CA3057184C

CA3057184C - Method for recovering viscous oil from a reservoir

Info

Publication number: CA3057184C
Application number: CA3057184A
Authority: CA
Inventors: Cathal J. Tunney; Haibo Huang; Victor Del Valle; Gary Bunio; Paul Morris
Original assignee: Suncor Energy Inc; Innotech Alberta Inc
Current assignee: Suncor Energy Inc; Innotech Alberta Inc
Priority date: 2019-10-01
Filing date: 2019-10-01
Publication date: 2022-09-27
Anticipated expiration: 2039-10-01
Also published as: CA3057184A1

Abstract

Methods are provided for recovering viscous oil from a subterranean reservoir having at least one well installed therein. The method may comprise injecting a first heated vapor- phase working fluid via the at least one well to form a vapor chamber and producing a production fluid via the at least one well followed by intermittently injecting a second heated vapor-phase working fluid via the at least one well and producing a second production fluid via the at least one well. In some embodiments, at least a portion of the second heated vapor-phase working fluid is heated electrically using a variably available electrical power source. In some embodiments, the variably available electrical power source is a low-carbon power source such as solar power, wind power, and others.

Description

METHOD FOR RECOVERING VISCOUS OIL FROM A RESERVOIR
TECHNICAL FIELD:
[0001] The present disclosure relates to oil recovery methods. More particularly, the present disclosure relates to in situ thermal oil recovery methods.
BACKGROUND:

[0002] A variety of in situ steam-based thermal oil recovery processes have been used for recovering heavy oil and bitumen from subterranean reservoirs. One such method is steam-assisted gravity drainage (SAGD). Typical SAGD operations use a pair of horizontal wells including a production well located near the bottom of the reservoir and an injection well located about 5 meters above and co-planar with the production well. High pressure steam may be injected through the injection well to heat the adjacent volume of reservoir and reduce the viscosity of the oil therein.
Provided flow communication has been established between the injection and production well, mobilized oil and condensed steam may drain under the force of gravity to the production well while a voided pore space created by the draining oil is filled with steam.
Mobilized oil and condensed steam may be produced to surface from the production well.

[0003] Other steam-based gravity drainage oil recovery methods may use the same paired well configuration as SAGD. However, instead of injecting steam alone, other vapor phase fluids may be injected. For example, a combination of steam and a solvent that is effective in reducing the viscosity of oil by dilution, a combination of steam and non-condensable gas, a hot solvent vapor alone, or any other sequential or simultaneous combination of steam, solvent, and/or non-condensable gas may be injected.

[0004] Thermal gravity drainage processes typically require significant thermal energy input to raise the temperature within the reservoir to the extent needed to reduce the viscosity of the oil therein such that it flows under the force of gravity.
Conventionally, the thermal energy input for thermal oil recovery is provided by the combustion of natural gas. However, the greenhouse gas emissions from natural gas combustion are undesirable and subject to increasingly strict regulations.

[0005] An alternative source of thermal energy input is electricity.
Some electrically powered thermal oil recovery processes use radio frequency radiation or resistive heating to directly heat the reservoir rather than injecting a heated vapor-phase working fluid such as steam. Other processes involve inserting a resistive heating element into an injection well to provide additional thermal energy to injected hot solvent vapor. Alternatively, a resistive heating element may be inserted into a production well to reduce the viscosity of the oil therein and potentially also reflux condensed solvent vapor. However, these processes have difficulty achieving comparable oil production performance to that of SAGD.

[0006] U.S. Patent No. 9,097,110 to Kaminsky etal. describes an oil recovery process in which some of the steam for injection is generated using an electrical heater powered by fluctuating power sources, for example, wind or solar power. The electrical heater is supplemented by a fired heater system, thereby generating two separate fluid streams that are combined prior to injection to maintain continuous steam injection rates. However, this approach requires duplicated equipment for both electrical and conventional steam generation capacity.

[0007] Alternatively, Klinginger et al. proposed a SAGD-type process in which the steam for injection is generated by solar radiation in a solarthermal plant (Klinginger, C., "Cyclic steam Injection into the subsurface ¨ solarthermal steam generation for enhanced oil recovery", University of Stuttgart, submitted January 26, 2010).
Steam is injected at a cyclic injection rate based on the daily available hours of direct sunlight.
However, the author notes that steam chamber development may progress differently than that of conventional SAGD. Other limitations of this method include the need to have the solarthermal plant in close proximity to the SAGD wells and the potential for significantly increased capital costs.

SUMMARY:

[0008] In one aspect, there is provided a method of recovering viscous oil from a subterranean reservoir having at least one well installed therein, the method comprising:
injecting a first heated vapor-phase working fluid via the at least one well to form a heated vapor chamber and producing a first production fluid via the at least one well;
ceasing injection of the first heated vapor-phase working fluid and intermittently injecting a second heated vapor-phase working fluid via the at least one well and producing a second production fluid via the at least one well; and wherein the second heated vapor-phase working fluid is heated electrically.

[0009] In some embodiments, the at least one well comprises an injection well and a production well in fluid communication within the vapor chamber, the first and second heated vapor-phase working fluids are injected via the injection well, and the first and second production fluids are produced via the production well.

[0010] In some embodiments, the method of recovering oil is steam assisted gravity drainage (SAGD).

[0011] In some embodiments, the same at least one well is used for injection and production.

[0012] In some embodiments, the method of recovering oil is cyclic steam stimulation (CSS).

[0013] In some embodiments, the method of recovering oil is steam flooding.

[0014] In some embodiments, at least a portion of the second heated vapor-phase working fluid is heated electrically using a variably available electrical power source.

[0015] In some embodiments, the variably available electrical power source is a low carbon power source.

[0016] In some embodiments, the low carbon power source is at least one of wind power, solar power, hydroelectric power, geothermal power, nuclear power, and co-generation power.

[0017] In some embodiments, all of the second heated vapor-phase working fluid is generated electrically using the variably available electrical power source.

[0018] In some embodiments, a first portion of the second heated vapor-phase working fluid is generated electrically using the variably available electrical power source and a second portion of the second heated vapor-phase working fluid is generated electrically using a continuously available electrical power source.

[0019] In some embodiments, the first heated vapor-phase working fluid is heated using a fired heating system.

[0020] In some embodiments, the method further comprises continuously injecting a third heated vapor-phase working fluid concurrently with intermittent injection of the second heated vapor phase working fluid, wherein the third heated vapor-phase working fluid is about 50% or lower of a cumulative injected volume of the second and third vapor-phase working fluids by liquid volume equivalent.

[0021] In some embodiments, the third heated vapor-phase working fluid has substantially the same composition or a substantially similar composition as the second heated vapor-phase working fluid.

[0022] In some embodiments, the method further comprises intermittently injecting a fourth vapor-phase working fluid when an injection rate of the second heated vapor-phase working fluid is at or near zero.

[0023] In some embodiments, the fourth vapor-phase working fluid comprises at least one of a vapor-phase solvent and a non-condensable gas.

[0024] In some embodiments, ceasing injection of the first heated vapor-phase fluid is based on at least one of a preselected time, a numerical simulation, and a comparable continuous thermal oil recovery process.

[0025] In some embodiments, the method further comprises determining a target range for an operating parameter of the vapor chamber.

[0026] In some embodiments, the method further comprises monitoring the operating parameter of the vapor chamber during injection of the first heated vapor-phase working fluid.

[0027] In some embodiments, a lower limit of the target range is adjusted upward or downward based on observed fluctuations in at least one of operating pressure and oil production.

[0028] In some embodiments, ceasing injection of the first heated vapor-phase working fluid and starting intermittent injection of the second heated vapor-phase working fluid when the operating parameter of the vapor chamber is within the target range.

[0029] In some embodiments, monitoring the operating parameter of the vapor chamber during intermittent injection of the second heated vapor-phase working fluid.

[0030] In some embodiments, if the operating parameter of the vapor chamber falls below the target range, continuously injecting the first or second heated vapor-phase working fluid to bring the operating parameter of the vapor chamber within the target range.

[0031] In some embodiments, adjusting an instantaneous injection rate of the second heated vapor-phase working fluid to maintain the operating parameter of the vapor chamber within the target range.

[0032] In some embodiments, the operating parameter is at least one of pressure and temperature.

[0033] In some embodiments, the method further comprises maintaining a level of a pool of drained liquid around the at least one production well at or above a threshold level to prevent vapor breakthrough into the at least one production well during production of the second production fluid.

[0034] In some embodiments, maintaining the level of the pool of drained liquid comprises adjusting an instantaneous production rate of the second production fluid.

[0035] In some embodiments, adjusting the instantaneous production rate of the second production fluid comprises increasing the instantaneous production rate during periods when injection of the second heated vapor-phase working fluid is high and decreasing the instantaneous production rate during periods when injection of the second heated vapor-phase working fluid is low.

[0036] In some embodiments, the level of the drained pool of liquid is allowed to vary while maintaining an approximately constant instantaneous production rate of the second production fluid.

[0037] In some embodiments, the level of the drained pool of liquid is estimated using a subcool value.

[0038] In some embodiments, injecting the first heated vapor-phase working fluid comprises continuously injecting the first heated vapor-phase working fluid.

[0039] In some embodiments, the first heated vapor-phase working fluid comprises steam, a vapor-phase solvent, a non-condensable gas, or a combination thereof.

[0040] In some embodiments, the second heated vapor-phase working fluid comprises steam, a vapor-phase solvent, a non-condensable gas, or a combination thereof.

[0041] In some embodiments, the vapor-phase solvent comprises propane, butane, pentane, hexane, heptane, octane, nonane, decane, undecane, dodecane, tridecane, tetradecane, diluent, natural gas condensate, kerosene, naptha, dimethyl ether, or a combination thereof.

[0042] In some embodiments, the non-condensable gas comprises natural gas, carbon dioxide, nitrogen, carbon monoxide, hydrogen sulfide, hydrogen, anhydrous ammonia, helium, flue gas, methane, ethane, or a combination thereof.

[0043] In some embodiments, the second heated vapor-phase working fluid has substantially the same composition as the first heated vapor-phase working fluid.

[0044] In another aspect, there is provided a system for recovering viscous oil from a subterranean reservoir comprising: at least one well installed in the subterranean reservoir; an electrical heating system to heat a vapor-phase working fluid for injection via the at least one injection well; and a control system configured to implement embodiments of the methods disclosed herein.

[0045] In some embodiments, the electrical heating system is operatively connected to a variably available power source.

[0046] In some embodiments, the electrical heating system is operatively connected to a continuously available power source.

[0047] In some embodiments, the system further comprises a fired heater system to heat the vapor-phase working fluid for injection via the at least one injection well.

[0048] 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:

[0049] Some aspects of the disclosure will now be described in greater detail with reference to the accompanying drawings. In the drawings:

[0050] 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;

[0051] Figure 2 is a cross-sectional view of the well pair of Figure 1;

[0052] Figure 3 is a flowchart of an example method for recovering viscous oil from a subterranean reservoir, according to some embodiments;

[0053] Figure 4 is a flowchart of another example method showing additional details regarding transition from injection of a first heated vapor-phase working fluid to intermittent injection of a second heated vapor-phase working fluid, according to some embodiments;

[0054] Figure 5 is a flowchart of another example method showing additional details regarding how an operating pressure may be maintained within a target operating pressure range, according to some embodiments;

[0055] Figure 6 is a flowchart of another example method showing additional details regarding how a liquid pool around the production well may be maintained at or above a threshold level, according to some embodiments;

[0056] Figure 7 shows a simulated distribution of horizontal absolute permeability distribution for a two-dimensional SAGD model in a deep reservoir;

[0057] Figure 8 is a graph showing simulated steam injection rate and oil production rate over time for a SAGD baseline case;

[0058] Figure 9 is a graph showing simulated bottom-hole pressure (BHP) of an injection well (injector) and production well (producer) over time for the SAGD baseline case;

[0059] Figure 10 is a graph showing hourly wind power availability for Pan-Canadian Wind Integration (PCWIS) site 3416 for the year 2008;

[0060] Figure 11 is a graph showing monthly wind power availability for PCWIS
site 3416 for 2008, 2009, and 2010;

[0061] Figure 12 is a graph showing a simulated daily steam injection rate for an example case, in which steam is injected intermittently, and the SAGD baseline case;

[0062] Figure 13 is a graph showing simulated daily oil production rate for the example case of Figure 12 and the SAGD baseline case;

[0063] Figure 14 is a graph showing simulated cumulative oil production rate for the example case of Figure 12 and the SAGD baseline case;

[0064] Figure 15 is a graph showing simulated injector BHP over time for the example case of Figure 12 and the SAGD baseline case;

[0065] Figure 16 is a graph showing simulated injector BHP over time for three example cases in which intermittent steam injection is preceded by varying periods (1, 2, or 4 months) of continuous steam injection, and the SAGD baseline case;

[0066] Figure 17 is a graph showing simulated wellbore temperature over time for one of the example cases of Figure 16 and the SAGD baseline case;

[0067] Figure 18 is a graph showing simulated daily oil production rate for the example cases of Figure 16 and the SAGD baseline case;

[0068] Figure 19 is a graph showing simulated cumulative oil production rate for the example cases of Figure 16 and the SAGD baseline case;

[0069] Figure 20 is a graph showing simulated injector BHP over time for two example cases in which intermittent steam injection is preceded by two months of continuous steam injection and starts in January or June, respectively, and the SAGD
baseline case;

[0070] Figure 21 is a graph showing simulated daily oil rate for the example cases of Figure 20, and the SAGD baseline case;

[0071] Figure 22 is a graph showing simulated cumulative oil production rate for the example cases of Figure 20, and the SAGD baseline case;

[0072] Figure 23 is a graph showing simulated injector BHP over time for three example cases in which steam is injected intermittently, and the SAGD baseline case, in a shallow reservoir;

[0073] Figure 24 is a graph showing simulated daily oil production rate for the example cases of Figure 23, and the SAGD baseline case, in the shallow reservoir;

[0074] Figure 25 is a graph showing simulated cumulative oil production rate for the example cases of Figure 23, and the SAGD baseline case, in the shallow reservoir;

[0075] Figure 26 shows a simulated vapor chamber expansion for the deep reservoir cases; and

[0076] Figure 27 shows a simulated vapor chamber expansion for the shallow reservoir cases.
DETAILED DESCRIPTION OF EMBODIMENTS:

[0077] Generally, the present disclosure provides a method for recovering viscous oil from a subterranean reservoir having at least one well installed therein. The method may comprise injecting a first heated vapor-phase working fluid via the at least one well to form a heated vapor chamber and producing a first production fluid via the at least one well. Injection of the first heated vapor-phase working fluid may be ceased and then a second heated vapor-phase working fluid may be intermittently injected via the at least one well and a second heated vapor-phase working fluid may be produced via the at least one well. In some embodiments, the second heated vapor-phase working fluid may be heated electrically. In some embodiments, at least a portion of the second vapor-phase working fluid may be heated electrically using a variably available power source.

[0078] 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 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 10 API or lower.

[0079] 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". In some embodiments, the reservoir has a relatively thick pay interval, for example, a pay interval with a thickness of 15 meters or greater. In some embodiments, the reservoir has relatively high vertical permeability, for example, a permeability of 1 Darcy or greater.

[0080] As used herein, a "thermal oil recovery process" refers to a process comprising in situ heating of the reservoir, via injection of a heated vapor-phase working fluid, to mobilize the viscous oil therein such that the oil may be displaced to a production well from which it may be produced to surface. In some embodiments, the displacement mechanism of the thermal oil recovery process is gravity drainage such that heated 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 hot vapor.

[0081] 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 heated vapor-phase working fluid into the reservoir. The heated vapor-phase working fluid reduces the viscosity of the viscous oil and mobilizes the viscous oil within 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.

[0082] In some embodiments, one or both of the wells 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 wells are horizontal wells. As used herein, a "horizontal" well refers to a well having a vertical section that extends downward into the pay interval followed by a 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 800 from vertical.

[0083] 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 in this embodiment is similar to the well pairs typically used in SAGD operations.

[0084] The well pair 101 in this embodiment is installed in an earth formation 102 having subterranean reservoir 103 with pay interval 105. 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. In some 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.

[0085] The injection well 104 and the production well 106 may be in flow communication via the reservoir 103. In some embodiments, flow communication between the injection well 104 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.
In some embodiments, initialization comprises heating the injection well 104 and the production well 106 for an extended period to mobilize the oil in the interwell zone 108 by conductive heating. 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 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.

[0086] Once flow communication is established between the injection well and the production well 106, a heated vapor-phase working fluid may be injected via the injection well 104 and flow into the reservoir 103. Mobilized oil in the reservoir 103, along with condensed working fluid, may flow to the production well 104 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.

[0087] As shown in Figure 2, 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 SAGD operations, the vapor chamber is also referred to as a steam chamber. The vapor chamber 110 may grow upward and outward from the injection well 104 as indicated by arrows A. Mobilized oil and condensed working fluid 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 is displaced from the pore space within the reservoir 103 and the voided pore space is filled with the hot vapor of the heated vapor-phase working fluid.

[0088] The heated vapor-phase working fluid may thereby mobilize the viscous oil in the reservoir 103 by reducing its viscosity by heat and, in some embodiments, also by dilution of the oil at the boundaries of the vapor chamber 110. The heated vapor-phase working fluid may also act as a gaseous displacement fluid to fill the void space voided by the drained mobilized oil. Other functions of the working fluid include maintaining the operating pressure of the vapor chamber and, in some embodiments, transporting a solvent component of the working fluid to the boundaries of the vapor chamber.

[0089] As the vapor chamber 110 may be filled with heated vapor-phase working fluid, the vapor chamber 110 may store a considerable amount of heat. The stored heat may be released into the reservoir 103 beyond the vapor chamber 110 even if the rate of heat input into the vapor chamber 110 is reduced. Therefore, in some embodiments, the viscous oil in the pay interval 105 may continue to be heated and mobilized even when injection of the heated vapor-phase working fluid is temporarily suspended. A
previous study by Birrell et al. demonstrated that short term variances in injection rate may have little impact on vapor chamber temperature (Birrell et al., "Cyclic SAGD ¨
Economic Implications of Manipulating Steam Injection Rates in SAGD Projects ¨
Re-examination of the Dover Project", J. Can. Petrol. Technol. 2005 Vol 44(1), pp 54-58).

[0090] In some embodiments, a liquid pool 112 of drained, mobilized oil and condensed working fluid 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" or "steam breakthrough"
refers to heated vapor-phase working fluid entering the production well 106 such that the vapor-phase fluid may be produced to the surface.

[0091] Referring again to Figure 1, in some embodiments, the production fluid produced from production well 106 may be received at a treatment facility 109 where the condensed working fluid may be separated from the oil in the production fluid. In some embodiments, the condensed working fluid may be treated to remove residual contaminants such that the treated fluid may be recycled and used to generate new heated vapor-phase working fluid for injection. In some embodiments, the treated working fluid, typically in liquid-phase, is received in working fluid storage 111 where the treated working fluid may be combined with make-up working fluid, also typically in liquid phase.

[0092] The system 100 may further comprise at least one heating system.
In some embodiments, the heating system comprises at least one electrical heating system 116. The electrical heating system 116 may receive working fluid from the working fluid storage 111 and heat the working fluid for injection into injection well 104.

As used herein, "heated" or "heating", when used in reference to a working fluid, refers to increasing the thermal energy of a fluid to the extent that the fluid can transport heat into the reservoir to mobilize the oil therein. In some embodiments, heating the working fluid comprises vaporizing a liquid-phase fluid to vapor-phase. In some embodiments, the electrical heating system 116 comprises an electrode boiler that passes an electrical current through liquid-phase working fluid to vaporize the liquid-phase working fluid to heated vapor-phase working fluid. In other embodiments, the electrical heating system 116 comprises electrical resistance heating elements that are submerged in the liquid-phase working fluid. In other embodiments, the electrical heating system 116 comprises an indirect heating system in which a heat transfer fluid is heated and transfers heat to the working fluid. In other embodiments, the electrical heating system 116 comprises any suitable electrical heating means. In some embodiments, the electrical heating system 116 may comprise more than one heating means, for example, more than one electrical boiler.

[0093] Optionally, the system 100 may further comprise a fired heating system 117, which may also receive working fluid from the working fluid storage 111 and heat the working fluid for injection into injection well 104. In some embodiments, the fired heating system 117 comprises a fired boiler such as a natural gas fired boiler. In other embodiments, the fired heating system 117 comprises any other suitable type of fired heating system.

[0094] The system 100 may further comprise a control system 118 operatively connected to the heating system. The control system 118 may be configured to implement embodiments of the methods described herein. In this embodiment, the control system 118 is operatively connected to the electrical heating system 116 and the optional fired heating system 117. The control system 118 may thereby control the operation of the electrical heating system 116 and the fired heating system 117 if used.
In some embodiments, the control system 118 is also operatively connected to one or more temperature and/or pressure sensors installed in the injection and/or production wells 104 and 106. In some embodiments, the control system 118 is operatively connected to at least one pressure sensor 113 and at least one temperature sensor 115 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. Therefore, in some embodiments, the control system 118 may receive input from the pressure and temperature sensors 113 and 115 and may regulate the electrical heating system 116 and the fired heating system 117 based on such input.

[0095] In some embodiments, at least one temperature sensor 115 may be installed in the injection well 104 to monitor the temperature of the heated vapor-phase working fluid. In some embodiments, at least one temperature sensor 115 may be installed in the production well 106 to monitor the temperature of the production fluid.
Each of the temperature sensors 115 may comprise thermocouples, a fiber optic array, or any other suitable temperature sensing means. 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. 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.

[0096] In some embodiments, the electrical heating system 116 is operatively connected to at least one power source. In some embodiments, the power source is a variably available power source 119. As used herein, a "variably available electrical power source" refers to a power source from which the amount of available power varies at least somewhat unpredictably over time and at some time points may be zero.
In some embodiments, the amount of available power varies hourly, daily, weekly, and/or seasonally. In some embodiments, the variably available electrical power source 119 may comprise a single primary power plant. In other embodiments, the variably available electrical power source 119 may comprise a local or regional electrical power grid that is supplied by several independently operated primary power plants.

[0097] As used herein, the "amount of available power" refers to the amount of power available to be used by the electrical heating system, which may be limited by physical and/or economic factors. In some embodiments, the amount of available power may not be all of the power that is generated, for example, if some of the generated power is committed to another application or if some of the generated power is sold to an electrical power grid when the price for power is at or above a certain threshold. In other embodiments, the amount of available power may be the amount of available power from a commercial electrical power grid at or below a specific price threshold.

[0098] In some embodiments, the variably available electrical power source 119 is a low-carbon power source. As used herein "low-carbon power source" refers to a power source that produces power with substantially lower carbon dioxide emissions than conventional fossil fuel power sources. In some embodiments, the low-carbon power source comprises at least one of of wind power, solar power, hydroelectric power, geothermal power, nuclear power, and combinations thereof. In some embodiments, the electrical heating system 116 may receive power from more than one variably available electrical power source 119.

[0099] In some embodiments, the low-carbon power source comprises a co-generation power source in which power is co-generated along with heat. For example, SAGD operations may include one or more natural gas-fired co-generation plants in which electricity is co-generated along with steam for injection. In some embodiments, the SAGD "co-gen" plant may generate power continuously even when other demands for power are low.

[00100] In some embodiments, the electrical heating system 116 may also be operatively connected to a continuously available power source 120. As used herein, a "continuously available electrical power source" refers to a power source from which at least some amount of power is approximately constantly available, although minor fluctuations may still be possible. For example, the continuously available electrical power source 120 may be a natural gas fired steam and power co-generation plant, an electrical power grid supplied by at least one power plant capable of continuous power generation, or any other continuously available electrical power source.

[00101] Figure 3 is a flowchart of an example method 300 for recovering viscous oil from a subterranean reservoir that may be implemented using the system 100 of Figure 1.

[00102] At block 302, a first heated vapor-phase working fluid is injected, via the injection well 104, to form a vapor chamber 110 in flow communication with the injection well 104 and the production well 106.

[00103] In some embodiments, the first heated vapor-phase working fluid comprises steam. In other embodiments, the first heated vapor-phase working fluid comprises at least one vapor-phase solvent that is effective in reducing the viscosity of viscous oil by dilution. In other embodiments, the first heated vapor-phase working fluid comprises a combination of steam and at least one vapor-phase solvent. In some embodiments, the vapor-phase solvent may comprise at least one Cl to 030 hydrocarbon solvent. The Cl to C30 hydrocarbon solvent may comprise at least one of propane, butane, pentane, hexane, heptane, octane, nonane, decane, undecane, dodecane, tridecane, and tetradecane. In some embodiments, the vapor-phase solvent comprises a multi-component solvent including but not limited to diluent, natural gas condensate, kerosene, naptha, and combinations thereof. In other embodiments, the vapor-phase solvent may comprise dimethyl ether. In other embodiments, the vapor-phase solvent is any suitable vapor-phase solvent capable of mobilizing viscous oil.
With respect to heat transport performance, a first heated vapor-phase working fluid at least partially comprising steam may be preferred in some embodiments because water has a particularly high latent heat of vaporization.

[00104] In some embodiments, the first heated vapor-phase working fluid further comprises a non-condensable gas (NCG). As used herein, a "non-condensable" gas refers a gas that does not condense under reservoir conditions. Examples of suitable non-condensable gases include, but are not limited to, natural gas, carbon dioxide, nitrogen, carbon monoxide, hydrogen sulfide, hydrogen, anhydrous ammonia, helium, flue gas, methane, ethane, and combinations thereof.

[00105] The first heated vapor-phase working fluid may be injected at a suitable pressure and temperature such that the working fluid remains in vapor phase.
The upper limit on operating pressure is typically set on a reservoir-specific basis as the pressure beyond which the risk of loss of reservoir confinement is deemed to be too high. For both steam-dominated processes, where the hot vapor-phase working fluid in the vapor chamber 110 comprises 90% or more steam on a liquid volume equivalent basis, and solvent-dominated thermal processes, where the hot vapor-phase working fluid in the vapor chamber 110 comprises 90% or more solvent on a liquid volume equivalent basis, operating temperature is determined by the operating pressure. For an all-steam process, the operating pressure range may be from about 500kPa to about 5,000kPa corresponding to an operating temperature range from about 150 C to about 260 C. Preferably the operating pressure ranges from about 1,500kPa to about 3,300kPa corresponding to an operating temperature range from about 200 C to about 240 C. For solvent-dominated processes the operating pressure may range from about 500kPa to about 5,000kPa and the corresponding operating temperature depends on the composition of the solvent or mixture of solvents used. To achieve improved energy intensity performance, preferably the operating temperature for solvent-dominated processes ranges from about 40 C to about 150 C.

[00106] A person skilled in the art will recognize that, depending on the composition of the first heated vapor-phase fluid, some constituents may not condense at the boundaries of the vapor chamber 110 and may dissolve into the viscous oil in a gaseous state. As one example, methane will remain in vapor phase at the operating temperatures and pressures described above.

[00107] The first vapor-phase working fluid may be heated using any suitable heating means at a surface facility prior to injection via the injection well 104. In some embodiments, the first vapor-phase working fluid is heated using the electrical heating system 116. In other embodiments, the first vapor-phase working fluid is heated using the fired heating system 117 if used. In other embodiments, the first vapor-phase working fluid is heated using any other suitable heating means.

[00108] In some embodiments, the first heated vapor-phase working fluid is injected continuously. As used herein, "continuous injection" or "injected continuously"
refers to substantially uninterrupted injection of a heated vapor-phase working fluid, although occasional interruptions may be required, for example, for maintenance or emergency purposes.

[00109] As the first heated vapor-phase working fluid is injected, a first production fluid may be produced via the production well 106 to surface. The first production fluid may comprise mobilized oil and condensed working fluid that drains to the production well 106 via gravity drainage.

[00110] In some embodiments, injection of the first heated vapor-phase working fluid, and production of the first production fluid, is similar to or the same as a SAGD
process. In other embodiments, injection of the first heated vapor-phase working fluid, and production of the first production fluid, is similar to or the same as a cyclic steam stimulation (CSS) process, a combination of a SAGD process and a CSS process, or any other suitable thermal oil recovery process that promotes the formation of a vapor chamber.

[00111] At block 304, injection of the first heated vapor-phase working fluid is ceased and a second heated vapor-phase working fluid is intermittently injected via the injection well 104.

[00112] The second heated vapor-phase working fluid may comprise at least one of steam and a vapor-phase solvent. The vapor-phase solvent may comprise, for example, any of the solvents described above for the first heated vapor-phase working fluid. In some embodiments, the second heated vapor-phase working fluid further comprises a non-condensable gas, for example, any of the NCG described above with respect to the first heated vapor-phase working fluid. In some embodiments, the second heated vapor-phase working fluid has approximately the same composition as the first heated vapor-phase working fluid. In other embodiments, the second heated vapor-phase working fluid has a different composition than the first heated vapor-phase working fluid.

[00113] The second heated vapor-phase working fluid may be injected at any suitable temperature and pressure, for example, within the temperature and pressure ranges described above with respect to the first heated vapor-phase working fluid.

[00114] As used here, "intermittently injecting" or "intermittent injection" of the second heated vapor-phase working fluid refers to injecting the second heated vapor-phase working fluid at an irregular or non-continuous injection rate that varies over a given time period and may at some time points be zero. The time period may be, for example, an hour, a day, or a week. For clarity, intermittent injection does not refer to extended periods of continuous injection followed by extended shut-in periods with no injection, such as seen in CSS processes, for example. As one example, intermittent injection may comprise injecting a heated vapor-phase working fluid (e.g.
steam) at an injection rate that varies daily between zero to around 700 m3/day as shown in Figure 12 and discussed in the Examples below.

[00115] At least a portion of the second vapor-phase working fluid may be heated electrically using the electrical heating system 116. In some embodiments, all of the second vapor-phase working fluid is heated electrically using the electrical heating system 116.

[00116] As the second heated vapor-phase working fluid is injected, a second production fluid may be produced via the production well 106 to surface. The second production fluid may comprise mobilized oil and condensed working fluid that drains to the production well 106 by gravity drainage.

[00117] Therefore, in some embodiments, the continuous injection of a first heated vapor-phase working fluid forms a vapor chamber and thereby stores heat in the reservoir such that the second heated vapor-phase working fluid may be injected intermittently. By using a variably available, low-carbon electrical power source to heat the second heated vapor-phase working fluid, the greenhouse gas emissions during intermittent injection of the second heated vapor-phase working fluid may be reduced or minimized compared to conventional thermal oil recovery processes.

[00118] In some embodiments, the second heated vapor-phase working fluid is heated only when power is available from the variably available electrical power source

119. The second heated vapor-phase working fluid may then be injected, via the injection well 104, as the second heated vapor-phase working fluid is heated.
In some embodiments, the instantaneous injection rate of the second heated vapor-phase working fluid is approximately equivalent to the rate at which the second heated vapor-phase working fluid is heated. As used herein, "instantaneous injection rate"
refers to the injected volume of fluid over a short time period, for example, the volume of injected fluid per hour, as opposed to the cumulative injection rate over time. As described in the Examples below, the instantaneous injection rate of the second heated vapor-phase working fluid may exhibit large amplitude variations including periods during which the instantaneous injection rate is essentially zero and periods in which the instantaneous steam injection rate is considerably higher than rates typically used in continuous injection processes such as SAGD.
[00119] In some embodiments, an instantaneous production rate at the production well 106 may be held approximately constant during intermittent injection of the second heated vapor-phase working fluid. As used herein, "instantaneous 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 this embodiment, the level of the liquid pool 112 above and around the production well 106 may rise during periods of high injection and may be drawn down during periods of low injection. As the ratio of the instantaneous injection rate to the instantaneous production rate may vary, there may be periods during which more condensed working fluid in the production fluid is produced than heated vapor-phase working fluid is injected. In some embodiments, if the condensed working fluid is to be recycled for re-injection, additional storage capacity may be needed to store condensed working fluid during periods of low injection.

[00120] In other embodiments, the instantaneous production rate at production well 106 may be decreased during periods in which the instantaneous injection rate is low and increased during periods in which the instantaneous injection rate is high.

Therefore, in this embodiment, the level of the liquid pool 112 rises during periods of low injection and low production, thereby effectively storing mobilized oil and condensed working fluid in the reservoir. During periods of high injection and high production, the liquid pool 112 may be drawn down and higher volumes of production fluid may be produced to surface.

[00121] In some embodiments, a cumulative oil production rate during intermittent injection of the second heated vapor-phase working fluid may be maintained approximately equivalent to that of a comparable continuous injection thermal oil recovery process. As used herein, "cumulative oil production rate" refers to the cumulative volume of production fluid produced over time. As used herein, "comparable", when used in reference to a continuous thermal oil recovery process, refers to a thermal gravity drainage process comprising continuous injection of a compositionally similar heated vapor-phase working fluid into a reservoir of similar petrophysical characteristics. For example, in embodiments in which the second heated vapor-phase working fluid is steam, the cumulative oil production rate during intermittent injection of the second heated vapor-phase working fluid may be approximately equivalent to that of a SAGD process operated in the same or a substantially similar reservoir.

[00122] In some embodiments, to maintain the cumulative oil production rate approximately equivalent to that of the comparable continuous injection process, higher instantaneous injection rates may be needed during time periods in which there is a large amount of available power in order to compensate for time periods in which the amount of available power is low or essentially zero. Therefore, in some embodiments, the electrical heating system 116 may require a higher capacity than the fired heating systems typically used in conventional continuous injection thermal oil recovery processes like SAGD.

[00123] In other embodiments, a first portion of second heated vapor-phase working fluid heated using the variably available electrical power source 119 may be supplemented with a second portion of second heated vapor-phase working fluid heated using the continuously available electrical power source 120. In some embodiments, the second portion of second heated vapor-phase working fluid is injected continuously. In other embodiments, the second portion of second heated vapor-phase working fluid is injected only when the amount of power from the variably available electrical power source 119 is low. In other embodiments, additional second heated vapor-phase working fluid may be heated using the optional fired heater system 117. By supplementing the second heated vapor-phase working fluid heated from the variably available power source 119, in some embodiments, the large amplitude fluctuations in the instantaneous injection rate may be reduced and a lower capacity electrical heating system may be used.

[00124] In other embodiments, a third heated vapor-phase working fluid may be continuously injected concurrently with intermittent injection of the second heated vapor-phase working fluid. In some embodiments, the third heated vapor-phase working fluid may form only a small portion of a cumulative injected volume of the second and third heated vapor-phase working fluids by liquid volume equivalent. In some embodiments, the third heated vapor-phase working fluid may be about 50% or lower of the cumulative injected volume by liquid volume equivalent. In some embodiments, the third heated vapor-phase working fluid may be about 25% or lower of the cumulative injected volume by liquid volume equivalent.

[00125] In some embodiments, the third heated vapor-phase working fluid has substantially the same composition as the second heated vapor-phase working fluid or a substantially similar composition. In other embodiments, the third heated vapor-phase working fluid may have a different composition than the second heated vapor-phase working fluid.

[00126] In some embodiments, the third heated vapor-phase working fluid is heated via the electrical heating system 116 using power from the continuously available power source 120. In other embodiments, the third heated vapor-phase working fluid is heated via the optional fired heating system 117.

[00127] In other embodiments, a fourth vapor-phase working fluid may be intermittently injected during periods when the instantaneous injection rate is at or near zero. The fourth vapor-phase working fluid may be heated or unheated. In some embodiments, the fourth vapor-phase working fluid may comprise at least one of a vapor-phase solvent and a non-condensable gas. The solvent and non-condensable gas may comprise any of the solvents and NCG described above for the first or second vapor-phase working fluids that can be injected in the vapor-phase at the operating temperature and pressure of the vapor chamber 110. By supplementing intermittent injection of the second heat transport fluid with intermittent injection of the fourth vapor-phase working fluid, the cumulative oil production rate may be maintained approximately equivalent to that of a continuous injection process without additional thermal input or with only minor additional thermal input.

[00128] Figure 4 is a flowchart of another example method 400 that may be implemented using the system 100 of Figure 1, showing additional details of a transition between injection of the first heated vapor-phase working fluid and intermittent injection of the second heated vapor-phase working fluid.

[00129] As discussed in the Examples below, the timing of the transition may affect oil production performance during intermittent injection of the second heated vapor-phase working fluid. A person skilled in the art will understand that oil production performance is a multi-factorial measure that includes the time to achieve a suitably high oil production rate, the ability to sustain a high oil production rate, and the ultimate recovery factor (RF). If the transition to intermittent injection is made too soon, the oil production performance may be poorer than desired. The presence of a sufficiently large vapor chamber at the transition between injection of the first heated vapor-phase working fluid and intermittent injection of the second heated vapor-phase working fluid may prevent a reduction in oil production performance.

[00130] As the size of the vapor chamber itself is difficult to directly monitor, one or more operating parameters may be monitored as a proxy to estimate the development of the vapor chamber. In the example method 400 of Figure 4, the operating parameter is an operating pressure, also referred to as "bottom-hole pressure" or BHP.
In other embodiments, the operating parameter may be an operating temperature or a combination of operating pressure and operating temperature. In other embodiments, any other suitable proxy for the development of the vapor chamber may be used.

[00131] At block 402 of Figure 4, a first heated vapor-phase working fluid is injected via the injection well 104 to form a vapor chamber 110 in flow communication with the injection well 104 and the production well 106. The steps at block 402 may be similar to those of block 302 in Figure 3 as described above.

[00132] At block 404, a target operating pressure range is determined for the vapor chamber 110. Although in the example method 400 of Figure 4, the step of determining the target operating pressure range (block 404) is shown between the injection of the first heated vapor-phase working fluid and intermittent injection of the second heated vapor-phase working fluid (blocks 402 and 408); a person skilled in the art will understand that the target operating pressure range may be determined at any time before intermittent injection of the second heated vapor-phase working fluid, including during or before injection of the first heated vapor-phase working fluid.

[00133] The target operating pressure range may have an upper limit and a lower limit. In some embodiments, the upper limit of the target operating pressure range is based on the allowable maximum operating pressure (MOP), which is determined with respect to the depth and geology of the reservoir and is independent of the thermal oil recovery process being employed.

[00134] In some embodiments, the lower limit of the target operating pressure range is determined based on the minimum operating pressure required to achieve a desired oil production performance during intermittent injection of the second heated vapor-phase working fluid (block 408, discussed in more detail below). In some embodiments, the desired oil production performance and the minimum operating pressure to achieve that oil production performance are determined based on simulation studies. In other embodiments, the minimum operating pressure is determined based on the operating pressure that maintained the desired oil production performance in a comparable continuous thermal oil recovery process.

[00135] In some embodiments, the lower limit of the target operating pressure range may be set at approximately 70 to 95% of the operating pressure required to maintain the desired oil production performance in the comparable continuous injection thermal oil recovery process. In some embodiments, an approximately 70% value may be used when large amplitude fluctuations in the instantaneous injection rate are expected during intermittent injection of the second heated vapor-phase working fluid, such as in embodiments in which all of the second heat transfer fluid will be heated electrically using the variably available power source 119. In other embodiments, an approximately 95% value may be used when the fluctuations in the instantaneous injection rate are expected to be lower, such as in embodiments in which a first portion of second heated vapor-phase working fluid heated using the variably available power source 119 will be supplemented with a second portion of second heated vapor-phase working fluid heated using the continuously available electrical power source 120.

[00136] At block 406, an operating pressure of the vapor chamber 110 is monitored during injection of the first heated vapor-phase working fluid. In some embodiments, the operating pressure may be monitored at set time intervals, for example, once per hour, once per day, once per week, etc. In other embodiments, the operating pressure may be monitored substantially continuously.

[00137] In some embodiments, the operating pressure of the vapor chamber is monitored by converting temperature data collected by at least one temperature sensor 115 in the injection well 104 into corresponding pressure data. For example, in embodiments in which the first heated vapor-phase working fluid is steam, steam saturation temperature data from the temperature sensors 115 may be converted to corresponding steam saturation pressures. In other embodiments, the operating pressure may be monitored by conducting injection well annulus blanket gas pressure surveys. In other embodiments, the operating pressure may be monitored by periodically reducing the injection rate to near-zero and estimating operating pressure based on measured surface injection pressure. A person skilled in the art will understand that monitoring operating pressure "during" injection of the first heated vapor-phase working fluid may involve temporarily suspending injection to measure the operating pressure.

[00138] At block 408, a transition is made from injection of the first heated vapor-phase working fluid to intermittent injection of the second heated vapor-phase working fluid when the monitored operating pressure is within the target range. As used herein, "transition" or "transitioning", when used in reference to injection of the first and second heated vapor-phase working fluids, refers to ceasing injection of the first heated vapor-phase working fluid and initiating intermittent injection of the second heated vapor-phase working fluid.

[00139] In some embodiments, the transition from injection of the first heated vapor-phase working fluid to intermittent injection of the second heated vapor-phase working fluid is made as soon as, or shortly after, the operating pressure reaches the target range. In other embodiments, the transition may be made after the operating pressure has remained within the target range for an extended period of time, for example, at least one month, two months, three months, or longer. The longer the first heated vapor-phase working fluid is continuously injected, the larger will be the vapor chamber 110 at the transition to intermittent injection of the second heated vapor-phase working fluid, which may reduce the risk that oil production performance drops during intermittent injection. In addition, a larger vapor chamber 110 at the transition may lead to reduced fluctuations in operating pressure during intermittent injection of the second heated vapor-phase working fluid, as described in the Examples below.

[00140] In some embodiments, the timing of the transition may be based on a numerical simulation. The numerical simulation may be based on a predicted availability of the variably available electrical power source 119 and therefore a predicted profile of intermittent injection of the second heated vapor-phase working fluid. For example, if wind power is to be used as the variably available electrical power source 119, the numerical simulation may use a predicted intermittent injection profile based on historical wind patterns in the region from which the wind power will be sourced.

[00141] In other embodiments, the timing of the transition may be based on data from a comparable continuous injection thermal oil recovery process. For example, for a comparable continuous process the operating pressure response to short periods, for example 1 to 2 days, during which injection of heated vapor-phase working fluid is suspended may be recorded for a range of cumulative injected heated vapor-phase working fluid volumes. This data may then be used to develop a relationship between cumulative injected volume of working fluid, a proxy for vapor chamber size, and the rate of operating pressure fall-off during periods of no injection. This relationship may then be used to estimate a lower limit for the cumulative injected volume required to maintain the operating pressure above a specified lower limit during a period of no injection of a specified duration. Then, since injection rate history will be known, the estimated lower limit for cumulative injection of heated vapor-phase working fluid can be converted into a time at which intermittent injection may begin.

[00142] In other embodiments, the timing of the transition may be based on a preselected time, for example, after one month, two months, or three months of continuous injection of the first heated vapor-phase fluid, as described in the Examples below.

[00143] At block 410, operating pressure of the vapor chamber is monitored during intermittent injection of the second heated vapor-phase working fluid. The steps at block 410 may be similar to the steps of block 406 as described above.

[00144] If the operating pressure is within the target range (yes at block 412), then intermittent injection of the second heated vapor-phase working fluid can continue at block 414. The intermittent injection of the second heated vapor-phase working fluid may continue in a similar manner to that of block 408.

[00145] If the operating pressure falls below the target operating pressure range (no at block 412), then, at block 416, the first or second heated vapor-phase working fluid may be continuously injected to bring the operating pressure into the target range.
In some embodiments, the steps at block 416 are similar to the steps at block 402. In other embodiments, a first portion of second heated vapor-phase working fluid heated using the variably available electrical power source 119 is supplemented with injection of a second portion of second heated vapor-phase working fluid heated using the continuously available electrical power source 120 or using the optional fired heating system 117 to bring the operating pressure within the target range.

[00146]
The method 400 may then return to block 408, at which point a transition is again made to intermittent injection of the second heated vapor-phase working fluid.
At block 410, the operating pressure of the vapor chamber 110 may again be monitored. If the operating pressure is now within the target range (yes at block 412), then intermittent injection of the second heated vapor-phase working fluid may continue at block 414. If the operating pressure still falls below the target range (no at block 412), then at block 416, continuous injection of the first or second heated vapor-phase working fluid can resume. This method 400 may continue in this manner until the operating pressure is within the target operating pressure range and intermittent injection can continue at block 414.

[00147] As demonstrated in the Examples below, the large fluctuations in the instantaneous injection rate during intermittent injection of the second heated vapor-phase working fluid may lead to large fluctuations in the operating pressure of the vapor chamber 110. Therefore, in some embodiments, additional steps may be taken to maintain the operating pressure of the vapor chamber 110 within the target operating pressure range during intermittent injection of the second heated vapor-phase working fluid.

[00148]
Figure 5 is a flowchart of another example method 500, implemented using the system 100 of Figure 1, with additional steps for maintaining the operating pressure within the target operating pressure range during intermittent injection of the second heated vapor-phase working fluid.

[00149] At block 502, a first heated vapor-phase working fluid is injected via the injection well 104 to form a vapor chamber 110 in flow communication with the injection well 104 and the production well 106. The steps at block 502 may be similar to those of block 302 in Figure 3 as described above.

[00150] At block 504, a target operating pressure range is determined for the vapor chamber 110. The steps at block 504 may be similar to those of block 404 in Figure 4 as described above.

[00151] At block 506, a second heated vapor-phase working fluid may be intermittently injected. At least a portion of the second heated vapor-phase working fluid may be heated electrically using the variably available power source 119. The steps at block 506 may be similar to those of block 304 in Figure 3 as described above.

[00152] At block 508, an operating pressure of the vapor chamber 110 is monitored. The steps at block 508 may be similar to those of block 410 in Figure 4 as described above.

[00153] If the operating pressure of the vapor chamber 110 is within the target operating pressure range (yes at block 510), then the method 500 can return to block 506 and intermittent injection of the second heated vapor-phase working fluid can continue as before.

[00154] If the operating pressure of the vapor chamber 110 is outside of the target operating pressure range (no at block 510), then the instantaneous injection rate of the second heated vapor-phase working fluid may be adjusted at block 512 to bring the operating pressure into the target range. If the operating pressure is above the upper limit of the target range, the instantaneous injection rate may be reduced to lower the operating pressure. In some embodiments, the instantaneous injection rate may be lowered by suspending power to the electrical heating system 116. In other embodiments, the injection rate may be lowered by injecting only a portion of the second heated vapor-phase working fluid that has been heated.

[00155] If the operating pressure is below the lower limit of the target range, the instantaneous injection rate may be increased to increase the operating pressure. In some embodiments, the injection rate may be increased by supplementing the second heated vapor-phase working fluid heated using the variably available power source 119 with additional second heated vapor-phase working fluid heated using the continuously available power source 120 or the fired heater system 117 if used.

[00156] In some embodiments, if the operating pressure is still within the target range, but is close to the upper or lower limit, the injection rate may still be adjusted to maintain the operating pressure within the target operating pressure range.

[00157] In some embodiments, the lower limit of the target operating pressure range may be adjusted upward or downward during the intermittent injection of the second heated vapor-phase working fluid based on the observed fluctuations in operating pressure as well as the desired oil production performance at a given time.
For example, if the oil production performance drops below a desired level, the lower limit may be adjusted upward to increase the oil production rate.

[00158] The method 500 may then return to block 508 and the operating pressure of the vapor chamber 110 can be determined again. If the operating pressure is now within the target range (yes at block 510), then the method may return to block 506 and the intermittent injection of the second heated vapor-phase working fluid may continue.
If the operating pressure is still outside of the target range, (no at block 510), then the injection rate may be adjusted again at block 512. In some embodiments, the method 500 may continue in this manner until the operating pressure is within the target operating pressure range and the intermittent injection of the second heated vapor-phase working fluid can continue at block 506.

[00159] In other embodiments, to maintain the operating pressure within the target operating pressure range, a fourth vapor-phase working fluid may be intermittently injected when the instantaneous injection rate of the second heated vapor-phase working fluid is at or near zero as discussed above.

[00160] Due to the potentially large amplitude fluctuations in the instantaneous injection rate during intermittent injection of the second heated vapor-phase working fluid, there may be extended periods during which the injection rate is relatively low.
During such periods, unless the production rate is also decreased, the level of the liquid pool 112 around the production well 106 may be drawn down, thereby increasing the risk of vapor breakthrough into the production well 106. Therefore, in some embodiments, additional steps may be taken to maintain the liquid pool 112 at or above a threshold level during intermittent injection of the second heated vapor-phase working fluid.

[00161] Figure 6 is a flowchart showing another example method 600 that may be implemented using the system 100 of Figure 1, with additional steps to maintain the liquid pool 112 at or above a threshold level during intermittent injection of the second heated vapor-phase working fluid.

[00162] The level of the liquid pool 112 may be difficult to directly monitor from surface. Therefore, in some embodiments, subcool may be used as a proxy for the level of the liquid pool 112. As used herein, "subcool" refers to a difference between the saturation temperature for the primary heat transport component of the heated vapor-phase working fluid at its partial pressure within the vapor chamber 110 and the temperature of the mobilized oil and condensed working fluid entering the production well 106. Higher subcool values may indicate a higher level of the liquid pool 112 while lower subcool values may indicate a lower level of the liquid pool 112 and thus an increased risk of vapor breakthrough. In other embodiments, any other suitable proxy for the level of the liquid pool 112 may be used.

[00163] At block 602, a first heated vapor-phase working fluid is injected to form a vapor chamber 110 in flow communication with the injection well 104 and the production well 106. The steps at block 602 may be similar to those of block 302 in Figure 3 as described above.

[00164] At block 604, a target subcool is determined as a proxy for a threshold level of the liquid pool 112. In some embodiments, the target subcool is a set temperature; in other embodiments, the target subcool is a temperature range.
In this embodiment, the target subcool is determined before intermittent injection of the second heated vapor-phase working fluid, for example, during injection of the first heated vapor-phase working fluid. In other embodiments, the target subcool may be determined during intermittent injection of the second heated vapor-phase working fluid after observing the fluctuations in the subcool as the result of fluctuations in the instantaneous injection rate of the second heated vapor-phase working fluid.
In some embodiments, the target subcool may be selected based on typical target subcool values as practiced in SAGD operations, for example, ranging from about 5 C to 30 C.

[00165] At block 606, a second heated vapor-phase working fluid is intermittently injected. The steps at block 606 may be similar to those of block 304 in Figure 3 as described above.

[00166] At block 608, a subcool value is determined for at least a portion of the production well 106. The subcool value may be determined at one or more locations along the well pair 102 where temperature sensors 115 installed along the length of the production well 106 may be used to estimate the subcool value at each temperature measurement location. In other embodiments, the subcool value may be determined using any other suitable method.

[00167] If the determined subcool value is approximately at the target subcool (yes at block 610), then the method 600 can return to block 606 and intermittent injection of the second heated vapor-phase working fluid can be continue as before. In some embodiments, the subcool value may be slightly above or below the target subcool, for example, within 10% of the target subcool.

[00168] If the determined subcool value is significantly above or below the target subcool (no at block 610), then an instantaneous production rate at production well 106 may be adjusted at block 612. If the subcool value is too low, the instantaneous production rate may be decreased to allow the liquid pool 112 to rise and thereby reduce the risk of vapor breakthrough. In some embodiments, too high of a subcool value may also be undesirable as the higher level of the liquid pool 112 may reduce the overall gravity drainage head and thereby reduce the oil production rate.
Therefore, if the subcool value is too high, the instantaneous production rate may be increased to draw down a portion of the liquid pool 112.

[00169] The method 600 may then return to block 608 and the subcool value may be determined again. If the subcool value is now approximately at the target subcool (yes at block 610), then the method may return to block 606 and the intermittent injection of the second heated vapor-phase working fluid may continue. If the subcool value is still too high or too low, (no at block 610), then the production rate may be adjusted again at block 612. In some embodiments, the method 600 may continue in this manner until the subcool is approximately at the target subcool and intermittent injection of the second heated vapor-phase working fluid can continue at block 606.

[00170] In other embodiments, the level of the liquid pool 112 may be maintained at or above a threshold level by adjusting the pumping rate of the optional pump 107. In this embodiment, the undesirable presence of vapor in the production well 106 can be detected by monitoring the performance of the pump 107. For example, by monitoring at least one of the load, operating temperature, and mechanical vibration of the pump 107, the presence and amount of vapor that is co-mingled with the production fluid may be detected and estimated. The detection of a significant volume of vapor at the pump 107 may indicate that the liquid level has been drawn down too low at some point along the production well 106, thereby allowing live vapor to enter the production well 106. When this condition occurs, the pumping rate may be reduced to allow the liquid level at all points along the production well 106 to rise until the vapor breakthrough is remediated, which may be confirmed by a return to stable performance for the pump 107.

[00171] In other embodiments, the liquid pool 112 may be maintained at or above a threshold level using any other suitable method.

[00172] For a given target subcool range, corresponding to a working range for the level of the drained liquid pool 112, two different operating strategies may be chosen during intermittent injection of the second heated vapor-phase working fluid.
In one, the liquid pool 112 may be drawn down, by increasing the instantaneous production rate of the second production fluid, during periods when the rate of injection of the second heated vapor-phase working fluid is high and may be expanded, by reducing the instantaneous production rate, during periods when the rate of injection of the second heated vapor-phase working fluid is low. In this embodiment, condensed second working fluid in the liquid pool 112 is effectively stored in the reservoir 103 during periods when injection of the second heated vapor-phase working fluid is low.
During periods when injection of the second heated vapor-phase working fluid is high, the instantaneous supply of condensed second working fluid produced to surface may also be high and such condensed working fluid may be recycled to produce second heated vapor-phase working fluid for injection. Thus, this strategy may reduce the amount of at-surface storage capacity required to store the recycled second working fluid.
However, the throughput for treatment facility 109 may fluctuate, perhaps quite dramatically.

[00173] In other embodiments, the instantaneous production rate is controlled to be essentially constant, providing that the subcool is maintained within the target range.
The advantage of this approach may be that the treatment facility 109 sees an essentially constant throughput rate. However, there may be a need to provide more at-surface storage capacity for recycled second working fluid.

[00174] Numerous variations of the thermal oil recovery processes described herein are also possible. As noted above, in some embodiments, instead of a SAGD-like well pair as shown in Figures 1 and 2, the system 100 may comprise a single injection and production well as used in CSS processes. In these embodiments, injection of the first heated vapor-phase working fluid may be similar to or the same as a CSS process. The second heated vapor-phase working fluid may then be intermittently injected during an injection period, followed by a soaking period and then a production period. During the soaking and production periods, no second heated vapor-phase working fluid may be injected. Embodiments of the methods described above may be implemented in a similar fashion in the single-well arrangement. However, an important difference between CSS and SAGD processes is that typical operating pressure for SAGD may only be a fraction of the allowable maximum to maintain a caprock seal whereas, in CSS, operating pressure may be at our above this maximum limit. Therefore, implementation of intermittent injection during the injection cycles of a CSS-like process may require a much tighter operating pressure range than that of the SAGD-like processes described above.

[00175] In other embodiments, variations of the methods described herein may be applied to steam flooding or any other suitable thermal oil recovery processes.

[00176] A few other variations are discussed below using steam as the exemplary first and second heated vapor-phase working fluid. However, a person skilled in the art will understand that any other suitable heated vapor-phase working fluid may be used in the examples described below and embodiments are not limited to steam.

[00177] In some embodiments, the composition of the first or second heated vapor-phase working fluid may be adjusted over time or may cycle between two or more different compositions. As one example, the second heated vapor-phase working fluid may initially comprise steam or a mixture of steam and a vapor-phase solvent and may later be adjusted to a composition comprising solvent-only or a mixture of steam and/or solvent and a non-condensable gas.

[00178] In some embodiments, steam injection may be supplemented with concurrent or sequential injection of at least one of a solvent and a NCG. The solvent and NCG may be any of the solvents or NCG described above with respect to the first and second heated vapor-phase working fluids. The solvent may be liquid-phase or vapor-phase. The injection of the solvent and/or NCG may be continuous or intermittent.
If intermittent, solvent and/or NCG injection may vary at the same rate as the intermittent steam injection (during intermittent injection of the second heated vapor-phase working fluid) or at a different intermittent rate.

[00179] In some embodiments, steam injection may be combined with injection of at least one natural or synthetic surfactant to reduce the oil-water interfacial tension.
Injection of the surfactant may be concurrent with steam injection or may be alternated with steam injection. The surfactant may be volatile such that the surfactant is transported with the steam to the boundary of the vapor chamber. The surfactant may be ionic, zwitterionic, or non-ionic.

[00180] In other embodiments, steam injection may be combined concurrently or sequentially with injection of at least one surfactant-generating agent. As used herein, a "surfactant generating agent" is a substance that converts native compounds present in the reservoir into natural surfactants. In some embodiments, the surfactant generating agent comprises at least one of ammonia, an acid compound, and an alkali compound.
For example, alkali compounds may convert in situ acids in bitumen into natural surfactants. The surfactant-generating agent can be combined with the steam or injected separately in an aqueous solution or a suitable solvent.

[00181] In some embodiments, steam injection may be combined concurrently or sequentially with a foaming agent to generate a foam within the reservoir. The foam may function to reduce the mobility of the steam, force the steam into undeveloped regions along the well pair, and/or contribute to more uniform development of the steam chamber. Suitable foaming agents include, for example, alpha olefin sulfonates (AOS), alpha olefin sulfonate dimers (AOSD), internal olefin sulfonates (I0S), alkylaryl sulfonates (AAS), alkylaryl ethoxy sulfonates, and combinations thereof.

[00182] In other embodiments, any other suitable additive may be injected concurrently or sequentially with steam and embodiments are not limited by the specific additives described herein.
EXAMPLES

[00183] Simulation studies were undertaken to test the viability of a thermal gravity drainage process comprising intermittent injection of steam. Conventional SAGD
with continuous steam injection was chosen as the baseline thermal gravity drainage process for comparison. Wind power was chosen as the variably available power source and it was assumed that the profile of steam generation and injection would follow the profile of power availability. Simulation studies were performed using models of both deep and shallow reservoirs.

Example 1 ¨ Simulation model of deep reservoir

[00184] A generic two-dimensional Athabasca bitumen SAGD reservoir model was implemented in a STARSTm simulator (Computer Modelling Group Ltd., Calgary, Canada). Figure 7 illustrates the distribution of horizontal permeability in this model.

[00185] In this model, the depth to the top of the reservoir is 330 m and the calculated maximum operating pressure (MOP) is 5,500 kPa. The target oil sand pay zone is 25 m thick. The average horizontal absolutely permeability is 3,000 md. The average oil saturation of the target pay zone is 0.85. The model also includes an upper low quality zone for which the absolutely permeability is set at 100 md. The width of the model is 100 m and the well pair (injection well and production well) is located in the centre of the model. The well length is 1,000 m. The petrophysical and thermal properties of the geomaterials in the model are typical of those used in simulations of Athabasca oil sand reservoirs. The initial reservoir pore pressure is 1,000 kPa. Porosity is 0.32. Initial reservoir temperature is 12 C. The initial dissolved gas to oil ratio (GOR) of the reservoir is 3Ø
Example 2 ¨ Simulation model of shallow reservoir

[00186] To assess the application of intermittent steam injection to shallow reservoirs, a generic two-dimensional reservoir model representing a relatively shallow reservoir, at a depth of 110m, was developed. The petrophysical properties of this shallow reservoir model mimic those of the MacKay River SAGD project run by Suncor Energy lnc.TM. The initial reservoir pore pressure is 400 kPa and the temperature is 7 C.
The initial dissolved gas/oil ratio (GOR) of the reservoir is 0.82, compared to 3.0 for the deep reservoir model. The calculated MOP for this shallow reservoir model is 1,800 kPa.
Example 3 ¨ Baseline case for deep reservoir simulations

[00187] To establish flow communication between the injection and production wells, a 90-day steam circulation phase was run in both wells using the HTVVELL utility in STARS. After 90 days of steam circulation, the temperature at the mid-point between the injection and production well was approximately 85 C. Thereafter, a continuous steam injection SAGD simulation was run for the baseline case. The operating pressure is set at 2,500 kPa and the maximum steam injection rate is set at 400 m3/day, which is representative of typical field practice. The production well is operated under steam trap control with a subcool value of 10 C. The SAGD simulation was run for 10 years.

[00188] The steam injection rate and oil production rate for this baseline case are shown in Figure 8. It can be observed that maximum steam injection rate achieved was a little less than 300 m3/day, 25% below the pre-set maximum. The bottom hole pressure (BHP) for the injection well (injector) and production well (producer) are shown in Figure 9.
Example 4 ¨Baseline case for shallow reservoir simulations

[00189] A continuous steam injection SAGD baseline case for the shallow reservoir model was run as follows. To establish flow communication between the injection and production wells, a 90-day steam circulation phase is run in both wells using the HTWELL utility in STARS. After 90 days of steam circulation the temperature at the mid-point between the injection and production well is approximately 85 C.
Thereafter, a continuous steam injection SAGD simulation is run for 10 years.
Because of the reduced MOP, the operating pressure is set at 1,200 kPa and the maximum steam injection rate is set at 400 m3/day. The production well is operated under steam trap control with a subcool value of 10 C. Except for the switch to intermittent steam injection, all of the shallow reservoir cases were initialized and run in the same way.
Example 5 ¨ Wind power availability

[00190] To test the impact intermittent steam injection on SAGD
performance, a varying steam injection profile was developed to mimic representative variable availability of wind power in Alberta. To do this, an example of the three-year wind power production profiles developed as part of the Canadian Wind Energy Association's (CanWEA) 2016 Pan Canadian Wind Integration Study (PCWIS) was used. The final report of the PCWIS and the hourly wind data are downloadable from the CanWea website (www.canwea.ca/wind-integration-study/) and the 10-minute grid cell data may be obtained from CanWea upon request. As part of the PCWIS, wind power generation profiles were developed for thousands of locations across Canada, including Alberta.
For each chosen location, an hourly power availability profile was developed for the years 2008, 2009, and 2010 based on modelled wind speed data. The profile for each site represents the time varying availability of power from an assumed amount of installed generation capacity. The site designated ID 3416 in the PCWIS
report, at longitude -111.03 and latitude 52.259, was chosen for this study. This site is located approximately 100 km south of the city of Lloydminster on the Alberta-Saskatchewan border.

[00191] To illustrate the degree of variability in the hourly data, predicted wind power availability for the year 2008 is shown in Figure 10. Note the y-axis represents gross power output in megawatts (MW).

[00192] Monthly wind power availability for each of 2008, 2009, and 2010 is shown in Figure 11. Although there is quite a bit of variability from year to year, it can be seen that wind power availability is general higher in winter than in summer.
Example 6 ¨ Intermittent steam injection profile

[00193] To develop an intermittent steam injection profile that mimicked the variable wind power availability profile, the following assumptions were made.
All available wind power output from a representative PCWIS wind farm site is used for electrical steam generation for SAGD operations, such that the availability of electrically generated steam is driven by the availability of variable wind power. An adequate representation of variability over a multi-year period is provided by sequentially repeating the variable hourly profile developed for the three-year period modelled in the PCWIS. To a first approximation it is assumed that cumulative oil production is driven by cumulative steam injection such that, to compare the impact on oil production, cumulative annual steam injection should be the same for both the continuous and intermittent injection scenarios.

[00194] Given the foregoing assumptions and the constraint that, in the STARS
simulator, the smallest time interval for which input steam injection rates can be specified is one day, a representative variable hourly steam injection profile is implemented as follows. Using the steam injection profile from the continuous steam injection base case (as shown in Figure 8), an average daily steam injection rate is input for each year of the ten year long simulation run. To capture the impact of the sort of hourly variability that results from electrical steam generation using wind power, the simulation time step is set to one hour. Variable hourly steam injection rates are determined by dividing the daily average rate by 24, effectively converting it to an average hourly rate, which is then multiplied by a normalized variable wind power availability factor. The normalized variable wind power availability factor is calculated by dividing the raw hourly wind power availability predicted by the PCWIS by the average predicted hourly wind power availability for the relevant year.
Example 7 ¨ Simulation Cases

[00195] A number of simulation cases were run using hourly variable steam injection rate to assess the impact of various parameters, including:
reservoir depth; the timing of the switch from continuous to intermittent steam injection; and the month in which intermittent steam injection begins. The combination of parameter values used for each simulation case is listed in Table 1.

Simulation Reservoir Starting month for Timing of switch from continuous case depth Intermittent steam injection to intermittent steam injection 1 330 m January 0 months 2 330 m January 1 month 3 330 m January 2 months 4 330 m January 4 months 330 m June 2 months 6 110 m January 0 months 7 110 m January 2 months 8 110 m January 4 months

[00196] For simulations using hourly variable steam injection, operating pressure control is relaxed to accommodate periodically high instantaneous steam injection rates to allow the annual cumulative steam injection to approximately match that of the continuous steam injection base case. Also, in the intermittent steam injection simulation runs, the maximum steam injection rate restriction of 400 m3/day that applied to the continuous steam injection baseline case is removed.
Example 8 ¨ Results of Simulation Case 1

[00197] Figure 12 shows the daily steam injection rate for Case 1, in which hourly variable steam injection starts immediately after completion of the same 90-day period of steam circulation start-up as used in the baseline case. For comparison, the daily steam injection rate for the SAGD baseline case is also shown in Figure 12.
The equivalent daily steam injection rate for Case 1 ranges from 0 m3/day to 700 m3/day.

[00198] Figures 13 and 14 compare the daily oil rate and cumulative oil rate, respectively, between Case 1 and the SAGD baseline. The spike in daily oil production at the commencement of intermittent steam injection appears to be an artifact associated with modelling the impact of a rapid increase in steam pressure on gravity drainage of the bank of mobilized oil generated during the steam circulation phase.

[00199] As shown in Figure 14, the simulation predicts that intermittent steam injection can achieve approximately the same oil production performance as the continuous steam injection baseline. In practice, a number of factors may reduce the oil production performance of the intermittent steam injection process. For example, if the intermittent steam injection process is operated with a too high of a level of drained liquid above and around the production well, the overall gravity drainage head may be reduced, thereby reducing the oil production rate. This outcome can be avoided by implementing more reliable temperature and pressure monitoring to ensure reliable liquid level control at the production well. In combination with improved liquid level control, the oil production rate for intermittent steam injection could also be increased by increasing cumulative steam injection thereby increasing the time averaged operating temperature. However, this may result in an increased steam-oil ratio, reflecting a reduced energy intensity performance.

[00200] Figure 15 compares the injector BHP for Case 1 compared to the SAGD
baseline case. It can be seen that in Case 1, the BHP spikes above the maximum operating pressure (MOP) of 5,500 kPa, which is a non-permissible condition.
For the first two years of operation, the BHP for Case 1 fluctuates above and below the set BHP
for the SAGD baseline case with significant but ever declining amplitude.
After year three, the fluctuation in BHP for Case 1 is minimal.
Example 9 ¨ Results of Simulation Cases 2, 3, and 4

[00201] To investigate the impact of a period of continuous steam injection before switching to intermittent steam injection, simulation Cases 2, 3, and 4 were run.

[00202] Figure 16 shows the injector BHP for Cases 2, 3, and 4, in which intermittent steam injection was preceded by one, two, or four months of continuous steam injection, respectively. Injector BHP for the continuous steam injection SAGD
baseline case is shown for reference. In all three intermittent steam injection cases, the allowable MOP of 5,500 kPa is never exceeded. Thus, even a short period of continuous steam injection, during which the steam chamber is expanded to a modest extent, may be sufficient to establish the desired "storage heater"
characteristic of the steam chamber. Also, it can be seen that as the length of the initial period of operation with continuous steam injection is increased, the amplitude of the BHP
fluctuations is reduced during subsequent operation with intermittent steam injection, most noticeably during the first year of intermittent steam injection.

[00203] Figure 17 shows the injector and producer wellbore temperature for Case 3 compared to the SAGD baseline case. Operating pressure directly determines steam condensation and operating temperature at the steam chamber boundary. Wellbore temperature fluctuates in sync with operating pressure fluctuations. However, during the first few years of operation, the magnitude of the wellbore temperature fluctuations is significantly lower than the respective fluctuations in operating pressure.
For the injector wellbore, the maximum percentage temperature fluctuation below the mean is approximately -6% (13 C below an average of about 225 C) whereas the maximum percentage pressure fluctuation below the mean is approximately -20% (500 kPa below an average of 2,500 kPa). This effect reduces cyclic thermally induced stresses on wellbore liners and other hardware.

[00204] Figure 18 shows the daily oil rate for Cases 2, 3 and 4 compared to the SAGD baseline case. For all three intermittent steam injection cases, the amplitude of the fluctuations in the daily oil rate is significantly reduced by the end of the third year of operation.

[00205] Figure 19 shows cumulative oil production for Cases 2, 3 and 4 compared to the SAGD baseline case. The cumulative oil production curve is approximately the same for all cases.
Example 10 ¨ Results of Simulation Case 5

[00206] From the monthly wind power data presented in Figure 11, it can be seen that significantly more wind power is available in winter (e.g. during the month of January) than in summer (e.g. during the month of June). To investigate the impact of the seasonal timing of the switch to intermittent steam injection, simulation Case 5 was run. Case 5 is the same as Case 3 except that intermittent steam injection starts in June rather than in January.

[00207] Figures 20, 21, and 22 show the BHP, daily oil rate, and cumulative oil production, respectively, for Cases 3 and 5 compared to the SAGD baseline case. The seasonal shift in the timing of the switch to intermittent steam injection was not found to have a significant impact on oil production performance. However, there is an observable impact on injector BHP, which reaches a maximum of just under 3,500 kPa for Case 3 relative to 3,000 kPa for Case 5. These results suggest that BHP
during the early stages of intermittent steam injection may be managed by reducing the highest spikes in the injection rate.

Example 11 ¨ Results for Simulation Cases 6, 7, and 8

[00208] Cases 6, 7, and 8 were run to assess the impact of the timing of the switch from continuous to intermittent steam injection for the shallow reservoir model. Cases 6, 7, and 8 include periods of zero, two, and four months of continuous steam injection prior to the switch to intermittent injection, respectively.

[00209] Figures 23, 24, and 25 show injector BHP, daily oil rate, and cumulative oil production, respectively, for Cases 6, 7, and 8 compared to the SAGD baseline case for the shallow reservoir model. For the shallow reservoir model, daily oil rate and cumulative oil production for the intermittent steam injection cases follow a similar pattern as was seen for the deep reservoir model. Specifically, cumulative oil production is approximately the same for all intermittent steam injection cases as well as the baseline case, and the oscillations in daily oil rate are largely attenuated after three years of operation.

[00210] However, in absolute terms, the daily oil rate for the deep reservoir model is approximately 50% higher than for the shallow reservoir model, indicating that the steam chamber is expanding more slowly for all shallow reservoir cases. In addition, for cases with intermittent steam injection, early spikes in BHP as a percentage of the target continuous injection SAGD baseline are significantly higher for the shallow reservoir model compared to the deep reservoir model. Thus, a longer period of SAGD
operation with continuous steam injection may be required before switching to intermittent steam injection in shallow reservoirs to avoid instances where the MOP of 1,800 kPa is exceeded.
Example 12 ¨ Vapor chamber development in the deep reservoir model

[00211] Figure 26 shows the development of the expanding vapor chamber over time for the deep reservoir model cases. The vapor chamber develops as the heated and mobilized oil drains under gravity, which means that sustained oil drainage (and production) requires sustained vapor chamber expansion. However, sustained expansion of the vapor chamber need not occur at a uniform or smoothly changing rate.

Since the cumulative oil production curves are essentially the same for all the deep reservoir simulation cases, whether with continuous or intermittent steam injection, the expanding cross-sectional area of the vapor chamber as represented in Figure 26 is representative of all of deep reservoir cases.

[00212] The leftmost image represents the vapor chamber at the end of the 90-day steam circulation (initialization) period. Referring to the temperature gradation scale on the right, it can be seen that at this time only the wellbores are at the target steam temperature of 225 C. The centre image represents the vapor chamber after 120 days of SAGD operation, corresponding to the timing of the switch to variable steam injection for Case 4. At this time, there is a substantially expanded zone that has reached the target steam temperature. The rightmost image represents the vapor chamber after 480 days of SAGD operation, by which time the vapor chamber has expanded substantially both vertically and horizontally.
Example 14 ¨ Vapor chamber development in the shallow reservoir model

[00213] Figure 27 shows the development of the expanding vapor chamber over time for the shallow reservoir cases. Compared to the deep reservoir cases, the cumulative rate of vapor chamber expansion is slower, which results from the lower mean operating temperature which in turn results from the lower mean target operating pressure. As discussed above, the oil production rate for the deep reservoir cases is also about 50% higher than for the shallow reservoir cases. Comparing the graded temperature scale of Figure 27 to Figure 26, it can be seen that the steam temperature for the shallow reservoir cases is approximately 190 C, compared to 225 C for the deep reservoir cases.

[00214] 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 utilized, or combined with other elements, components, or steps that are not expressly reference.

[00215]
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.

Claims

49

1. A method of recovering viscous oil from a subterranean reservoir having at least one well installed therein, the method comprising:
injecting a first heated vapor-phase working fluid via the at least one well to form a heated vapor chamber and producing a first production fluid via the at least one well;
ceasing injection of the first heated vapor-phase working fluid and intermittently injecting a second heated vapor-phase working fluid via the at least one well and producing a second production fluid via the at least one well; and wherein the second heated vapor-phase working fluid is heated electrically.

2. The method of claim 1, wherein the at least one well comprises an injection well and a production well in fluid communication within the vapor chamber and wherein the first and second heated vapor-phase working fluids are injected via the injection well and the first and second production fluids are produced via the production well.

3. The method of claim 2, wherein the method of recovering viscous oil is steam assisted gravity drainage (SAGD).

4 The method of claim 1, wherein the same at least one well is used for injection and production.

5. The method of claim 4, wherein the method of recovering viscous oil is cyclic steam stimulation (CSS).

6. The method of claim 4, wherein the method of recovering oil is steam flooding.

7. The method of any one of claims 1 to 6, wherein at least a portion of the second heated vapor-phase working fluid is heated electrically using a variably available electrical power source.
Date recue / Date received 2021-11-30

8. The method of claim 7, wherein the variably available electrical power source is a low carbon power source.

9. The method of claim 8, wherein the low carbon power source is at least one of wind power, solar power, hydroelectric power, geothermal power, nuclear power, and co-generation power.

10. The method of any one of claims 7 to 9, wherein all of the second heated vapor-phase working fluid is heated electrically using the variably available electrical power source.

11. The method of any one of claims 7 to 10, wherein a first portion of the second heated vapor-phase working fluid is heated electrically using the variably available electrical power source and a second portion of the second heated vapor-phase working fluid is heated electrically using a continuously available electrical power source.

12. The method of any one of claims 1 to 11, wherein the first heated vapor-phase working fluid is heated using a fired heating system.

13. The method of any one of claims 1 to 12, further comprising continuously injecting a third heated vapor-phase working fluid concurrently with intermittent injection of the second heated vapor phase working fluid, wherein the third heated vapor-phase working fluid is about 50% or lower of a cumulative injected volume of the second and third heated vapor-phase working fluids by liquid volume equivalent.

14. The method of claim 13, wherein the third heated vapor-phase working fluid has substantially the same composition or a substantially similar composition as the second heated vapor-phase working fluid.

15. The method of any one of claims 1 to 14, further comprising intermittently injecting a fourth vapor-phase working fluid when an injection rate of the second heated vapor-phase working fluid is at or near zero.
Date recue / Date received 2021-11-30

16. The method of claim 15, wherein the fourth vapor-phase working fluid comprises at least one of a vapor-phase solvent and a non-condensable gas.

17. The method of any one of claims 1 to 16, wherein ceasing injection of the first heated vapor-phase fluid is based on at least one of a preselected time, a numerical simulation, and a comparable continuous thermal oil recovery process.

18. The method of any one of claims 1 to 17, further comprising determining a target range for an operating parameter of the vapor chamber.

19. The method of claim 18, further comprising monitoring the operating parameter of the vapor chamber during injection of the first heated vapor-phase working fluid.

20. The method of claim 18 or 19, wherein a lower limit of the target range is adjusted upward or downward based on observed fluctuations in at least one of operating pressure and oil production.

21. The method of claim 20, further comprising ceasing injection of the first heated vapor-phase working fluid and starting intermittent injection of the second heated vapor-phase working fluid when the operating parameter of the vapor chamber is within the target range.

22. The method of any one of claims 18 to 21, further comprising monitoring the operating parameter of the vapor chamber during intermittent injection of the second heated vapor-phase working fluid.

23. The method of claim 22, wherein, if the operating parameter of the vapor chamber falls below the target range, continuously injecting the first or second heated vapor-phase working fluid to bring the operating parameter of the vapor chamber within the target range.

24. The method of claim 22 or 23, further comprising adjusting an instantaneous injection rate of the second heated vapor-phase working fluid to maintain the operating parameter of the vapor chamber within the target range.
Date recue / Date received 2021-11-30

25. The method of any one of claims 18 to 24, wherein the operating parameter is at least one of pressure and temperature.

26. The method of any one of claim 2, further comprising maintaining a level of a pool of drained liquid around the at least one production well at or above a threshold level to prevent vapor breakthrough into the at least one production well during production of the second production fluid.

27. The method of claim 26, wherein maintaining the level of the pool of drained liquid comprises adjusting an instantaneous production rate of the second production fluid.

28. The method of claim 27, wherein adjusting the instantaneous production rate of the second production fluid comprises increasing the instantaneous production rate during periods when injection of the second heated vapor-phase working fluid is high and decreasing the instantaneous production rate during periods when injection of the second heated vapor-phase working fluid is low.

29. The method of claim 26, wherein the level of the drained pool of liquid is allowed to vary while maintaining an approximately constant instantaneous production rate of the second production fluid.

30. The method of any one of claims 26 to 29, wherein the level of the drained pool of liquid is estimated using a subcool value.

31. The method of any one of claims 1 to 30, wherein injecting the first heated vapor-phase working fluid comprises continuously injecting the first heated vapor-phase working fluid.

32. The method of any one of claims 1 to 31, wherein the first heated vapor-phase working fluid comprises steam, a vapor-phase solvent, a non-condensable gas, or a combination thereof.
Date recue / Date received 2021-11-30

33. The method of any one of claims 1 to 32, wherein the second heated vapor-phase working fluid comprises steam, a vapor-phase solvent, a non-condensable gas, or a combination thereof.

34. The method of claim 32 or 33, wherein the vapor-phase solvent comprises propane, butane, pentane, hexane, heptane, octane, nonane, decane, undecane, dodecane, tridecane, tetradecane, diluent, natural gas condensate, kerosene, naptha, dimethyl ether, or a combination thereof.

35. The method of any one of claims 32 to 34, wherein the non-condensable gas comprises natural gas, carbon dioxide, nitrogen, carbon monoxide, hydrogen sulfide, hydrogen, anhydrous ammonia, helium, flue gas, methane, ethane, or a combination thereof.

36. The method of any one of claims 32 to 35, wherein the second heated vapor-phase working fluid has substantially the same composition as the first heated vapor-phase working fluid.

37. A system for recovering viscous oil from a subterranean reservoir, comprising:
at least one well installed in the subterranean reservoir;
an electrical heating system to heat a vapor-phase working fluid for injection via the at least one injection well; and a control system configured to implement the method of any one of claims 1 to 36.

38. The system of claim 37, wherein the electrical heating system is operatively connected to a variably available power source.

39. The system of claim 37 or 38, wherein the electrical heating system is operatively connected to a continuously available power source.
Date recue / Date received 2021-11-30

40.
The system of any one of claims 37 to 39, further comprising a fired heater system to heat the vapor-phase working fluid for injection via the at least one injection well.
Date recue / Date received 2021-11-30