CA3156254C - Gravity drainage of hydrocarbons by steam and solvent injections with reduced energy usage - Google Patents

Abstract

A gravity drainage process for production of viscous oil from one or more well pairs in an underground reservoir is described. The process includes a first step of providing an injection of steam into an upper well of the well pair to form a steam chamber which mobilizes and produces the viscous oil via a lower well of the well pair until the steam chamber occupies between 25% to 80% of the reservoir volume. Then in a second step, the injection of steam is stopped and a predominantly vaporized, condensable non- aqueous solvent is injected into the upper well. The non-aqueous solvent mixes with the steam in the steam chamber, thereby lowering the temperature of the steam chamber and vaporizing water in the steam chamber which then transfers heat stored in the steam chamber to the steam chamber boundary. The process greatly reduces heat requirements for producing the remaining viscous oil while making efficient use of heat injected by steam.

Description

Gravity Drainage of Hydrocarbons by Steam and Solvent Injections with Reduced Energy Usage TECHNICAL FIELD
[0001] The disclosure relates generally to hydrocarbon recovery from underground reservoirs. More specifically, the disclosure relates to gravity drainage processes utilizing both steam and hydrocarbon solvents to recover viscous hydrocarbons.
BACKGROUND

[0002] Bitumen and heavy oil reserves (collectively referred to herein as "viscous oil" or "viscous hydrocarbons" as further defined below) exist at various depths beneath the earth's surface. Where viscous oil is found at depth, it is commonly produced to surface using in situ processes. Most commonly, in situ processes comprise injecting a mobilizing agent such as steam or solvent into the underground reservoir through a well to mobilize the oil and then a combination of gravity drainage and pressure cause the oil to flow to a production well. The viscous oil is pumped to the surface from the production well.

[0003] One example of an in situ process is steam-assisted gravity drainage (SAGD). In SAGD, directional drilling is employed to place two horizontal wells in the reservoir; a lower horizontal well near the base of the reservoir which is used for production with a second horizontal well above the first well which is used for injection. Steam is injected into the upper well to heat the bitumen and lower its viscosity. The condensed steam, viscous oil and other reservoir fluids will then drain downward through the reservoir under the action of gravity drainage and flow into the lower production well, whereby these liquids are pumped to surface. On the surface, the viscous oil is separated from the other fluids so that it can be transported to an oil refinery and converted into a variety of products of value. An example of SAGD is described in U.S. Patent No. 4,344,485 (Butler).

[0004] Another example of an in situ process is a process known as "Vapor Extraction"
(Vapex) where a similar well configuration to SAGD is employed but instead of steam, a solvent vapor such as a light hydrocarbon (e.g. propane, butane or other alkanes) is injected as the mobilizing agent. An example of Vapex is described in U.S.
Patent No

5,899,274 (Frauenfeld).

Date Recue/Date Received 2022-04-19 [0005] In situ processes can also combine heat and solvent as the mobilizing agents. An example is Heated Vapex (H-Vapex) where heated solvent is injected into the reservoir.
An example of H-Vapex is described in U.S. Patent 6,883,607 (Nenniger).

[0006] In situ processes can also combine steam and solvent injection as the mobilizing agents along with their associated heat. Examples include Solvent-Assisted Steam-Assisted Gravity Drainage (SA-SAGD) as described in Canadian Patent No.
2,323,029 (Nasr), and the Steam and Vapor Extraction Process (SAVEX) as described in U.S. Patent No. 6,662,872 (Gutek) and Canadian Patent No. 2,553,297 (Gates).

[0007] Azeotropic Vapex (AzeoVapex) is an improvement on H-Vapex where steam and solvent are co-injected, thereby significantly reducing the volumes of solvent required while maintaining the benefits of a lower operating temperature as described in Canadian Patent No. 2,915,571 (Boone).

[0008] It is desirable to provide an improved or alternative gravity drainage process for recovering viscous oil from an underground reservoir. In particular, it is desirable to develop improved processes that reduce or minimize the heat required to produce the recoverable oil and thereby minimize the associated greenhouse gas (GHG) emissions as well as reducing the large volumes of solvent that must be processed with the H-Vapex and AzeoVapex processes.
SUMMARY

[0009] The process described herein provides a gravity drainage process for producing viscous oil using steam injection followed by solvent injection. Mixing solvent in the steam chamber of the reservoir at an appropriate point in time provides the effect of lowering the temperature of the steam chamber and vaporizing water in the steam chamber which then transfers heat stored in the steam chamber to the steam chamber boundary. The process greatly reduces heat requirements for producing the remaining viscous oil while making efficient use of heat injected by steam and limiting the volume of solvent that is injected.

[0010] Accordingly, in one embodiment, a gravity drainage process for production of viscous oil from one or more well pairs in an underground reservoir is provided which includes the steps of: (a) providing an injection of steam into an upper well of the well pair Date Recue/Date Received 2022-04-19 to form a steam chamber which mobilizes and produces the viscous oil via a lower well of the well pair until the steam chamber occupies between 25% to 80% of the reservoir volume; (b) stopping the injection of steam after step (a) and starting the injection of a predominantly vaporized, condensable non-aqueous solvent as a vapor into the upper well, the non-aqueous solvent mixing with the steam in the steam chamber, thereby lowering the temperature of the steam chamber and transferring heat to the steam chamber boundary, thereby reducing heat requirements for producing the viscous oil; and c) continuing the production of the viscous oil.

[0011] According to another embodiment, a gravity drainage process for production of viscous oil from one or more well pairs in an underground reservoir is provided, which includes the steps of: (a) providing an injection of steam into an upper well of the well pair to form a steam chamber which mobilizes and produces the viscous oil via a lower well of the well pair until at least 15% of the original oil-in-place (00IP) has been produced; (b) stopping the injection of steam after step (a) and starting the injection of a predominantly vaporized condensable non-aqueous solvent as a vapor into the upper well, the non-aqueous solvent mixing with the steam in the steam chamber, thereby lowering the temperature of the steam chamber and transferring heat to the steam chamber boundary, thereby reducing heat requirements for producing the viscous oil; and c) continuing the production of the viscous oil.

[0012] The solvent may be selected to produce a steam-solvent mixture having an azeotrope temperature at least 20 C lower than the temperature of the steam in the reservoir. In some embodiments, the solvent is a C3 to C7 hydrocarbon.

[0013] The step of injecting the solvent may be performed at a time point selected to minimize total heat requirements for producing the viscous oil to the estimated ultimate recovery.

[0014] The step of injecting the solvent may be performed at a time point selected to minimize the total volume of the solvent injected for producing the viscous oil to the estimated ultimate recovery.

Date Recue/Date Received 2022-04-19

[0015] In some embodiments, the solvent is commercially available diluent or a fractionated portion of commercially available diluent.

[0016] In some embodiments, the reservoir pressure is maintained approximately constant following step (b). In other embodiments, the reservoir pressure is permitted to decline following step (b).

[0017] In some embodiments, the solvent is in a composition including steam and the composition is injected with a molar solvent concentration greater than its azeotropic solvent molar fraction at the reservoir operating pressure. In other embodiments, the solvent is in a composition including steam and the composition is injected with a molar solvent concentration greater than 70% of its azeotropic solvent molar fraction at the reservoir operating pressure.

[0018] In some embodiments, up to about 30% by mass of the injected solvent or the composition is in a liquid state during injection.

[0019] In some embodiments, the operating pressure of the reservoir is about 0.5 MPa to about 5 MPa.

[0020] In some embodiments, operating temperature of the reservoir during steps (b) and (c) is about 30 C to about 250 C.

[0021] In some embodiments, after a selected period of solvent injection, a second solvent is injected, the second solvent selected to further reduce the azeotrope temperature of the steam-solvent mixture.

[0022] In some embodiments, the process further includes the step of stopping the injection of the solvent and permitting production of the viscous oil to continue.

[0023] In some embodiments, after the injection of the solvent is stopped, a gas which does not condense in the reservoir is injected. The gas may be natural gas, methane or nitrogen.

Date Recue/Date Received 2022-04-19

[0024] In some embodiments, in step (a), up to 20% by volume of a separate non-aqueous solvent is injected with the steam for at least a fraction of the time that step (a) is performed.

[0025] In some embodiments, the process further includes providing one or more infill wells between the well pairs and injecting steam or solvent into the infill wells in step (a) or step (b), or in both step (a) and step (b). Additionally, viscous oil may also be produced from the infill wells.

[0026] In some embodiments, the process further includes providing one or more infill wells between the well pairs and producing the viscous oil from the infill wells.
BRIEF DESCRIPTION OF THE DRAWINGS

[0027] Various objects, features and advantages of the technology will be apparent from the following description of particular embodiments, as illustrated in the accompanying drawings. Instead, emphasis is placed upon illustrating the principles of various embodiments.
Figure 1 is a diagram of a typical SAGD well configuration in an underground reservoir.
Figure 2 is a plot of steam-solvent dew point temperatures for various solvents at a pressure of 2.5 MPa.
Figure 3 illustrates the evolution of the temperature within the steam-solvent chamber after starting solvent injection.
Figure 4A is a drawing showing typical temperature regions in the reservoir during steam or steam solvent injection.
Figure 4B is a drawing showing how the temperature in the reservoir evolves over time during SAGD operations followed by steam injection.
Figure 5 is a plot showing the evolution of average mole fraction of solvent and average temperature in the steam-solvent chamber from simulations of steam Date Recue/Date Received 2022-04-19 injection (SAGD) followed by (i) azeotropic steam-pentane injection and (ii) 100%
pentane injection.
Figure 6 is a plot showing the evolution of average mole fraction of solvent and average temperature in the steam-solvent chamber from simulations of steam injection (SAGD) followed by (i) azeotropic steam-butane injection and (ii) 100%
butane injection.
Figure 7 is a plot comparing the total heat requirement (in equivalent m3 of steam) to achieve ultimate recovery for simulated cases of SAGD, azeotropic pentane and butane injection and cases of SAGD followed by solvent injection.
Figure 8 is a plot comparing the total steam and solvent volumes required to achieve ultimate recovery for simulated cases of SAGD, azeotropic pentane and butane injection and cases of SAGD followed by solvent injection.
Figure 9 is a process flow diagram indicating main steps of a process according to one example embodiment.
Figure 10 is a process flow diagram indicating main steps of a process according to another example embodiment.
DETAILED DESCRIPTION
Introduction and Rationale

[0028] Existing in situ recovery processes that rely on gravity drainage have significant limitations. SAGD exploits the characteristic that water is a very effective working fluid for heat transfer. However, in order to mobilize the viscous oil the reservoir must be heated to high temperatures, typically 200 C or greater. This results in significant fuel costs for heating water to steam and significant greenhouse gas (GHG) emissions. In recent years GHG emissions have become a significant concern to society and operators incur associated costs such as carbon taxes. It is expected that future costs associated with GHG emissions from SAGD operations will increase significantly, potentially making it uneconomic to continue with the SAGD operations.

Date Recue/Date Received 2022-04-19

[0029] VAPEX has not proven to be practically viable when operating at typical reservoir temperatures due to very low production rates of the viscous oil. H-VAPEX is more practically viable but suffers from the limitation that hydrocarbon solvents such as alkanes are not effective working fluids for heating the reservoir. As a result, there is a requirement to inject and process much larger volumes of solvent than is necessary with steam to mobilize the viscous oil. This results in excessively high injected solvent to produced oil ratios and higher associated costs.

[0030] SAVEX is a process where initially steam is injected and then after a short period of steam injection, prior to the steam chamber reaching the top of the reservoir, solvent injection begins. SAVEX suffers the same limitation as H-VAPEX that it relies on hydrocarbon solvents as a working fluid for heat transfer and there is a requirement to inject and process much larger volumes of solvent than is necessary with steam to mobilize the viscous oil.

[0031] The process described by Gates in Canadian Patent 2,553,297 is one where steam, hydrocarbon solvent gases and non-condensable gases are co-injected, and the volumes are progressively adjusted so that the hydrocarbon solvent and non-condensable gases become predominant. This process also requires much larger volumes of hydrocarbon solvent than is necessary with steam to mobilize the viscous oil.

[0032] AzeoVAPEX partially addresses the problem of H-VAPEX by injecting a fraction of steam with the solvent for the purposes utilizing steam as a working fluid to augment the heat transfer. It also has the advantage of reducing both the injection temperature and the average temperature of the reservoir, so that less heat is required to recover the viscous oil. Nonetheless, the AzeoVAPEX process still requires very high volumes of solvent to be cycled through the reservoir.

[0033] Embodiments of the process described herein exploit the benefits of steam as an effective working fluid while capturing most of the benefit of the full life-cycle lower heat utilization of AzeoVAPEX at the ultimate economic recovery of the viscous oil.
An additional benefit is that it can be effectively integrated with existing SAGD
operations which rely on steam generators to generate the heat required to produce viscous oil. As such, the process can be efficiently used by most existing SAGD operations to both Date Recue/Date Received 2022-04-19 increase oil production rates, reduce energy requirements and reduce associated GHG
emissions.

[0034] Selection of the timing for solvent injection is one aspect of this technology. During the steam injection phase, the steam chamber is at or near steam temperatures and, in effect, excess heat is being stored in the reservoir. After solvent injection commences, the excess heat is progressively redistributed from the depleted reservoir to the boundaries of the steam-solvent chamber as it further expands. The process benefits from maximizing the excessive heat stored during the steam injection phase because steam is an effective working fluid for heat transfer. On the other hand, it is desirable to minimize the total heat usage. Therefore, it is preferable not to inject steam beyond what is required to supply the heat needed to efficiently produce the remaining oil during the solvent injection phase.

[0035] Heat losses to the overburden and underburden are also important considerations in selecting the timing for solvent injection. The processes of SAVEX and Gates (Canadian Patent No. 2,553,297) initiate solvent injection early in the operational life, or at low recovery levels, of a SAGD well pair. In the case of SAVEX, solvent injection is initiated prior to the steam chamber reaching the overburden. By contrast, this process relies upon utilizing steam as the working fluid to provide much of the required heat to the overburden and underburden. Therefore solvent injection does not commence until the steam chamber has spread across much of the top of the reservoir.

[0036] In the idealized case illustrated in Figure 1, the steam chamber 103 has expanded to the point where it occupies about 25% of the reservoir volume and has spread across about 50% of the reservoir overburden. When the steam chamber has expanded to occupy about 50% of the reservoir volume, as indicated by areas 103 and 104 in Figure 1, it will have spread across the entire reservoir overburden.

[0037] It is recognized that in a real-world case, the shape of the steam chamber is much more complex and it is not practical to accurately map or image the extent of a steam chamber on a continuous basis. A useful physical factor to consider in the process, is the volume of the steam chamber rather than its specific shape because the process exploits the excess heat stored in the materials, primarily in the sand grains, contained within the Date Recue/Date Received 2022-04-19 volume of reservoir occupied by the steam chamber. Additionally, the volume of the steam chamber is also directly related to the volume of the oil produced. Therefore, the oil recovery factor, such as for example, a percentage of the original oil-in-place (00IP) can be used as a practical measure of the extent and volume of the steam chamber.

[0038] In order to select the optimal time for the start of solvent injection a variety of methods can be used to assess the benefits including field performance of existing wells, analytical models and simulation models.

[0039] It is recognized that all operations have specific characteristics that may impact the selection of the optimal timing of solvent injection including factors such as depletion state of the operating well pairs, steam generation capacity, produced water handling capacity, and produced oil handling capacity.

[0040] While the process can be optimally timed to minimize total heat injection, to limit solvent requirements or a combination thereof, many existing SAGD well pairs will already have exceeded this time or recovery level. Nonetheless, there will still be very significant benefits from implementing the process. For example, if one starts solvent injection at a the time when 60% of the original-oil-in-place (00IP) has been recovered and the estimated ultimate recovery is 75% of 00IP a heat savings of up to 20%
relative to total heat requirements for SAGD operations can be achieved.

[0041] Selection of the solvent is one aspect of the process which relates to the azeotrope temperature or minimum dew point temperature for the steam-solvent system.
Ultimately, the objective of minimizing heat requirements for the process relies upon reducing the temperature in the steam-solvent chamber to as close to the azeotrope temperature as practical to maximize the abovementioned process of progressively redistributing heat from the depleted reservoir to the boundaries of the steam-solvent chamber. As such, solvents with lower azeotrope temperatures generally allow for greater reductions in heat requirements.

[0042] Another important advantage of process is that it can be operated at constant or near constant pressure. For practical purposes, it is often preferable to operate gravity processes at or near constant pressure. For example constant pressure will prevent fluids Date Recue/Date Received 2022-04-19 from being lost or will prevent fluids from flowing in from or out to an underlying aquifer (water) zone or overlying gas zone.

[0043] The processes permit selection of specific solvents for injection and permit selection of timing of the solvent injection. These selections may be made based on the characteristics of individual reservoirs. During the initial phase of steam injection by SAGD
a large volume of the reservoir is heated to steam temperatures and significant amounts of heat are lost to the underburden and overburden. Through appropriate selection of the solvent and timing of solvent injection, most of the heat required for recovering the remaining viscous oil may be provided from within the reservoir itself while significantly reducing the total heat requirement.
Terms and Definitions

[0044] For ease of reference, certain terms used in this application and their meaning, as used in this context, are set forth below. If a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.

[0045] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.

[0046] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of: 19 weight (wt.) percent (%) aliphatics (which can range from 5 wt. % - 30 wt.%, or higher); 19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt.
%, or Date Recue/Date Received 2022-04-19 higher); 30 wt. % aromatics (which can range from 15 wt. % -50 wt. %, or higher); 32 wt.
% resins (which can range from 15 wt. % -50 wt. %, or higher); and some amount of sulfur (which can range from 2 to 7 wt. %, or higher%). In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt %. to in excess of 0.7 wt. %.
The percentage of the hydrocarbon found in bitumen can vary. The term "heavy oil"
includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.

[0047] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil"
includes bitumen.
Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1 g/cm3).
An extra heavy oil, in general, has an API gravity of less than 10.0 API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen.

[0048] The term "viscous oil" as used herein means a hydrocarbon, or mixture of hydrocarbons, which occurs naturally and that has a viscosity of at least 10 cP (centipoise) at initial reservoir conditions. Viscous oil includes oils generally defined as "heavy oil" or "bitumen." Bitumen is classified as an extra heavy oil, with an API gravity of about 10 or less, referring to its gravity as measured in degrees on the American Petroleum Institute (API) Scale. Heavy oil has an API gravity in the range of about 22.3 to about 10 . The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.

[0049] "In situ' is a Latin phrase for "in the place" and, in the context of hydrocarbon recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For example, in situ temperature means the temperature within the reservoir. In another usage, an in situ oil recovery technique is one that recovers oil from a reservoir below the earth's surface.

[0050] The terms "formation" and "subterranean formation" refer to the material existing below the earth's surface. The subterranean formation may comprise a range of Date Recue/Date Received 2022-04-19 components, e.g. minerals such as quartz, siliceous materials such as sand and clays, as well as the oil and/or gas that is extracted. The subterranean formation may be a subterranean body of rock or sand that is distinct and continuous. The terms "reservoir"
and "formation" may be used interchangeably.

[0051] The term "reservoir" may be used to refer to a regional volume subterranean formation that encompasses multiple SAGD well pairs or the volume of the subterranean formation that is local to a single SAGD well pair where that SAGD well pair can drain the oil.

[0052] "Pressure" is the force exerted per unit area by the gas on the walls of the volume.
Pressure may be shown in this disclosure as pounds per square inch (psi), kilopascals (kPa) or megapascals (MPa). "Atmospheric pressure" refers to the local pressure of the air. "Absolute pressure" (psia) refers to the sum of the atmospheric pressure (14.7 psia at standard conditions) plus the gauge pressure. "Gauge pressure" (psig) refers to the pressure measured by a gauge, which indicates only the pressure exceeding the local atmospheric pressure (i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia). The term "vapor pressure" has the usual thermodynamic meaning.

[0053] For a pure component in an enclosed system at a given pressure, the component vapor pressure is essentially equal to the total pressure in the system.
Unless otherwise specified, the pressures in the present disclosure are absolute pressures.

[0054] The term "steam chamber" refers to the region of the reservoir where a portion of the reservoir's porosity is occupied by gas, including water vapor, and the temperature is near the steam temperature for the specific pressure in the reservoir. The term "steam chamber" may also be used for cases where there is both steam and solvent in the vapor phase. In the case of steam and solvent, the temperature in the steam chamber will be near the dew point temperature corresponding to the local molar fractions of steam and solvent.

[0055] "Azeotrope" means the thermodynamic azeotrope composition of a mixture of liquids whose proportions cannot be altered by distillation. As more specifically used herein, the azeotrope is characterized by a specific molar concentration of solvent relative Date Recue/Date Received 2022-04-19 to steam. The related term "azeotrope temperature" refers to the temperature of the steam-solvent chamber at a defined pressure when the azeotrope composition is reached.
The azeotrope temperature also represents the minimum dew point temperature for a steam-solvent system. At the azeotrope temperature the two fluids condense together in the same molar concentration as they exist in the gas. Figure 3 illustrates the azeotrope temperature for a steam-pentane system at a pressure of 2.5 MPa.

[0056] The term "Original Oil in Place" ("00IP") is a production term commonly used in the oil and gas industry. It is the best estimate of the volume of oil initially contained within a reservoir.

[0057] "Recovery Factor" is a production term commonly used in the oil and gas industry.
It is a measure of the total production to date from a reservoir or well and is commonly measured as a fraction or percent of the 00IP.

[0058] The term "infill well" refers to a single horizontal well, drilled between two adjacent SAGD well pairs. Conventionally, an infill well will be constructed to produce unproduced oil between the two adjacent SAGD well pairs. In the process described herein, an infill well may be provided as an additional point of injection for steam or solvent as well as an additional point for production.

[0059] Estimated Ultimate Recovery ("EUR") is a production term commonly used in the oil and gas industry. Estimated Ultimate Recovery is an approximation of or the current best engineering estimate of the quantity of oil or gas that is potentially recoverable from a well or a SAGD well pair. Another term used in industry which is synonymous with the EUR is "Proved + Probable Reserves" which can be characterized as the volume of oil that has at least a 50% chance of being produced. Reserves are commonly determined by the operator and reported to regulators. Methods for estimating reserves are described in detail in Canadian Oil and Gas Evaluation Handbook (COGEH) published by the Calgary Chapter of the Society of Petroleum Evaluation Engineers (SPEE) which is an industry standard for the evaluation of oil and gas properties. It is recognized that there is always uncertainty in this estimate prior to the final cessation of production. Operators will modify and update the EUR as the production of oil progresses. For SAGD
operations, the EUR is commonly between 50 and 80% of the initial oil-in-place above the production Date Recue/Date Received 2022-04-19 well. Reserves or the EUR is commonly reported for a group or pad of SAGD
wells. In such a case, the EUR for a single SAGD well pair can be determined as the total reserves divided by the number of SAGD well pairs. The EUR may vary somewhat when processes such as SA-SAGD, VAPEX or AzeoVapex are applied but the same overall range is generally applicable.
Description of Embodiments

[0060] Figure 1 shows a simplified cross-section of a SAGD well pair. Most commonly in commercial operations, there are multiple pairs of adjacent SAGD well pairs where the dimension W shown in Figure 1 is the spacing between SAGD well pairs..

[0061] Figure 2 shows dew point temperatures for different steam-solvent systems as a function of solvent mole fraction at equilibrium. When selecting a solvent, it is desirable to select a solvent with the lowest minimum dew point for the desired pressure.
The minimum dew point temperature is also known as the azeotrope temperature.

[0062] The greater the difference between the steam temperature (solvent mole fraction = 0) and the minimum dew point temperature, the greater the available heat that can be scavenged and redistributed from the reservoir contacted during SAGD
operations.

[0063] As can be seen from Figure 2, lighter hydrocarbons have lower minimum dew points which is desirable. However, lighter hydrocarbons are also generally less soluble in bitumen so they may be less effective in reducing the viscosity of the viscous oil resulting in lower oil production rates.

[0064] An additional consideration is availability of the solvent. Many SAGD
operations rely on mixing diluent with bitumen to ship the viscous oil to market from the production facility. Diluent commonly has high fractions of pentane but only small fractions of butane or propane. So pentane or a mix of alkanes with an average molecular weight comparable to pentane may be readily available.

[0065] As noted above, Figure 1 is a cross-section of a SAGD well pair. The SAGD
injection well (101) and production well (102) are cross sections of wells extending into the plane of the page with a defined length (L ¨ not illustrated in Figure 1).
The reservoir Date Recue/Date Received 2022-04-19 volume that is assigned to the well pair is commonly taken as the width (W) times the height (H) times the length (L). The 00IP for the well pair is the volume of oil contained within the volume WxHx L.

[0066] A common simplification used in industry is to characterize the steam chamber as having a triangular shape as shown in Figure 1. Reference numerals 103, 104 and 105 indicate the extent of the steam chamber at different points in time as steam is injected, as described in more detail below. The steam chamber is assumed to be uniform along the length of the well. Area 103 illustrates a point in time at which the steam chamber encompasses about 25% of the reservoir volume. Areas 103 and 104 added together illustrate the stage where the steam chamber encompasses about 50% of the reservoir volume at a later point in time as steam is injected. It is usually not economical to operate the SAGD wells until the steam chamber encompasses the entire reservoir volume. Areas 103, 104 and 105 added together are illustrative of the steam chamber at the end of SAGD
operations where the steam chamber encompasses about 87.5% of the reservoir volume.
In this case, the recoverable oil within areas 103, 104 and 105 added together is the EUR.

[0067] When determining the recovery factor at a given time, one must consider the reservoir porosity, (I), initial saturation of oil in the reservoir, Soi, and the saturation after depletion or the residual oil saturation, So,. In the common simplified model, the volume of oil recovered can be estimated as the reservoir volume occupied by the steam chamber times the porosity (d)) times the change in oil saturation (S0i-S01).

[0068] For the process to be advantageous, a significant volume of the reservoir must be encompassed by the steam chamber prior to solvent injection and it is also beneficial if the steam chamber has spread across a significant fraction of the reservoir.
Area 103 in Figure 1 illustrates a point in time where these criteria are first reached as the steam chamber encompasses about 25% of the reservoir volume. At this time, the recovery factor will commonly be between about 15% and about 20% of the 00IP.

[0069] The process exploits the transfer of heat from the volume of the reservoir that is occupied by the steam chamber at the start of solvent injection to the progressively growing steam-solvent chamber after the start of solvent injection. The steam chamber volume can be determined, for example, by 3D seismic imaging or simulation models.

Date Recue/Date Received 2022-04-19 However, such images or models may not exist for all SAGD well pairs. Recovery factor is an alternative measure that can be determined for all SAGD well pairs and is an alternative measure that directly relates to the volume of the steam chamber.

[0070] If pentane is selected as the solvent to inject, the average temperature in the steam-solvent chamber will progress as shown in Figure 3 for a case where the steam-solvent chamber has a constant pressure of 2.5 MPa. For example, initially 100% steam may be injected until approximately 50% of the reservoir volume is occupied by the steam chamber as is illustrated by areas 103 and 104 in Figure 1. At this stage, all of the steam chamber illustrated by areas 103 and 104 will be at the steam temperature (solvent mole fraction = 0) in Figure 3. If at this stage an injection of either 100%
pentane gas or a mixture of pentane and steam is started, the average solvent mole fraction in the steam-solvent chamber will increase and average temperature will decrease. By appropriately selecting the timing of the start of pentane injection, the temperature in the entire steam-solvent chamber (i.e. areas 103, 104 and 105 in Figure 1) will be at or near the minimum dew point temperature at the time of ultimate oil recovery or (EUR) is reached.

[0071] Effectively, excess heat from the reservoir materials, primarily the sand grains, represented by areas 103 and 104 in Figure 1 at the end of steam-only injection will be redistributed to reservoir represented by area 105 as the viscous oil recovery progresses to the EUR. The primary physical mechanism by which this heat transfer will occur is evaporation of water in the existing steam-solvent chamber and subsequent condensation of the steam at the boundary of the steam-solvent chamber.

[0072] For this heat transfer to occur, there must be sufficient water in the reservoir to evaporate and sufficiently cool the region that had been heated to steam temperatures.
Fortunately, all SAGD reservoirs have significant initial water saturations and SAGD
operations may further increase the water saturations. Additionally, a water cycle will develop in the reservoir where the water is repeatedly vaporized and condensed without being produced.

[0073] Heat losses to the overburden and the underburden are also an important consideration. Edmunds et al. have developed a simple model that calculates the steam to oil ratio required to produce viscous oil using SAGD (A Unified Model for Prediction of Date Recue/Date Received 2022-04-19 CSOR in Steam-Based Bitumen Recovery, N. Edmunds; J. Peterson, Paper presented at the Canadian International Petroleum Conference, Calgary, Alberta, June 2007., Paper Number: PETSOC-2007-027). The model has two key terms. One term relates to the heat required to heat the reservoir sand, water and oil. The second term relates to the heat loss to the overburden and underburden. The Edmunds model and most reservoir simulators model the heat loss to the over and underburden using 1D analytical models.
Using these same models, it can be shown that if the overburden or underburden boundary is maintained at steam temperatures for a period of time and then subsequently the temperature at the boundary is reduced to a significantly lower temperature, such as the azeotrope temperature, there may be little or no additional heat loss to the boundary as the process continues. This, in effect, significantly reduces or eliminates the second term in the Edmunds model. From a practical perspective, when employing this technology, the steam injected during SAGD operations is used to provide most or all of the heat required to heat the overburden and underburden to achieve the ultimate recovery.

[0074] Another useful feature of the steam-solvent chamber is that at the boundary of the chamber where steam and solvent are condensing, the temperature is at or near the azeotrope temperature even when the average temperature of the steam-solvent chamber is much higher. This feature is readily observed in Figures 14, 15 and 16 of Khaledi et al., 2018 (Azeotropic Heated Vapour Extraction- A New Thermal-Solvent Assisted Gravity Drainage Recovery Process, Rahman Khaledi; Hamed Reza Motahhari; Thomas J.
Boone; Chen Fang; Adam S. Coutee, Paper presented at the SPE Canada Heavy Oil Technical Conference, March 13-14, 2018, SPE-189755-MS) and is illustrated in Figure 4A. If after a period of steam-only operations, solvent vapor is injected into the steam chamber, the temperatures will evolve as shown in Figure 4B. Most importantly the temperature at the boundary of the steam-solvent chamber rapidly reduces to at or near the azeotrope temperature after the initiation of solvent injection which aids in reducing or eliminating additional heat loss to the underburden and overburden after the start of solvent injection.

[0075] The simulated examples show significant benefits for both butane and pentane injection. Other alkanes may also be effective depending on the reservoir pressures, temperatures, and the availability of solvents. Heavier solvents such as hexane tend to Date Recue/Date Received 2022-04-19 have higher azeotropic temperatures making them less effective. Lighter solvents such as propane are less soluble in bitumen and may be less effective at reducing the bitumen-solvent mixture viscosities.

[0076] Mixtures of various hydrocarbons, such as what is commonly termed "diluent" in the industry, can be effectively used in the place of pentane or butane alone.
Specific fractions of commercially available diluent can be employed. Solvents can be extracted from the produced hydrocarbons and reused in the reservoir.

[0077] Solvents or solvent steam mixtures are preferably injected predominantly in the vapor phase. Heat in the reservoir may vaporize some liquid solvent when injected but there is also a risk that liquid solvent will drain directly to the production well and not aid in producing viscous oil.

[0078] An alternative mechanism for reducing the reservoir temperature over time is to reduce the reservoir pressure which in turn reduces the steam temperature.
Where practical, reducing the reservoir pressure can be employed prior to or in conjunction with solvent injection.

[0079] The benefits of the process can also be realized by injecting a first solvent such as pentane and then subsequently converting to injection of a second solvent such as butane with a lower minimum steam-solvent dew point than the first solvent.

[0080] In order to minimize the volume of solvent injected it is desirable to delay solvent injection until the steam chamber occupies at least about 25% to about 80% of the reservoir volume or the recovery factor reaches at least about 15% to about 70% of 00IP
However, if it is found that more oil can be viably recovered than estimated and the average steam-solvent chamber has declined to the azeotrope temperature, then oil production can be continued with H-Vapex or AzeoVapex.

[0081] Eventually, after a period of solvent injection, oil production rates will decline and it will become uneconomic to continue solvent injection into the SAGD well pair. Various methods may be employed after the end of solvent injection to recovery additional viscous oil and solvent that may remain in the reservoir. These methods may include continued Date Recue/Date Received 2022-04-19 production without any injection, with injection of non-condensable gases such as natural gas, methane or nitrogen or low-pressure steam injection.

[0082] Another benefit of initiating with steam injection then converting SAGD
well pairs to solvent injection is that solvent is much more expensive than steam and it is advantageous to have developed a stable, well controlled steam chamber prior to the introduction of solvent so that there is a lower likelihood of losing or displacing solvent in a manner such that it cannot be recovered.

[0083] As an alternative embodiment to initially injecting steam-only, the SA-SAGD
process may be employed where a relatively small fraction of solvent, typically less than 20% by volume, is injected with the steam.

[0084] It is common practice now to drill one or more "infill wells" between SAGD well pairs at a point in time after initiation of SAGD operations. See, for example, US Patent No. 7,556,099B2 (Arthur). In an alternative embodiment of the process described herein, the process may include provision of one or more infill wells. In some embodiments, steam, solvent or both fluids may be injected into the infill well intermittently or for the entire period that the process performed. In some alternative embodiments, production may also occur from the infill wells.

[0085] Figure 9 is a process flow diagram illustrating one general embodiment.
Upon characterization of a reservoir containing viscous hydrocarbons, the reservoir volume will be determined and a solvent or a composition of solvents will be selected in accordance with the characteristics of the viscous hydrocarbons. Steam is injected at an appropriate rate until the steam chamber encompasses about 25% to about 80% of the reservoir's volume. During this process, a steam chamber is formed with a concurrent temperature increase. At this point, steam injection is stopped and injection of a solvent or a composition of solvents will be started to generate a gradually increasing average solvent mole fraction in the steam-solvent chamber with a concurrent gradually decreasing average temperature in the steam-solvent chamber, occurring as a result of evaporation of water to steam in the steam-solvent chamber (see Figure 4B). This temperature decrease induces scavenging and redistribution of heat from the reservoir occupied by the steam chamber into the growing steam-solvent chamber, which, in turn, reduces heat Date Recue/Date Received 2022-04-19 requirements for continued production. An advantageous feature of the steam-solvent system is that at the boundary of the steam-solvent chamber the temperature rapidly approaches the azeotrope temperature after the start of solvent injection.
This greatly reduces heat losses to the overburden and underburden after the start of solvent injection.
The production continues with continuous solvent injection until 100% of the EUR is produced. It is to be understood that a specific time point for stopping injection of steam and starting injection of solvent may be selected based on a projection of the EUR for a specific solvent or solvent composition, in view of other production parameters, such that the entire input of energy is minimized. Alternatively, if solvent injection does not begin at that specific time point but instead begins earlier or later, it is to be understood that, while the process will not be exactly optimized for maximal energy savings, significant energy savings will still be obtained as a result of scavenging heat from the formation as outlined above. Therefore the process does not require detailed optimization to derive a significant economic benefit. It is also possible to adjust the time of solvent injection to minimize the total volume of solvent projected to be used by the process. An economic benefit will also be derived from the process if employed in this manner, by reducing the total cost associated with the solvent. Also shown in Figure 9 is an optional step of separating solvent from hydrocarbons produced from the reservoir followed by recycling the solvent back to the solvent injection step. Implementation of this step will reduce total solvent input into the process.

[0086] Figure 10 illustrates the steps of another embodiment of the process which is generally similar to the embodiment shown in Figure 9 with the exception that the original-oil-in-place (00IP) for the reservoir is determined and the solvent injection begins at a time point when at least 15% of the 00IP has been produced (as an alternative to estimating the percentage volume of the reservoir occupied by the steam chamber). This also represents a time point where sufficient heat provided by steam has been provided to the reservoir such that the steam chamber is sufficiently developed to begin scavenging and redistributing heat within the steam chamber for continued production of viscous oil without additional steam, thereby reducing the energy requirements for continued production.
Examples Date Recue/Date Received 2022-04-19 Example 1: Simulation Model for Embodiments of Hydrocarbon Recovery Using Steam and Solvent Injections

[0087] A fit-for-purpose simulation model was developed to model the process and aid in determining optimal implementation. Key features of the model are that it accounts for the phase behavior illustrated in Figures 2 and 3, it balances all heat and mass flows, it models progressive development of the steam-solvent chamber, it accounts for heat losses to the overburden and underburden using the Edmunds model and it accounts for cooling and water vaporization in the steam chamber. Consistent with analytical models and field observations a constant oil production rate is used to determine the rate of growth for the steam chamber. Parameters used in the simulation model are listed in Table 1.
Table 1: Process Model Simulation Parameters Well and Reservoir Properties (Units) Value Reservoir Height (m) 20 Well Spacing (m) 100 Well Length (m) 1000 Porosity 0.32 Initial Temperature ( C) 12.0 Initial Water Saturation 0.2 Initial Oil Saturation 0.8 Residual Oil Saturation 0.15 Initial Reservoir Heat capacity (kJ/m3/ C) 2231 Depleted Reservoir Heat capacity (kJ/m3/ C) 1815 Oil Production Rate (m3/day) 100 Fluid Properties Reservoir Pressure (MPa) 2.5 Steam Temperature ( C) 224.5 Steam-Pentane Azeotrope Temperature ( C) 157.7 Steam-Pentane Azeotrope Mole Fraction Pentane 0.8 Steam-Butane Azeotrope Temperature ( C) 125 Steam-Butane Azeotrope Mole Fraction Pentane 0.92 Edmunds Steam-Oil-Ratio Parameters Reservoir Heat Capacity (kJ/m3/ C 2231 Overburden Heat Capacity (kJ/m3/ C) 2231 Date Recue/Date Received 2022-04-19 Overburden Heat Conduction (MJ/m K year) 85

[0088] Figure 5 shows results of the simulations for cases where (i) SAGD is operated with steam-only injection until a recovery level of 52% of 00IP is reached and then 100%
pentane vapor is injected until the recovery level reaches the EUR of 71% of 00IP and (ii) SAGD is operated with steam-only injection until a recovery level of 47%
of 00IP is reached then azeotropic pentane-steam vapor is injected until the EUR is reached. The timing of the start of pentane injection was selected in both cases to result in a final average temperature in the steam-solvent chamber close to the azeotropic temperature for pentane-steam mixtures.

[0089] The benefits of azeotropic steam-solvent injection are described in Khaledi et al., 2018. In Figure 5, it can be seen to allow for earlier implementation of conversion to solvent injection.

[0090] Figure 6 shows results of the simulations for cases where (i) SAGD is operated with steam-only injection until a recovery level of 41% of 00IP then 100%
butane vapor is injected until the EUR of 71% of the oil-in-place is reached and (ii) SAGD
is operated with steam-only injection until a 37% recovery of 00IP then azeotropic butane-steam vapor is injected until the EUR is reached. The timing of the start of butane injection was selected in both cases to result in a final average temperature in the steam-solvent chamber close to the azeotropic temperature for butane-steam mixtures.

[0091] When comparing the plots in Figures 5 and 6, one can see that the final temperatures in the cases of butane injection are significantly lower than with pentane injection. As result the process of solvent injection can be started earlier with butane than with pentane.

[0092] The benefit of a greatly reduced heat requirement is illustrated in Figure 7. The heat requirement to achieve the same ultimate recovery is compared between SAGD, AzeoVapex, and the simulated cases as measured in terms of equivalent cold water equivalent steam volumes as is customarily used in the industry. Compared to SAGD, AzeoVapex with pentane injection requires approximately 69% of the heat to achieve the Date Recue/Date Received 2022-04-19 same EUR. The process of described herein with steam-only injection followed by pentane only and azeotropic pentane-steam require approximately 78% and 77%, respectively, of the heat of SAGD. Similarly, compared to SAGD, AzeoVapex utilizing butane injection requires approximately 54% of the heat to achieve ultimate recovery. The process described herein with steam-only injection followed by butane only and azeotropic butane-steam requires approximately 63% and 62%, respectively, of the heat of SAGD.
The process described herein captures most of the benefit of the AzeoVAPEX as measured by heat reduction and is much superior to operating SAGD for the full recovery period.

[0093] Figure 8 compares the volumes of both steam and solvent for all the cases. The processes described herein use measurably less steam and, most critically, an order of magnitude less solvent to achieve the same EUR. The latter is of great practical significance.
Equivalents and Scope

[0094] Other than described herein, or unless otherwise expressly specified, all of the numerical ranges, amounts, values and percentages, such as those for amounts of materials, elemental contents, times and current rate, ratios of amounts, and others, in the following portion of the specification and attached claims may be read as if prefaced by the word "about" even though the term "about" may not expressly appear with the value, amount, or range. Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending upon the desired properties sought to be obtained. At the very least, each numerical parameter should at least be construed in light of the number of reported significant digits and by applying ordinary rounding techniques.

[0095] The terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.

Date Recue/Date Received 2022-04-19

[0096] The articles "the", "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.

[0097] "At least one," in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entities in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one"
refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at least one of A and/or B") may refer, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities).
In other words, the phrases "at least one," "one or more," and "and/or" are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C," "at least one of A, B, or C,"
"one or more of A, B, and C," "one or more of A, B, or C" and "A, B, and/or C" may mean A
alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C
together, and optionally any of the above in combination with at least one other entity.

[0098] Where two or more ranges are used, such as but not limited to 1 to 5 or 2 to 4, any number between or inclusive of these ranges is implied.

[0099] As used herein, the phrase, "for example," the phrase, "as an example,"
and/or simply the term "example," when used with reference to one or more components, features, details, structures, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, and/or method is an illustrative, non-exclusive example of components, features, details, structures, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, and/or Date Recue/Date Received 2022-04-19 methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, and/or methods, are also within the scope of the present disclosure.

[00100] The term "comprising" is intended to be open and permits but does not require the inclusion of additional elements or steps. When the term "comprising" is used herein, the term "consisting of' is thus also encompassed and disclosed. Where ranges are given, endpoints are included. Furthermore, it is to be understood that unless otherwise indicated or otherwise evident from the context and understanding of one of ordinary skill in the art, values that are expressed as ranges can assume any specific value or subrange within the stated ranges in different embodiments, to the tenth of the unit of the lower limit of the range, unless the context clearly dictates otherwise. Where the term "about" is used, it is understood to reflect +/- 10% of the recited value. In addition, it is to be understood that any particular embodiment that falls within the prior art may be explicitly excluded from any one or more of the claims. Since such embodiments are deemed to be known to one of ordinary skill in the art, they may be excluded even if the exclusion is not set forth explicitly herein.

Date Recue/Date Received 2022-04-19

Claims (21)

1. A gravity drainage process for production of viscous oil from one or more well pairs in an underground reservoir, the process comprising:
(a) providing an injection of steam into an upper well of the well pair to form a steam chamber which mobilizes and produces the viscous oil via a lower well of the well pair until the steam chamber occupies between 25% to 80% of the reservoir volume;
(b) stopping the injection of steam after step (a) and starting an injection of a predominantly vaporized, condensable non-aqueous solvent into the upper well, the non-aqueous solvent mixing with the steam in the steam chamber, thereby lowering the temperature of the steam chamber and transferring heat to a boundary of the steam chamber, thereby reducing heat requirements for producing the viscous oil; and c) continuing the production of the viscous oil.

2. The process of claim 1, further comprising measuring temperature of the steam in the reservoir or determining the temperature of the steam from pressure measurements of the steam in the reservoir in step (a), wherein the solvent is selected to produce a steam-solvent mixture having an azeotrope temperature at least 20 C lower than the temperature of the steam in the reservoir.

3. The process of claim 1 or 2, wherein the solvent is a C3 tO C7 hydrocarbon.

4. The process of any one of claims 1 to 3, wherein the step of injecting the solvent is performed at a time point selected to minimize total heat requirements for producing the viscous oil to estimated ultimate recovery.

5. The process of any one of claims 1 to 3, wherein the step of injecting the solvent is performed at a time point selected to minimize the total volume of the solvent injected for producing the viscous oil to estimated ultimate recovery.

6. The process of any one of claims 1 to 5, where the solvent is commercially available diluent or a fractionated portion of commercially available diluent.

Date Recue/Date Received 2023-01-12

7. The process of any one of claims 1 to 6, wherein reservoir pressure is maintained approximately constant following step (b).

8. The process of any one of claims 1 to 6, wherein reservoir pressure is permitted to decline following step (b).

9. The process of any one of claims 1 to 8 wherein the solvent is in a composition comprising steam and the composition is injected with a molar solvent concentration greater than its azeotropic solvent molar fraction at reservoir operating pressure.

10. The process of any one of claims 1 to 8, wherein the solvent is in a composition comprising steam and the composition is injected with a molar solvent concentration greater than 70% of its azeotropic solvent molar fraction at reservoir operating pressure.

11. The process of claim 9 or 10, wherein up to about 30% by mass of the injected solvent or the composition is in a liquid state during injection.

12. The process of any one of claims 1 to 11, wherein operating pressure of the reservoir is about 0.5 MPa to about 5 MPa.

13. The process of any one of claims 1 to 12, wherein operating temperature of the reservoir during steps (b) and (c) is about 30 C to about 250 C.

14. The process of any one of claims 2 to 13, wherein after a selected period of solvent injection, a second solvent is injected, the second solvent selected to further reduce the azeotrope temperature of the steam-solvent mixture.

15. The process of any one of claims 1 to 13, further comprising stopping the injection of the solvent and permitting production of the viscous oil to continue.

16. The process of claim 15, wherein after the injection of the solvent is stopped, and then a gas which does not condense in the reservoir is injected.

17. The process of claim 16, wherein the gas is natural gas, methane or nitrogen.

18. The process of claim 1 to 17 wherein, in step (a), up to 20% by volume of a separate non-aqueous solvent is injected with the steam for at least a fraction of the time that step (a) is performed.

Date Recue/Date Received 2022-09-15

19. The process of any one of claims 1 to 18, further comprising providing one or more infill wells between the well pairs and injecting steam or solvent into the infill wells in step (a) or step (b), or in both step (a) and step (b).

20. The process of claim 19, further comprising producing the viscous oil from the infill wells.

21. The process of any one of claims 1 to 18, further comprising providing one or more infill wells between the well pairs and producing the viscous oil from the infill wells.

Date Recue/Date Received 2022-09-15