CA3107586A1 - Process for producing hydrocarbons from a hydrocarbon-bearing reservoir - Google Patents

Abstract

Abstract A process for producing hydrocarbons from a subterranean hydrocarbon-bearing reservoir includes injecting mobilizing gas via an injection well into the hydrocarbon-bearing reservoir and producing fluids from the hydrocarbon-bearing reservoir to a surface through a production well, and injecting combined fluids including water and solvent through the injection well and into the hydrocarbon-bearing reservoir to mobilize the hydrocarbons, the combined fluids injected at a temperature at which the water is liquid and at least 50% of the solvent is in vapour phase in the hydrocarbon-bearing reservoir. A fluid mixture is produced through the production well, the fluid mixture including the mobilized hydrocarbons and at least a portion of the water and the solvent, from the hydrocarbon-bearing reservoir to the surface. The water in the produced fluid mixture is separated from the mobilized hydrocarbons.
Date Recue/Date Received 2021-01-28

Description

PROCESS FOR PRODUCING HYDROCARBONS FROM A HYDROCARBON-BEARING RESERVOIR
Technical Field [0001] The present disclosure relates to the production of fluids including hydrocarbons from a subterranean reservoir bearing heavy oil or bitumen.
Background

[0002] Extensive deposits of hydrocarbons exist around the world.
Reservoirs of such deposits may be referred to as reservoirs of light oil, medium oil, heavy oil, extra-heavy oil, bitumen, or oil sands, and include large oil deposits in Alberta, Canada. It is common practice to segregate petroleum substances into categories that may be based on oil characteristics, for example, viscosity, density, American Petroleum Institute gravity ( API), or a combination thereof. For example, light oil may be defined as having an API 31, medium oil as having an API 22 and < 31, heavy oil as having an API 10 and < 22 and extra-heavy oil as having an API 10 (see Santos, R. G., et al. Braz.
J.
Chem. Eng. Vol. 31, No. 03, pp. 571-590). Although these terms are in common use, references to different types of oil represent categories of convenience, and there is a continuum of properties between light oil, medium oil, heavy oil, extra-heavy oil, and bitumen. Accordingly, references to such types of oil herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the substances.

[0003] One thermal method of recovering viscous hydrocarbons in the form of bitumen, also referred to as oil sands, is known as steam-assisted gravity drainage (SAGD). In the SAGD process, pressurized steam is delivered through Date Recue/Date Received 2021-01-28 an upper, horizontal, injection well, also referred to as an injector, into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, generally parallel, horizontal, production well, also referred to as a producer, that is near the injection well and is vertically spaced from the injection well. The injection and production wells are situated in the lower portion of the reservoir, with the producer located close to the base of the hydrocarbon reservoir to collect the hydrocarbons that flow toward the base of the reservoir.

[0004] The injected steam during SAGD initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well. The term steam chamber in the context of a SAGD operation is utilized to refer to the volume of the reservoir that is heated to the steam saturation temperature with injected steam and from which mobilized oil has at least partially drained and been replaced with steam vapor. As the steam chamber expands, viscous hydrocarbons in the reservoir and water originally present in the reservoir are heated and mobilized and move with aqueous condensate, under the effect of gravity, toward the bottom of the steam chamber. The hydrocarbons, the water originally present, and the aqueous condensate are typically referred to collectively as emulsion. The emulsion accumulates and is collected and produced from the production well. The produced emulsion is separated into dry oil for sales and produced water.

[0005] Such thermal processes are extremely energy intensive, utilize significant volumes of water for the production of steam, and may require additional equipment to control or handle the steam or gasses produced.

[0006] A solvent may be utilized to aid a steam-assisted recovery process, in a so-called solvent-aided process (SAP). Hydrocarbon solvent is generally utilized to improve mobility in the hydrocarbon reservoir, potentially improving production and/or reducing steam and/or heating requirements. Gas production is problematic however, as gas coning occurs. Increasing steam injection in an Date Recue/Date Received 2021-01-28 attempt to reduce gas coning, however, is energy intensive, may require additional capital costs, and results in additional greenhouse gas emissions.

[0007] Improvements in hydrocarbon recovery from reservoirs are desirable.
Summary

[0008] According to an aspect of an embodiment, a process for producing hydrocarbons from a subterranean hydrocarbon-bearing reservoir includes injecting mobilizing gas via an injection well into the hydrocarbon-bearing reservoir and producing fluids from the hydrocarbon-bearing reservoir to a surface through a production well, and injecting combined fluids including water and solvent through the injection well and into the hydrocarbon-bearing reservoir to mobilize the hydrocarbons, the combined fluids injected at a temperature at which a majority of the water injected is liquid and at least 50% of the solvent is in vapour phase in the hydrocarbon-bearing reservoir. A fluid mixture is produced through the production well, the fluid mixture including the mobilized hydrocarbons and at least a portion of the water and the solvent, from the hydrocarbon-bearing reservoir to the surface. The water in the produced fluid mixture is separated from the mobilized hydrocarbons.

[0009] The combined fluids may be injected at a temperature at which at least 80% by weight of the water is liquid and at least 50% of the solvent is in vapour phase in the hydrocarbon-bearing reservoir.

[0010] The process may include controlling a rate of water injected in the combined fluids based on a water content of the fluid mixture produced.

[0011] The rate of water injected in the combined fluids may be adjusted to achieve a target water cut of the fluid mixture produced.

Date Recue/Date Received 2021-01-28

[0012] The process may include controlling one or both of pressure and temperature in the reservoir to control a ratio of the water to the solvent in the gas phase in the reservoir.

[0013] According to another aspect, a process for producing hydrocarbons from a subterranean hydrocarbon-bearing reservoir includes injecting fluids including water via an injection well and into the hydrocarbon-bearing reservoir to mobilize the hydrocarbons, producing a fluid mixture through the production well, the fluid mixture including the mobilized hydrocarbons and at least a portion of the water injected, identifying a water cut of the fluid mixture produced, and based on the water cut identified, adjusting the rate of water injection during injecting the fluids.

[0014] According to yet another aspect, a process for producing hydrocarbons from a subterranean hydrocarbon-bearing reservoir is provided.
The process includes injecting combined fluids including water and solvent through the injection well and into the hydrocarbon-bearing reservoir to mobilize the hydrocarbons, controlling at least one of pressure and temperature in the reservoir to control a ratio of the water to the solvent in the gas phase in the reservoir, and producing a fluid mixture through the production well, the fluid mixture including the mobilized hydrocarbons and at least a portion of the water and the solvent, from the hydrocarbon-bearing reservoir to the surface.
Brief Description of the Drawings

[0015] Embodiments of the present invention will be described, by way of example, with reference to the drawings and to the following description, in which:

[0016] FIG. 1 is a schematic sectional view of a reservoir and shows the relative location of an injection well and a production well;

Date Recue/Date Received 2021-01-28

[0017] FIG. 2 is a sectional side view of a well pair including an injection well and a production well;

[0018] FIG. 3 is a flowchart showing a process for producing fluids from a subterranean hydrocarbon-bearing reservoir according to an embodiment; and

[0019] FIG. 4 is a graph illustrating recovery factor and cumulative steam to oil ratio (CSOR) equivalent for SAGD and for the process according to an embodiment of the present invention utilizing pentane and utilizing hexane.
Detailed Description

[0020] The present application is directed to a process for producing hydrocarbons from a subterranean hydrocarbon-bearing reservoir. The process includes injecting mobilizing gas via an injection well into the hydrocarbon-bearing reservoir and producing fluids from the hydrocarbon-bearing reservoir to a surface through a production well, and injecting combined fluids including water and solvent through the injection well and into the hydrocarbon-bearing reservoir to mobilize the hydrocarbons. The combined fluids are injected at a temperature at which a majority of the water injected is liquid and at least 50%
of the solvent is in vapour phase in the hydrocarbon-bearing reservoir. The process also includes producing a fluid mixture through the production well, the fluid mixture including the mobilized hydrocarbons and at least a portion of the water and the solvent, from the hydrocarbon-bearing reservoir to the surface.
The water in the produced fluid mixture is separated from the mobilized hydrocarbons.

[0021] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not Date Recue/Date Received 2021-01-28 described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.

[0022] One example of a well pair is illustrated in FIG. 1 and FIG. 2.
The hydrocarbon production well 100 includes a generally horizontal segment 102 that extends near the base or bottom 104 of the hydrocarbon reservoir 106. An injection well 112 also includes a generally horizontal segment 114 that is disposed generally parallel to and is spaced vertically above the horizontal segment 102 of the hydrocarbon production well 100.

[0023] During production utilizing, for example, SAGD, solvent aided process (SAP), a solvent driven process (SDP), and high temperature solvent only (HTSO) process, a gas is injected through an injection well to mobilize the hydrocarbons and create a mobilizing gas chamber in the reservoir, around and above the generally horizontal segment of the injection well. Referring to SAGD, for example, steam is injected into the injection well head 116 and through the steam injection well 112 to mobilize the hydrocarbons and create a steam chamber 108 in the reservoir 106, around and above the generally horizontal segment 114.

[0024] Viscous hydrocarbons in the reservoir 106 are heated and mobilized and the mobilized hydrocarbons drain under the effects of gravity. Fluids, including the mobilized hydrocarbons along with condensate, are collected in the generally horizontal segment 102 and are recovered via the hydrocarbon production well 100 and the production well head 118. The fluids may also include steam. Production may be carried out for any suitable period of time as referred to below.

[0025] After the period of production of fluids including hydrocarbons, hot water is co-injected with solvent into the hydrocarbon-bearing reservoir 106 through the injection well 112. The water and solvent are co-injected at a temperature sufficient for at least 50% of the solvent to be in vapour phase in Date Recue/Date Received 2021-01-28 the hydrocarbon-bearing reservoir 106. The solvent may be a single solvent or a mixture of solvents. The solvent vapor in the hydrocarbon reservoir facilitates hydrocarbon recovery.

[0026] In the example shown in FIG. 1 and in FIG. 2, a well pair, including the production well 100 and the injection well 112, is illustrated.
Alternatively, the production well and injection well may be, for example, laterals of a multi-lateral well.

[0027] A flowchart illustrating a process for producing hydrocarbons in accordance with one embodiment of the present invention is shown in FIG. 3.
The process may include additional or fewer elements than shown and described and parts of the process may be performed in a different order than shown or described herein. The process is carried out to produce hydrocarbons from a subterranean hydrocarbon-bearing reservoir, such as the reservoir illustrated in FIG. 1.

[0028] A mobilizing gas is injected via the injection well at 302 into the hydrocarbon-bearing reservoir 106. Viscous hydrocarbons in the reservoir 106 are heated and mobilized and the mobilized hydrocarbons drain under the effect of gravity. The mobilizing gas forms a mobilizing gas chamber, referred to as a steam chamber in the case of SAGD, around and above the generally horizontal segment 114 of the injection well 112 in the reservoir 106.

[0029] Fluids are produced at 304. The produced fluids include mobilized hydrocarbons as well as condensate, such as water from the steam, and connate water, in an emulsion. The injection of mobilizing gas at 302 and the production of fluids at 304 may be part of a SAGD process, solvent aided process (SAP), a solvent driven process (SDP), and high temperature solvent only (HTSO) process.

[0030] The mobilizing gas injection and fluid production is carried out, for example, for a predetermined or threshold period of time. The period of time Date Recue/Date Received 2021-01-28 may be one year or may be any other suitable period of time. Alternatively, the mobilizing gas injection and fluid production may be carried out until another threshold or target is reached. For example, mobilizing gas injection and fluid production may be carried out until a hydrocarbon production rate is stabilized, until gas, which may be or may include steam, has reached a top of a hydrocarbon-rich zone in the reservoir 106, until a target recovery is reached, until a steam to oil ratio increases, or until a steam to oil ratio reaches a pre-determined valued.

[0031] A determination is made at 306 if the threshold or target is reached.
As indicated, the threshold or target may be any suitable threshold or target such as a threshold period of time, stabilization of a hydrocarbon production rate, mobilizing gas reaching a top of a rich zone in the reservoir 106, a target recovery, such as a target of from 20% to 50% of total hydrocarbons in the reservoir 106 being reached, a steam to oil ratio increase, or a steam to oil ratio reaching a pre-determined valued, for example, about 2.5 to about 3Ø In response to determining that the threshold or target is reached at 306, the process continues at 308.

[0032] Combined fluids including hot water and solvent are co-injected at 308. The combined fluids are injected at a temperature that is near saturation temperature at the pressure in the reservoir, or between the bubble and dew points at reservoir conditions. The combined fluids are thus injected at a temperature such that a majority of the water that is injected is liquid in the hydrocarbon-bearing reservoir 106 and at least 50% of the solvent is in the vapour phase. Along with the hot water and the solvent, the combined fluids includes some steam or gas phase. The temperature of the combined fluids may be selected such that at least 80% by weight of the water is liquid and at least 50% of the solvent is in vapour phase in the hydrocarbon-bearing reservoir conditions.

Date Recue/Date Received 2021-01-28

[0033] The volume of water injected may be adjusted to achieve a desired water cut, i.e., the percentage of emulsion produced that is water. Typically, more water is produced when more water is injected. Thus, by controlling the water that is injected, the water cut may be controlled to maintain sufficient water to reduce the chance of gas breakthrough in the production well. The volume of water injected may be controlled to achieve a water cut of, for example, greater than 50%, or greater than 75%. The volume of water injected may also be controlled to achieve a water cut that falls within a range, such as from about 60% to about 70%, from about 70% to about 80%, or from about 45% to about 55%. The water cut may be measured in line or via sampling.
Additional water that is injected may be heated to achieve a desired percentage of solvent in the gas phase.

[0034] The solvent may be any organic solvent, such as dinnethyl-ether, methanol, ethanol, or any other suitable organic solvent, or combination of solvents. The concentration of solvent in the combined fluids may vary depending on reservoir conditions. The solvent concentration may be 3 wt.% or greater. For example, the solvent concentration may be 10 wt.%, 15 wt.%, 20 wt.%, 50 wt.%, 60 wt.%, 80 wt.% or any other suitable concentration.
Regardless of the solvent concentration, at least 50% of the solvent injected is in the vapour phase at the bottom hole conditions in the reservoir 106. A higher portion of the solvent of, for example, 60%, 80%, 90%, 95%, 99%, or even greater wt. % in the vapour phase is desirable. Optionally, a heating coil or electric heater may be utilized in the injection well to heat the combined fluids, in the production well, or in both the injection well and the production well.

[0035] The reservoir conditions may be controlled to control the ratio of water to solvent in the gas phase. The reservoir conditions are controlled by controlling the pressure in the reservoir, which is controllable based on the rate of injection of gasses including steam, and the temperature in the reservoir, which is controllable based on the injection of heated fluids such as steam.
The Date Recue/Date Received 2021-01-28 pressure or the temperature or both the temperature and pressure may be controlled to control the ratio of the water to solvent in the gas phase to achieve a favourable or desired ratio for production. The temperature of the heated fluids with propane as the solvent may be, for example from 115 C to 160 C at a reservoir pressure of 3000 kPa. The temperature of the heated fluids with propane as the solvent may be, for example from 110 C to 155 C at a reservoir pressure of 2500 kPa.

[0036] Viscous hydrocarbons in the reservoir 106 are mobilized and the mobilized hydrocarbons drain under the effects of gravity. A fluid mixture, including the mobilized hydrocarbons along with at least a portion of the water and solvent injected in the combined fluids are collected in the generally horizontal segment 102 and are produced at 310 via the hydrocarbon production well 100 and the production well head 118.

[0037] The fluid mixture that is produced is treated at the surface to separate out the mobilized hydrocarbons and the solvent. The solvent may be recycled for injection into the reservoir 106. In addition, water may be recovered from the produced fluids and recycled back for re-injection into the reservoir 106.

[0038] As indicated above, the water cut may be controlled to maintain sufficient water to reduce the chance of gas breakthrough in the production well by controlling the injection of water at 308. The water cut may be determined and, based on the water cut, the rate of injection of water is adjusted. By controlling the water cut, the chance of gas breakthrough or gas coning in the production well is reduced, more efficient pump operation may be achieved, and generally consistent drawdown across the production well may be achieved.

[0039] As indicated, the water may be recovered and reinjected. The water is treated at the surface and then recycled along with other injected fluids.

Date Recue/Date Received 2021-01-28

[0040] As indicated, the solvent may be, for example, dinnethyl ether or ethanol. Such solvents that are soluble in water may be recycled with the water without separation from the aqueous phase at any point.

[0041] The concentration of solvent in the combined fluids injected may be consistent for a period of time, followed by a reduction in the concentration of the solvent in the combined fluids injected at 312. The reduction in the concentration of the solvent in the combined fluids may be carried out for any suitable reason. For example, the reduction in concentration of the solvent may be carried out in response to reaching a threshold recovery factor, in response to reaching a threshold total solvent loading in the reservoir, in response to a hydrocarbon production rate dropping below a predetermined value, in response to reaching a threshold value of an equivalent cumulative steam to oil ratio, in response to reaching steady state solvent recovery, or in response to reaching a target bottom hole pressure.

[0042] With the reduction in solvent injected, additional water may be injected to maintain bottom hole pressure. Thus, at least some of the solvent may be replaced with water. Alternatively, at least some of the solvent may be replaced with steam, a non-condensable gas, or any combination of two or all three of water, steam, and non-condensable gas. As indicated above, the reservoir conditions may be controlled to control the ratio of water to solvent in the gas phase.

[0043] A determination is made at 314 if a threshold or target production is reached. As indicated, the threshold or target production may be a target or threshold total solvent recovery, such as 80% of the total solvent injected or higher. Alternatively, the threshold or target production may be a low threshold such as a solvent recovery rate that has declined to a target value or less, such as 15 t/d or less, or an oil rate that has dropped to a threshold value, for example, 25 t/d or less. The threshold or target production may instead be a cumulative steam to oil ratio (CSOR) or energy equivalent that has reached a Date Recue/Date Received 2021-01-28 threshold value such as 2 or greater, or a pressure that has reached a threshold value, for example, 0.5 MPa or greater.

[0044] In response to determining that the threshold or target is reached at 314, the process continues at 316. Injection of the fluids including hot water and any solvent is discontinued at 316. Production of the fluid mixture, including mobilized hydrocarbons along with water and some solvent continues at 316.
Injection of a non-condensable gas such as methane or air in order to maintain the reservoir pressure, to continue bitumen production, and to recover solvent in the absence of the injection of the fluid mixture, may continue during a blowdown process at 316.

[0045] The process for producing hydrocarbons is described with reference to the examples shown in FIG. 1 and FIG. 2. Optionally, other wells may be utilized. For example, the system may include more production wells than injection wells or may include more injection wells than production wells. In addition, the injection wells may extend along a path that is laterally spaced from any production well, for example, and thus is not located directly above.
Optionally, the injection and production well may be spaced laterally and generally at a same depth in the reservoir. In addition, vertical wells and wedge wells may also be utilized.

[0046] The use of hot water with solvent is advantageous as the heating and injection of water is less costly than the generation of steam. The water used in steam generation requires significant pre-treatment by comparison to heated water for injection. The hot water stream may also include 1 to 2% oil, for example, without reducing efficacy of the process, saving separation costs.

[0047] In addition, the volume of hot water to heat the solvent is greater than would be utilized by steam alone, resulting in a greater liquid volume at the production well, reducing gas coning and increasing oil rates. Additionally, the large volume of water injected results in the production of an emulsion that is Date Recue/Date Received 2021-01-28 similar in quality to that produced during a SAGD operation, as opposed to low-water emulsion formed by a solvent driven process, facilitating the use of existing SAGD facilities.

[0048] The water utilized for the process may be a by-product of the steam generation. In addition, the water produced may be re-heated and re-injected, reducing the amount of heat input and the physical equipment for heating.
Solvent that remains in the produced water after separation of the bitumen and after any attempted solvent separation, may be heated along with the water and reinjected into the formation. Solvents that are soluble in water may be recycled with the water without any attempt to separate the solvent from the aqueous phase.

[0049] The use of solvent reduces the density of oil and facilitates separation of the produced fluids at the surface. In addition, the produced bitumen may be upgraded due to in-situ solvent deasphalting. Solvent deasphalting further facilitates oil separation at the surface. The volume of solvent that is retained in the reservoir is less than that for other solvent processes because the water fills up pore space in the reservoir, thus improving process economics.

[0050] Injected water may include chemicals such as potassium chloride (KCI) to reduce the chance of formation damage. Because KCI stays in liquid phase, KCI is not easily injected during SAGD yet is injectable in the present process. Further, solvents that are highly soluble in water or chemically unstable at steam temperature may be utilized in the present process.
EXAMPLES
Modelling Date Recue/Date Received 2021-01-28 Reservoir simulations were performed to demonstrate the process. Simulation parameters utilized are included in Table 1 below. For demonstration purposes, a two-hundred meter wide reservoir containing both rich and non-rich pay, as well as two injector and producer well pairs was simulated.
Table 1: Simulation Parameters Reservoir Properties (Rich Pay) Property Value Units Pay Height 10 meters Permeability (Horiz) 5 Darcies Permeability (Vertical) 3 Darcies Initial Oil Saturation 0.86 -Initial Water Saturation 0.14 -Initial Temperature 12 C
Initial Pressure 3000 kPa Porosity 0.33 -Non-Rich Pay Properties Property Value Units Pay Height 10 meters Permeability (Horiz) 0.05 Darcies Permeability (Vertical) 0.02 Darcies Initial Oil Saturation 0.8 -Initial Water Saturation 0.2 -Initial Temperature 12 C
Initial Pressure 3000 kPa Porosity 0.25 -Well & Reservoir Dimensions Property Value Units Well length 800 meters No. Wells 2 -Well Pair Lateral Spacing 100 meters Injector/Producer Spacing 5 meters Operating Parameters Property Value Units Injection Pressure Constraint 3200 kPa Injector Rate Constraint 800 t/d/well Injector Solvent Concentration 10 Percent (W) Producer Pressure Constraint 3200 kPa Producer Rate Constraint 800 t/d/well Producer Gas Constraint 5 t/d/well Date Recue/Date Received 2021-01-28

[0051] To quantify the benefit of the use of solvents, CSOR and cumulative recovery factor were determined. FIG. 4 is a graph showing the recovery factor (RF) and cumulative steam to oil ratio (equivalent) for the process illustrated in FIG. 3 and described herein utilizing propane, referred to as C3, as the solvent and utilizing pentane, referred to as C5, as the solvent. The recovery factor (RF) and cumulative steam to oil ratio (equivalent) for SAGD is illustrated for comparison purposes. The solid lines indicate recovery factor and the dashed lines show the cumulative steam to oil ratio (equivalent). The circles plotted on the lines indicate the recovery factor (RF) and cumulative steam to oil ratio (equivalent) for the process utilizing propane. The triangles plotted on the lines indicate the recovery factor (RF) and cumulative steam to oil ratio (equivalent) for the process utilizing pentane. The squares plotted on the lines indicate the recovery factor (RF) and cumulative steam to oil ratio (equivalent) for SAGD.

[0052] A solvent concentration of 10 wt.% was utilized at 308. As indicated, propane and pentane were utilized in separate simulations. The volume of water and solvent injected was varied to maintain reservoir pressure.
The relative amount of water to solvent injected, however, was constant. Thus, the relative volume of solvent injected was not reduced. Hot water and solvent injection continued for 3000 days. The production rate was constrained to limit the volume of gas produced.

[0053] As shown in FIG. 4, utilizing pentane in the process and utilizing propane in the process reduced energy intensity in comparison with a SAGD only process. Utilizing pentane and propane in the process produced a CSOR
equivalent of 1.9 and 1.5, respectively, at an oil recovery factor of 55%. By comparison, the SAGD CSOR at 55% oil recovery was 2.7. The use of pentane had the additional benefit of reaching 55% oil recovery factor after approximately four years of simulation as compared with 5.6 and 6.9 years for SAGD and for the process utilizing propane, respectively.

Date Recue/Date Received 2021-01-28

[0054] The results shown in FIG. 4 illustrate that the present process reduces energy intensity associated with bitumen production by comparison to a SAGD operation. Utilizing the present process, a reduction in gas coning, and simplification of facilities and operations is achievable by comparison to processes such as solvent aided processes or solvent driven processes.

[0055] Tests were carried out to show the effect of the presence of water combined with solvent. The tests were carried out in basket soaking tests utilizing simulated reservoir conditions and known amount of oil in sand. The test parameters and results are shown in Table 2. As shown, the tests were carried out utilizing propane as the solvent at 80 wt. % and 20 wt. % water in the combined fluids for extraction of oil from the sand. For comparison purposes, tests were carried out utilizing propane as the solvent at 100 wt. %

and 0 wt. % water in the combined fluids for extraction of oil from the sand.
Tests were also carried out utilizing butane as the solvent at 70 wt. % and at 100 wt. % of the combined fluids.
TABLE 2: BASKET SOAKING TESTS
Conc Total oil Oil Asphaltene, in the %00IP Tcore, C Pressure kPa oil API
Solvent % drained g mass%
core, g propane 80 1841 11.50 62.47 80.6 3117 11.5 1t72 propane 80 17.95 1201. 66.89 81.9 3175 propane 100 18A6 13.79 75.93 81.2 3150 10.5 12.90 propane 100 18.20 1340 73.62 81.2 3155 butane 70 18.09 10.33 57.10 134.2 3168 all sample used 13.5 for blending butane 70 18.01 11A8 6207. 133A 3166 tests butane 100 18.22 15.23 83.61 136.9 3172 butane 100 18.01 15.33 85A4 136.6 3157 butane 100 18A1 14.78 8t60 148.0 4012 butane 100 17.92 13.87 7T38 144.0 4022 butane 100 18A6 10.83 59.23 153.2 4842 Date Recue/Date Received 2021-01-28 In which:
Conc % is the wt. % solvent utilized;
Total oil in the core is the weight of the oil in the sample;
Oil drained in the weight of oil recovered utilizing the combined fluids (or solvent in the case of 100% solvent);
%00IP is the percentage of the original oil in the sample that is recovered;
Tcore is the measured temperature of the core of the sample;
Pressure is the pressure at which the sample is tested;
Oil API is the index of density of the oil recovered; and Asphaltene mass % is the mass percent of asphaltene in the recovered oil.

[0056] As shown, the API is higher in the tests utilizing 80% propane (and 20% water) in the combined fluids by comparison to the tests utilizing about 100% propane. This improvement in API is a result of upgrading by reducing the asphaltenes in the oil recovered. The asphaltene mass % is also lower than the asphaltene mass % of typical produced oil, which is generally about 20%.

[0057] The API is also higher in the tests utilizing 70% butane (and 30%
water) in the combined fluids by comparison to the tests utilizing about 100%
butane.

[0058] Thus, the produced oil, in the form of bitumen, is upgraded due to solvent deasphalting, which facilitates oil separation at the surface.

[0059] The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. All changes that come with meaning and range of equivalency of the claims are to be embraced within their scope.

Date Recue/Date Received 2021-01-28

Claims (22)

Claims

1. A process for producing hydrocarbons from a subterranean hydrocarbon-bearing reservoir, the process comprising:
injecting mobilizing gas via an injection well into the hydrocarbon-bearing reservoir and producing fluids from the hydrocarbon-bearing reservoir to a surface through a production well;
injecting combined fluids including water and solvent through the injection well and into the hydrocarbon-bearing reservoir to mobilize the hydrocarbons, the combined fluids injected at a temperature at which a majority of the water injected is liquid and at least 50% of the solvent is in vapour phase in the hydrocarbon-bearing reservoir;
producing a fluid mixture through the production well, the fluid mixture including the mobilized hydrocarbons and at least a portion of the water and the solvent, from the hydrocarbon-bearing reservoir to the surface;
separating the water in the produced fluid mixture from the mobilized hydrocarbons.

2. The process according to claim 1, wherein the combined fluids are injected at a temperature at which at least 80% by weight of the water is liquid and at least 50% of the solvent is in vapour phase in the hydrocarbon-bearing reservoir.

3. The process according to claim 1, wherein the solvent comprises one or more organic solvents.

Date Recue/Date Received 2021-01-28

4. The process according to claim 1, wherein the solvent comprises one or more of dimethyl ether, ethanol, methanol.

5. The process according to claim 1, wherein injecting mobilizing gas into the hydrocarbon-bearing reservoir and producing fluids from the hydrocarbon-bearing reservoir to a surface is carried out in a steam-assisted gravity drainage process.

6. The process according to claim 1, comprising recycling the separated water to the injection of the combined fluids.

7. The process according to claim 1, comprising reducing a proportion of the solvent in the injection of the combined fluids.

8. The process according to claim 7, wherein reducing the proportion of the solvent is carried out after injecting the combined fluids at a constant proportion of solvent in the combined fluids for a period of time.

9. The process according to claim 7, wherein reducing the proportion of the solvent is carried out in response to one of: reaching a threshold recovery factor;
reaching a threshold total solvent loading in the reservoir; a hydrocarbon production rate dropping below a predetermined value; reaching a threshold value of an equivalent cumulative steam to oil ratio; reaching steady state solvent recovery; reaching a target bottom hole pressure.

10. The process according to claim 7, comprising replacing at least some of the solvent injected with one or more of water, steam, and non-condensable gas.

Date Recue/Date Received 2021-01-28

11. The process according to claim 1, comprising discontinuing injecting the combined fluids in response to reaching a threshold value.

12. The process according to claim 11, wherein the threshold comprises a target solvent recovery, a solvent recovery rate, a hydrocarbon production rate, a threshold value of an equivalent cumulative steam to oil ratio, or a target pressure.

13. The process according to claim 11, comprising continuing producing the fluid mixture for a period of time after discontinuing injecting the combined fluids.

14. The process according to claim 1, comprising recycling produced solvent by injecting the produced solvent in the combined fluids.

15. The process according to claim 1, wherein injecting the combined fluids comprises injecting steam with the water and the solvent.

16. The process according to claim 1, wherein injecting the combined fluids is carried out after one of producing fluids for a threshold period of time, a hydrocarbon production rate is stabilized, the mobilizing gas has reached a top of a rich zone in the reservoir, a target recovery is reached, a steam to oil ratio increases, or a steam to oil ratio reaches a pre-determined valued.

17. The process according to claim 1, wherein the combined fluids are injected at a temperature at which the water is liquid and at least 60% of the solvent injected is in vapour phase in the hydrocarbon-bearing reservoir.

Date Recue/Date Received 2021-01-28

18. The process according to claim 1, wherein the combined fluids are injected at a temperature at which at least 80% of the solvent injected is in vapour phase in the hydrocarbon-bearing reservoir.

19. The process according to claim 1, wherein the combined fluids are injected at a temperature at which at least 90% of the solvent injected is in vapour phase in the hydrocarbon-bearing reservoir.

20. The process according to claim 1, wherein the solvent concentration in the combined fluids is about 3 wt.% of total combined fluids or greater.

21. The process according to claim 1, wherein the solvent concentration in the combined fluids is about 10 wt.% of total combined fluids or greater.

22. The process according to claim 1, wherein the solvent concentration in the combined fluids is about 50 wt.% of total combined fluids or greater.

Date Recue/Date Received 2021-01-28