CA3130631C

CA3130631C - Thermal solvent gravity drainage process with operating strategies

Info

Publication number: CA3130631C
Application number: CA3130631A
Authority: CA
Inventors: Jennifer Smith; Kristopher Rupert; Tair Ibatullin; Robert GLOVER; Ronald Zakariasen
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2019-08-23
Filing date: 2019-08-23
Publication date: 2023-10-17
Anticipated expiration: 2039-08-23
Also published as: CA3052855A1; CA3130631A1; CA3175303A1; CA3052855C

Abstract

A process for recovering bitumen from an underground reservoir having a horizontal injection well and a horizontal production well located below the injection well is provided. The process includes a first phase during which a solvent is injected in vapor form via the injection well at a first pressure that is higher than an initial reservoir pressure condition; and a second phase during which the solvent is injected via the injection well at a second pressure that is lower than the first pressure. Each of the first and second phases can further include providing heat to the injection well; condensing the solvent at a bitumen extraction interface thereby delivering heat to the bitumen and dissolving the bitumen; and recovering produced fluids including at least bitumen and solvent from the production well.

Description

THERMAL SOLVENT GRAVITY DRAINAGE PROCESS WITH OPERATING
STRATEGIES
TECHNICAL FIELD
[1] The technical field generally relates to a gravity drainage process for recovering heavy oil or bitumen from an underground reservoir using solvent and heat. More particularly, the technical field relates to a thermal solvent injection process with operating strategies, such as operating strategies involving pressure changes, for mobilizing and recovering heavy oil or bitumen from an underground reservoir.
BACKGROUND

[2] In situ recovery of viscous petroleum hydrocarbons, such as heavy oil or bitumen, from an underground formation, can be performed by injecting a solvent within the formation to mobilize the viscous hydrocarbons. Solvent vapor is injected into the formation via a horizontal well, which can be referred to as an injector well.
When contacting the cold viscous hydrocarbons in the reservoir, the solvent condenses and diffuses into and dissolves the hydrocarbons. As a result, the viscous hydrocarbons are diluted to a lower viscosity fluid, which drains to a production well that can be placed vertically below the injector well, in a spaced-apart relationship. Depending on the solvent composition that is used, some in situ deasphalting and upgrading of the viscous hydrocarbons can occur. Upon continuing solvent injection, a solvent chamber can grow around the well pair and above the injection well. Such hydrocarbon recovery processes can require the use of large quantities of solvent, in part because a portion of the solvent condenses within the chamber prior to reaching the chamber edges. In such scenarios, larger solvent quantities need to be recovered from the reservoir and then recycled via surface facilities.

[3] The performance of the solvent hydrocarbon recovery process can be impacted by its operating conditions. Various challenges exist in terms of operating Date Recue/Date Received 2021-09-14 strategies for recovering hydrocarbons, such as heavy oil or bitumen, from an underground reservoir using solvent vapour injection.
SUMMARY

[4]
According to an aspect, there is provided a process for recovering bitumen from an underground reservoir having a horizontal injection well and a horizontal production well located below the injection well. The process comprises a first phase during which a solvent comprising butane is injected in vapor form via the injection well at a first pressure of from about 50 to about 300 kPa above an initial reservoir pressure condition to enter the reservoir and develop an extraction chamber extending upward and outward from the injection well;
a second phase during which the solvent is injected via the injection well into the extraction chamber at a second pressure that is lower than the first pressure and at most about 50 kPa above an initial reservoir pressure condition;
wherein each of the first and second phases further comprises:
providing heat to the injection well;
condensing the solvent at a bitumen extraction interface thereby delivering heat to the bitumen and dissolving the bitumen; and recovering produced fluids comprising at least bitumen and solvent from the production well;
wherein the heat is provided using down hole heating means delivering heat energy at a rate per unit length ranging about 300 to about 800 W/m, and/or through injecting the solvent in a superheated state at a temperature of at least 100 C above a dew point thereof.
Date Recue/Date Received 2021-09-14

[5] In some implementations, the process further comprises monitoring a process parameter during the first phase and/or the second phase.

[6] In some implementations, the process parameter comprises at least one of HBR, SBR and a bitumen production rate.

[7] In some implementations, the downhole heating means includes an electric resistive heater.

[8] In some implementations, the first phase is performed after completion of a start-up operation for the recovery process.

[9] In some implementations, the first phase is performed as part of a ramp-up phase of the recovery process.

[10] In some implementations, the first phase is performed until a bitumen production rate reaches a plateau and/or inflection point.

[11] In some implementations, the first phase is performed as part of a ramp-up phase of the recovery process and until reaching an early portion of a bitumen production rate plateau.

[12] In some implementations, the first pressure ranges from about 350 to about 1000 kPa. In other implementations, the first pressure ranges from about 350 to about 900 kPa, or from about 350 to about 800 kPa, or from about 500 to about 700 kPa, or from about 600 to about 700 kPa, or from about 400 to about 550 kPa, or from about 450 to about 500 kPa.

[13] In some implementations, the first pressure is about 700 kPa and the second pressure is about 500 kPa.

[14] In some implementations, the second phase includes an initial transition phase during which the pressure is gradually reduced from the first pressure to the second pressure. In some implementations, the initial transition phase is performed over a period of about 10 months to about 15 months.
Date Recue/Date Received 2021-09-14

[15] In some implementations, the solvent injection in the second phase is performed about 1 year to about 2 years after a peak production rate is first achieved.

[16] In some implementations, the heat is provided during the first phase at a first phase heat energy that is lower than a second phase heat energy in the second phase.

[17] In some implementations, the first phase, heat energy is provided at a rate per unit length ranging from about 300 to about 600 W/m. In another implementation, in the second phase, heat energy is provided at a rate per unit length ranging from about 400 to about 800 W/m.

[18] In some implementations, the superheated solvent has a temperature ranging from about 30 C to about 200 C. In other implementations, the superheated solvent has a temperature ranging from about 30 C to about 170 C.
In another implementation, the superheated solvent has a temperature ranging from about 30 C to about 140 C.

[19] According to another aspect, there is provided a process for recovering bitumen from an underground reservoir having a horizontal injection well and a horizontal production well located below the injection well. The process comprises:
a first phase during which a solvent is injected in vapour form into the injection well at a first pressure that is higher than an initial reservoir pressure condition;
a second phase during which the solvent is injected into the injection well at a second pressure that is lower than the first pressure;
wherein each of the first and second phases further comprises:
providing heat to the injection well;
Date Recue/Date Received 2021-09-14 condensing the solvent at a bitumen extraction interface thereby delivering heat to the bitumen and dissolving the bitumen; and recovering produced fluids comprising at least bitumen and solvent from the production well.

[20] In some implementations, the solvent is selected and provided in an amount to induce asphaltene precipitation in the reservoir.

[21] In some implementations, the solvent is selected from propane, butane, pentane or any mixture thereof. In particular implementations, the solvent is butane.

[22] In some implementations, the process further comprises monitoring a process parameter during the first phase and/or the second phase.

[23] In some implementations, the process parameter comprises at least one of HBR, SBR and a bitumen production rate.

[24] In some implementations, the heat is provided using a downhole electric resistive heater, through electromagnetic heating, through injecting the solvent in a superheated state, or a combination thereof.

[25] In some implementations, the first phase is conducted to cause rapid growth of a first phase solvent chamber in the reservoir.

[26] In some implementations, the first phase is performed after completion of a start-up operation for the recovery process.

[27] In some implementations, the first phase is performed as part of a ramp-up phase of the recovery process.

[28] In some implementations, the first phase is performed until a bitumen production rate reaches a plateau.
Date Recue/Date Received 2021-09-14

[29] In some implementations, the first phase is performed as part of a ramp-up phase of the recovery process and until reaching an early portion of a bitumen production rate plateau.

[30] In some implementations, the first pressure is from about 50 to about 600 kPa above the initial reservoir pressure condition. In some implementations, the first pressure is from about 50 to about 500 kPa above the initial reservoir pressure condition. In other implementations, the first pressure is from about 50 to about 400 kPa above the initial reservoir pressure condition. In another implementation, the first pressure is from about 50 to about 300 kPa above the initial reservoir pressure condition.

[31] In some implementations, the solvent is butane and the first pressure ranges from about 350 to about 1000 kPa. In other implementations, the solvent is butane and the first pressure ranges from about 350 to about 900 kPa, or from about 350 to about 800 kPa, or from about 500 to about 700 kPa, or from about 600 to about 700 kPa.

[32] In some implementations, the second pressure is from about 50 to about 400 kPa above the initial reservoir pressure condition. In some implementations, the second pressure is from about 50 to about 300 kPa above the initial reservoir pressure condition. In other implementations, the second pressure is from about 50 to about 200 kPa above the initial reservoir pressure condition. In another implementation, the second pressure is from about 50 to about 100 kPa above the initial reservoir pressure condition.

[33] In some implementations, the second pressure is at most about 50 kPa above the initial reservoir pressure condition.

[34] In some implementations, the solvent is butane and the second pressure ranges from about 450 to about 500 kPa.
Date Recue/Date Received 2021-09-14

[35] In some implementations, the second pressure is 75% or lower than the first pressure. In other implementations, the second pressure is 50% or lower than the first pressure. In another implementation, the second pressure is 25% or lower than the first pressure.

[36] In some implementations, the second pressure is at least about 200 kPa lower than the first pressure.

[37] In some implementations, the difference between the second pressure and the initial reservoir pressure condition is at least about 200 kPa lower than the difference between the first pressure and the initial reservoir pressure condition.

[38] In some implementations, the second phase includes an initial transition phase during which the pressure is gradually reduced from the first pressure to the second pressure. In some implementations, the initial transition phase is performed over a period of about 10 months to about 15 months.

[39] In some implementations, the solvent injection at the lower second pressure is performed about 1 year to about 2 years after a peak production rate is first achieved.

[40] In some implementations, the heat provided during the first phase is lower than the heat provided in the second phase.

[41] In some implementations, the heat is provided during the first phase at a first phase heat energy that is lower than a second phase heat energy in the second phase.

[42] In some implementations, in the first phase, heat energy is provided at a rate per unit length ranging ranging from about 300 to about 1200 W/m. In some implementations, in the first phase, heat energy is provided at a rate per unit length ranging from about 300 to about 1000 W/m, or from about 300 to about 800 W/m, or from about 300 to about 600 W/m, or from about 300 to about 500 W/m, or from about 300 to about 400 W/m.
Date Recue/Date Received 2021-09-14

[43] In some implementations, in the first phase, heat energy is provided at a rate per unit length ranging from about 400 to about 600 W/m. In some implementations, in the first phase, heat energy is provided at a rate per unit length ranging from about 400 to about 500 W/m.

[44] In some implementations, in the first phase, heat energy is provided at a rate per unit length ranging from about 500 to about 600 W/m.

[45] In some implementations, in the second phase, heat energy is provided at a rate per unit length ranging from about 400 to about 1200 W/m. In some implementations, in the second phase, heat energy is provided at a rate per unit length ranging from about 400 to about 1000 W/m, or from about 400 to about W/m, or from about 400 to about 600 W/m.

[46] In some implementations, in the second phase, heat energy is provided at a rate per unit length ranging from about 500 to about 800 W/m. In some implementations, in the second phase, heat energy is provided at a rate per unit length ranging from about 500 to about 700 W/m, or from about 500 to about 600 W/m.

[47] In some implementations, in the second phase, heat energy is provided at a rate per unit length ranging from about 600 to about 800 W/m. In some implementations, in the second phase, heat energy is provided at a rate per unit length ranging from about 600 to about 700 W/m.

[48] In some implementations, the heat energy is provided at least using a downhole electric resistive (ER) heater.

[49] In some implementations, the heat is provided at least through injecting superheated solvent and the superheated solvent has a temperature of at least 100 C above a dew point thereof and up to a maximum temperature of 250 C. In some implementations, the heat is provided at least through injecting superheated Date Recue/Date Received 2021-09-14 solvent and the superheated solvent has a temperature of at least 100 C above a dew point thereof and up to a maximum temperature of 200 C.

[50] In some implementations, the heat is provided at least through injecting superheated solvent and the superheated solvent has a temperature ranging from about 30 C to about 200 C. In some implementations, the heat is provided at least through injecting superheated solvent and the superheated solvent has a temperature ranging from about 30 C to about 170 C, or from about 30 C to about 140 C.

[51] In accordance with another aspect, there is provided a process for recovering bitumen from an underground reservoir having a horizontal injection well and a horizontal production well located below the injection well. The process comprises:
injecting a solvent in vapour form into the underground reservoir via the injection well at a first pressure during a first phase, the first pressure being higher than an initial reservoir pressure;
monitoring a process parameter;
injecting the solvent in vapour form into the underground reservoir via the injection well at a second pressure during a second phase, the second pressure being determined at least in part based on the process parameter; and recovering a production fluid comprising bitumen via the production well.

[52] In some implementations, the process further comprises providing heat to the injection well.

[53] In some implementations, the heat is provided using a downhole electric resistive heater, through electromagnetic heating, through injecting the solvent in a superheated state, or a combination thereof.
Date Recue/Date Received 2021-09-14

[54] In some implementations, the process parameter comprises at least one of HBR, SBR and a bitumen production rate.

[55] In some implementations, when the HBR and/or the SBR reaches an upper threshold, the process is transitioned from the first phase to the second phase.

[56] In some implementations, when the HBR and/or the SBR has been maintained at an upper threshold for a given duration, the process is transitioned from the first phase to the second phase.

[57] In some implementations, the heat is provided during the second phase to remain within a similar range of the bitumen production rate achieved during the first phase.

[58] In some implementations, the heat is provided during the second phase to reduce a pressure differential between the first pressure and the second pressure.

[59] In some implementations, the heat is provided during the second phase to decrease the HBR or the SBR compared to the first phase.

[60] In some implementations, the second pressure is determined to limit solvent leaking-off to the underground reservoir.

[61] In accordance with another aspect, there is provided a method to determine an operating strategy for a process for recovering bitumen from an underground reservoir having a horizontal injection well and a horizontal production well located below the injection well using solvent injection. The process comprises:
performing a first set of reservoir simulations over a first range of simulation pressures to determine a first pressure at which to inject the solvent in a first phase of the process, wherein the first pressure enables to achieve a peak bitumen production rate or to achieve the peak bitumen production faster than other pressures within the first range of simulation pressures;
Date Recue/Date Received 2021-09-14 performing a second set of reservoir simulations over a second range of simulation pressures to obtain a set of data indicative of solvent consumption over a period of time; and performing a third set of reservoir simulations using the first pressure in the first phase and the set of data indicative of solvent consumption to determine a second pressure at which to inject the solvent in a second phase of the process, wherein the second pressure is lower than the first pressure.

[62] In some implementations, the data indicative of solvent consumption comprises at least one of SBR and HBR.

[63] In some implementations, the first range of simulation pressures is between about a native pressure of the underground reservoir and about 300 kPa above the native pressure of the underground reservoir.

[64] In some implementations, the first range of simulation pressure is determined in accordance with a property of the underground reservoir.

[65] In some implementations, the property of the underground reservoir comprises reservoir permeability, water saturation or water mobility.

[66] In some implementations, the period of time corresponds to between a completion of a start-up operation for the recovery process up until a wind-down phase.

[67] In some implementations, the method further comprises performing a fourth set of simulations to determine at which temperature to inject the solvent in the first phase and/or the second phase.

[68] In some implementations, the method further comprises injecting the solvent as vaporized solvent into the underground reservoir at the first pressure during the first phase of the process, and injecting the solvent as vaporized solvent Date Recue/Date Received 2021-09-14 into the underground reservoir at the second pressure during the second phase of the process.

[69] It should also be noted that various aspects, implementations, features or steps described or illustrated herein can be combined with other aspects, implementations, features or steps.
BRIEF DESCRIPTION OF THE DRAWINGS

[70] Fig. 1 is a cross sectional view of a solvent chamber developed above a horizontal well pair within an underground reservoir, using a thermal solvent recovery process according to some implementations.

[71] Fig. 2 is a diagram representing the effect of operating pressure and heat input on cumulative bitumen (oil) in a simulation of a two-phase thermal solvent recovery process according to some implementations. The simulation contemplates the use of an electric resistive heater to provide heat.

[72] Fig. 3 is a diagram representing the effect of operating pressure and heat input on cumulative hold-up in a simulation of a two-phase thermal solvent recovery process according to some implementations. The simulation contemplates the use of an electric resistive heater to provide heat.

[73] Fig. 4 is a diagram representing the effect of operating pressure and heat input on bitumen (oil) rate in a simulation of a two-phase thermal solvent recovery process according to some implementations. The simulation contemplates the use of an electric resistive heater to provide heat.

[74] Fig. 5 is a diagram representing the effect of operating pressure and heat input on solvent-to-bitumen (oil) ratio in a simulation of a two-phase thermal solvent recovery process according to some implementations. The simulation contemplates the use of an electric resistive heater to provide heat.
Date Recue/Date Received 2021-09-14

[75] Fig. 6 a diagram representing the effect of operating pressure and heat input on cumulative bitumen (oil) in a simulation of a two-phase thermal solvent recovery process according to some implementations. The simulation contemplates the use of superheated solvent to provide heat.

[76] Fig. 7 is a diagram representing the effect of operating pressure and heat input on cumulative hold-up in a simulation of a two-phase thermal solvent recovery process according to some implementations. The simulation contemplates the use of superheated solvent to provide heat.

[77] Fig. 8 is a diagram representing the effect of operating pressure and heat input on bitumen (oil) rate in a simulation of a two-phase thermal solvent recovery process according to some implementations. The simulation contemplates the use of superheated solvent to provide heat.

[78] Fig. 9 is a diagram representing the effect of operating pressure and heat input on solvent-to-bitumen (oil) ratio in a simulation of a two-phase thermal solvent recovery process according to some implementations. The simulation contemplates the use of superheated solvent to provide heat.
DETAILED DESCRIPTION

[79] Techniques described herein relate to processes for recovering heavy oil or bitumen from an underground reservoir using a solvent and heat to enhance mobilizing the heavy oil or bitumen within the reservoir. More particularly, the techniques involve injecting at least one solvent in the underground reservoir while providing heat at the injection location, for recovering heavy oil or bitumen, where the operating pressure and heating conditions are selected to balance bitumen production rate, solvent-to-bitumen ratio and/or hold-up bitumen ratio.

[80] In some implementations, there is provided a process for recovering bitumen from an underground reservoir having a horizontal injection well and a horizontal production well located below the injection well in a spaced-apart Date Recue/Date Received 2021-09-14 relationship. The process includes a first phase and a second phase. During the first phase, a solvent is injected in vapor form via the injection well into the reservoir so as to pressurize the reservoir to a first pressure that is higher than an initial reservoir pressure condition. During the second phase, the solvent is injected via the injection well so that the reservoir pressure is reduced to a second pressure that is lower than the first pressure. In each one of the first and second phases, the solvent is injected into the reservoir at a sufficiently high temperature such that the solvent remains in vapour phase until it contacts bitumen at an extraction interface. In order to do so, the solvent can be, for instance, heated at surface to be injected via the injected well as a superheated solvent, and/or various heating means can be provided in at least one of the horizontal wells so that the solvent can be heated and vaporized as it travels therealong prior to being injected into the reservoir. The process further includes providing heat to the injection well, condensing the solvent at the bitumen extraction interface thereby delivering heat to the bitumen and dissolving the bitumen, and recovering produced fluids including at least bitumen and solvent via the production well.

[81] "Bitumen" as used herein can refer to hydrocarbon material extracted from bituminous formations, such as oil sands formations, the density of which is typically around 1000 kg/m3 and the American Petroleum Industry's (API) gravity is around 8 . Bitumen can be recovered from a bitumen-containing reservoir using in situ recovery processes. The bitumen can include various non-hydrocarbon compounds (e.g., sulfur, metals, etc.) that are often found in bitumen and can be associated with certain hydrocarbon components (e.g., asphaltenes). Examples of bitumen include bitumen extracted from the Athabasca and Cold Lake regions, in Alberta, Canada.

[82] "Heavy oil", which can also be referred to as "heavy crude oil", can refer to any liquid petroleum with an American Petroleum Industry's (API) gravity of less than 22.3 and a density of about 920 to about 1000 kg/m3, although the density could be higher. Heavy oil usually contains asphaltenes and resins.
Date Recue/Date Received 2021-09-14

[83] For ease of reading, the term "bitumen" will be used in the following description of some implementations. However, one will understand that the described processes can be used in underground reservoirs containing either bitumen or heavy oil.

[84] Some of the quantitative expressions mentioned herein can be qualified with the term "about". The term "about" means within an acceptable error range for the particular value as determined by one of ordinary skill in the art, which will depend in part on how the value is measured or determined, i.e. the limitations of the measurement system. It is commonly accepted that a 10% precision measure is acceptable and encompasses the term "about".

[85] As mentioned above, the process described herein involves the injection of solvent to mobilize and then recover bitumen from a well region around horizontal injection and production wells of a well pair in subsurface bitumen containing reservoirs. This process can be used after fluid communication has been established between the wells, i.e. after completion of a start-up phase.

[86] In some implementations, a SAGD-type well pair as represented in Fig. 1 can be used for implementing the process. The well pair includes a first horizontal well 12, also referred to as an injection well, and a second horizontal well 14, also referred to as a production well, downwardly spaced apart from the injection well 12. A bitumen containing space is defined between the two horizontal wells and can be referred to as the interwell region 16. It should be understood that SAGD-type horizontal wells refer to the wells in their entirety including both the vertical and horizontal portions thereof. Multiple well pairs are generally arranged in parallel to one another in the reservoir, with an array of well pairs extending from a well pad at surface.

[87] As mentioned above, the present process is generally implemented after completion of a start-up phase. In some implementations, the start-up phase can include a reservoir conditioning phase during which a mobilizing fluid, such as a non-deasphalting fluid, is circulated in each horizontal well and then pushed from Date Recue/Date Received 2021-09-14 the injection well to the production well to sweep the interwell region. An initial pre-heating of the horizontal wells can be performed before circulating the non-deasphalting fluid. The mobilizing fluid can include diesel, naphtha or any other fluid known in the art for assisting mobilizing the bitumen in the interwell region and establish communication between the injection and production well. The fluid can also include steam, or a combination of a hydrocarbon-based fluid as mentioned above and steam.

[88] Various other start-up methods can be used to establish fluid communication between the horizontal wells. For instance, start-up methods can include fluid injection, fluid circulation, electrical heating, radio-frequency (RF) heating, chemical injection in at least one of the wells. Various combinations of these start-up methods can also be implemented. The injected or circulated fluid can include a hydrocarbon solvent, steam or a combination thereof, and the fluid can be provided as a vapour or a liquid. The start-up method can also be conducted in more than one stage using a different technique for each stage.

[89] Once the start-up phase is completed and fluid communication has been established between the horizontal wells, a heated solvent is injected into the reservoir in vaporized form via the injection well 12. When contacting the cold bitumen in the reservoir, the solvent condenses on the bitumen surface and releases latent heat of condensation which is transferred to the bitumen. In addition to providing heat to the bitumen, the solvent can also contribute to diluting the bitumen. The bitumen that has been diluted and heated produces a mobilized fluid having a lower viscosity, enabling the mobilized fluid to drain towards the production well 14. From the production well 14, the mobilized bitumen can be recovered to the surface as a production fluid and be further treated using surface facilities. The production fluid, in addition to the mobilized bitumen and some solvent, can include water that can be present in the reservoir, such as connate water from the pores of rock sediments, and also some solids and gas.
Depending on the solvent composition that is used, some degree of in situ solvent Date Recue/Date Received 2021-09-14 deasphalting can occur, and asphaltenes can be precipitated within the reservoir resulting in an in situ upgrading of the bitumen.

[90] Upon continuation of solvent injection, a solvent chamber 18 can grow upward and outward from the injection well 12. Optionally, to reduce early condensation of solvent and therefore solvent demand, additional heat can be provided in the reservoir. Heat addition can assist in maintaining the solvent in vapor state within the solvent chamber such that less solvent is produced with the bitumen when the production fluid is recovered to the surface via the production well. In such implementations, the heat can be provided at the injection well, at the production well, or both. The heat can also be provided proximate the injection, e.g., above the injection well, within the chamber. Various methods and equipment can be used to provide heat, for instance providing downhole heaters or injecting solvent that has been superheated at surface.

[91] In the present process, at least one solvent can be injected in the reservoir to dissolve bitumen and thereby reduce the bitumen viscosity, such that bitumen having a reduced viscosity can drain towards the production well and be recovered to the surface. In some implementations, the solvent can be selected and provided in an amount sufficient to induce asphaltene precipitation and deposition within the reservoir. Examples of solvents that can be used are low molecular weight alkanes, such as propane, butane or pentane, as well as combinations of such solvents can also be used.

[92] In the present thermal process, the solvent is injected into the reservoir as a vaporized solvent. Various methods can be used to introduce the solvent as vaporized solvent into the reservoir. For instance, heat can be provided to the injection well by direct wellbore heating, for instance by using electric resistive heaters. In other implementations, the solvent can be injected in a superheated state. A combination of superheated solvent and downhole heating can also be used. In this context, "superheated solvent" refers to a solvent that is injected at a temperature above its dew point temperature at the operating reservoir pressure.
Date Recue/Date Received 2021-09-14 Other heating means can include hot tubes that use a circulating heating media provided in the well, induction or electromagnetic heating, radio-frequency heating, microwave heating, or the like.

[93] In some implementations, the injection design can include injecting the solvent in vapour phase and then controlling the degree of superheating of the vapour via surface heaters and downhole electric resistive heaters. The degree of superheat can be 20 C, 30 C, 40 C or more.

[94] In some implementations, heating through downhole heating and/or injecting a superheated solvent having a certain degree of superheat can contribute to maintaining solvent within the solvent chamber in a vaporized state.

[95] The operating pressure in the solvent chamber, i.e., the pressure within the solvent chamber, and, optionally, the heat input provided to keep the solvent in vapor state in at least a portion of the solvent chamber, can impact the performance of the bitumen recovery process. For instance, process parameters such as solvent-bitumen ratio (SBR), hold-up bitumen ratio (HBR) and/or bitumen production rate can be particularly affected. For instance, injecting solvent such that the solvent chamber operating pressure is at a high pressure, or within a range of high pressures, can facilitate rapid solvent chamber development, which in turn can result in a higher production rate. On the other hand, operating the solvent chamber at a high pressure can result in a high SBR and HBR, which can be undesirable, for example for economical reasons. Operating the solvent chamber at a low pressure, or within a range of low pressures, can results in a low SBR and HBR, which can be advantageous under certain circumstances. The present process proposes operating strategies that include initially injecting solvent at high pressure, and then injecting solvent at a lower pressure during the hydrocarbon recovery process to balance bitumen production rate, SBR and/or HBR.

[96] In some implementations, an example of an operating pressure strategy for the present thermal solvent hydrocarbon recovery process can include initially injecting solvent at a high injection pressure to rapidly grow the solvent chamber Date Recue/Date Received 2021-09-14 in the reservoir, and subsequently reducing the injection pressure such that the solvent is injected at a lower injection pressure. In some implementations, the transition from a high injection pressure to a low injection pressure can be implemented to lower the long term SBR and HBR. The initial rapid chamber growth can result in a solvent chamber having a large surface area, which can facilitate bitumen drainage when subsequently operating at lower pressures as recovery operations continues over time. This operating strategy can result in a bitumen production profile that is substantially similar to one that would be obtained using high pressures only, but with limited impact on long term solvent performance, SBR and HBR.

[97] According to the present process, the solvent can be injected at a first pressure during a first phase and then at a second pressure during a second phase, the second pressure being lower than the first pressure. The "first pressure"
and "second pressure" at which the solvent can be injected refer to the pressure that is reached in the chamber in the underground reservoir upon solvent injection.
The expression "extraction pressure" or "injection pressure" can also be used to refer to such pressure in the reservoir. The first pressure is also above the initial reservoir pressure condition. The terms "initial reservoir pressure condition"
or "initial reservoir pressure" refer to the pressure in the reservoir before starting the present two-phase recovery process, which corresponds to the reservoir native pressure.

[98] By injecting the solvent at high pressure in the first phase of the process, solvent leak-off can be facilitated which, in turn, can enhance convective mixing of the solvent with the bitumen. The solvent/bitumen fluid that is produced in situ can then drain towards the production well and be produced at the surface, resulting in a rapid growth of the solvent chamber in the reservoir.

[99] In some implementations, the injection pressure in the first phase of the process can range from about 50 to about 600 kPa above the initial reservoir pressure. In other implementations, the injection pressure in the first phase can Date Recue/Date Received 2021-09-14 range from about 50 to about 500 kPa, or from about 50 to about 400 kPa, or from about 50 to about 300 kPa, or from about 50 to about 200 kPa, or from about 50 to about 100 kPa above the initial reservoir pressure.

[100] As previously mentioned, the solvent used for assisting the bitumen recovery from the underground reservoir can be butane. When butane is used as the solvent, the injection pressure in the first phase can range from about 350 to about 1000 kPa, for example. In some implementations where butane is the solvent that is injected in the reservoir, the first phase injection pressure can range from about 350 to about 900 kPa, or from about 350 to about 800 kPa, or from about 500 to about 700 kPa. In other implementations, butane can be injected in the first phase at an injection pressure ranging from about 600 to about 700 kPa.
The selection of the pressure in the first phase of the process can be determined in accordance with the type of reservoir, the type of solvent, and the initial pressure condition thereof. In addition, the first phase can be operated at a generally constant first phase pressure, or can be operated at different pressures that are within a first operating envelope for the first phase pressure.

[101] In some implementations, the first phase of the process involving injecting the solvent at high pressure can be performed after completion of the start-up operation for the recovery process. This first phase can therefore be performed as part of the ramp-up phase of the recovery process. During this phase, the communication zone between the wells is expanded axially along the full well pair length to enhance conformance along the well, and the solvent chamber grows vertically up to the top of the bitumen zone in the reservoir.

[102] In some implementations, the first phase of the process can be performed until a bitumen production rate reaches a plateau or a maximum, i.e., when substantially full expected production rate capacity is attained. The injection of the solvent at high pressure can be maintained throughout the ramp-up and into the early portion of the plateau to maximize bitumen production rates. In some implementations, the first phase can be performed until the bitumen production Date Recue/Date Received 2021-09-14 rate reaches about 120 to about 160 m3/d, or from about 120 to about 150 m3/d, or from about 120 to about 140 m3/d, or from about 130 to about 150 m3/d, or from 130 to about 140 m3/d.

[103] In the second phase of the present process, the solvent is injected into the reservoir at a lower pressure than that of the first phase. In some implementations, the injection pressure can be gradually decreased from the higher level in the first phase to the lower level in the second phase. In other words, a transition phase can be implemented at the end of the high pressure injection phase until reaching the lower pressure intended to be used for the second phase.

[104] In some implementations, the solvent injection pressure in the second phase can range from about 50 to about 400 kPa above the initial reservoir pressure condition. In other implementations, the solvent injection pressure in the second phase is at most about 10 kPa, 20 kPa, 30 kPa, 40 kPa, 50 kPa, 60 kPa, 70 kPa, 80 kPa, 90 kPa or 100 kPa above an initial reservoir pressure, for example.
Using a lower solvent injection pressure in the second phase of the process can help minimize solvent losses as the solvent chamber spreads and/or the production rates decline. In some implementations, the injection pressure is lowered in the second phase to approach or generally match the initial reservoir conditions thereby minimizing solvent leak-off rate to the native reservoir adjacent to the swept solvent chamber.

[105] In some implementations, butane can be used as the solvent for mobilizing the bitumen within the reservoir, and the butane injection pressure during the second phase of the process can range from about 400 to about 550 kPa or 450 to 500 kPa.

[106] In some implementations, the second phase injection pressure can be at least about 100 kPa, 150 kPa, 200 kPa, or 250 kPa lower than the first pressure.
In other implementations, the difference between the second pressure and the initial reservoir pressure condition can be at least about 200 kPa, 250 kPa or Date Recue/Date Received 2021-09-14 kPa lower than the difference between the first pressure and the initial reservoir pressure condition.

[107] In some implementations, the solvent is injected in the second phase at a pressure which can be at most 75% compared to the injection pressure in the first phase of the process. In other implementations, the injection pressure in the second phase can be at most 50% of the first phase pressure, at most 25% of the first phase pressure, or lower.

[108] As explained above, the timing for the operating pressure change between the first and second phases of the recovery process, i.e., the timing to switch to a lower operating pressure, can be aligned with the end of ramp-up/early stages of the plateau phase of production. In some implementations, the solvent injection at the lower pressure in the second phase of the process can start about one year to about two years after a peak production rate is first achieved. In other implementations, the solvent injection in the second phase of the process can be performed about one year after a peak production rate is first achieved.

[109] In some implementations, an operating pressure strategy that includes a first phase during which vaporized solvent is injected at a first pressure, i.e., a high pressure, followed by a second phase during which vaporized solvent is injected at a second that is lower than the first pressure, can contribute to balance process parameters such as HBR, SBR and production rate. In the present description and as mentioned above, a high pressure can be for instance a pressure between about 50 to about 600 kPa above the initial reservoir pressure. For instance, operating the solvent chamber at a first pressure during ramp-up can facilitate growing the solvent chamber as rapidly as possible, and advantageously result in a desirable production rate. However, maintaining the solvent chamber at the first pressure involves injecting substantial amount of vaporized solvent into the reservoir to compensate for solvent leak-off, resulting in a high SBR and HBR.
To benefit from the advantages of operating the solvent chamber at the first pressure without continuing the injection of large amounts of vaporized solvent, the first Date Recue/Date Received 2021-09-14 phase is performed for a given duration which can be up until a peak bitumen production rate is attained, and then a transition to the second phase can be initiated. In the second phase, the extent of pressure reduction can be determined so as to maintain the bitumen production rate within a desirable range while reducing solvent leak-off and thus HBR and SBR so that the recovery operations can remain economical over time. Advantageously, reducing the operating pressure of the solvent chamber can contribute to maintain solvent in vaporized form within the solvent chamber, thereby reducing the amount of solvent necessary to remain within the desirable range of production rate as less solvent is being produced with the production fluid, and thus reducing HBR and SBR. In some implementations, additional heat can also be provided in at least a portion of the solvent chamber to contribute maintaining solvent in vaporized form within the solvent chamber, which can also facilitate remaining within the desirable range of bitumen production rate.

[110] During the first phase of the recovery process where the solvent is injected at high pressure and during the second phase of the process which is performed at a lower pressure than the first phase, heat energy is provided in at least a portion of the solvent chamber, for instance to the injection well, to maintain the solvent in vaporized form. As mentioned above, the amount of heat energy provided around the injection well can affect the performance of the recovery process. In some implementations, the heat input provided in the first phase and the second phase of the recovery process can thus be selected to balance the bitumen production rate, SBR and/or HBR. The heat input can also be selected based on the pressure operating strategy.

[111] In some implementations, the method selected for providing the desired heat during the first phase of the process can be different than the heating method used during the second phase. For instance, superheated vaporized solvent can be injected at high pressure during the first phase, and then solvent can be injected at a lower temperature while heat is provided using downhole heating during the second phase. Alternatively, the first phase can involve injecting vaporized solvent Date Recue/Date Received 2021-09-14 at high pressure and heating the injection well using downhole heating, and then injecting superheated solvent during the second phase. The two phases can also utilize both heating methods to different degrees, such that one phase uses more superheating energy than the other. In some implementations, the solvent injected temperatures and pressures can be varied in the first phase and the second phase, using surface and downhole equipment and/or by varying the degree of solvent superheat at surface.

[112] In some implementations, the heat provided during the first phase and the second phase of the recovery process can be the same. However, it can be advantageous, in some implementations, to vary the heat input in the first phase and the second phase of the process. In some implementations, the heat energy provided in the first phase of the process while injecting the solvent at high pressure can be lower than the heat energy provided in the second phase of the process while injecting the solvent at lower pressure. In other implementations, the heat energy provided in the first phase of the process while injecting the solvent at high pressure, can be higher than the heat energy provided in the second phase of the process while injecting the solvent at lower pressure. For instance, during the first phase of the process when the solvent is injected at a first pressure, i.e., a high pressure, that is sufficient to facilitate convective mixing of the solvent with the bitumen at the extraction interface, the solvent chamber is still small and it may be advantageous to limit the heat provided such that solvent is still under conditions that it can condenses at the extraction interface. Then, as the first phase of the process transitions to the second phase of the process and as the solvent chamber grows, increased heat can be provided since the solvent chamber is now larger. Then, during the second phase of the process, the amount of heat can be chosen such that sufficient solvent remains in vapor phase within the solvent chamber to maintain the operating pressure of the solvent chamber and/or maintain a desirable production rate. Use of a downhole electric resistive (ER) heater to provide the desired heat energy can be particularly convenient in the Date Recue/Date Received 2021-09-14 context of the present description, although other downhole heating means can also be contemplated, as previously mentioned.

[113] The amount of heat energy can be adapted depending on the type of solvent that is injected. Higher heat energy can be desired to maintain a solvent having a higher molecular weight in vapour form. For instance, if the solvent is pentane, the heat energy can be higher than the heat energy provided if butane or propane are used as the solvent, at the same operating pressure.

[114] In addition, in some implementations, the amount of heat provided can be determined according to the operating pressure of the solvent chamber, to compensate for certain drawbacks of operating at either a high pressure or a lower pressure. For instance, as mentioned above, the amount of heat to be provided can be determined such that the production rate is maintained within an acceptable range when the operating pressure of the solvent chamber is reduced. In some implementations, providing additional heat to a portion of the solvent chamber can also contribute to maintain a certain pressure within the solvent chamber while less solvent is being injected.

[115] In some implementations, the heat energy can be provided in the first phase of the process, at a rate per unit length ranging from about 300 to about 1200 W/m.
An amount of up to 1200 W/m can be desirable when pentane is used as the solvent. In other implementations, the heat energy can be provided in the first phase of the process at a rate per unit length ranging from about 300 to about W/m, or from about 300 to about 800 W/m, or from about 300 to about 600 W/m, or from about 300 to about 500 W/m, or from about 300 to about 400 W/m, or from about 400 to about 600 W/m, or from about 400 to about 500 W/m, or from about 500 to about 600 W/m.

[116] In the second phase of the process, while the solvent is injected at lower pressure, the heat energy can be provided a rate per unit length ranging from about 400 to about 1200 W/m. As for the first phase, higher heat energy rate can be desired if the solvent is pentane compared to butane or propane. In other Date Recue/Date Received 2021-09-14 implementations, the heat energy can be provided in the second phase of the process at a rate per unit length ranging from about 400 to about 1000 W/m, or from about 400 to about 700 W/m, or from about 400 to about 600 W/m, or from about 500 to about 800 W/m, or from about 500 to about 700 W/m, or from about 500 to about 600 W/m, or from about 600 to about 800 W/m, or from about 600 to about 700 W/m.

[117] When the solvent is injected in a superheated state, the heat energy transferred by the solvent to the reservoir around the injection well can be sufficient to limit early condensation of the solvent in the proximity of the injection well.
Therefore, in some implementations, the recovery process can involve injecting superheated solvent during the first phase and the second phase of the process, without requiring additional downhole heating means. However, if the degree of superheating of the solvent vapour provided by surface heaters is insufficient, downhole electric resistive heaters, or any other downhole heating means, can be used to increase the superheated solvent temperature in either one or both phases of the process.

[118] In further implementations, the injection temperature of the superheated solvent can be the same in the first and second phase. In other implementations, the temperature of the superheated solvent injected in the first phase can be different than the temperature in the second phase of the process. For instance, the superheated solvent can be injected at a temperature that is higher in the first phase of the process than in the second phase. Alternatively, the superheated solvent can be injected at a lower temperature in the first phase than in the second phase of the process. For instance, in some implementations, process parameters such as HBR, SBR and bitumen production rate can be monitored, and the degree of superheat in the first phase and/or the second phase can be determined at least in part based on a monitored process parameter. For instance, when solvent is injected at a pressure higher than the native reservoir pressure during the first phase of the process, a portion of solvent can leak-off to the reservoir, resulting in a high HBR and SBR. In such implementations, additional solvent may be injected Date Recue/Date Received 2021-09-14 at a high degree of super heat to encourage solvent to remain within the chamber and reduce the need for injection of fresh solvent in the reservoir. In other implementations, the amount of heating in the second phase can be chosen so as to maintain the production rate achieved during the first phase of the process without having to inject substantial amount of fresh solvent in the reservoir, as the heating contributes to solvent remaining in vapour phase in the solvent chamber to efficiently extract bitumen at the edge of the solvent chamber. Thus, the amount of heat can be determined so as to reduce the amount of fresh solvent that would be required to maintain the solvent chamber at a given pressure and maintain a desirable bitumen production rate.

[119] In some implementations, the determination of the degree of superheat in each one of the first phase and the second phase can be done in accordance with the injection pressure of the solvent in these respective phases. In some implementations, injecting the solvent at a higher degree of superheat can contribute to maintain a given operating pressure of the solvent chamber since the solvent will thus have a higher tendency to remain in the solvent chamber.

[120] In some implementations, the superheated solvent can be injected at a temperature of at least 100 C above a dew point of the solvent. In some implementations, the superheated solvent can be injected up to an upper temperature threshold. The upper temperature threshold can be a temperature at which coking of bitumen is avoided in the reservoir. The upper temperature threshold can be a temperature determined according to practical considerations of the process. For example, the upper temperature threshold can be 200 C, or can be 250 C.

[121] In other implementations, the solvent can be injected in a superheated state at a temperature ranging from about 30 C to about 200 C, or from about 30 C to about 170 C, or from about 30 C to about 140 C. If butane is used as the solvent, a temperature from about 30 C to about 140 C can be suitable.
Date Recue/Date Received 2021-09-14

[122] The second phase of the process can continue as long as the bitumen production rate is economic and/or that the SBR does not increase to an undesirable limit. In some implementations, solvent injection is then ceased and a wind-down phase can be implemented, where a non-condensable gas (NCG) can be injected under pressure in the context of a pressure maintenance strategy.

[123] It is also noted that several well pairs can be deployed from a well pad and are typically arranged so that at least some of the well pairs are in parallel and side-by-side relationship to each other to form an array of well pairs in the reservoir.
For an array of side-by-side well pairs, the solvent injection can be controlled so that multiple well pairs, and optionally all of the well pairs, are transitioned from the high pressure phase to the low pressure phase generally at the same time.
Coordinating the transition from high to low pressure for the side-by-side well pairs can reduce the risk of high pressure solvent inadvertently leaking from a high pressure chamber into an adjacent low pressure chamber. In some implementations, adjacent well pairs are transitioned from the higher pressure phase to the low pressure phase together. Surface operations can also be facilitated when all adjacent well pairs are converted together from high to low pressure modes. Nevertheless, depending on well pair spacing, chamber growth, and the progression of the process for each well pair, it may be desirable to operate some adjacent well pairs at different pressure phases.

[124] It is also noted that an array of adjacent well pairs can be operated so that all of the injection wells are operated under the same pressure during the different pressure stages of the process. Alternatively, the well pairs could be operated at different specific pressures from each other while all being within a general pressure operating envelope for the given stage. In addition, for an array of wells, eventually adjacent chambers can coalesce to form a common chamber that has a generally uniform pressure. The well pairs can be operated such that coalescence occurs during the second phase and thus under low pressure conditions.
Date Recue/Date Received 2021-09-14

[125] The pressure and heating operating conditions of the process described above can vary depending on the nature of the bitumen reservoir and the initial reservoir parameters. However, thermal solvent bitumen recovery from any bitumen reservoir can benefit from the two-phase strategy described herein.

[126] In accordance with another aspect, there is provided a method that can be implemented to determine a first pressure and a second pressure at which to operate the two-phase strategy, the second pressure being lower than the first pressure. In the method, simulations are performed, such as reservoir simulations, and solvent injection can be performed in accordance with the output of the simulations, in particular with regard to the pressure and optionally the temperature at which the solvent is injected. The method includes performing a first set of simulations over a first range of simulation pressures to determine a first pressure at which to inject the solvent in a first phase of the process. In other words, an initial reservoir pressure is set in a simulation model, and this initial pressure can be determined for instance taking into account reservoir permeability, water saturation, and water mobility. In some implementations, this initial pressure can be for instance about 200 to 300 kPa above the native reservoir pressure. In other implementations, the initial pressure can be set to be between the native reservoir pressure and up to about 500 kPa above the native reservoir pressure.
Simulations are run for the life of the well at the initial pressure chosen. Then simulations are repeated to determine which of the initial pressure chosen enables to achieve a peak bitumen production rate or at which a faster peak bitumen production can be achieved, compared to other pressures used in the simulations. Simulations are also performed at different pressures to obtain data that is indicative of solvent consumption over the life of the well. A combination results obtained from the simulations can be used to determine which pressure is advantageous to achieve a desirable bitumen production rate and/or to achieve the peak bitumen production rate faster, at which point during the life of the well the consumption of solvent reaches an upper limit that is undesirable, for instance for economic considerations, and at which point during the life of the well the initial pressure can Date Recue/Date Received 2021-09-14 be dropped to a lower pressure that enables maintaining a substantially similar bitumen production rate while reducing solvent consumption. The initial pressure data indicative of solvent consumption can thus contribute to determine a second pressure at which to inject the solvent in a second phase of the process, wherein the second pressure is lower than the first pressure.
EXAMPLES / SIMULATION EXPERIMENTS

[127] Reservoir simulations were performed using the software STARS
developed by the company Computer Modelling Group Ltd. Several sensitivity runs were performed with respect to operating pressure and heat input to verify operating strategies. Two sets of simulations were performed. The first simulation set was performed contemplating the use of an electric resistive heater (ER
heater) to provide heat and the second set was performed contemplating the use of superheated solvent to provide heat. Both simulations were initialized with reservoir properties around the producer and injector representative of a pre-heat and start-up phase having been completed. The initial reservoir pressure was thus set to 450 kPa. The solvent contemplated for the simulation was butane.

[128] The results are reported in Figs. 2 to 9. For both simulation sets, the cumulative bitumen (oil), the cumulative hold-up, the bitumen (oil) rate and the solvent-to-bitumen ratio (referred to as "iSvOR" in the diagrams) were recorded. It is worth mentioning that the cumulative hold-up can be converted to HBR by dividing by cumulative oil.

[129] In both simulation sets, data were collected to compare a single-phase process in which the injection pressure was set to a single value over time (400, 450, 500, 600 or 700 kPa) with a two-phase process according to the present technology in which the pressure in the first phase was higher than the pressure in the second phase. More particularly, the two-phase process simulation was performed at a pressure set to 700 kPa in the first phase and to 500 kPa in the second phase. The pressure was dropped from 700 KPa to 500 KPa over 1-2 months. In the simulations, the pressure change translated into the artefact Date Recue/Date Received 2021-09-14 observed around 31-35 months in the plots represented in Figs. 3 to 5 and 7 to 9, where a rapid pressure drop can be observed. It is worth mentioning that in a real reservoir, the injection pressure may not transition so rapidly, as the transition can occur over a period of about 10 months to about 15 months, or about one year.

[130] The results reported in Figs. 2 to 9 show that the influence of pressure and heat input on the cumulative bitumen, the cumulative hold-up, the bitumen rate and the solvent-to-bitumen ratio, is generally comparable whichever heating method is used.

[131] The data show that low operating pressures (400 to 500 kPa) encourage a low solvent-bitumen ratio (SBR) and hold-up bitumen ratio (HBR), while high pressures (500 to 700 kPa) encourage rapid solvent chamber development and thus higher oil rates, at the expense of higher SBR and HBR, for instance due to solvent leak-off. From the simulations, one can note that the operating pressure strategy for a solvent-based gravity drainage recovery process comprising of a combination of high injection pressures initially, to rapidly grow the chamber, followed by a gradual drop to low pressures to reduce solvent leak-off, can contribute to lower the long term SBR and HBR. The initial rapid chamber growth can advantageously provide a large surface area for drainage to occur more effectively at lower pressures throughout the remainder of the well life. This can result in a bitumen profile similar to that of the high pressure cases, with limited impact to long term solvent performance, as well as the SBR and HBR on a facility basis.

[132] The simulation data also indicate that the amount of heat input can affect process parameters. In general, higher heat input lowers SBR and HBR as solvent is encouraged to remain in the solvent chamber as vaporized solvent, while operating at high pressure in the solvent chamber can contribute to increase the bitumen production rate.

[133] It is worth noting that heating rates, whether accomplished via ER
heater power or degrees of solvent superheat at surface, can be tied to the process Date Recue/Date Received 2021-09-14 operating pressure. Since the dew point temperature of butane increases with pressure, it can take a greater amount of enthalpy to maintain butane in the vapour phase and to condense butane in the reservoir as the operating pressure increases.

[134] From the simulations data, one can note that a particularly interesting strategy for a reservoir presenting the above mentioned conditions (initial pressure of 450 kPa) and using butane as solvent, can be to implement the first phase at a pressure of about 700 KPa and the second phase at a pressure of about 500 KPa.

Moreover, heating to about 600 W/m using an ER heater or injected superheated butane at about 140 C, in both the first and second phases, appear to provide a good balance in terms of the cumulative oil, oil rate, SBR and/or cumulative HBR.
Date Recue/Date Received 2021-09-14

Claims

33

1. A process for recovering bitumen from an underground reservoir having a horizontal injection well and a horizontal production well located below the injection well, the process comprising:
injecting a solvent in vapour form into the underground reservoir via the injection well at a first pressure during a first phase, the first pressure being higher than an initial reservoir pressure;
monitoring a process parameter;
injecting the solvent in vapour form into the underground reservoir via the injection well at a second pressure during a second phase, the second pressure being determined at least in part based on the process parameter; and recovering a production fluid comprising bitumen via the production well.

2. The process of claim 1, wherein the process parameter comprises at least one of a hold-up bitumen ratio, a solvent-bitumen ratio and a bitumen production rate.

3. The process of claim 2, wherein when the hold-up bitumen ratio and/or the solvent-bitumen ratio reaches an upper threshold, the process is transitioned from the first phase to the second phase.

4. The process of claim 2, wherein when the hold-up bitumen ratio and/or the solvent-bitumen ratio has been maintained at an upper threshold for a given duration, the process is transitioned from the first phase to the second phase.

5. The process of any one of claims 2 to 4, further comprising providing heat to the injection well.
Date Recue/Date Received 2023-02-09

6. The process of claim 5, wherein the heat is provided using a downhole electric resistive heater, through electromagnetic heating, through injecting the solvent in a superheated state, or a combination thereof.

7. The process of claim 5 or 6, wherein the heat is provided during the second phase to decrease the hold-up bitumen ratio or the solvent-bitumen ratio compared to the first phase.

8. The process of any one of claims 5 to 7, wherein the heat is provided during the second phase to remain within a similar range of the bitumen production rate achieved during the first phase.

9. The process of any one of claims 5 to 8, wherein the heat is provided during the second phase to reduce a pressure differential between the first pressure and the second pressure.

10. The process of any one of claims 1 to 9, wherein the second pressure is determined to limit solvent leaking-off to the underground reservoir.
Date Recue/Date Received 2023-02-09