CA3097200A1 - Dimethyl ether-based method for recovering viscous oil from a water-wet reservoir - Google Patents

Abstract

Methods are provided for recovering viscous oil from a water-wet subterranean reservoir having at least one injection well and at least one production well installed therein. The method may comprise establishing flow communication between the injection well and the production well; and injecting a heated vapor-phase working fluid comprising vapor-phase dimethyl ether (DME) and vapor-phase water via the injection well and producing a production fluid via the production well. The vapor-phase water may be about 5% or lower of a total volume of the heated vapor-phase working fluid by liquid volume equivalent. In some embodiments, the method may allow for lower operating temperatures compared to typical steam-based processes without sacrificing oil production performance as in typical solvent-dominated processes. Related systems are also provided.

Description

DIMETHYL ETHER-BASED METHOD FOR RECOVERING VISCOUS OIL FROM A
WATER-WET RESERVOIR
RELATED APPLICATION:
[0001] The present disclosure claims priority to U.S. Provisional Patent Application No. 62/927,847, filed October 30, 2019, the entire contents of which are incorporated by reference herein.
TECHNICAL FIELD:

[0002] The present disclosure relates to oil recovery methods. More particularly, the present disclosure relates to solvent-based in situ thermal oil recovery methods.
BACKGROUND:

[0003] Steam-based thermal oil recovery processes, including steam flooding, cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) are commercially well-established processes. In these processes, the temperature of the reservoir is typically raised to 200 C or more by injection of steam to reduce the viscosity of crude oil therein. Steam consumption in these processes is high, ranging from about two to six volumes of steam on a liquid (water) equivalent basis per volume of produced oil. High steam demand creates both economic and environmental performance challenges, including high capital and operating costs for large capacity water treatment and steam generation facilities, high water consumption rates, and high greenhouse gas emission intensity.

[0004] To improve or replace steam-based processes, much effort has been devoted to the development of recovery processes that use solvents that are effective in reducing the viscosity of crude oil by dilution. Various solvent-dominated or solvent-assisted processes have been proposed including processes comprising injecting solvent alone at ambient reservoir temperature, injecting heated solvent alone, or co-injecting solvent as an additive to steam. However, no solvent-dominated process, i.e.

Date Recue/Date Received 2020-10-27 where a high partial pressure of steam is not the dominant factor in mobilizing viscous oil, has yet been deployed at commercial scale.

[0005] The viability of solvent-dominated processes is challenged by comparatively low oil production rates, which are typically significantly less than what can be achieved with competing steam-dominated processes. This results from the fact that, under reservoir conditions and typical operating pressure constraints, molecular diffusion (of hydrocarbon solvent into oil) is significantly lower than thermal diffusivity.
Solvent-dominated processes may also be challenged by high costs associated with accumulation or loss of solvent in the depleted reservoir.

[0006] Dimethyl ether (DME) has been suggested as a potential candidate solvent for use in viscous oil recovery processes. DME has significant solubility in bitumen and heavy oils, is relatively inexpensive, and is not associated with any known health or environmental concerns. Canadian Patent No. 2,652,930 discloses an example of a DME-based oil recovery process in which heated DME alone (in vapor or liquid form) is injected into a SAGD-type well configuration. However, DME-only processes may face similar challenges as other solvent-dominated processes including relatively low oil production performance compared to steam-dominated processes.

[0007] DME has also been proposed as an additive in steam-dominated processes including variations on SAGD as described, for example, in U.S.
Patent No.
10,125,591 and Canadian Patent Application No. 2,936,649. However, in a study by Haddadnia et al., a steam-dominated process with about 5% DME on a liquid volume basis was found to provide a higher oil production rate than steam alone but a lower oil production rate than steam combined with a hydrocarbon solvent additive (i.e.
butane) (Haddadnia et a/., "Dimethylether ¨ A promising solvent for ES-SAGD", Society of Petroleum Engineers 2018 SPE-189741-MS). In addition, steam-dominated processes that include DME as an additive still require high steam consumption and high operating temperatures.

Date Recue/Date Received 2020-10-27 SUMMARY:

[0008] In one aspect, there is provided a method of recovering viscous oil from a subterranean reservoir having at least one injection well and at least one production well installed therein, the method comprising: establishing flow communication between the at least one injection well and the at least one production well;
injecting a heated vapor-phase working fluid comprising vapor-phase dimethyl ether (DME) and vapor-phase water via the at least one injection well and producing a production fluid via the at least one production well; wherein the vapor-phase water is about 5% or lower of a total volume of the heated vapor-phase working fluid by liquid volume equivalent.

[0009] In some embodiments, a ratio of vapor-phase DME to vapor-phase water is between about 20:1 and about 250:1 by liquid volume equivalent.

[0010] In some embodiments, injecting the heated vapor-phase working fluid comprises co-injecting a first fluid stream comprising heated vapor-phase DME
and a second fluid stream comprising heated vapor-phase water such that the first fluid stream and second fluid stream combine in the at least one injection well to form the heated vapor-phase working fluid.

[0011] In some embodiments, the first fluid stream is injected at a first temperature and the second fluid stream is injected at a second temperature.

[0012] In some embodiments, the first temperature and the second temperature are each between about 50 C and about 250 C.

[0013] In some embodiments, the method further comprises forming the heated vapor-phase working fluid prior to injection.

[0014] In some embodiments, the heated vapor-phase working fluid is injected at a temperature of between about 50 C to about 250 C.

Date Recue/Date Received 2020-10-27

[0015] In some embodiments, the method further comprises maintaining a vapor chamber operating temperature of between about 50 C and about 100 C during injection of the heated vapor-phase working fluid.

[0016] In some embodiments, at least one heater is installed in the at least one injection well and/or the at least one production well and wherein maintaining the operating temperature comprises heating the at least one injection well and/or the at least one production well via the at least one heater.

[0017] In some embodiments, the heated vapor-phase working fluid further comprises at least one volatile hydrocarbon solvent.

[0018] In some embodiments, the method further comprises adjusting a concentration of the at least one volatile hydrocarbon solvent based on a desired degree of asphaltene precipitation.

[0019] In some embodiments, the heated vapor-phase working fluid further comprises at least one non-condensable gas.

[0020] In some embodiments, the method further comprises separating at least a portion of produced DME from the production fluid.

[0021] In some embodiments, the method further comprises recycling the produced DME to form new heated vapor-phase working fluid.

[0022] In some embodiments, establishing flow communication comprises injecting a liquid-phase initialization fluid via the at least one injection well, the at least one production well, or both the at least one injection well and the at least one production well.

[0023] In some embodiments, the liquid-phase initialization fluid comprises liquid-phase DME.

Date Recue/Date Received 2020-10-27

[0024] In some embodiments, the liquid-phase initialization fluid further comprises at least one liquid-phase hydrocarbon solvent.

[0025] In some embodiments, establishing flow communication further comprises: ceasing injection of the liquid-phase initialization fluid; and injecting a heated vapor-phase initialization fluid and producing an initial production fluid via the at least one injection well, the at least one production well, or both the at least one injection well and the at least one production well.

[0026] In some embodiments, the heated vapor-phase initialization fluid comprises vapor-phase DME and vapor-phase water and wherein the vapor-phase water is about 5% or lower of a total volume of the heated vapor-phase initialization fluid by liquid volume equivalent.

[0027] In some embodiments, the heated vapor-phase initialization fluid further comprises at least one vapor-phase hydrocarbon solvent.

[0028] In some embodiments, the method further comprises ceasing injection of the heated vapor-phase working fluid and injecting a non-condensable gas via the at least one injection well and producing at least a portion of remaining DME in the reservoir via the at least one production well.

[0029] In another aspect, there is provided a system for recovering viscous oil from a subterranean water-wet reservoir, comprising: at least one injection well and at least one production well installed in the subterranean water-wet reservoir;
at least one heating system; a control system operatively connected to the at least one heating system and configured to implement embodiments of the methods described herein.

[0030] In some embodiments, the at least one injection well and the at least one production well comprise a plurality of well pairs and a ratio of inter-well-pair spacing to pay interval thickness is about 4:1 or lower.

[0031] In some embodiments, the at least one injection well and the at least one production well are each non-thermally completed.
Date Recue/Date Received 2020-10-27

[0032] In some embodiments, the system further comprises at least one heater installed in the at least one injection well and/or the at least one production well.

[0033] Other aspects and features of the present disclosure will become apparent, to those ordinarily skilled in the art, upon review of the following description of the specific embodiments of the disclosure.
BRIEF DESCRIPTION OF THE DRAWINGS:

[0034] Some aspects of the disclosure will now be described in greater detail with reference to the accompanying drawings. In the drawings:

[0035] Figure 1 is a side view diagram of a system for implementing embodiments of the methods disclosed herein, including a well pair in a subterranean reservoir;

[0036] Figure 2A is a cross-sectional view of the well pair of Figure 1;

[0037] Figure 2B is a cross-sectional view of the well pair of Figure 1, shown with an adjacent well pair;

[0038] Figure 3 is a flowchart of an example method for recovering viscous oil from a subterranean reservoir, according to some embodiments;

[0039] Figure 4 is a flowchart of another example method showing additional steps for recycling at least a portion of produced DME, according to some embodiments;

[0040] Figure 5 is a flowchart of another example method showing additional details regarding how flow communication may be established between an injection well and a production well, according to some embodiments;

[0041] Figure 6 is a flowchart of another example method showing additional steps for recovering DME from the reservoir, according to some embodiments;

Date Recue/Date Received 2020-10-27

[0042] Figure 7 is a phase envelope diagram for a multi-component (condensable) vapor-phase working fluid;

[0043] Figure 8 is a graph showing DME and water vapor injection rates by liquid volume equivalent for a laboratory test of DME-water vapor injection in a 2D
high pressure-high temperature test cell with Athabasca bitumen;

[0044] Figure 9 is a graph showing cumulative bitumen production for the DME-water vapor test of Figure 8;

[0045] Figure 10 is a graph showing cumulative DME injection and production for the DME-water vapor test of Figure 8;

[0046] Figure 11 is a graph showing cumulative bitumen production for the DME-water vapor test of Figure 8 in comparison to a steam-only test and a DME-only test;

[0047] Figure 12 is a graph showing cumulative DME and steam injection for the DME-water vapor test of Figure 8 and the DME-only test of Figure 11;

[0048] Figure 13 shows residual oil saturation for a DME-water vapor test (left) compared to a DME-water-butane test (right).
DETAILED DESCRIPTION:

[0049] Generally, the present disclosure provides a method for recovering viscous oil from a water-wet subterranean reservoir having at least one injection well and at least one production well installed therein. The method may comprise establishing flow communication between the at least one injection well and the at least one production well; and injecting a heated vapor-phase working fluid comprising vapor-phase dimethyl ether (DME) and vapor-phase water via the at least one injection well and producing a production fluid via the at least one production well. The vapor-phase water may be about 5% or lower of a total volume of the heated vapor-phase working fluid by liquid volume equivalent.

Date Recue/Date Received 2020-10-27

[0050] As used herein the terms "a," "an," and "the" may include plural referents unless the context clearly dictates otherwise.

[0051] As used herein, "viscous oil" refers to a hydrocarbon material having a high viscosity and a high specific gravity. In some embodiments, viscous oil comprises heavy oil and/or bitumen. As used herein, "heavy oil" refers to a hydrocarbon material having a viscosity greater than 100 centipoise under virgin reservoir conditions and an API gravity of about 20 API or lower. Bitumen may be defined as a hydrocarbon material having a viscosity greater than 10,000 centipoise under virgin reservoir conditions and an API gravity of about 100 API or lower.

[0052] As used herein, "reservoir" refers to any subterranean region, in an earth formation, including at least one pool or deposit of hydrocarbons such as viscous oil therein. A portion of the reservoir containing viscous oil therein may be referred to as a "pay interval" or "pay zone".

[0053] Within the pay interval, heavy oil or bitumen exists in the pore space between reservoir sand particles. In a "water-wet" reservoir, in the virgin state, there may be an approximately continuous film of water attached to the solid surfaces of the reservoir sand particles. The oil residing in the interconnected pore space may be substantially surrounded by and in contact with this film of water. As a result, the interfacial area of contact between the film of water and the oil may be very large.

[0054] As used herein, "thermal oil recovery process" refers to a process that involves in situ heating of the reservoir to mobilize the viscous oil therein such that the mobilized oil may be displaced to a production well and produced to surface.
In some embodiments, the in situ heating of the reservoir is provided by injection of a heated working fluid. As used herein, a "working fluid" refers to any fluid injected into the reservoir. In some embodiments, the heated working fluid is a heated vapor-phase working fluid. In some embodiments, the heated vapor-phase working fluid may comprise steam, one or more solvents, or a combination thereof. The heat of the heated vapor-phase working fluid may reduce the viscosity of the viscous oil and thereby Date Recue/Date Received 2020-10-27 mobilize the viscous oil within the reservoir. In processes that employ solvents, the oil may be mobilized by a combination of heating and dissolution of the solvent into the oil.
In some embodiments, the displacement mechanism of the thermal oil recovery process is gravity drainage such that mobilized oil flows to the production well under the force of gravity while the voided pore space from which the oil is displaced is filled with injected working fluid.

[0055] Thermal gravity drainage oil recovery processes may be implemented using a variety of different well configurations. In some embodiments, the well configuration comprises at least one injection well and at least one production well. The injection well is used to inject a working fluid into the reservoir. The production well is used to collect drained mobilized oil and condensed working fluid and convey a production fluid to the surface. As used herein, "production fluid" refers to the fluid produced from the production well which may include oil, condensed working fluid, and any other fluids flowing into the production well from the reservoir. In other embodiments, a single well may function as both the injection well and the production well.

[0056] In some embodiments, one or both of the injection well and the production well are vertical wells. As used herein, a "vertical" well refers to a well that extends substantially directly downward from the surface of the reservoir into the target pay interval. In some embodiments, one or both of the injection well and the production well are horizontal wells. As used herein, a "horizontal" well refers to a well having a substantially vertical section that extends downward into the pay interval followed by a substantially horizontal section that extends approximately parallel to the bottom of the pay interval. In some embodiments, the horizontal section of the horizontal well may be at least 80 from vertical.

[0057] Figure 1 shows an example system 100, according to some embodiments, that may implement one or more of the methods described herein. The example system 100 may comprise a well pair 101. The well pair 101 is similar to the well pairs typically used in SAGD operations.

Date Recue/Date Received 2020-10-27

[0058] The well pair 101 in this embodiment is installed in an earth formation 102 having subterranean reservoir 103 with pay interval 105. The earth formation 102 may have a water-saturated zone 114 below the reservoir 103. In this embodiment, the reservoir 103 is a water-wet reservoir.

[0059] The well pair 101 may comprise an injection well 104 and a production well 106. In this embodiment, the injection well 104 and the production well 106 are both horizontal wells. The production well 106 may be located at or near the bottom of the pay interval 105. The injection well 104 may be vertically spaced above the production well 106 and substantially parallel with the production well 106. In some embodiments, the injection well 104 is approximately five meters above the production well 106.

[0060] In some embodiments, the injection well 104 and the production well 106 are thermally completed. As used herein, "thermally completed" refers to a well that has been completed with production casing and cement that are selected or configured to withstand high temperatures. The thermally completed wells may therefore operate at a maximum steam temperature of about 300 C or higher. In other embodiments, the injection well 104 and the production well 106 are not thermally completed. As used herein, "not thermally completed" or "non-thermally completed" refers to a well that has been completed with production casing and cement that are not selected or configured to withstand high temperatures. The non-thermally completed wells may have a maximum operating temperature based on the rating of the conventional cement used.
For example, the non-thermally completed wells may be limited to a maximum operating temperature of about 120 C in some embodiments. The temperature rating of the injection and production wells 104 and 106 completions may determine the maximum operating temperature of the thermal oil recovery process, as described in more detail below.

[0061] The injection well 104 and the production well 106 may be in flow communication via the reservoir 103, as described in more detail below. Once flow communication is established between the injection well 104 and the production well 106, a heated vapor-phase working fluid may be injected via the injection well 104 and Date Recue/Date Received 2020-10-27 flow into the reservoir 103. The heated vapor-phase working fluid may comprise vapor-phase DME and vapor-phase water as described in more detail below. As used herein, the terms "vapor-phase water" and "steam" may each refer to water in a vapor state.
Mobilized, DME-diluted oil in the reservoir 103, along with liquid-phase water containing dissolved DME and any other condensed components of the working fluid, may flow to the production well 106 via gravity drainage. Production fluid may then be produced to surface via the production well 106. In some embodiments, a pump 107 may be installed in the production well 106 to lift the production fluid to surface.

[0062] As shown in Figure 2A, as the heated vapor-phase working fluid is injected into the reservoir 103 via the injection well 104, a vapor chamber 110 may be formed in the reservoir 103. As used herein, "vapor chamber" refers to a volume of the reservoir that is at least partially filled with heated vapor-phase working fluid and at least partially depleted of oil. In this embodiment, the vapor-chamber 110 may be at least partially filled with vapor-phase DME, vapor-phase water, and any other vapor-phase components of the heated vapor-phase working fluid.

[0063] The vapor chamber 110 may grow upward and outward from the injection well 104 as indicated by arrows A. Mobilized DME-diluted oil and water containing dissolved DME may drain downward within or along the periphery of the vapor chamber 110 towards the production well 106 as indicated by arrows B. Within the vapor chamber 110, the mobilized oil may be displaced from the pore space within the reservoir 103 and the voided pore space may be filled with the DME, water vapor, and any other vapor-phase components of the heated vapor-phase working fluid.

[0064] In some embodiments, a liquid pool 112 of drained, DME-diluted oil and water containing dissolved DME may be maintained around and above the production well 106. The liquid pool 112 may act as a barrier to prevent vapor breakthrough into the production well 106. As used herein "vapor breakthrough" refers to heated vapor-phase working fluid entering the production well 106 such that vapor-phase fluid may be produced to the surface.

Date Recue/Date Received 2020-10-27

[0065] Referring again to Figure 1, in some embodiments, the production fluid produced from the production well 106 may be received at an optional treatment facility 109 where at least a portion of the DME and water may be separated from the oil in the production fluid. In some embodiments, the separated DME and water may be treated at the treatment facility 109 to remove residual contaminants such that the treated DME
and water may be recycled and used to generate new heated vapor-phase working fluid for injection. In some embodiments, the treated working fluid is received in a working fluid storage facility 111, where the treated working fluid may be combined with make-up working fluid. In some embodiments, the treated working fluid is primarily in liquid phase and the working fluid storage facility 111 is pressurized to maintain the treated working fluid in liquid-phase. In other embodiments, the working fluid storage facility 111 may comprise separate storage components for DME and water. In some embodiments, a pressurized storage component is provided for the DME and an atmospheric-pressure storage component is provided for the water. In some embodiments, separate supplies of make-up DME and make-up water may also be provided.

[0066] The system 100 may further comprise at least one heating system 116 to heat the working fluid to provide the heated vapor-phase working fluid for injection via the injection well 104. In some embodiments, the heating system 116 comprises an electrical heating system. The electrical heating system may comprise an electrical boiler or any other suitable type of electrical heating system. In other embodiments, the heating system 116 comprises a fired heating system. The fired heating system may be used to directly or indirectly heat the working fluid. In some embodiments, the fired heating system comprises a natural gas fired boiler that directly heats and vaporizes the working fluid. In other embodiments, the fired heating system comprises a natural gas fired boiler operatively connected to a condensing heat exchanger such that the boiler generates steam to provide heat input to the condensing heat exchanger in which the working fluid is heated and vaporized. In some embodiments, the heating system comprises two or more electrical or fired boilers. In other embodiments, the heating Date Recue/Date Received 2020-10-27 system 116 comprises any other suitable heating system or combination of heating systems.

[0067] In some embodiments, the heating system 116 receives working fluid from the working fluid storage facility 111. In other embodiments, the heating system 116 receives separate fluid streams of DME and water from separate DME and water storage components of the working fluid storage facility 111. In some embodiments, the separate fluid streams are combined in a single boiler of the heating system 116. In other embodiments, the heating system 116 comprises a first boiler to heat the fluid stream of DME and a second boiler to heat the fluid stream of water. As discussed in more detail below, as the heated vapor-phase working fluid may comprise a relatively small proportion of vapor-phase water, the second boiler may have a smaller capacity than the first boiler. In some embodiments, the second boiler may have a much smaller capacity than conventional boilers used in SAGD operations.

[0068] In some embodiments, the system 100 further comprises one or more sensors installed in the injection and/or production wells 104 and 106. As shown in Figure 1, in some embodiments, at least one pressure sensor 113 and at least one temperature sensor 115 may be installed in the injection and/or production wells 104 and 106. In Figure 1, pressure sensors 113 are shown as triangles and temperature sensors 115 are shown are circles. It is to be understood that the number and arrangement of the pressure and temperature sensors 113 and 115 in Figure 1 are shown for example purposes only and embodiments are not limited to any specific number and arrangement of sensors.

[0069] In some embodiments, at least one pressure sensor 113 is installed in the injection well 104 to provide a means to monitor pressure within the vapor chamber 110.
In some embodiments, at least one pressure sensor 113 is installed in the horizontal section of the production well 106, to provide a measurement of bottom-hole pressure.
Each of the pressure sensors 113 may comprise a piezometer, bubble tube-type system, or any other suitable pressure sensing means. In some embodiments, at least one temperature sensor 115 is installed in the injection well 104 to monitor the Date Recue/Date Received 2020-10-27 temperature of the heated vapor-phase working fluid. In some embodiments, at least one temperature sensor 115 is installed in the production well 106 to monitor the temperature of the production fluid. Each of the temperature sensors 115 may comprise a thermocouple, a fiber optic array, or any other suitable temperature sensing means.

[0070] Optionally, at least one heater (not shown) may be installed in the injection well 104 and/or the production well 106. In some embodiments, the heater is an electrical heater. As one example, the electrical heater may comprise a Hot-TubeTm downhole electrical heating system supplied by PetroSpec Engineering Ltd.TM.
In other embodiments, the heater may comprise any other suitable type of heater.

[0071] The system 100 may further comprise a control system 118. The control system 118 may be configured to implement embodiments of the methods described herein. The control system 118 may be operatively connected to the heating system 116 to control operation thereof. In some embodiments, the control system 118 may also be operatively connected to the optional pressure and/or temperature sensors 113 and 115. In some embodiments, the control system 118 may receive input from the pressure and temperature sensors 113 and 115 and may control the operation of the heating system 116 based on such input. In some embodiments, the control system 118 may also be operatively connected to the optional heater in the injection well 104 and/or the production well 106. The control system 118 may control the operation of the heater(s) as required to maintain the temperature in the injection well 104 and/or production well 106 within a desired range.

[0072] In some embodiments, the system 100 may comprise a plurality of well pairs 101 within the reservoir 103. In some embodiments, the plurality of well pairs 101 may be installed in the same pay interval 105. In other embodiments, the reservoir 103 may comprise a plurality of pay intervals 105 and at least one well pair 101 may be installed in each pay interval 105. In some embodiments, the plurality of well pairs 101 may be arranged in at least one parallel array known as pad (not shown).

Date Recue/Date Received 2020-10-27

[0073] Figure 2B shows the well pair 101 with an adjacent well pair 101B.
It will be understood that although only two well pairs 101, 101B are shown in Figure 2B, any suitable number of well pairs can be arranged in a similar manner. Hereafter, the well pair 101 is also referred to as the first well pair 101 and the adjacent well pair 101B is also referred to as the second well pair 101B. The second well pair 101B may comprise an injection well 104B and a production well 106B which may be approximately parallel to the injection well 104 and production well 106 of the first well pair 101.
Injection of heated vapor-phase working fluid via the injection well 104B may lead to the formation of a vapor chamber 110B, similar to the vapor chamber 110 of the first well pair 101. A
liquid pool 112B may act as a barrier to prevent vapor breakthrough into the production well 106B.

[0074] As shown in Figure 2B, the first well pair 101 and the second well pair 101B may have an inter-well-pair spacing 120. As used herein, "inter-well-pair spacing"
refers to the lateral distance between adjacent well pairs within the same reservoir 103.
In some embodiments, inter-well-pair spacing may be expressed as a multiple of the pay interval thickness since the ratio of pay interval thickness to inter-well-pair spacing provides an approximate proxy for the average slope of the vapor chamber boundary along which the mobilized oil drains when the vapor chamber is fully developed laterally.
In some embodiments, the inter-well-pair spacing 120 may be similar to that of conventional SAGD operations. In these embodiments, the ratio of inter-well-pair spacing 120 to pay interval 105 thickness may range from between about 4:1 and about 5:1 to correspond to that of conventional SAGD operations. In other embodiments, the inter-well-pair spacing 120 may be less than that of conventional SAGD
operations. In some embodiments, the ratio of inter-well-pair spacing 120 to pay interval 105 thickness may be about 4:1 or less. In some embodiments, the ratio of inter-well-pair spacing 120 to pay interval 105 thickness may be between about 1.5:1 and about 3:1.

[0075] As discussed in more detail below, one advantage of embodiments of the thermal oil recovery processes described herein is the ability to operate at lower operating temperatures than conventional SAGD processes. SAGD processes are Date Recue/Date Received 2020-10-27 typically implemented in thick reservoirs with a pay interval 105 thickness of about 20m and above. However, the processes described herein can also be applied to thin reservoirs with a pay interval 105 thickness less than that of SAGD processes.
To offset the lower oil production rate expected due to the thinner pay interval 105, a smaller inter-well-pair spacing 120 can be used to achieve an acceptable oil production rate.

[0076] Figure 3 is a flowchart of an example method 300 for recovering viscous oil from a water-wet subterranean reservoir that may be implemented using the system 100 of Figure 1.

[0077] At block 302, flow communication between the at least one injection well and the at least one production well is established. As used herein, "flow communication" refers to fluid communication between the injection well 104 and the production well 106, via the reservoir 103, such that viscous oil in the reservoir 103, mobilized by fluids injected through the injection well 104, may flow to the production well 106.

[0078] In some embodiments, flow communication between the injection well and the production well 106 may be established through a process known as "initialization". Initialization may comprise mobilizing oil in an inter-well zone 108, between the injection well 104 and the production well 106 such that mobilized oil in the inter-well zone 108 can flow to the production well 106.

[0079] Initialization may be achieved by any suitable mechanism. Non-limiting examples of initialization mechanisms include conductive heating and solvent dissolution, which may be enhanced by inter-well differential pressure modulation and/or geomechanical dilation effects. In some embodiments, any suitable sequential or concurrent combination of the initialization mechanisms described herein may be used to establish flow communication between the injection well 104 and the production well 106.

[0080] In some embodiments, where the injection and production wells 104 and 106 of the well pair 101 are thermally completed, initialization may be based solely or Date Recue/Date Received 2020-10-27 predominantly on conductive heating of the inter-well zone 108 by heating the injection and production wells 104 and 106.

[0081] In some embodiments, the injection and production wells 104 and 106 are heated by injecting steam through both the injection well 104 and the production well 106 in a process known as "steam circulation". In other embodiments, initialization may be achieved or assisted by an extended period of a heated vapor-phase solvent injection, either alone or in combination with steam. The solvent may be injected through the injection well 104 or through both the injection and production wells 104 and 106. The solvent may be any solvent that is effective in reducing the viscosity of viscous oil by dilution. Non-limiting examples of suitable solvents include: single-component solvents including DME, propane, butane, pentane, hexane, heptane, octane, nonane, decane, undecane, dodecane, tridecane, and tetradecane; multicomponent solvents including diluent, natural gas condensate, kerosene, and naptha; and combinations thereof.

[0082] During initialization of a thermally completed well pair 101, the temperature at the injection well 104 and production well 106 may range from about 50 C to 250 C, depending on the temperature rating of the well completion. In some embodiments, the overall duration of the initialization period may be approximately two to six months.

[0083] In other embodiments, where the injection and production wells 104 and 106 of the well pair 101 are not thermally completed, the maximum temperature at the injection and production wells 104 and 106 during initialization may be limited, for example to less than 100 C. This temperature limitation may lengthen the time required for the initialization period if initialization is based solely or predominantly on a conductive heating mechanism. Therefore, in some embodiments, initialization may instead be based solely or predominantly on a solvent dissolution mechanism.
In these embodiments, DME may be particularly useful as a solvent due to its relatively high effective rate of diffusion into oil under water-wet reservoir conditions.

Date Recue/Date Received 2020-10-27

[0084]
In some embodiments, liquid-phase DME may be injected, at or above reservoir pressure, through the injection well 104 or through both the injection and production wells 104 and 106. Liquid-phase DME may be injected for a suitable "solvent soaking" period during which no production fluids are produced via the production well 106 to surface. In some embodiments, the duration of the solvent soaking period may be about two to nine months.

[0085]
In some embodiments, to limit the potential loss of DME to the water-saturated zone 114 below the reservoir 103, DME may be injected through the injection well 104 but not through the production well 106. In some embodiments, a liquid-phase hydrocarbon solvent may be injected through the production well 106 in place of DME.
Non-limiting examples of suitable liquid-phase hydrocarbon solvents include:
single-component solvents including propane, butane, pentane, hexane, heptane, octane, nonane, decane, undecane, dodecane, tridecane, and tetradecane; multicomponent solvents including diluent, natural gas condensate, kerosene, and naptha, and combinations thereof.

[0086]
The liquid-phase DME and optional hydrocarbon solvent injected during the solvent soaking period may be heated or unheated. If heated, the DME and optional hydrocarbon solvent may be injected at a temperature of about 50 C to about 250 C, to maintain the temperature at the injection and production wells 104 and 106 between about 50 C and about 100 C. In some embodiments, the temperature at the injection and production wells 104 and 106 is between about 80 C and 100 C. In some embodiments, the liquid-phase DME and optional hydrocarbon solvent may be heated at surface e.g. by the heating system 116. In other embodiments, the optional heater (not shown) installed in at least one of the injection well 104 and the production well 106 may be operated to maintain the temperature at the injection and production wells 104 and 106 within the desired range.

[0087]
In other embodiments, any other suitable initialization method may be used to establish flow communication between injection well 104 and production well Date Recue/Date Received 2020-10-27 106. An alternative DME-based initialization method for non-thermally completed wells will be described in more detail below with reference to Figure 5.

[0088] In some embodiments, to determine if adequate flow communication has been established between the injection well 104 and the production well 106 by any of the initialization methods described herein, periodic testing may be performed comprising monitoring a response in the production well 106 to an increase in pressure in the injection well 104, or vice versa. In some embodiments, the response is monitored by measuring pressure in the production well 106 or injection well 104 via at least one pressure sensor 113 installed therein.

[0089] At block 304, a heated vapor-phase working fluid comprising vapor-phase DME and vapor-phase water is injected via the at least one injection well 104.
As the heated vapor-phase working fluid is injected via the injection well 104, a production fluid may be produced via the production well 106 to surface.

[0090] The vapor-phase water may only be a small portion of the heated vapor-phase working fluid. In some embodiments, the vapor-phase water may be about 5% or lower of a total volume of the heated vapor-phase working fluid by liquid volume equivalent. In some embodiments, the vapor-phase water is about 3% or lower of the total volume of the heated vapor-phase working fluid by liquid volume equivalent.

[0091] In some embodiments, the ratio of vapor-phase DME to vapor-phase water is between about 20:1 and about 250:1 by liquid volume equivalent. In some embodiments, the ratio of vapor-phase DME to vapor-phase water is about 20:1, about 25:1, about 35: 1, about 187:1, about 200:1, or about 233:1. In some embodiments, the ratio of vapor-phase DME to vapor-phase water remains approximately the same over time. In other embodiments, the ratio may be adjusted over time. For example, in some embodiments the ratio of vapor-phase DME to vapor-phase water may be increased during the later stages of operation of well pair 101.

[0092] In some embodiments, injecting the heated vapor-phase working fluid comprises co-injecting a first fluid stream comprising heated vapor-phase DME
and a Date Recue/Date Received 2020-10-27 second fluid stream comprising heated vapor-phase water such that the first fluid stream and second fluid stream combine in the injection well 104 to form the heated vapor-phase working fluid.

[0093] In some embodiments, the first fluid stream is injected at a first temperature and the second fluid stream is injected at a second temperature.
The first and second temperature may each be in the range of about 50 C to about 250 C.
In some embodiments, the first and second temperatures are selected to achieve an operating temperature in the range of about 50 C to about 100 C (e.g. about 80 C), as described in more detail below. In some embodiments, the first and second temperatures are approximately the same. In other embodiments, the second temperature may be higher than the first temperature (or vice versa). In some embodiments, the first and/or second temperatures may be adjusted as needed to maintain the operating temperature in the desired range. In other embodiments, the first and second fluid streams are injected at any other suitable temperature. In some embodiments, the injection pressure may range from about 500kPa to about 5,000kPa.

[0094] In other embodiments, the heated vapor-phase working fluid is formed prior to injection via the injection well 104. In some embodiments, the heated vapor-phase working fluid is formed by combining heated vapor-phase DME and vapor-phase water. In other embodiments, the heated vapor-phase working fluid is formed by combining unheated liquid or vapor-phase DME and liquid water, and heating the combination of DME and water to form the heated vapor-phase working fluid. In other embodiments, the heated vapor-phase working fluid may be formed by bubbling heated vapor-phase DME through liquid water. In other embodiments, the heated vapor-phase working fluid may be formed by any other suitable means.

[0095] In embodiments in which the heated vapor-phase working fluid is formed prior to injection, the heated vapor-phase working fluid may be injected at a temperature of between about 50 C to about 250 C. In some embodiments, the temperature is selected to achieve an operating temperature in the range of about 50 C to about 100 C
Date Recue/Date Received 2020-10-27 (e.g. about 80 C), as described in more detail below. In some embodiments, the injection pressure may range from about 500kPa to about 5,000kPa.

[0096] In some embodiments, the heated vapor-phase working fluid is superheated. As used herein, "superheated" refers to heating a fluid to beyond its saturation temperature at a given pressure. In some embodiments, the vapor-phase working fluid is superheated before or during injection. In some embodiments, the vapor-phase working fluid has a degree of superheat of between about 0 C to about 25 C above the saturation temperature of the working fluid at a given pressure. In some embodiments, the vapor-phase working fluid has a degree of superheat of about 20 C.
In some embodiments, superheating the vapor-phase working fluid may ensure that all components therein are injected in the vapor phase. In these embodiments, the superheated vapor-phase working fluid may thereby take greater advantage of the working fluid's heat transport capacity than a heated vapor-phase working fluid that is not superheated.

[0097] As the heated vapor-phase fluid is injected via the injection well 104, the vapor chamber 110 may form as shown in Figure 2A and described above. Without being limited by theory, it is believed that the combination of vapor-phase DME and a small amount of vapor-phase water in the injected heated vapor-phase working fluid may act synergistically to accelerate mobilization of viscous oil at the boundary of and within the vapor chamber 110 as the vapor chamber 110 expands into the surrounding oil-saturated, water-wet reservoir 103. Briefly, when heated DME vapor is injected into the water-wet reservoir 103, it may diffuse quickly into the water films on the surface of the water-wet solids at the vapor chamber 110 boundary, thereby achieving an expanded area of contact with the oil in the pore space bounded by these water films.
The heated DME vapor may thereby dissolve into the oil in these pore spaces and reduce the viscosity of the oil by both heat and dissolution. If DME is injected alone, without vapor-phase water, the water-wet reservoir may eventually become desiccated, resulting in an oil-wet condition that limits the further dissolution of DME
beyond the vapor chamber 110 boundary. However, in the methods described herein, the small Date Recue/Date Received 2020-10-27 amount of vapor-phase water in the heated vapor-phase working fluid may condense to liquid-phase water at the vapor chamber 110 boundary and the liquid-phase water may dissolve DME therein to facilitate transfer of DME to the water film of the water-wet solids beyond the vapor chamber 110 boundary. By this mechanism, the DME may achieve expanded contact with the oil in the pore space beyond the vapor chamber 110 boundary as well as accelerated mass transfer into such oil. The net effect may thereby be accelerated dilution and mobilization of the oil by the DME. Condensation of the vapor-phase water at the colder boundary of the vapor chamber 110 may also provide additional heat, thereby increasing the rate at which oil beyond the vapor chamber 110 boundary is heated.

[0098]
In some embodiments, the method 300 further comprises determining a suitable operating temperature. In some embodiments, a suitable operating temperature may be determined by first selecting a suitable total pressure at which to operate the vapor chamber 110. The total operating pressure may have an upper limit that is determined with respect to avoiding geomechanical failure of the confining reservoir caprock (seal). Then, for a given total operating pressure, the operating temperature may be determined based on the composition of the heated vapor-phase working fluid, i.e. the thermodynamic properties and partial pressure for each of its constituents (such as DME vapor, water vapor, vapor-phase hydrocarbon solvent species, etc.). As shown in Figure 7, the vapor-liquid equilibrium behaviour of a mixture is defined as an envelope rather than as a single curve, such that for a given total pressure, a specific vapor mixture condenses to liquid over a temperature range rather than at a single temperature. Therefore, the relationship between total operating pressure and temperature for a multi-component vapor-phase working fluid is more complicated than for a single component vapor-phase working fluid. For example, measured operating pressure and temperature data for a subset of the conditions explored in the Examples below are presented in Table 1, showing that for the same operating pressure, operating temperature varies with the composition of the working fluid.

Date Recue/Date Received 2020-10-27 Total Operating Operating Composition Injection Temperature Pressure Temperature 180:1, DME:water 2,200 kPa 82 C 20 C superheat 35:1, DME:water 2,200 kPa 96 C 20 C superheat Steam only 2,200 kPa 215 C 225 C (10 C
superheat)

[0099] Therefore, in some embodiments, a combination of experimental measurements and fluid system modelling may be used to define, at least approximately, the relationship between total operating pressure, the partial pressure of various components in a multi-component vapor-phase working fluid, and operating temperature.

[00100] In some embodiments, the operating temperature of the vapor chamber 110 ranges from about 50 C to about 100 C. In some embodiments, the operating temperature of the vapor chamber 110 is between about 80 C and about 100 C. In some embodiments, the operating temperature is about 80 C. Therefore, in some embodiments, the operating temperature may be considerably lower than that of conventional steam-based thermal oil recovery processes, such as SAGD, that typically operate at or above 200 C.

[00101] In some embodiments, the method 300 further comprises maintaining the operating temperature within a desired or target range, for example, within any of the ranges described above. In some embodiments, the total pressure and temperature in the vapor chamber 110 may be monitored to determine if the operating temperature is outside of the desired range and, if so, the operating temperature may be adjusted as needed.

[00102] In some embodiments, either or both of the total injection pressure or the composition of the injected vapor-phase working fluid may be adjusted to maintain the operating temperature within the desired range. For a fixed vapor-phase fluid composition, operating temperature is directly related to total operating pressure which Date Recue/Date Received 2020-10-27 may be manipulated by changing the injection pressure. For a fixed total operating pressure, operating temperature may be increased by increasing the concentration of higher boiling point constituents within the injected vapor-phase working fluid.
Conversely, for a fixed total operating pressure, operating temperature may be decreased by decreasing the concentration of higher boiling point constituents within the injected vapor-phase working fluid.

[00103] In other embodiments, the optional heater in the injection well

104 and/or the production well 106 may be used to maintain the operating temperature in the desired range. For example, if the operating temperature falls below the desired range, the heater may be operated to heat the injection well 104 and/or production well 106 to raise the operating temperature as desired. In some embodiments, the operating temperature may be maintained by operation of the heater alone. In other embodiments, the operating temperature may be maintained by a combination of operation of the heater and by adjusting the total injection pressure and/or composition of the injected vapor-phase working fluid as described above.
[00104] As the heated vapor-phase working fluid is injected via the injection well 104, DME-diluted oil and water containing dissolved DME (and any other condensed components of the working fluid) may drain to the production well 106 by gravity drainage to be produced to surface. In some embodiments, the liquids draining to the production well 106 may comprise a relatively large oil phase comprising the DME-diluted oil. Compared to steam-dominated processes such as SAGD, the volume of the draining oil phase may comprise a significantly larger percentage of the total volume of draining liquids, which may increase the relative permeability of the draining oil phase, thereby facilitating its transport to the production well 106.

[00105] In some embodiments, the method 300 may further comprise maintaining the level of the drained liquid pool 112 around the production well 106 or above a threshold level to prevent vapor break-through. In some embodiments an instantaneous production rate of the production fluid may be adjusted to maintain the level of the drained liquid pool 112 at or above the threshold. As used herein, "instantaneous Date Recue/Date Received 2020-10-27 production rate" refers to the produced volume of production fluid over a short time period, for example, the volume of produced fluid per hour, as opposed to the cumulative production rate over time. In other embodiments, the level of the liquid pool 112 may be maintained at or above a threshold level by any other suitable means.

[00106] As demonstrated in the Examples below, in some embodiments, a cumulative production rate of the production fluid may be similar to or approximately the same as that of a steam-only process operating at over 200 C and may be better than that of a DME-only process operating at less than 100 C. As used herein, "cumulative oil production rate" refers to the cumulative volume of production fluid produced over time.

[00107] Therefore, in some embodiments, the method 300 may allow for lower operating temperatures compared to typical steam-based processes without sacrificing oil production performance as in typical solvent-dominated processes. Lower operating temperatures may provide a number of economic and/or environmental advantages including at least one of: reducing the overall energy intensity; reducing or eliminating the need for expensive thermal well completions for at least a portion of the injection well and/or the production well; and reducing or eliminating the need for large-capacity, high-pressure steam generation and related boiler feedwater treatment facilities typically associated with steam-dominated processes such as SAGD.

[00108] A major challenge to the economic viability of conventional solvent-dominated oil recovery processes is the accumulation of valuable solvent within the reservoir, both within the oil-depleted vapor chamber and in the reservoir just beyond the vapor chamber boundary. Moreover, this solvent inventory build-up problem may worsen if operation the solvent-dominated process continues after the oil rate has plateaued, since the bulk of the solvent produced back to surface is dissolved in produced oil. In the thermal oil recovery processes described herein, if the inter-well-pair spacing is similar to that of conventional SAGD operations, the oil rate may be expected to plateau and decline after about three years of operation, by which time Date Recue/Date Received 2020-10-27 about 30-40% of the target oil recovery factor may be achieved. In some embodiments, the target oil recovery factor is approximately 60 to 70% of original oil in place (00IP).

[00109] As a result, in some embodiments, the method 300 may be implemented in an embodiment of the system 100 in which the inter-well-pair spacing is less than that of conventional SAGD operations. The lower operating temperatures of the heated vapor chamber 110 as described above may allow lower cost well completions to be used that may offset increased costs for the greater number of well pairs 101 required to achieve smaller inter-well-pair spacing. In some embodiments, the inter-well-pair spacing may be small enough to achieve 100% of the designed oil recovery factor within about five to seven years. The reduced inter-well-pair spacing may therefore allow the target oil recovery factor to be achieved faster and may eliminate or reduce the need for continued DME injection past the oil rate plateau. Therefore, the reduced inter-well-pair spacing may help to reduce the accumulation of DME in the reservoir 103.

[00110] Furthermore, in some embodiments, additional steps may be taken to recover injected DME from the reservoir 103. An example method 600 with steps to recover injected DME is shown in Figure 6 and discussed in more detail below.

[00111] Variations of the method 300 are also possible. In some embodiments, the heated vapor-phase working fluid further comprises at least one volatile hydrocarbon solvent that is effective in reducing the viscosity of viscous oil by dilution. As used herein, "volatile", when used in reference to a solvent, refers to a solvent for which the boiling point is less than that of water. Non-limiting examples of volatile hydrocarbon solvents include propane, butane, and combinations thereof. The volatile hydrocarbon solvent may function to diffuse into and further mobilize the oil at the vapor chamber 110 boundary that has already been partially mobilized by the combined effects of the mild heating and dilution by vapor-phase DME.

[00112] In some embodiments, the volatile hydrocarbon solvent is added to the heated vapor-phase working fluid in addition to the DME component. In other Date Recue/Date Received 2020-10-27 embodiments, the volatile hydrocarbon solvent replaces a portion of the DME
component in the heated vapor-phase working fluid. In some embodiments, the ratio of DME to DME plus volatile hydrocarbon solvent may range from between about 1.0 to about 0Ø In some embodiments, the ratio of DME to DME plus volatile hydrocarbon solvent decreases with time and increasing recovery factor. In some embodiments, the ratio of total solvent (DME plus volatile hydrocarbon solvent) to vapor-phase water in the heated vapor-phase working fluid is about 20:1 to about 250:1. The vapor-phase water may therefore remain at about 5% or lower of the total volume of the heated vapor-phase working fluid by liquid volume equivalent.

[00113] As described in the Examples below, substitution of a portion of the DME
in the heated vapor-phase working fluid with a volatile hydrocarbon solvent may reduce asphaltene precipitation in the reservoir 103. Therefore, in some embodiments, a concentration of volatile hydrocarbon solvent in the heated vapor-phase working fluid may be selected based on a desired degree of asphaltene precipitation. In some embodiments, the concentration of the volatile hydrocarbon solvent may be selected such that the degree of asphaltene precipitation is controlled to be approximately constant during the operating life of the recovery process. In other embodiments, the concentration of the volatile hydrocarbon solvent may be adjusted over time such that the degree of asphaltene precipitation varies over the operating life of the recovery process.

[00114] In some embodiments, the volatile hydrocarbon solvent is combined with vapor-phase DME and vapor-phase water prior to injection to form the heated vapor-phase working fluid. In other embodiments, the volatile hydrocarbon solvent is combined with heated vapor-phase DME in the first fluid stream and the first fluid stream is co-injected with the second fluid stream comprising heated vapor-phase water. In other embodiments, the hydrocarbon solvent is co-injected as a third fluid stream, separate from the first and second fluid streams.

[00115] Within the operating temperature of the vapor chamber 110, different solvents may exhibit differing temperature-dependent solubility in oil. For example, the Date Recue/Date Received 2020-10-27 solubility of DME and other volatile hydrocarbon solvents may decline with increasing temperature. Therefore, in some embodiments, the composition of the volatile hydrocarbon solvent may be adjusted to optimize oil production at a given operating temperature. As one example, the volatile hydrocarbon solvent may comprise a mixture of butane and propane and the ratio of butane to propane may be adjusted based on the desired operating temperature. For example, a high butane to propane ratio may be used at higher operating temperatures (e.g. about 80 C to about 100 C) and a low butane to propane ratio may be used at lower operating temperatures (e.g.
about 50 C
to about 79 C).

[00116] In some embodiments, the heated vapor-phase working fluid may further comprise a non-condensable gas (NCG). As used herein, a "non-condensable" gas refers a gas that does not condense nor readily dissolve into oil under reservoir conditions. Examples of suitable non-condensable gases include, but are not limited to, natural gas, carbon dioxide, nitrogen, carbon monoxide, flue gas, methane, ethane, and combinations thereof.

[00117] In some embodiments, the NCG is combined with vapor-phase DME and vapor-phase water prior to injection to form the heated vapor-phase working fluid. In other embodiments, the NCG is co-injected as a third fluid stream, separate from the first and second fluid streams. In other embodiments, the NCG may comprise methane or carbon dioxide that already exist in the reservoir 103 and therefore form part of the recycled DME and hydrocarbon solvent (if used) that is recycled for re-injection, as described in more detail below.

[00118] In some embodiments, the amount of NCG is relatively minor compared to the other components of the heated vapor-phase working fluid. For example, the NCG
may comprise about 5% or less of the heated vapor-phase working fluid by liquid volume equivalent. In some embodiments, injection of NCG is implemented in the later stages of the overall operating lifecycle of the well pair 101 such that oil production performance during the early and middle stages of the lifecycle is not detrimentally affected. In some embodiments, injection of NCG in the later stages of the operating Date Recue/Date Received 2020-10-27 lifecycle may facilitate recovery of injected DME as described in more detail below with respect to the method 600.

[00119] Figure 4 is a flowchart of another example method 400, implemented using the system 100 of Figure 1. The method 400 may be used to recycle at least a portion of the DME from the production fluid for re-injection.

[00120] At block 402, flow communication between the at least one injection well and the at least one production well is established. The steps at block 402 may be similar to the steps at block 302 as described above.

[00121] At block 404, a heated vapor-phase working fluid comprising vapor-phase DME and vapor-phase water is injected via the at least one injection well 104.
As the heated vapor-phase working fluid is injected via the injection well 104, a production fluid may be produced via the production well 106 to surface. The steps of block 404 may be similar to the steps of block 304 as described above.

[00122] At block 406, at least a portion of produced DME is separated from the production fluid. As used herein, "produced DME" refers to DME in the oil phase of the production fluid as well as the DME dissolved in the water phase of the production fluid.
In some embodiments, at least a portion of the produced DME is separated from the production fluid at the treatment facility 109.

[00123] In some embodiments, at least a portion of the DME in the oil phase of the production fluid is separated from the oil. In some embodiments, the water phase containing dissolved DME in the production fluid is separated from the oil phase and at least a portion of the DME in the water phase is separated from the water. In other embodiments, the water phase may be separated from the oil phase without separating the dissolved DME from the water.

[00124] In some embodiments, the heated vapor-phase working fluid further comprises at least one volatile hydrocarbon solvent and at least a portion of the hydrocarbon solvent may also be separated from the production fluid.

Date Recue/Date Received 2020-10-27

[00125] At block 408, at least a portion of the separated, produced DME is recycled to form new heated vapor-phase working fluid for injection. In some embodiments, the separated DME is treated to remove other contaminants and then the treated DME may be used to form new heated vapor-phase working fluid. In some embodiments, the separated DME is treated at the treatment facility 109.

[00126] In some embodiments, the water may also be recycled to form new heated vapor-phase working fluid for injection. In some embodiments, the water may also be treated to remove contaminants and then used to form new heated vapor-phase working fluid. In some embodiments, the hydrocarbon solvent may also be recycled to form new heated vapor-phase working fluid for injection. In some embodiments, the hydrocarbon solvent may also be treated to remove contaminants and then used to form new heated vapor-phase working fluid.

[00127] As discussed above, the production fluid may comprise methane and/or carbon dioxide that are naturally present in the reservoir 103. In some embodiments, it may not be practically or economically feasible to completely remove the methane or carbon dioxide from the DME (and the hydrocarbon solvent, if used). Therefore, in some embodiments, at least a portion of the methane or carbon dioxide may be recycled along with the DME and hydrocarbon solvent to form the new heated vapor-phase working fluid.

[00128] Figure 5 is a flowchart of an example method 500, implemented using the system 100 of Figure 1, with additional steps for establishing flow communication between the injection well 104 and the production well 106. The method 500 of Figure 5 may be used to achieve faster initialization for a non-thermally completed well pair 101 than the initialization methods described above.

[00129] At block 502, a liquid-phase initialization fluid is injected for a first time period. As used herein, the term "initialization fluid" is equivalent to a working fluid and is used for ease of reference only to distinguish between a fluid injected during an initialization stage and a fluid injected during a production stage. The liquid-phase Date Recue/Date Received 2020-10-27 initialization fluid may comprise liquid-phase DME. The first time period may be similar to the solvent soaking period described above at block 302 and during the first time period, no displaced fluids may be produced via the production well 106 to surface. In some embodiments, the duration of the first time period is about two to six weeks.

[00130] The liquid-phase initialization fluid may be injected through the injection well 104 or through both the injection well 104 and the production well 106.
In some embodiments, the liquid-phase initialization fluid may only be injected through the injection well 104 (and not through the production well 106) to limit loss of DME to the water-saturated zone 114 below the reservoir 103.

[00131] In some embodiments, the liquid-phase initialization fluid may further comprise at least one liquid-phase hydrocarbon solvent. Non-limiting examples of suitable liquid-phase hydrocarbon solvents include: single-component solvents including propane, butane, pentane, hexane, heptane, octane, nonane, decane, undecane, dodecane, tridecane, and tetradecane; multicomponent solvents including diluent, natural gas condensate, kerosene, and naptha, and combinations thereof.

[00132] In some embodiments, liquid-phase DME may be injected through the injection well 104 and the liquid-phase hydrocarbon solvent may be injected through the production well 106. In some embodiments, the liquid-phase DME and optional hydrocarbon solvent may be heated at surface prior to injection. In some embodiments, the optional heater installed in the injection well 104 and/or the production well 106 may be used to maintain the temperature at the injection well 104 and the production well 106 within a desired range, for example between about 50 C and about 100 C or between about 80 C and about 100 C.

[00133] At block 504, injection of the liquid-phase initialization fluid is ceased and a heated vapor-phase initialization fluid is injected for a second time period. In some embodiments, the duration of the second time period may be about two to five months.

[00134] The heated vapor-phase initialization fluid may comprise vapor-phase DME and vapor-phase water. The vapor-phase water may comprise 5% or lower of a Date Recue/Date Received 2020-10-27 total volume of the heated vapor-phase initialization fluid by liquid volume equivalent.
The heated vapor-phase initialization fluid may be similar to, or the same as, the heated vapor-phase working fluid as described above.

[00135] The heated vapor-phase initialization fluid may be injected through the injection well 104 or through both the injection well 104 and the production well 106. In some embodiments, the heated vapor-phase initialization fluid may only be injected through the injection well 104 (and not through the production well 106) to limit loss of DME to the water-saturated zone 114 below the reservoir 103.

[00136] In some embodiments, the heated vapor-phase initialization fluid further comprises at least one vapor-phase hydrocarbon solvent. The vapor-phase hydrocarbon solvent may be any of the solvents described above for the liquid-phase hydrocarbon solvent. In some embodiments, vapor-phase DME may be injected through the injection well 104 and the vapor-phase hydrocarbon solvent may be injected through the production well 106.

[00137] During the second time period, an initial production fluid comprising mobilized, DME-diluted oil (or DME- and hydrocarbon solvent-diluted oil) may be produced to surface via the injection well 104 and/or the production well 106.
In some embodiments, the initial production fluid is lifted to surface using the pump 107 installed in the production well 106 and/or a pump installed in the injection well 104 (not shown).

[00138] In some embodiments, production of the initial production fluid may be continuous. In other embodiments, the initial production fluid may be produced intermittently. For example, in some embodiments, there may be alternating periods of injection through both the injection well 104 and the production well 106 and production through one or both of the injection well 104 and the production well 106.

[00139] Therefore, in some embodiments, by producing a small amount of mobilized oil to surface, a small amount of heated vapor-phase initialization fluid may fill the voided pore space of the reservoir 103 from which the mobilized oil was displaced.
A "mini" vapor chamber may thereby be created in the reservoir 103 around the well Date Recue/Date Received 2020-10-27 pair 101 to facilitate subsequent convective heating and solvent mass transfer to the boundary of the mini vapor chamber. The overall duration of the initialization period, including both the first time period and the second time period, may therefore be about three to six months.

[00140] In some embodiments, to determine if adequate flow communication has been established between the injection well 104 and the production well 106 during the second time period, periodic testing may be performed as described above.

[00141] At block 506, injection of the heated vapor-phase initialization fluid is ceased and a heated vapor-phase working fluid comprising vapor-phase DME and vapor-phase water is injected via the injection well 104. A production fluid may be produced via the production well 106. The steps at block 506 may be similar to those of block 304 of the method 300 as described above.

[00142] Figure 6 is a flowchart of another example method 600, implemented using the system 100 of Figure 1, with additional steps for recovering injected DME.

[00143] At block 602, flow communication between the at least one injection well and the at least one production well is established. The steps at block 602 may be similar to block 302 of the method 300 (or blocks 502 and 504 of the method 500) as described above.

[00144] At block 604, a heated vapor-phase working fluid comprising vapor-phase DME and vapor-phase water is injected via the injection well 104. As the heated vapor-phase working fluid is injected via the injection well 104, a production fluid may be produced via the production well 106 to surface. The steps of block 604 may be similar to the steps of block 304 as described above.

[00145] At block 606, following a suitable operating period of the well pair 101, injection of the heated vapor-phase working fluid may be ceased and an NCG may be injected via the injection well 104. The NCG may be any of the NCG listed above with respect to the heated vapor-phase working fluid. The NCG may be heated or unheated.

Date Recue/Date Received 2020-10-27 In some embodiments, the switch to NCG injection occurs as the oil recovery factor approaches a target oil recovery factor.

[00146] Injection of NCG may function to maintain the operating pressure of the oil depleted vapor chamber 110 at or near the target operating pressure. The NCG
may thereby displace mobilized oil toward the production well 106 and effectively sweep at least a portion of the remaining DME from the vapor chamber 110 and the reservoir 103 just beyond the vapor chamber 110 boundary to the production well 106. In embodiments in which the heated vapor-phase working fluid further comprises at least one volatile hydrocarbon solvent, the NCG may also effectively sweep at least a portion of the remaining hydrocarbon solvent to the production well 106. By displacing mobilized oil to the production well 106, injection of NCG may also facilitate incremental oil recovery.

[00147] Therefore, in some embodiments, at least a portion of the DME (and other optional solvents) injected into the reservoir can effectively be recovered for re-use in the oil recovery methods described herein and/or for use in other applications.
EXAMPLES

[00148] Laboratory tests were undertaken to assess the viability of a thermal gravity drainage process comprising injection of a heated vapor-phase working fluid comprising vapor-phase DME and vapor-phase water, wherein the vapor-phase water is less than 5% of the total vapor-phase working fluid volume. Hereafter, the combination of heated vapor-phase DME and a small amount of vapor-phase water will be referred to as the "DME-vapor water test". For comparison, lab tests for steam-only injection (the "steam-only test"; equivalent to conventional SAGD) and heated vapor-phase DME-only injection (the "DME-only test") were also conducted. The lab tests were conducted using a 2D high pressure-high temperature test cell with Athabasca bitumen.
Example 1 - Laboratory Test Apparatus Date Recue/Date Received 2020-10-27

[00149] The test cell used in the experiments described herein was similar to that described in Deng et al., "Simulating the ES-SAGD process with solvent mixture in Athabasca reservoirs", 2010, Journal of Canadian Petroleum Technology Vol.
49(1) SPE-132488-PA, incorporated herein by reference. The test cell was constructed of stainless steel and its dimensions were 24 cm x 80 cm x 10 cm. The test cell was packed with frac sand resulting in a sandpack of 34.5% porosity and permeability of about 120 Darcy. The test cell was insulated and placed into a pressure vessel. The sandpack was then saturated with water and thereafter with dead Athabasca bitumen before the experiment. The procedure of saturating the sandpack is as follows:
the cell was first saturated with water by pumping 1.5 pore volume of water through the test cell, then the water was displaced with the Athabasca bitumen by pumping about 1.2 pore volume of oil through the cell. To speed up the bitumen saturating process, the test cell was pre-heated to about 55 C before pumping the bitumen. The test cell was then cooled to the lab temperature after the saturation process was completed. Data of the initial oil saturation and water saturation were recorded.
Example 2 - Initial Conditions

[00150] After the initial water and oil saturation processes, a total of 6218.0 gm of bitumen and 213.0 gm of water were in the sandpacked test cell, which corresponded to an initial oil saturation of 0.927 and an initial water saturation of 0.073.
Other model parameters are listed in Table 2 and operating parameters are listed in Table 3.

Permeability (Darcy) 120 Pore Volume (cc) 6689.4 Porosity (%) 34.5 Oil-in-Place (gm) 6218.0 Viscosity of dead -517,000 at 20 C
Athabasca bitumen (cp) -903 at 80 C
-16.8 at 180 C
Date Recue/Date Received 2020-10-27 Production Pressure -2200 kPa Steam injection -225 C
temperature DME injection temperature -125 C

[00151]
For the DME-vapor water test, the experimental operating scheme was as outlined in Table 4 below. In Table 4, CWE = cold water equivalent and "liquid" = liquid volume equivalent.

Stage Operating Duration (min) Injection Rate Scheme 1 Initialization 0 - 10 Starting at 33cc/min (CWE) each = Upper and lower wells = Produce from upper and lower 2 SAGD 10 - 20 Water at 33cc/min (CWE) 3 DME-water 20 - 240* DME at 28cc/min (liquid) Water at 0.15cc/min (CWE) 4 DME-water 240 - 250 DME at 20cc/min (liquid) Water at 1.0cc/min (CWE) DME-water 250 - 300 DME at 25cc/min (liquid) Water at 1.0cc/min (CWE) 6 DME-water 300 - 360 DME at 35cc/min (liquid) Water at 1.0cc/min (CWE) 7 DME-water 360 - 480 DME at 35cc/min (liquid) Water at 0.15cc/min (CWE) 8 DME-water 480 - 600 DME at 30cc/min (liquid) Water at 0.15cc/min (CWE) 9 N2 Injection 600 - 610 N2 at - 10L/m in N2 Injection 610 - 630 N2 at - 5L/min *There was an minor, unintentional spike in the water injection rate between 36 and 39 minutes due to an operational issue.

[00152]
For the steam-only test, stages 1 and 2 were the same as in Table 4 and steam injection at an injection rate of about 33 cc/min continued for the rest of the test.

Date Recue/Date Received 2020-10-27

[00153] For the DME-only test, the experimental operating scheme was as outlined in Table 5 below.

Stage Operating Duration (min) Injection Rate Scheme Starting at 33cc/min (CWE) each 1 Initialization 0 - 10 = Upper and lower wells = Produce from upper and lower 2 SAGD 10 - 30 Steam at 33cc/min (CWE) 3 Warm DME 30 - 420 DME at 30cc/min (liquid) 4 Warm DME 420 - 500 DME at 15cc/min (liquid) Warm DME 500 - 600 DME at 30cc/min (liquid) Example 3 - Experimental Test Results

[00154] Figure 8 shows the DME and vapor water injection rates by liquid equivalent for the DME-steam test. The density is around 0.635 g/cc. During stages 1 and 2 (initialization and SAGD), the total steam injection was around 990g.
During stages 3 to 8, total DME injection was around 11,125g and total water injection was around 190g.

[00155] Figure 9 shows the cumulative bitumen production for the DME-vapor water test. Total bitumen production was 4.522kg (recovery factor of about 72.8%) which included 0.232kg from stage 1 and 2 (initialization and SAGD), 4.152kg from stages 3 to 8 (DME and vapor water injection), and 0.138kg during stages 9 and 10 (N2 injection).

[00156] Figure 10 shows cumulative DME injection and DME production for the DME-vapor water test. Net DME injection was about 1.23kg. DME injection was -11.12 kg, DME production was -9.41kg, and -0.582 of DME was produced with N2 injection.
Total recovery was therefore -90.2%.

[00157] Figure 11 shows a comparison of the cumulative bitumen production from the steam-only test (SAGD), the DME-only test (DME - Test #1), and the DME-vapor Date Recue/Date Received 2020-10-27 water test (DME - Test #2). The DME-only test resulted in total bitumen production of about 2981g and the DME-vapor water test resulted in total bitumen production of about 4152 g.

[00158] Figure 12 shows a comparison of cumulative DME and steam injection from DME-only test (DME ¨ Test #1), and the DME-vapor water test (DME - Test #2).
Total DME injection for the DME-only test was about 10,118g. For the DME-vapor water test, total DME injection was about 11,125 g and total steam injection was about 190g.

[00159] The results for the first 300 minutes of each of the three experimental tests are summarized in Table 6 below.

Test Steam Injection DME Injection Bitumen Production (g) (g) (g) Steam only (SAGD) 10,230 N/A 2,683 DME-only 1,320 8,100 2,022 DME-vapor water 1,083 7,610 2,479 Example 4 ¨ Preliminary Observations on Asphaltene Precipitation

[00160] In the experimental tests with DME (i.e. DME-only and DME-vapor water), it was observed that an appreciable amount of asphaltene precipitation occurred, as evidenced by areas were the oil depleted sandpack was darker than in the all-steam test and, in such darker areas, some degree of cementing of the sandpack.
Evidently, at least in some parts of the sandpack, it appeared that the concentration of DME in the mobilized bitumen exceeded the asphaltene precipitation threshold. It was hypothesized that by substituting one or more normal hydrocarbon solvents, e.g.
propane or butane, for some fraction of the DME, the concentration of each individual solvent component (i.e. DME, propane, butane, etc.) dissolved into the bitumen might Date Recue/Date Received 2020-10-27 be kept below its asphaltene precipitation threshold and therefore less asphaltene in the bitumen would be precipitated in the recovery process.

[00161] Consequently, a fourth experimental test was conducted in which the heated vapor-phase working fluid comprised DME, water and various ratios of butane. The fourth experiment was operated using a similar scheme as the DME-vapor water test. The DME plus butane liquid volumetric injection rate was the same as the DME injection rate in the DME-vapor water test. The DME to butane ratio was 19:11 between 80 to 540 minutes and 11:19 between 540 to 600 minutes. The water injection rate was the same as in the DME-vapor water test. Figure 13 shows the residual oil saturations in the sandpack after the experiments. It is noted that the residual oil saturations in the depleted zone in the DME-water-butane experiment (right) were lower than that in the DME-water experiment (left). SARA (Saturate, Aromatic, Resin and Asphaltene) analysis of the residual oil showed that asphaltene contents in the residual oils was more than 93wtc/o. Therefore the results show that less asphaltene was left in the sandpack in the DME-water-butane experiment, which indirectly confirms the hypothesis that asphaltene precipitation can be reduced by partially substituting butane, a normal hydrocarbon, for a portion of the DME. This is a potentially important finding since it may provide a means to control the extent of in-situ asphaltene precipitation by varying the composition of the injected heated vapor-phase working fluid. For example, this capability might be used to achieve a single controlled degree of asphaltene precipitation or to vary the degree of asphaltene precipitation over the operating life of the recovery process.

[00162] Various modifications besides those already described are possible without departing from the concepts disclosed herein. Moreover, in interpreting the disclosure, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms "comprises" and "comprising" should be interpreted as referring to elements, components, or steps in a non-exclusive manner, indicating that the referenced elements, components, or steps may be present, or Date Recue/Date Received 2020-10-27 utilized, or combined with other elements, components, or steps that are not expressly referenced.

[00163]
Although particular embodiments have been shown and described, it will be appreciated by those skilled in the art that various changes and modifications might be made without departing from the scope of the disclosure. The terms and expressions used in the preceding specification have been used herein as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding equivalents of the features shown and described or portions thereof.
Date Recue/Date Received 2020-10-27

Claims (25)

1. A method of recovering viscous oil from a subterranean reservoir having at least one injection well and at least one production well installed therein, the method comprising:
establishing flow communication between the at least one injection well and the at least one production well;
injecting a heated vapor-phase working fluid comprising vapor-phase dimethyl ether (DME) and vapor-phase water via the at least one injection well and producing a production fluid via the at least one production well; and wherein the vapor-phase water is about 5% or lower of a total volume of the heated vapor-phase working fluid by liquid volume equivalent.

2. The method of claim 1, wherein a ratio of vapor-phase DME to vapor-phase water is between about 20:1 and about 250:1 by liquid volume equivalent.

3. The method of claim 1 or 2, wherein injecting the heated vapor-phase working fluid comprises co-injecting a first fluid stream comprising heated vapor-phase DME and a second fluid stream comprising heated vapor-phase water such that the first fluid stream and second fluid stream combine in the at least one injection well to form the heated vapor-phase working fluid.

4. The method of claim 3, wherein the first fluid stream is injected at a first temperature and the second fluid stream is injected at a second temperature.

5. The method of claim 4, wherein the first temperature and the second temperature are each between about 50 C and about 250 C.

6. The method of claim 1 or 2, further comprising forming the heated vapor-phase working fluid prior to injection.

7. The method of claim 6, wherein the heated vapor-phase working fluid is injected at a temperature of between about 50 C and about 250 C.

8. The method of any one of claims 1 to 7, further comprising maintaining a vapor chamber operating temperature of between about 50 C and about 100 C during injection of the heated vapor-phase working fluid.

9. The method of claim 8, wherein at least one heater is installed in the at least one injection well and/or the at least one production well and wherein maintaining the operating temperature comprises heating the at least one injection well and/or the at least one production well via the at least one heater.

10. The method of any one of claims 1 to 9, wherein the heated vapor-phase working fluid further comprises at least one volatile hydrocarbon solvent.

11. The method of claim 10, further comprising adjusting a concentration of the at least one volatile hydrocarbon solvent based on a desired degree of asphaltene precipitation.

12. The method of any one of claims 1 to 11, wherein the heated vapor-phase working fluid further comprises at least one non-condensable gas.

13. The method of any one of claims 1 to 12, further comprising separating at least a portion of produced DME from the production fluid.

14. The method of claim 13, further comprising recycling the produced DME
to form new heated vapor-phase working fluid.

15. The method of any one of claims 1 to 14, wherein establishing flow communication comprises injecting a liquid-phase initialization fluid via the at least one injection well, the at least one production well, or both the at least one injection well and the at least one production well.

16. The method of claim 15, wherein the liquid-phase initialization fluid comprises liquid-phase DME.

17. The method of claim 16, wherein the liquid-phase initialization fluid further comprises at least one liquid-phase hydrocarbon solvent.

18. The method of any one of claims 15 to 17, wherein establishing flow communication further comprises:
ceasing injection of the liquid-phase initialization fluid; and injecting a heated vapor-phase initialization fluid and producing an initial production fluid via the at least one injection well, the at least one production well, or both the at least one injection well and the at least one production well.

19. The method of claim 18, wherein the heated vapor-phase initialization fluid comprises vapor-phase DME and vapor-phase water and wherein the vapor-phase water is about 5% or lower of a total volume of the heated vapor-phase initialization fluid by liquid volume equivalent.

20. The method of claim 19, wherein the heated vapor-phase initialization fluid further comprises at least one vapor-phase hydrocarbon solvent.

21. The method of any one of claims 1 to 20, further comprising ceasing injection of the heated vapor-phase working fluid and injecting a non-condensable gas via the at least one injection well and producing at least a portion of remaining DME in the reservoir via the at least one production well.

22. A system for recovering viscous oil from a subterranean water-wet reservoir, comprising:
at least one injection well and at least one production well installed in the subterranean water-wet reservoir;
at least one heating system; and a control system operatively connected to the at least one heating system and configured to implement the method of any one of claims 1 to 21.

23. The system of claim 22, wherein the at least one injection well and the at least one production well comprise a plurality of well pairs and wherein a ratio of inter-well-pair spacing to pay interval thickness is about 4:1 or lower.

24. The system of claim 22 or 23, wherein the at least one injection well and the at least one production well are each non-thermally completed.

25. The system of any one of claims 22 to 24, further comprising at least one heater installed in the at least one injection well and/or the at least one production well.