selected temperatures.

[0086] In FIG. 3, the line labelled as "x=1" represents the gas-to-liquid phase transition boundary and the line labelled as "x=0" represents the liquid-to-gas phase transition boundary. The point at which the liquid phase line and the gas phase line meet represents the critical point of propane. At pressures and temperatures above the critical point, the solvent is supercritical and the gas and liquid phases are indistinguishable. It can also been seen from FIG. 3 that at pressures below the critical pressure, the solvent can transition from the gas phase to the liquid phase with a very small pressure or temperature change and the density change is quite quick and substantial at the transition point when the temperature is relatively low so that the density-pressure line at that temperature is on the x=1 line or relatively close to it.
Further, the density of the solvent can change substantially quickly near the critical point (see the slope of the line indicated as representing T= 75 C or 100 C).

[0087] To avoid such drastic change in density at or near the injection conditions, the injection temperature and pressure should be selected to be at a point some distance away from the gas phase line and the critical point.

[0088] The injection conditions should also be selected so that the solvent density is relative low and the rate of density change with respect temperature or pressure at the injection conditions is low.

[0089] The selection criteria are illustrated herein with reference to propane as an example but it should be appreciated that similar approaches can be applied in embodiments using other solvents.

[0090] The first selection criterion is that, as already mentioned, the solvent density is relatively low at the injection conditions. In particular, the reduced density of the solvent should be less than 0.5. In some embodiments, the reduced density may be less than 0.25. The reduced density may be 0.05, 0.1, 0.11, 0.12, 0.13, 0.14, 0.15, 0.16, 0.17, 0.18, 0.19, 0.2, 0.21, 0.22, 0.23, 0.24, or 0.25. The reduced density may also be 0.3 or 0.4 in some embodiments.

[0091] The reduced density (pr) is the ratio of actual solvent density (p) to the solvent critical density (density at the critical point, pc), as defined in Equation (1):
Pr = (1) PC
Similarly, the reduced temperature (Tr) and reduced pressure (Pr) may be expressed as in Equations (2) and (3) respectively:
T
= ¨ , (2) Pr =¨ (3) Pc.
where T is the actual solvent temperature, Tc is the critical temperature, P
is the actual pressure, and Pc is the critical pressure.

[0092] To provide an economical solvent process, the first criterion is that the reduced density is less than about 0.5, or satisfies Equation (4):
Pr~ 5 . (4)

[0093] In FIG. 4, the shaded area indicates the region that satisfies this criterion (4) for propane.

[0094] The second criterion is that a relative small change in temperature or pressure would not lead to substantial change in the solvent density (i.e. the dependence of the solvent (reduced) density on temperature and pressure is "weak").
Quantitatively, it has been found that such a criterion can be expressed as requiring the second partial derivative of the solvent density with respect to pressure or temperature to be relatively small. Ideally, the second partial derivatives should be a2 a2 zero (i.e., 1- r 2. = o, and 1-'2r =0 , but such ideal solvents may not exist and in any aT,.
event are not necessary. For example, the temperature dependence of propane density at various pressures is illustrated in FIG. 5, and the temperature dependence of the first and second derivatives of propane reduced density are respectively illustrated in FIG. 6 and FIG. 7.

[0095] It is desirable that the first partial derivatives of density with respect to temperature or pressure have weak dependence on the temperature or pressure, although in ideal situations the first partial derivatives should be independent of temperature and pressure.

[0096] In FIG. 6, it may be seen that the density change is relatively less when the propane is injected at relatively higher temperatures for a given pressure. At lower pressures (such as 1 MPa to 2.6 MPa) the first derivative is relatively flat at temperatures from 125 C to 300 C. However, at a higher pressure, such as 4.2 MPa, the density is only relatively flat at temperatures higher than about 150 C.
At even higher pressures, the flat region starts at even higher temperatures.

[0097] FIG. 7 shows the second derivative of the reduced density with respect to temperature. To avoid positive, non-linear changes in the solvent density as the solvent temperature decreases, such as when the solvent travels from the injection well to the interface region through the solvent chamber, should be relatively small.

[0098] As an example, FIG. 7 shows that for operating pressures of 2.6 MPa, the minimum injection temperature may be selected as 200 C. At pressures lower than 1.8 MPa, the injection temperature may be as low as 150 C. In FIG. 7, points A, B, C, D and E represent the points where the second derivative of the propane density becomes lower than 1. The same points are also indicated on the phase diagram in FIG. 8.

[0099] In practice, it is expected to be sufficient if the second partial derivative of the solvent density with respect to temperature satisfies the following criterion shown in Equation (5):
a2pr <1 (5) aT2 r where the Tin; is the injection temperature and Pinj is the injection pressure.

[00100] From Equation (5), it follows that at different injection pressures, the suitable injection temperature ranges may be different and the injection temperature at any given injection pressure should be selected to match the given pressure.

[00101] The pressure dependence of the density at the injection conditions should also be considered. For example, Figs. 9 to 12 show the pressure dependence of propane density, its first derivative with respect to pressure, and the second derivative of the reduced density with respect to reduced pressure respectively, at various temperatures.

[00102] Generally, in a solvent-based recovery process, a higher injection pressure may be desirable due to increased solubility of the solvent in hydrocarbons at higher pressures. However, within the context of the present disclosure, the injection pressure should also be selected with consideration to limit the solvent density and variation of the solvent density in the central regions of the solvent chamber.

[00103] For example, as can be seen in FIG. 10, at temperatures below about 200 C, operating at injection pressures above 2 MPa would involve significant density variations with pressure changes.

[00104] Figs. 11 and 12 (enlarged portion of FIG. 11) show the pressure dependence of the second partial derivative of reduced density of propane with respect to reduced pressure. It is expected that the density variation will be within an acceptable range when the second derivative of the reduced density with respect to reduced pressure is less than about 0.1 at the selected injection pressure and temperature. As can be appreciated, such a low value of the second derivative of the reduced density with respect to reduced pressure indicates that the dependence of the solvent density on the pressure is weak. The points F, G, H at which the second derivative crosses the threshold 0.1 are better shown in FIG. 12. The points of F, G, H
are also shown on the phase diagram illustrated in FIG. 13.

[00105] From these results, it can be expected that for injection pressures between 2 MPa and 5 MPa, the minimum injection temperature of propane should be higher than 200 *C. Judging from FIGS. 11 and 12, and for propane, at pressures above about 6 MPa, the injection temperatures may be significantly lower, such as as low as about 175 C, due to the fact that the phase diagram lines are far away from the critical point. At pressures below about 2 MPa, the injection temperatures can also be as low as 175 C.

[00106] At pressures below about 1 MPa, propane is not expected to be a suitable solvent in some applications, as the injection temperature needs to be relative low at this pressure, and injection of the solvent at such low temperatures would limit the heat energy transferable to the reservoir by the injected solvent.

[00107] From FIGS. 3, 8 and 13, it is possible to find a region on the phase diagrams where injection of pure propane is expected to be more economical than in the other zones. This region is denoted as the "pure solvent economic zone" or "PSEZ" in FIG. 14.

[00108] However, in the PSEZ region where the pressure is below the critical pressure, the solvent is in the vapour phase. If the solvent vapour is at a temperature and pressure very close to the dew point conditions, significant solvent vapour condensation may occur in the reservoir in the central regions of the solvent chamber.
Thus, such lower pressure regions may need to be avoided in some embodiments depending on the injection temperature. For example, in some embodiments, the injection pressure is selected to be higher than about 2 MPa when such high pressures are permissible and practical in the particular application.

[00109] FIG. 15 shows the resulting PSEZ truncated at 2 MPa.

[00110] For reservoirs with maximum operating pressures (MOP) that allow for higher pressures, it is expected that injecting the solvent at least initially at a higher or the highest possible pressure within the PSEZ would provide improved and balanced production efficiency and performance. In particular, the PSEZ at higher pressures may overlap with a lower triangle zone within the supercritical region of the solvent. At later stages of hydrocarbon production, the injection pressure may be gradually dropped to the initial reservoir pressure, such as to avoid cap rock or thief zone issues.
The corresponding injecting temperatures may be chosen to also be within the PSEZ
as indicated on the phase diagram as shown in FIG. 15.

[00111] As an example, Table I lists the maximum density and minimum temperature conditions for the PSEZ at different injection pressures for propane in example embodiments.
TABLE I. Example Injection Conditions in the PSEZ for Propane Solvent Injection Minimum Injection Maximum Pressure Temperature Solvent Density (MPa) ( C) (kg/m3) 2.0 150 30 2.0 200 30 3.4 220 35 4.2 245 40 5.0 270 45 5.8 295 50

[00112] Generally, when selecting the solvent and the injection conditions, the following conditions or factors should be considered.

[00113] First, the solvent is soluble in the hydrocarbons to be recovered at the operating temperatures and pressures. This condition may be expressed as the solubility (S*) of the solvent in the hydrocarbons is greater than zero at the injection temperature and the reservoir pressure, as in Equation (6):
7.% > 0. (6)

[00114] The solubility is assessed at the injection temperature and the reservoir pressure because the solvent solubility decreases with increasing temperature and decreasing pressure. Equation (6) ensures the solubility is larger than zero at all possible conditions within the reservoir.

[00115] Secondly, it may be desirable if the viscosity (p) of the hydrocarbons diluted and heated by the injected solvent in a solvent based process is lower than the viscosity of the hydrocarbons if were heated by steam injection in a steam process at similar operating temperatures or pressures, or both. One of the operating temperatures and pressures may be different for this comparison. This condition may be expressed, as follows in Equation (7):
< (7)

[00116] In some applications, it may be desirable that the resulting hydrocarbon viscosity is an order of magnitude less in a solvent process than in a comparable steam process.

[00117] Thirdly, as noted above, the reduced density of the solvent is less than 0.5 and the second derivative of the reduced density with respect to reduced temperature is less than 1, as indicated in Equation (5) above. In other words, the change in the solvent density with respect to temperature at the injection conditions should be at least on the same order of magnitude as the change in the injection temperature.

[00118] As now can be appreciated, according an embodiment of the present disclosure, a higher injection pressure is not always desirable for increasing the hydrocarbon production rate. On the one hand, a higher injection pressure would provide a higher driving pressure to increase the fluid flow towards the production well.
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.

[00119] 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 and can condense at the expected temperature at the interface region of the solvent 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

[00120] In this regard, known data including simulation data may be utilized for selecting the solvent. For example, it is known from experimental and simulation results the bitumen viscosities generally decrease as the temperature increases. For practical production, the viscosity of the softened bitumen should be lower than about 50 cP to about 100 cP, such as from about 1 cP to about 20 cP, although bitumen with even lower viscosity is generally easier to produce.

[00121] The injection temperature may be controlled by heating the solvent above surface prior to injection. Alternatively or additionally, the solvent may be heated in the injection well.

[00122] Known analysis tools and methods including computer-aided methods may be used to aid the selection of the solvent and operating conditions.

[00123] 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 150 of the solvent chamber 106. Second, the viscosity of the propane-bitumen mixture decreases with decreased temperature at the temperature range of 50 C to 70 C, which is just below the propane bubble point in the mixture at the given pressure of about 3 MPa.
This may be helpful after the solvent propane has condensed to liquid phase and is recovered with mobilized hydrocarbons through the production well, as the temperature in the production well or the production zone around the production well is substantially lower than the injection temperature and may be lower than the bubble point of the solvent at the reservoir pressure.

[00124] 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.

[00125] 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.

[00126] In some embodiments, it may be 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.

[00127] In an embodiment, the recovery process may be a solvent-driven recovery process, and a relatively small amount of steam may be co-injected with the solvent in the production stage.

[00128] In a different embodiment, butane may be selected as the solvent, and the operation parameters and conditions may be selected based on the factors and considerations described herein.

[00129] In some embodiments, a natural gas liquid (NGL) may be used as the solvent. Natural gas liquids may include ethane, propane, butane (n-butane, or isobutane), pentanes, or heavier hydrocarbons.

[00130] 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.

[00131] 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.

[00132] 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.

[00133] 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.

[00134] 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, in some cases using butane as the solvent may provide better oil production rates than using propane, while using propane may reduce energy requirements and GHG emissions as compared to butane.

[00135] 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.

[00136] 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.

[00137] Hydrocarbon solvents, such 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 because 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.

[00138] 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 may be selected over the technically optimal solvent.

[00139] 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.

[00140] 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. A mixture of NLGs may also be used. For example, the solvent 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. The operating costs include the costs of the injected solvent, so a lower cost solvent may be a criterion to be considered when selecting the solvent.

[00141] 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.

[00142] 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-hydrocarbons, for example, 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 gas condensates, naphtha, diesel, other diluents, or combinations thereof.

[00143] 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 solvent 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.

[00144] 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.

[00145] 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 solvent 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. 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.

[00146] 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 may 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 C to about 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.

[00147] 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.

[00148] As can be appreciated, the temperatures under native conditions in different reservoirs may vary. For example, the native temperature may be from about 7 C to about 22 C, from about 9 C to about 15 C, or from about 10 C 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 MPa to about 4 MPa, from about 0.5 MPa to about 3.5 MPa, or from about 1 MPa 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.

[00149] 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 20 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 100 API Gravity.
The API Gravity of bitumen ranges from about 12 to about 7 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.

[00150] The recovery processes described herein are not limited to any particular type of reservoirs or hydrocarbon compositions in the reservoir.

[00151] 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.

[00152] 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.

[00153] In selected embodiments, the injection well 120 may be vertically spaced from the production well 140 by a distance within a range of from 3 m 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.

[00154] 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.

[00155] 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.

[00156] 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.

[00157] Downhole heaters (not shown), such as those disclosed in CA
2,304,938, may be used in selected embodiments as described herein. The heaters may include an electric heater. A suitable heating system may also be used.

[00158] 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 a combination thereof may be injected during a start-up stage. While not all of these fluids or solvents will work under all conditions, a suitable fluid for use in a start-up stage 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.

[00159] 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.

[00160] In selected embodiments, the time period of the production stage 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 may vary over time and may vary in different applications. The injection temperatures may be, for example, from about 175 C to about 350 C, depending on the solvent selected and the reservoir conditions. The injection pressures may be from about 2 MPa to about 7 MPa.

[00161] 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 solvent chamber 106.

[00162] In selected embodiments, the time period of the blowdown stage may vary. For example, the blowdown stage may last for a period of about 1 month to about 12 months. In selected embodiments, the injected fluid, injection temperature and pressure used during the blown-down stage 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 350 C.

[00163] As discussed earlier with respect to FIG. 2, 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 region 150 of the solvent chamber 106. In the interface region 150, the temperature may decrease quickly, and the temperature just outside the solvent 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 solvent chamber 106.

[00164] In select embodiments, the injection temperature may be between C and 350 C, and the injected solvent may cool down to a temperature between about 45 C and to about 145 C as it passes through the solvent chamber 106.
As the solvent vapor contacts materials within the cooler interface region 150 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 and mobilized hydrocarbons. The liquid mixture may also contain asphaltenes. In select embodiments the temperature at the interface region may be between 25 C and 125 C.

[00165] 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; recycling a solvent may not be as efficient as for recycling steam because the gravity is not as efficient for driving solvent drainage as compared to driving steam drainage.

[00166] Another factor to consider is overall reduced energy usage. Such a 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.

[00167] 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.

[00168] 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.

[00169] It is noted that it has been recognized that when a solvent is injected in the vapor phase into the reservoir at lower temperatures, such as when the injection temperature is close to the bubble point of the solvent at the given pressure, the solvent can condense quickly in the reservoir after entering into the reservoir and losing some of its heat energy to the surrounding materials. Further, the temperature in the production zone 108 around the production well 140 may be controlled to be lower than the bubble point temperature of the solvent to ensure that the solvent will be substantially in the liquid phase in the production zone 108.

[00170] When the solvent injection temperature is relatively high, viscous hydrocarbons in the reservoir may be mobilized mainly by viscosity reduction due to heat transfer, which will be higher at elevated temperatures. In this case, solvent dissolution can still have an effect on mobilizing the hydrocarbons but such effect may be secondary depending on the injection temperature and other factors such as solvent type and injection pressure. At a higher injection temperature, the solvent will have a lower density at a given pressure and thus the same amount of solvent can occupy more space within the reservoir. Consequently, a lower amount of the solvent may be required to achieve similar hydrocarbon recovery at a higher solvent injection temperature. However, to heat the solvent to these higher injection temperatures, the process may be more energy intensive.

[00171] In some embodiments, it may be beneficial to vary the solvent injection temperature during hydrocarbon production based on reservoir conditions and production progress, so as to balance and optimize energy efficiency, solvent usage, and hydrocarbon recovery performance. Varying the injection temperature may also provide other benefits in different embodiments.

[00172] ALTERNATIVES AND VARIATIONS

[00173] In some embodiments, injection pressure may be controlled using known techniques that have been used in other processes such as SAGD processes and other processes involving injection of a solvent. Alternatively, different or additional techniques may be sued.

[00174] As discussed above, the solvent may be delivered relatively hot to the reservoir formation. However, it is possible that the solvent may be fed into the injection well with or without pre-heating at the surface.

[00175] In some embodiments, the solvent condensed in the reservoir will be recovered (produced) in the oleic phase. Additionally or alternatively, vapor solvent could remain in the reservoir formation, and may also be recovered with a reservoir fluid in the gaseous phase.

[00176] In some embodiments, an additive or chemical such as toluene may be injected during solvent injection or during a post-production phase. Injection of toluene may help to reduce asphaltene precipitation. About 5 wt% of toluene may be co-injected with a solvent.

[00177] In some embodiments, fluids recovered at the surface may be separated from produced solvent to undergo recycling.

[00178] In some embodiments, the injected solvent may be recovered and recycled.

[00179] In some embodiments, particularly in a process with higher injection temperatures, a barrier or insulation layer may be formed at the overburden, which may assist in reducing heat loss through the overburden once the solvent chamber has substantially reached full vertical growth. For example, a barrier layer may be formed after this condition is reached. Alternatively, a barrier may be formed at an earlier or later point in time. In another example, a barrier layer may be formed at or about the time that the peak process threshold has been reached and detected.
The barrier layer may be formed of an insulation composition such as described in US
2015/0159476 to Warren et al., the entire contents of which are incorporated herein by reference. The barrier layer may also be formed from an artificial layer such as those disclosed in US 2011/0186295 or CA 2,729,430 to Kaminski et al., the entire contents of which are incorporated herein by reference.

[00180] In some embodiments, non-condensable gases (NCGs) may be generated in the reservoir such as due to heating. Additionally or alternatively, an NCG
may be injected as an additive in some embodiments. Conveniently, the presence of NCGs in the formation can enhance lateral dispersion of the solvent vapor to spread the solvent laterally into the reservoir formation. Increased lateral dispersion of the solvent is expected to assist lateral growth of the solvent chamber, and hence enhance oil production.

[00181] While in some of the above discussed embodiments a pair of wells is employed for injection and production respectively, it can be appreciated that some processes as disclosed herein may be implemented with a single well or unpaired wells. The single well, or an unpaired well, may be used alternately for injection or production. The single well may have a substantially horizontal or vertical section in fluid communication with the reservoir. The single well may be a well that is configured and completed for use in a cyclic steam stimulation (CSS) recovery process.

[00182] As alluded to earlier, the injected solvent may be an alkane or another hydrocarbon solvent, or may be a mixture of different solvents. The solvent mixture may also include a relatively small portion of another material. For example, the mixture may contain 90 wt% or more of a hydrocarbon solvent and 10 wt% or less of the other material. The other material may be light weight filler included to reduce the overall density of the injected mixture. The other material may also be a material for selective zone shutoff, or to reduce interfacial tension between various materials in the formation, or perform other functions. The other material may include one or more of Di-methyl ether (DME), methanol, ethanol, methane, CO2, surfactant, polymer, gel, nanoparticles, or the like.

[00183] The following examples further illustrate embodiments of the present disclosure, or demonstrate functionalities or results that could be achieved in various aspects, configurations, or combinations of the features described herein.

[00184] Examples

[00185] Example I

[00186] Computer simulations have been conducted to predict solvent density distribution in the solvent chamber of a simulated reservoir. A representative simulation result is shown in FIG. 16.

[00187] Figure 16 shows the average in-situ density profile of a pure solvent process, with propane as the solvent. As can be seen, the solvent density varies in the formation, increasing from the injection well towards the interface region.
The solvent density is about 30 kg/m3 in the region closer to the injection zone, but about 100 kg/m3 in the region closer to the chamber/bitumen interface. The density variation is expected to be due to heat loss from the solvent to the bitumen material in the chamber after the solvent enters the formation from the injection well. For the model simulation, the solvent injection temperature was modelled to be 225 C near the injection well, and the native reservoir temperature was modeled to be 15 C.
The reservoir pressure was modelled to be about 3MPa.

[00188] Figure 16 also shows that the solvent at the chamber/bitumen interface behaves more like a liquid than a gas, and hence the solvent is expected to dissolve more into the bitumen phase, which helps oil production. Such a solvent density profile is desirable for more efficient oil recovery, as in this case, the solvent in the majority of the solvent chamber is more gas-like and of lower density.

[00189] Example ll

[00190] FIG. 17 shows representative experimental data obtained from field tests.

[00191] For these tests, steam was initially injected and then both steam and propane solvent were co-injected. As can be seen, during the illustrated period, after propane injection was initiated, the propane injection rate was maintained at about 40 ton/day. The steam injection rate was maintained relatively constant at about ton/day before and after solvent injection.

[00192] With relatively constant heat energy input from the steam injection, it was expected that the reservoir temperature would gradually drop with time and continued solvent injection, as illustrated in FIG. 17, where the reservoir temperature dropped from about 200 C at the left-hand side of the graph (start of propane injection) to about 125 C at the right-hand side of the graph, within a time period of about 13 months.

[00193] Further decrease in the reservoir temperature below about 125 C
had a negative effect on the oil production rate. To increase or maintain the oil production rate, the propane injection rate needed to be increased, or the steam injection rate would need to be increased, which would increase the reservoir temperature.

[00194] It is noted that the oil production rate at the right-hand end of the graph was about 25% of the oil production rate at the left-hand end of the graph.

[00195] The injection pressure during solvent injection was as high as 5 MPa for injecting supercritical propane, and was gradually reduced to eventually about 3.2 MPa as temperature decreased.

[00196] FIG. 17 also shows the reduced density of the injected propane in the solvent chamber in the formation, which varied from about 0.2 to about 0.3, and was less than 0.5.

[00197] FIG. 17 further shows the first partial derivative of the reduced density of the solvent with respect to temperature (denoted as P.D.R.D_T), which varied substantially (increasing significantly) as the reservoir temperature dropped to below 150 C, which indicated that the first derivative is a strong function of temperature at temperatures below 150 C.

[00198] The median value of the second derivative of the reduced density with respect to reduced temperature at a high temperature region was about 0.43, indicating a weak dependence of the first derivate of the reduced density on temperature. In comparison, the median value of the corresponding second derivative at lower temperatures was found to be about 1.5, indicating relatively strong temperature dependence.

[00199] FIG. 18 shows an illustrative representation of the temperature dependence of the reduced solvent density and its first derivative as a function of reduced temperature (Tr) for representative field data. As can be seen, there are two (2) distinguishable regions or clusters of data: a first region in which the First P.D.R.D_T depends linearly with Tr (weak dependency region, represented by diamond shaped data points), and a second region in which the First P.D.R.D_T
depends non-linearly, up to the 3rd order, with Tr (strong dependence region, represented by triangular shaped data points). The degree of correlation (R2) among the data points is 0.9699 in the first region, and 0.265 in the second region.
A line fit of the data points in the first region can be represented by a linear equation, y (First P.D.R.D_T) = -0.8153 x (Tr) + 1.2387. In comparison, a line fit of the data points in the second region can be represented by a third order equation, y = - 273.41 x3 +
922.7 x2 + 1038.1 x + 389.68.

[00200] The First P.D.R.D_T may be considered to have a weak dependence on temperature if the condition in Equation (5) is satisfied. The First P.D.R.D_T
may be considered to not have a weak dependence on temperature if the second partial derivative of the reduced solvent density with respect to temperature is higher than 1, i.e., the condition in Equation (5) is not satisfied. In other words, if the First P.D.R.D_T
scales generally linearly (first order) with temperature, or with a less order of dependence, it is considered to have weak temperature dependence. If the First P.D.R.D_T scales on a higher order (>1) with temperature, it is considered to have strong temperature dependence.

[00201] CONCLUDING REMARKS

[00202] 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.

[00203] 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.

[00204] 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.

[00205] 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.

[00206] Of course, the above described embodiments of the present disclosure 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, rather, 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:
injecting a solvent at an injection pressure and an injection temperature into the reservoir to mobilize viscous hydrocarbons in the reservoir, wherein the injection pressure and injection temperature are selected and matched such that, the solvent has a reduced density of less than 0.5 and a second derivative of the reduced density with respect to temperature is less than 1, at the injection pressure and the injection temperature; and producing hydrocarbons mobilized by the solvent from the reservoir.

2. The method of claim 1, wherein a second derivative of the reduced density with respect to pressure is less than 0.1.

3. The method of claim 1 or claim 2, wherein the solvent is a supercritical solvent at the injection temperature and the injection pressure.

4. The method of claim 1 or claim 2, wherein the injection pressure is higher than the critical point pressure of the solvent.

5. The method of any one of claims 1 to 4, wherein the solvent is propane.

6. The method of claim 5, wherein the injection pressure is above 2 MPa, the injection temperature is less than 200 °C, and the density of the solvent at the injection pressure and the injection temperature is less than 100 kg/m3.

7. The method of claim 5 or claim 6, wherein the density of the solvent is less than 50 kg/m3.

8. The method of any one of claims 5 to 7, wherein the injection pressure is above 4.3 MPa.

9. The method of any one of claims 5 to 8, wherein the injection pressure is less than 7 MPa.

10.The method of any one of claims 5 to 9, wherein the injection temperature is less than a coking temperature of the hydrocarbons.

11.The method of claim 10, wherein the injection temperature is less than 350 °C.

12.The method of claim 5, wherein the injection pressure is about 2 MPa, and the injection temperature is higher than 150 °C.

13.The method of claim 5, wherein the injection pressure is about 3 MPa, and the injection temperature is higher than 200 °C.

14.The method of claim 5, wherein the injection pressure is about 4.5 MPa, and the injection temperature is higher than 250 °C.

15.The method of claim 5, wherein the injection pressure is about 5 MPa, and the injection temperature is higher than 300°C.

16.The method of any one of claims 1 to 4, wherein the solvent comprises butane.

17.The method of claim 16, wherein the injection pressure is above 3.8 MPa and the injection temperature is above 200 °C.

18.The method of any one of claims 1 to 4, wherein the solvent comprises a natural gas liquid.

19.A method of delivering a solvent to an interface region in a reservoir of hydrocarbons through a solvent chamber, comprising:
injecting the solvent into the solvent chamber in the reservoir at an injection pressure and an injection temperature selected and matched such that, at the injection pressure and the injection temperature the solvent has a reduced density of less than 0.5 in the solvent chamber before the solvent reaches the interface region, and a second derivative of the reduced density with respect to temperature is less than 1.

20. The method of claim 19, wherein the injection pressure and injection temperature are selected and matched to reduce solvent holdup in the solvent chamber.

21. A method of reducing solvent holdup in a solvent chamber in a reservoir of hydrocarbons, wherein a solvent is injected into the solvent chamber to assist production of hydrocarbons from the reservoir, the method comprising:
injecting the solvent into the solvent chamber in the reservoir at an injection pressure and an injection temperature selected and matched such that, at the injection pressure and the injection temperature the solvent has a reduced density of less than 0.5 in the solvent chamber before the solvent reaches an interface region between the solvent chamber and the reservoir, and a second derivative of the reduced density with respect to temperature is less than 1.