CA3048579A1 - Solvent production control method in solvent-steam processes - Google Patents

Abstract

A method for producing hydrocarbons from a subterranean reservoir, comprising:

injecting steam and a solvent into the reservoir to mobilize viscous hydrocarbons in the reservoir, wherein mobilized hydrocarbons drain towards a production zone, the production zone comprising a liquid phase comprising water and mobilized hydrocarbons, and a gas phase comprising the solvent; producing a fluid comprising the liquid phase and the gas phase, through a production well, the production well penetrating the liquid phase in the production zone; controlling a ratio of produced gas phase to produced liquid phase in the produced fluid, wherein the controlling comprises adjusting a flow rate of the fluid in the production well so as to raise or lower a liquid level of the liquid phase surrounding the production well, thus reducing or increasing flow of the solvent in the gas phase into the production well through the liquid phase in the production zone.

Description

SOLVENT PRODUCTION CONTROL METHOD
IN SOLVENT-STEAM PROCESSES
FIELD
[0001] The present disclosure relates generally to hydrocarbon recovery, and particularly to a solvent production control method in solvent-steam processes.
BACKGROUND

[0002] Hydrocarbon resources such as bituminous sands (also commonly referred to as oil sands) present significant technical and economic recovery challenges due to the hydrocarbons in the bituminous sands having high viscosities at initial reservoir temperature. Some subterranean deposits of heavy hydrocarbons can be extracted in situ by increasing the mobility of the heavy hydrocarbons so that they can be moved to, and recovered from, a production well (also referred to as producer) penetrating a formation of the hydrocarbons. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbons, heavy oil, bitumen, tar sands, bituminous sands, or oil sands. For example, such reservoirs include deposits as may be found in Canada's Athabasca oil sands.

[0003] The in situ processes for recovering oil from heavy hydrocarbon reservoirs typically involve the use of one or multiple wells drilled into the reservoir, and are assisted or aided by injecting a heated fluid such as steam or solvent into the reservoir formation from an injection well (also referred to as injector).

[0004] For example, a known in situ process for recovering viscous hydrocarbons is the steam-assisted gravity drainage (SAGD) process. A typical (conventional) SAGD
process utilizes one or more pairs of vertically spaced horizontal wells. For example, various embodiments of the SAGD process are described in CA 1,304,287 and related US 4,344,485.

[0005] In a SAGD process, steam is injected through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well vertically spaced proximate to the injection well. The injection and production wells are typically located near, but some distance above, the bottom of a pay zone in the hydrocarbon deposit. The injected steam initially heats and mobilizes the in situ hydrocarbons in the reservoir around the injection well.
Mobilized hydrocarbons will drain downward due to gravity, leaving a volume of the formation at least partially depleted of the hydrocarbons. The pores in the depleted volume of the formation, from which mobilized oil has at least partially drained, are then filled with fluids containing mainly injected steam, and the depleted volume is thus commonly referred to as the "steam chamber". As steam injection and gravity drainage continue, the steam chamber will continue to grow, expanding both upwardly and laterally from the injection well. As the steam chamber expands upwardly and laterally from the injection well, more and more viscous hydrocarbons in the reservoir are gradually heated and mobilized, especially at the margins of the steam chamber where the steam condenses and heats a layer of viscous hydrocarbons by thermal conduction.
The mobilized hydrocarbons (and aqueous condensate) drain under the effects of gravity towards the bottom of the steam chamber, where the production well is located.
The mobilized hydrocarbons are collected and produced from the production well. In a SAGD process, additional injection or production wells, such as a well drilled using Wedge WellTM technology, may also be provided.

[0006] Alternative processes aided by fluids other than steam have also been proposed. For example, solvent-aided processes (SAP) and a process known as the vapour-extraction (VAPEX) process have been proposed. In SAP, both steam and a solvent may be used to aid recovery. VAPEX utilizes a solvent vapour, instead of steam, to reduce the viscosity of viscous hydrocarbons. In a proposed VAPEX
process, a solvent, such as propane, is injected into the reservoir in the vapour phase, to form a vapour-filled chamber within the reservoir. The solvent vapour dissolves in the oil around the vapour chamber and the resulting solution drains, driven by gravity, to a horizontal production well placed low in the formation. The solvent vapour, at or near its dew point, is injected simultaneously with hot water from a horizontal well located at the top of the reservoir. See, Butler et al., "A New Process (VAPEX) for Recovering Heavy Oils Using Hot Water and Hydrocarbon Vapour", Journal of Canadian Petroleum Technology, 1991, vol. 30, issue 1, pages 97-106.

[0007] US 6,662,872 discloses a combined steam and vapour extraction process (SAVEX), where steam is injected until an upper surface of the steam chamber has progressed to 25 to 75 percent of the distance from the bottom of the injection well to the top of the reservoir, or until the recovery rate of hydrocarbons is about 25 to 75 percent of the peak predicted recovery rate using SAGD. When the condition is met, steam injection is suspended and replaced with solvent vapour injection (the VAPEX
process). One of the goals in modifying existing SAGD and other steam-assisted processes is to reduce the steam to oil ratio (SOR) or the cumulative SOR
(CSOR), as the SOR or CSOR is commonly considered an important metric for assessing the performance and efficiency of a steam-assisted recovery process. Replacing steam with solvent vapour and hot water as in the VAPEX or SAVEX process is expected to reduce CSOR. However, another important measure of the performance of an oil recovery process is the oil production rate, which indicates how fast oil can be produced from the reservoir. The proposed VAPEX or SAVEX processes are expected to result in significant reduction in peak oil production rate.

[0008] It has also been proposed in CA 2,893,221 to inject both steam and a diluting agent to assist hydrocarbon recovery from bituminous sands. For example, it has been suggested that a mobilizing composition comprising 75-98 vol% diluting agent and 2-25 vol% steam at the standard temperature and pressure (STP) may be used in a gravity drainage process for recovering viscous oil from an underground reservoir.
Bench-scale gravity drainage tests and simulation tests were performed using n-heptane and pentane as the diluting agents. The results were assessed based on the cumulative bitumen recovery, cumulative injected diluting agent, and diluting agent left in the reservoir.

[0009] CA 2,956,771 discloses a hybrid recover process to recover heavy hydrocarbons from a subterranean reservoir, which includes steam-dominant and solvent-dominant processes. In the steam-dominant process, the weight percentage of steam in the injection fluid is more than about 70 wt%. In the solvent-dominant process, a solvent and steam are co-injected into the vapour chamber, where the weight ratio of co-injected solvent vapour to co-injected steam is higher than 3/2. The solvent may include propane, butane, pentane, hexane, heptane, or octane. When propane is used as the solvent, the weight percentage of propane in the co-injection mixture may be higher than 70 wt%.

[0010] Instead of a well pair, one or more single horizontal well or vertical wells may be utilized for injection and production in in situ hydrocarbon recovery processes such as, but not limited to, SAGD, SAP, cyclic steam stimulation (CSS), or fluid flooding processes. For example, CA 2,844,345 discloses a single vertical or inclined well thermal recovery process. CA 2,868,560 discloses a single horizontal well for injection and production in thermal or solvent recovery processes. These single well processes may be preceded by start-up acceleration techniques to establish communication in the formation between openings in the single well that have been configured to allow for both injection and production. An assembly for coupling a high-pressure steam pipeline, a produced hydrocarbon emulsion pipeline, and a produced gas pipeline to a single well may be employed for facilitating injection and production.

[0011] In the aforementioned recovery processes or techniques where a solvent is used, the injected solvent may be recovered with oil through the production well, but it is difficult to control the solvent recovery without significantly impact on the oil production rate.
SUMMARY

[0012] In one aspect, the present disclosure relates to a method for producing hydrocarbons from a subterranean reservoir, comprising: injecting steam and a solvent into the reservoir to mobilize viscous hydrocarbons in the reservoir, wherein mobilized hydrocarbons drain towards a production zone, the production zone comprising a liquid phase comprising water and mobilized hydrocarbons, and a gas phase comprising the solvent; producing a fluid comprising the liquid phase and the gas phase, through a production well, the production well penetrating the liquid phase in the production zone;
controlling a ratio of produced gas phase to produced liquid phase in the produced fluid, wherein the controlling comprises adjusting a flow rate of the fluid in the production well so as to raise or lower a liquid level of the liquid phase surrounding the production well, thus reducing or increasing flow of the solvent in the gas phase into the production well through the liquid phase in the production zone.

[0013] In an embodiment of a method described herein, the fluid is pumped through the production well and the flow rate is adjusted by altering a pump speed in the production well.

[0014] In an embodiment of a method described herein, the pump speed is reduced by less than about 5% to reduce the ratio of produced gas phase to produced liquid phase by more than about 30%.

[0015] In an embodiment of a method described herein, the flow rate is adjusted by altering a downhole pressure in the production well.

[0016] In an embodiment of a method described herein, altering the downhole pressure comprises adjusting a valve downstream of the production well.

[0017] In an embodiment of a method described herein, the flow rate is controlled to maintain the production temperature of the produced fluid at about 20 C to about 80 C
below the injection temperature.

[0018] In an embodiment of a method described herein, the solvent comprises propane, the injection temperature is about 120 C to about 245 C and the production temperature is about 100 C to about 225 C.

[0019] In an embodiment of a method described herein, the production temperature is about 165 C to about 205 C.

[0020] In an embodiment of a method described herein, the production temperature is at least about 140*c.

[0021] In an embodiment of a method described herein, the production temperature is a temperature at a heel of the production well.

[0022] In an embodiment of a method described herein, the flow rate is controlled such that the liquid level is about 2 m to about 8 m above the production well.

[0023] In an embodiment of a method described herein, the flow rate is controlled such that the liquid level is about 3 m to about 4 m above the production well.

[0024] In an embodiment of a method described herein, the produced fluid comprises an emulsion.

[0025] In an embodiment of a method described herein, the gas phase further comprises at least one of steam and a non-condensable gas.

[0026] In an embodiment of a method described herein, the mobilized hydrocarbons drain downward into the production zone.

[0027] In an embodiment of a method described herein, the weight ratio of the gas phase to the liquid phase in the produced fluid is from about 1/16 to about 1/5.

[0028] In an embodiment of a method described herein, comprising adjusting the flow rate of the fluid in the production well to set the production well temperature at 182 C to 195 C.

[0029] In an embodiment of a method described herein, the weight ratio of injected solvent to injected steam is 1/19 to 9/1.

[0030] In an embodiment of a method described herein, the weight ratio of injected solvent to injected steam is 1.2 to 1.9.

[0031] In an embodiment of a method described herein, the flow rate is adjusted so that the weight ratio of injected solvent to produced solvent is 0.5 to 0.7.

[0032] In an embodiment of a method described herein, the flow rate is adjusted so that the weight ratio of injected solvent to produced solvent is 0.4 or lower.

[0033] In an embodiment of a method described herein, the solvent comprises one or more C1-12 alkanes, a natural gas liquid, a condensate, a diluent, or a mixture thereof.

[0034] In an embodiment of a method described herein, wherein the liquid phase comprises water, mobilized hydrocarbons and the solvent.

[0035] Other aspects, features, and embodiments of the present disclosure will become apparent to those of ordinary skill in the art upon review of the following description of specific embodiments of the disclosure in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS

[0036] In the figures, which illustrate, by way of example only, embodiments of the present disclosure:

[0037] FIG. 1 is a schematic side view of a hydrocarbon reservoir and a pair of wells penetrating the reservoir for recovery of hydrocarbons.

[0038] FIG. 2 is a schematic partial end view of the reservoir and wells of FIG. 1. -

[0039] FIG. 3 is a schematic perspective view of the reservoir and wells of FIG. 1 during operation after a vapour chamber has formed in the reservoir.

[0040] FIG. 4 is a schematic partial section view of the wells and the vapour chamber in the reservoir of FIG. 3 showing a low inventory of liquid surrounding the production well.

[0041] FIG. 5 is a schematic partial section view of the wells and the vapour chamber in the reservoir of FIG. 3 showing a high inventory of liquid surrounding the production well.

[0042] FIG. 6 is a data graph showing casing gas flow, oil production and pump speed in a solvent-steam process.

[0043] FIG. 7 is a schematic side view of a production well with a pump configured for pumping fluid through the production well.

[0044] FIG. 8 is a schematic side view of a well pair illustrating typical elevation changes of the horizontal sections of the injection well and production well.

[0045] FIG. 9 is a graph showing casing gas flow and pump speed in an example solvent-steam process before reducing pump speed.

[0046] FIG. 10 is graph showing casing gas flow and pump speed in a solvent-steam process after reducing pump speed.

[0047] FIG. 11 is a line graph illustrating possible liquid level variations in the production zone between the production well for a SAGD process and a solvent-steam process, respectively, based on simulation results.

[0048] FIG. 12 is a graph showing representative simulation results of the dependence of the production well heel temperature on pump speed in the SAGD
and solvent-seam processes respectively.

[0049] FIG. 13 is a graph showing representative simulation results of instantaneous steam-oil ration (iSOR) and cumulative SOR (cSOR) at different production well heel temperatures in a simulated propane-steam process.

[0050] FIG. 14 is a graph showing representative simulation results of rate uplift and cSOR at different production well heel temperatures in the propane-steam process.

[0051] FIG. 15 is a graph showing the same simulation results shown in FIG.
14 with the production well heel temperature as the x-axis variable.

DETAILED DESCRIPTION

[0052] In brief overview, the present inventors have discovered that a fluid produced from a subterranean reservoir in a solvent-steam process, the ratio of produced gas phase to produced liquid phase can be controlled by adjusting the flow rate of the fluid in the production well. In particular, the flow rate of the fluid in the production well may be adjusted so as to raise or lower the liquid level of the liquid phase surrounding the production well, thus reducing or increasing flow of the solvent in the gas phase into the production well through the liquid phase in the production zone.

[0053] For example, the flow rate of the fluid may be adjusted by adjusting the fluid flow pumping speed in the production well. In particular, decreasing the pump speed can result in increased inventory of liquid (and hence a higher liquid level) around the production well and reduced production of solvent in the gas phase.
Conversely, increasing the pump speed can result in reduced inventory of liquid around the production well (and hence a lower liquid level) and increased production of solvent in the gas phase.

[0054] Simulation and test results have shown that the solvent gas production rate can be quite sensitive to the pump speed. For example, in an example propane-steam process, test results showed that the ratio of produced gas phase to produced liquid phase could be reduced by more than 30 vol% (volume percent) when the pump speed was reduced by less than about 5% and the ratio was calculated based on the daily averages of the production rates. Moreover, it has been observed that the reduction of 5% in pump speed did not significantly affect the oil production rate.

[0055] It is quite unexpected that it is possible to recover the solvent in the gas phase with a controllable rate through the liquid phase in a solvent-steam process.

[0056] As comparison, in a SAGD process, it is expected that little steam could be produced in the gas phase if the liquid level in the production zone is above the production well, but if the liquid level drops too low a surge of the steam production rate ("short circuit") would occur. It is expected that steam would condense in the liquid phase and be produced as water if the liquid level is high, and can only be produced in a large amount if there is a gas phase passage through the production well (hence the "short circuit").

[0057] Thus, an embodiment of the present disclosure relates to a method of controlling the recovery of injected solvent by controlling the flow rate through the production well, such as by adjusting the pumping speed of a pump in the production well, or by adjusting the pressure differential between the injection well and the production well, which also affects the liquid level around the production well.

[0058] Further, if the pump speed can be reduced and the pump is consequently operated at a lower temperature when it is not necessary to maintain a higher speed in order to achieve the production targets, the pump life may be prolonged.

[0059] The flow rate of the fluid in the production well may also be adjusted by altering the emulsion pressure at the discharge port of the pump (also known as the "backpressure") in the production well that is used to control the liquid (such as emulsion) flow through the production well. The backpressure of the pump can be altered through the manipulation of a choke valve, such as an inline globe valve. By either closing or opening the choke valve, the backpressure on the pump will be increased or decreased, respectively. By managing the backpressure, this will allow the pump to operate at its Best Efficiency Point (BEP) while the pump speed is at significantly different rates. Operating the pump at the manufacturer recommended BEP
can increase the life expectancy of the pump and reduces the likelihood of undesirable pump trip conditions. Increasing the backpressure will limit liquid flow resulting in a higher liquid level of the liquid phase surrounding the production well and reduced production of solvent in the gas phase. Conversely, decreasing the backpressure will increase liquid flow resulting in a lower liquid level of the liquid phase surrounding the production well increased production of solvent in the gas phase. Therefore, the backpressure may be used to control the ratio of produced gas phase to produced liquid phase in the fluid produced from the reservoir.

[0060] Selected embodiments of the present disclosure relate to methods of hydrocarbon recovery from a reservoir of bituminous sands assisted by injection of steam and solvent as a mobilizing agent into the reservoir.

[0061] In an embodiment, steam is injected into the reservoir to soften and mobilize the native bitumen therein, thus forming a fluid containing hydrocarbons and water (condensed steam), which can be produced from the reservoir by an in-situ recovery process, such as steam-assisted gravity drainage (SAGD), or a cyclic steam recovery process such as cyclic steam stimulation (CSS). As will be further detailed below, a solvent is also injected or co-injected as a mobilizing agent to enhance mobility of the oleic phase in the reservoir, which can result in increased flow rate and thus hydrocarbon production rate. The injected mobilizing agent may also help to reduce the residual oil saturation in the reservoir, and reduce steam usage and increase energy efficiency. In some cases, the solvent when injected as a vapour may also help to maintain the reservoir pressure at a desired level, such as at the blowdown or pre-blowdown stages of the operation. The solvent may be injected after a period of steam injection and a steam chamber has been developed to a substantial size in the reservoir.

[0062] In an embodiment, a small amount of methane may be allowed to be injected with the solvent or steam. Alternatively or additionally, after a period of injecting steam and solvent, the amount of injected solvent may be reduced and a non-condensable gas such as methane may be injected in addition to, or instead of, the solvent.

[0063] Steam and the solvent may be injected from the same injection well or may be injected from different injection wells. For example, steam may be injected in a horizontal well and solvent may be injected from a vertical well, or a well placed between two adjacent steam chambers.

[0064] In various embodiments, the term "reservoir" refers to a subterranean or underground formation comprising recoverable oil (hydrocarbons); and the term "reservoir of bituminous sands" refers to such a formation wherein at least some of the hydrocarbons are viscous or immobile, and are disposed between or attached to sands.

[0065] In various embodiments, the terms "oil", "hydrocarbons" or "hydrocarbon"
relate to mixtures of varying compositions comprising hydrocarbons in the gaseous, liquid or solid states, which may be in combination with other fluids (liquids and gases) that are not hydrocarbons. For example, "heavy oil", "extra heavy oil", and "bitumen"
refer to hydrocarbons occurring in semi-solid or solid form and having a viscosity in the range of about 1,000 to over 1,000,000 centipoise (mPa-s or cP) measured at original in situ reservoir temperature. In this specification, the terms "hydrocarbons", "heavy oil", "oil" and "bitumen" are used interchangeably. Depending on the in situ density and viscosity of the hydrocarbons, the hydrocarbons may comprise, for example, a combination of heavy oil, extra heavy oil and bitumen. Heavy crude oil, for example, may be defined as any liquid petroleum hydrocarbon having an American Petroleum Institute (API) Gravity of less than about 20 such as lower than 6 , and a viscosity greater than 1,000 mPa-s. Oil may be defined, for example, as hydrocarbons mobile at typical reservoir conditions. Extra heavy oil, for example, may be defined as having a viscosity of over 10,000 mPa-s and about 100 API Gravity. The API Gravity of bitumen ranges from about 12 to about 6 or about 7 and the viscosity is greater than about 1,000,000 mPa-s.

[0066] A person skilled in the art will appreciate that a formation or reservoir of bitumen sands at its initial (or original) conditions (e.g., natural temperature or viscosity) has not been treated with heat or other mobilizing means. Instead, it is in its original or natural condition, prior to the recovery of hydrocarbons.

[0067] The hydrocarbons in the reservoir of bituminous sands occur in a complex mixture comprising interactions between sand particles, fines (e.g., clay), and water (e.g., interstitial water) which may form complex emulsions during processing.
The hydrocarbons derived from bituminous sands may contain other contaminant inorganic, organic or organometallic species which may be dissolved, dispersed or bound within suspended solid or liquid material. Accordingly, it remains challenging to separate hydrocarbons from the bituminous sands in situ, which may impede production performance of the in-situ process.

[0068] Production performance may be improved when a higher amount of oil is produced within a given period of time, or with a given amount of injected steam depending on the particular recovery technique used, or within the lifetime of a given production well (overall recovery), or in some other manner as can be understood by those skilled in the art. For example, production performance may be improved by increasing the amount of hydrocarbons recovered within the steam chamber, increasing drainage rate of the fluid or hydrocarbon from the steam chamber to the production well, or both.

[0069] Faster oil flow or drainage rates can lead to more efficient oil production, and the increase in the flow or drainage rate of reservoir fluids within the formation can be indirectly indicated or measured by the increase in the rate of oil production. Techniques for measurement of oil production rates have been well developed and are known to those skilled in the art.

[0070] The solvent as a mobilizing agent may be used in various in situ thermal recovery processes, such as SAGD, CSS, steam or solvent flooding, or a solvent aided process (SAP) where steam is also used. Selected embodiments disclosed herein may be applicable to an existing hydrocarbon recovery process, such as after the recovery process has completed the start-up stage or has been in the production stage for a period of time.

[0071] Also, with a gravity-dominated process, such as SAGD, a start-up process is required to established communication between the injection well and production well wells. A skilled person in the art would be aware of various techniques for start-up processes, such as for example hot fluid wellbore circulation, the use of selected solvents such as xylene (as for example described in CA 2,698,898 to Pugh, et al.), the application of geomechanical techniques such as dilation (as for example described in CA 2,757,125 to Abbate, etal.), or the use of one or more microorganisms to increase overall fluid mobility in a near-wellbore region in an oil sands reservoir (as for example in CA 2,831,928 to Bracho Dominguez, et al.). An embodiment of the present disclosure may be employed in combination with any of these start-up techniques.

[0072] A suitable solvent may be propane or butane. Other solvents may also be used in different embodiments. However, light alkanes such as propane and butane may be selected for commercial field applications as they may provide both technical and economic benefits as compared to other, heavier or more complicated solvents.

[0073] When selecting a solvent as the mobilizing agent, the following factors may be considered. The mobilizing agent should reduce viscosity of at least some viscous hydrocarbons in the reservoir and be more soluble in oil than in water. In selected embodiments, the mobilizing agent, when condensed in the reservoir, may dilute oil such that it may enhance the mobility of oil or the reservoir fluid in the reservoir and accelerate the flow rate of the fluid or oil from the steam chamber to the production well, as compared to a typical SAGD operation where only steam is used.

[0074] The mobilizing agent also should have a relatively lower boiling temperature at the operating pressures so that it can be injected as a vapour and has a partial pressure in the reservoir allowing it to be transported as vapour with steam to a steam front, as will be further described below.

[0075] In selected embodiments, the solvent is vapourizable at the operational pressure and temperature near the injection well and in the central region of the vapour chamber, which has been heated by steam to an elevated temperature, so that the solvent can enter the reservoir in the vapour phase and can remain in the vapour phase until the solvent vapour reaches the vapour chamber front The solvent is also substantially condensable at the edges, margins or boundaries of the vapour chamber, where the local temperature is significantly lower than the temperature in the central region of the vapour chamber. The condensed solvent is capable of dissolving hydrocarbons such that the condensed solvent (liquid solvent) can reduce the viscosity of the hydrocarbons, or increase the mobility of the hydrocarbons, which will assist to improve the hydrocarbon drainage rate and therefore hydrocarbon production rate.
There are a number of underlying mechanisms for increasing mobility of hydrocarbons in the reservoir formation as can be understood by those skilled in the art. A
suitable solvent may be selected to assist drainage of hydrocarbons based on any of these mechanisms or a combination of such mechanisms.

[0076] For example, a solvent may be selected based on its ability to reduce the viscosity of hydrocarbons, to dissolve in the reservoir fluid, or to reduce surface and interfacial tension between hydrocarbons and sands or other solid or liquid materials present in the reservoir formation. The solvent may act as a wetting agent or surfactant.
When oil attachment to sand or other immobile solid materials in the reservoir is reduced, the oil mobility can be increased. The solvent may function as an emulsifier for forming hydrocarbon-water emulsions, which may help to improve oil mobility with water in the reservoir. Suitable solvents may include volatile hydrocarbon solvents such as butane or propane, as will be further described below.

[0077] FIG. 1 schematically illustrates a typical well pair configuration in a hydrocarbon reservoir formation 100, which can be operated to implement an embodiment of the present disclosure. The well pair may be configured and arranged similar to a typical well pair configuration for SAGD operations.

[0078] As illustrated, the reservoir formation 100 contains heavy hydrocarbons below an overburden 110. Under natural conditions before any treatment, reservoir formation 100 is at a relatively low temperature, such as about 12 C, and the formation pressure may be from about 0.1 to about 4 MPa, depending on the location and other characteristics of the reservoir.

[0079] The well pair includes an injection well 120 and a production well 130, which have horizontal sections extending substantially horizontally in reservoir formation 100, and is drilled and completed for producing hydrocarbons from reservoir formation 100.
As depicted in FIG. 1, the well pair is typically positioned away from the overburden 110 and near the bottom of the pay zone or geological stratum in reservoir formation 100, as can be appreciated by those skilled in the art.

[0080] As is typical, injection well 120 may be vertically spaced from production well 130, such as at a distance of about 3 to 8 m, e.g., 5 m. The distance between the injection well and the production well may vary and may be selected to optimize the operation performance within technical and economical constraints, as can be understood by those skilled in the art. In some embodiments, the horizontal sections of wells 120 and 130 may have a length of about 800 m. In other embodiments, the length may be varied as can be understood and selected by those skilled in the art.
Wells 120 and 130 may be configured and completed according to any suitable techniques for configuring and completing horizontal in situ wells known to those skilled in the art.
Injection well 120 and production well 130 may also be referred to as the "injection well"
and "production well", respectively.

[0081] The overburden 110 may be a cap layer or cap rock. Overburden 110 may be formed of a layer of impermeable material such as clay or shale. A region in the formation 100 just below and near overburden 110 may be considered as an interface region 115.

[0082] As illustrated, wells 120 and 130 are connected to respective corresponding surface facilities, which typically include an injection surface facility 140 and a production surface facility 150. Surface facility 140 is configured and operated to supply injection fluids, such as steam and solvent, into injection well 120. Surface facility 150 is configured and operated to produce fluids collected in production well 130 to the surface. Each of surface facilities 140, 150 includes one or more fluid pipes or tubing for fluid communication with the respective well 120 or 130. As depicted for illustration, surface facility 140 may have a supply line connected to a steam generation plant for supplying steam for injection, and a supply connected to a solvent source for supplying the solvent for injection. Optionally, one or more additional supply lines may be provided for supplying other fluids, additives or the like for co-injection with steam or the solvent.
Each supply line may be connected to an appropriate source of supply (not shown), which may include, for example, a steam generation plant, a boiler, a fluid mixing plant, a fluid treatment plant, a truck, a fluid tank, or the like. In some embodiments, co-injected fluids or materials may be pre-mixed before injection. In other embodiments, co-injected fluids may be separately supplied into injection well 120. In particular, surface facility 140 is used to supply steam and a selected solvent into injection well 120. The solvent may be pre-mixed with steam at surface before co-injection.
Alternatively, the solvent and steam may be separately fed into injection well 120 for injection into formation 100. Optionally, surface facility 140 may include a heating facility (not separately shown) for pre-heating the solvent before injection.

[0083] As illustrated, surface facility 150 includes a fluid transport pipeline for conveying produced fluids to a downstream facility (not shown) for processing or treatment. Surface facility 150 includes necessary and optional equipment for producing fluids from production well 130, as can be understood by those skilled in the art. An embodiment of surface facility 150 includes one or more valves 111 for regulating the fluid flow in the liquid line of the produced fluid. The valve(s) may be a choke valve, such as an inline globe valve. The valve may be selected and configured to control the "backpressure" and the flow rate in the liquid line (also referred to as the emulsion line in the art).

[0084] Other necessary or optional surface facilities 160 may also be provided, as can be understood by those skilled in the art. For example, surface facilities 160 may include one or more of a pre-injection treatment facility for treating a material to be injected into the formation, a post-production treatment facility for treating a produced material, a control or data processing system for controlling the production operation or for processing collected operational data. Surface facilities 140, 150 and 160 may also include recycling facilities for separating, treating, and heating various fluid components from a recovered or produced reservoir fluid. For example, the recycling facilities may include facilities for recycling water and solvents from produced reservoir fluids.

[0085] Injection well 120 and production well 130 may be configured and completed in any suitable manner as can be understood or is known to those skilled in the art, so long as the wells are compatible with injection and recovery of the selectable solvent to be used in the solvent-steam process as will be disclosed below.

[0086] For example, in different embodiments, the well completions may include perforations, slotted liner, screens, outflow control devices such as in an injection well, inflow control devices such as in a production well, or a combination thereof known to one skilled in the art.

[0087] FIG. 2 shows a schematic cross-sectional view of wells 120, 130 in formation 100, and FIG. 3 is a schematic perspective view of wells 120, 130 in formation during a recovery process where a vapour chamber 360 has formed.

[0088] As illustrated, injection well 120 and production well 130, each have a casing 220, 230 (respectively). An injection well tubing 225 is positioned in injection well casing 220, the use of which can be understood by those skilled in the art and will be described below. For simplicity, other necessary or optional components, tools or equipment that are installed in the wells are not shown in the drawings as they are not particularly relevant to the present disclosure.

[0089] As depicted in FIG. 3, injection well casing 220 includes a slotted liner along the horizontal section of well 120 for injecting fluids into reservoir formation 100.

[0090] Production casing 230 is also completed with a slotted liner along the horizontal section of well 130 for collecting fluids drained from reservoir formation 100 by gravity. In some embodiments, production well 130 may be configured and completed similarly to injection well 120.

[0091] In some embodiments, each well 120, 130 may be configured and completed for both injection and production, which can be useful-in some applications as can be understood by those skilled in the art.

[0092] In operation, wells 120 and 130 may be operated to produce hydrocarbons from reservoir formation 100 according to a process disclosed here.

[0093] For example, in an embodiment the wells 120 and 130 may be initially operated as in a conventional SAGD process, or a suitable variation thereof, as can be understood by those skilled in the art. In this initial process, steam may be the only or the dominant injection fluid.

[0094] Alternatively, steam and a solvent may be co-injected at the start of the production stage after the start-up stage.

[0095] In any event, both steam and one or more solvents are injected during at least one period of the production stage, and the following description is focused on such injection period.

[0096] In an exemplary process, reservoir formation 100 is initially subjected to a "start-up" phase or stage, in which fluid communication between wells 120 and 130 is established. The start-up stage may be similar to the initial start-up stage in a conventional SAGD process. To permit drainage of mobilized hydrocarbons and condensate to production well 130, fluid communication between wells 120, 130 must be established. Fluid communication refers to fluid flow between the injection and production wells. Establishment of such fluid communication typically involves mobilizing viscous hydrocarbons in the reservoir to form a reservoir fluid and removing the reservoir fluid to create a porous pathway between the wells. Viscous hydrocarbons may be mobilized by heating such as by injecting or circulating pressurized steam or hot water through injection well 120 or production well 130. In some cases, steam may be injected into, or circulated in, both injection well 120 and production well 130 for faster start-up. For example, the start-up phase may include circulation of steam or hot water by way of injection well casing 220 and injection well tubing 225 in combination. A
pressure differential may be applied between injection well 120 and production well 130 to promote steam/hot water penetration into the porous geological formation that lies between the wells of the well pair. The pressure differential promotes fluid flow and convective heat transfer to facilitate communication between the wells.

[0097] Additionally or alternatively, other techniques may be employed during the start-up stage. For example, to facilitate fluid communication, a solvent may be injected into the reservoir region around and between the injection and production wells 120, 130. The region may be soaked with a solvent before or after steam injection.
An example of start-up using solvent injection is disclosed in CA 2,698,898. In further examples, the start-up phase may include one or more start-up processes or techniques disclosed in CA 2,886,934, CA 2,757,125, or CA 2,831,928.

[0098] Once fluid communication between injection well 120 and production well 130 has been achieved, oil production or recovery may commence. As the oil production rate is typically low initially and will increase as the vapour chamber develops, the early production phase is known as the "ramp-up" phase or stage. During the ramp-up stage, steam, with or without a solvent, is typically injected continuously into injection well 120, at constant or varying injection pressure and temperature. At the same time, mobilized heavy hydrocarbons and aqueous condensate are continuously removed from production well 130. During ramp-up, the zone of communication between injection well 120 and production well 130 may continue to expand axially along the full length of the horizontal portions of wells 120, 130.

[0099] As the injected fluid heats up formation 100, heavy hydrocarbons in the heated region are softened, resulting in reduced viscosity. Further, as heat is transferred from steam to formation 100, steam and solvent vapour condense.
The aqueous and solvent condensate and mobilized hydrocarbons will drain downward due to gravity. As a result of depletion of the heavy hydrocarbons, a porous region is formed in formation 100, which is referred to herein as the "vapour chamber" 360.
When the vapour chamber 360 is filled with mainly steam, it is commonly referred to in the art as the "steam chamber." The aqueous and solvent condensate and hydrocarbons drained towards production well 130 and collected in production well 130 are then produced (transferred to the surface), such as by gas lifting or through pumping with a pump 107 as is known to those skilled in the art.

[00100] More specifically, during oil production a heated fluid including steam and solvent may be injected into reservoir 100 through injection well 120. The injected fluid heats up the reservoir formation, softens or mobilizes the bitumen in a region in the reservoir 100 and lowers bitumen viscosity such that the mobilized bitumen can flow. As heat is transferred to the bituminous sands, injected steam and solvent vapour condense and a fluid mixture containing condensed steam and solvent and mobilized bitumen (oil) forms. The fluid mixture drains downward due to gravity, and the vapour chamber 360 is formed or expands in reservoir 100. This process is schematically illustrated in FIG. 4. The fluid mixture generally drains downward along the edge of vapour chamber 360 into the production zone 108 around the production well 130. The liquid fluid mixture 109 co-exists with gas phase steam/solvent in the production zone.
Condensed steam (water), liquid solvent, and oil in the fluid mixture collected in the production well 130 are then produced (transferred to the surface), such as by gas lifting or through pumping such as using an electric submersible pump (ESP), as is known to those skilled in the art.

[00101] As is typical, the injection and production wells 120, 130 have terminal sections that are substantially horizontal and substantially parallel to one another. A
person of skill in the art will appreciate that while there may be some variation in the vertical or lateral trajectory of the injection or production wells, causing increased or decreased separation between the wells, such wells for the purpose of this application will still be considered substantially horizontal and substantially parallel to one another.
Spacing, both vertical and lateral, between injection wells and production wells may be optimized for establishing start-up or based on reservoir conditions.

[00102] At the point of injection into the formation, or in the injection well 120, the injected fluid/mixture may be at a temperature that is selected to optimize the production performance and efficiency. For example, for a given solvent to be injected the injection temperature may be selected based on the boiling point (or saturation) temperature of the solvent at the expected operating pressure in the reservoir. For propane, the boiling temperature is about 2 C at 0.5 MPa, and about 77 C at 3 MPa. For a different solvent, the injection temperature may be higher if the boiling point temperature of that solvent at the reservoir pressure is higher. In different embodiments and applications, the injection temperature may be substantially higher than the boiling point temperature of the solvent by, e.g., 5 C to 200 C, depending on various operation and performance considerations. In some embodiments, the injection temperature may be from about 50 C to about 320 C, and at a pressure from about 0.5 MPa to about 12.5 MPa, such as from 0.6 MPa to 5.1 MPa or up to 10 MPa. At an injection pressure of about 3 MPa, the injection temperature for propane may be from about 80 C to about 250 C, and the injection temperature for butane may be from about 100 C to about 300 C. The injection temperature and pressure are referred to as injection conditions. A person skilled in the art will appreciate that the injection conditions may vary in different embodiments depending on, for example, the type of hydrocarbon recovery process implemented (e.g., SAGD, CSS) or the mobilizing agents selected, as well as various factors and considerations for balancing and optimizing production performance and efficiency. The injection temperature should not be too high as a higher injection temperature will typically require more heating energy to heat the injected fluid. Further, the injection temperature should be limited to avoid coking hydrocarbons in the reservoir formation.
In some oil sands reservoirs, the coking temperature of the bitumen in the reservoir is about 350 C.

[00103] Once injected steam and vapour of the injected solvent enter the reservoir, their temperature may drop under the reservoir conditions. The temperatures at different locations in the reservoir will vary as typically regions further away from injection well 120, or at the edges of the vapour chamber, are colder. During operations, the reservoir conditions may also vary. For example, the reservoir temperatures can vary from about 10 C to about 275 C, and the reservoir pressures can vary from about 0.6 MPa to about 7 MPa depending on the stage of operation. The reservoir conditions may also vary in different embodiments.

[00104] As noted above, injected steam and solvent condense in the reservoir mostly at regions where the reservoir temperature is lower than the dew point temperature of the solvent at the reservoir pressure. Condensed steam (water) and solvent can mix with the mobilized bitumen to form reservoir fluids. It is expected that in a typical reservoir subjected to steam/solvent injection, the reservoir fluids include a stream of condensed steam (or water, referred to as the water stream herein).
The water stream may flow at a faster rate (referred to as the water flow rate herein) than a stream of mobilized bitumen containing oil (referred to as the oil stream herein), which may flow at a slower rate (referred to as the oil flow rate herein). The reservoir fluids can be drained to the production well by gravity. The mobilized bitumen may still be substantially more viscous than water, and may drain at a relatively low rate if only steam is injected into the reservoir. However, condensed solvent may dilute the mobilized bitumen and increase the flow rate of the oil stream.

[00105] Thus, injected steam and vapour of the solvent both assist to mobilize the viscous hydrocarbons in the reservoir 100. A reservoir fluid formed in the vapour chamber 360 will include oil, condensed steam (water), and a condensed phase of the solvent. The reservoir fluid is drained by gravity along the edge of vapour chamber 360 into production well 130 for recovery of oil.

[00106] In various embodiments, the solvent may be selected so that dispersion of the solvent in the vapour chamber 360, as well as in the reservoir fluid increases the amount of oil contained in the fluid and increases the flow rate of oil stream from vapour chamber 360 to the production well 130. When solvent condenses (forming a liquid phase) in the vapour chamber 360, it can be dispersed in the reservoir fluid to increase the rate of drainage of the oil stream from the reservoir 100 into the production well 130.

[00107] After the reservoir fluid is removed from the reservoir 100, the solvent and water may be separated from oil in the produced fluids by a method known in the art depending on the particular solvent(s) involved. The separated water and solvent can be further processed by known methods, and recycled to the injection well 120.
In some embodiments, the solvent is also separated from the produced water before further treatment, re-injection into the reservoir or disposal.

[00108] As mentioned, vapour chamber 360 forms and expands due to depletion of hydrocarbons and other in situ materials from regions of reservoir formation 100 above the injection well 120. Injected steam/solvent vapour tend to rise up to reach the top of vapour chamber 360 before they condense, and steam/solvent vapour can also =
spread laterally as they travel upward. During early stages of chamber development, vapour chamber 360 expands upwardly and laterally from injection well 120.
During the ramp-up phase and the early production phase, vapour chamber 360 can grow vertically towards overburden 110. At later stages, after vapour chamber 360 has reached the overburden 110, vapour chamber 360 may expand mainly laterally.

[00109] Depending on the size of reservoir formation 100 and the pay therein and the distance between injection well 120 and overburden 110, it can take a long time, such as many months and up to two years, for vapour chamber 360 to reach overburden 110, when the pay zone is relative thick as is typically found in some operating oil sands reservoirs. However, it will be appreciated that in a thinner pay zone, the vapour chamber can reach the overburden sooner. The time to reach the vertical expansion limit can also be longer in cases where the pay zone is higher or highly heterogeneous, or the formation has complex overburden geologies such as with inclined heterolithic stratification (HIS), top water, top gas, or the like.

[00110] During a period in at least the production stage, steam and the solvent are injected into the reservoir to assist production and enhance hydrocarbon recovery.

[00111] In some embodiments, at early stages of oil production, steam may be injected without a solvent. The solvent may be added as a mobilizing agent after the vapour chamber 360 has reached or is near the top of the pay zone, e.g., near or at the lower edge of the overburden 110 as depicted in FIGS. 1 and 3 or after the oil production rate has peaked. The solvent can dissolve in oil and dilute the oil stream so as to increase the mobility and flow rate of hydrocarbons or the diluted oil stream towards production well 130 for improved oil recovery. Other materials in liquid or gas form may also be added to the injection fluid to enhance recovery performance.

[00112] The start-up, ramp-up, and production phases may be. conducted according to any suitable conventional techniques known to those skilled in the art except the aspects described herein, and the other aspects will therefore not be detailed herein for brevity.

[00113] As an example, during production, such as at the end of an initial production period with steam injection, the formation temperature in the vapour chamber 360 can reach about 235 C and the pressure in the vapour chamber 360 may be about 3 MPa. The temperature or pressure may vary by about 10% to 20%.

[00114] As mentioned earlier, in a particular embodiment where propane is used as the mobilizing agent, the injection temperature of the steam-propane mixture may be about 80 C to about 250 C. In other embodiments, the injection temperature may be selected based on the boiling point temperature of the solvent at the selected injection pressure.

[00115] Of course, depending on the reservoir and the application, the chamber temperature and pressure may also vary in different embodiments. For example, in various embodiments, steam may be injected at a temperature from about 150 C
to about 330 C and a pressure from about 0.1 MPa to about 12.5 MPa. In some embodiments, the highest temperature in the vapour chamber 360 may be from about 50 C to about 350 C and the pressure in the vapour chamber 360 may be from about 0.1 MPa to about 7 MPa.

[00116] In further embodiments, it may also be possible that steam is injected at a temperature sufficient to heat the solvent such that the injected solvent has a maximum temperature of between about 50 C and about 350 C within the vapour chamber 360.

[00117] It should be noted that the temperature in a vapour chamber varies from the injection well towards the edges of the vapour chamber, and the temperature at the chamber edges (also referred to as the "steam front") is still relatively low, such as about 15 C to about 25 C. The reservoir temperature can also vary from about 10 C to the highest chamber temperature discussed above.

[00118] A suitable solvent may be selected based on a number of considerations and factors as discussed herein.

[00119] The solvent should be injectable as a vapour, and can dissolve at least one of the heavy hydrocarbons to be recovered from reservoir formation 100 in the solvent-steam process for increasing mobility of the heavy hydrocarbons. The solvent may be a viscosity-reducing solvent, which reduces the viscosity of the heavy hydrocarbons in reservoir formation 100.

[00120] It is noted that steam injection with solvent injection can conveniently facilitate transportation of the solvent as a vapour with steam to the steam front. Steam is typically a more efficient heat-transfer medium than a solvent, and can increase the reservoir temperature more efficiently and more economically, or maintain the vapour chamber at a higher temperature. The heat, or higher formation temperature in a large region in the formation, can help to maintain the solvent in the vapour phase and assist dispersion of the solvent to the chamber edges ("steam front"). The heat from steam can also by itself assist reduction of viscosity of the hydrocarbons. However, injecting steam requires more heating energy and inject steam at a too high ratio can reduce the energy efficiency of the process.

[00121] Yet, replacing steam completely with a solvent or injecting too little steam, may reduce recovery performance and substantially increase the amount and cost of the solvent to be injected.

[00122] The solvent is injected into reservoir formation 100 in a vapour phase.
Injection of the solvent in a vapour phase allows the solvent vapour to travel in vapour chamber 360 and condense at a region away from injection well 120. Allowing solvent to travel in vapour chamber 360 before condensing may achieve beneficial effects. For example, when vapour of the solvent is delivered to vapour chamber 360 and then allowed to condense and disperse in the vapour chamber 360 particularly at or near the steam front (edges of vapour chamber 360), oil production performance, such as indicated by one or more of oil production rate, cumulative steam to oil ratio (CSOR), and overall efficiency, can be improved. Injection of solvent in the gaseous phase, rather than a liquid phase, may allow vapour to rise in vapour chamber 360 before condensing so that condensation occurs away from injection well 120. It is noted that injecting solvent vapour into the vapour chamber does not necessarily require solvent be fed into the injection well in vapour form. The solvent may be heated downhole and vaporized in the injection well in some embodiments. Alternatively, the solvent may be injected into another well or other wells for more efficient delivery of the solvent to desired locations in the reservoir. The additional well(s) may include a vertical well, a horizontal well, or a well drilled according to the well drilled using Wedge WellTM
technology.

[00123] The total injection pressure for solvent and steam co-injection may be the same or different than the injection pressure during a conventional SAGD
production process. For example, the injection pressure may be maintained at between 2 MPa and 3.5 MPa, or up to 4 MPa. In another example, steam may be injected at a pressure of about 3 MPa initially, while steam and solvent are co-injected at a pressure of about 2 MPa to about 3.5 MPa during co-injection.

[00124] The solvent may be heated before or during injection to vaporize the solvent. Additionally or alternatively, solvent may be mixed or co-injected with steam to heat the solvent to vaporize it and to maintain the solvent in vapour phase.
Depending on whether the solvent is pre-heated at surface, the weight ratio of steam in the injection stream should be high enough to provide sufficient heat to the co-injected solvent to maintain the injected solvent in the vapour phase. If the feed solvent from surface is in the liquid phase, more steam may be required to both vaporize the solvent and maintain the solvent in the vapour phase as the solvent travels through the vapour chamber 360.

[00125] In different embodiments, co-injection of steam and the solvent may be carried out in a number of different ways or manners as can be understood by those skilled in the art. For example, co-injection of the solvent and steam into the vapour chamber may include gradually increasing the weight ratio of the solvent in the co-injected solvent and steam, and gradually decreasing the weight ratio of steam in the co-injected solvent and steam. At a later stage, the solvent content in the co-injected solvent and steam may be gradually decreased, and the steam content in the co-injected solvent and steam may be gradually increased. For example, depending on market factors, the cost of solvent may change over the life of a steam-solvent process.
During or after the solvent-steam process, it may be of economic benefit to gradually decrease the solvent content and gradually increase the steam content.

[00126] Solvent injection is expected to result in increased mobility of at least some of the heavy hydrocarbons of reservoir formation 100. For example, some solvents such as propane and butane are expected to dissolve in and dilute heavy oil thus increasing the mobility of the oil. The effectiveness and efficiency of the solvent depends on the solubility and diffusion of the solvent in hydrocarbons. Slow diffusion or low solubility of the solvent in the hydrocarbons can limit the effect of the solvent on oil drainage rate. Therefore, the operation conditions may be modified to increase solvent diffusion and solubility so as to optimize process performance and efficiency.
The term "mobility" is used herein in a broad sense to refer to the ability of a substance to move about, and is not limited to the flow rate or permeability of the substance in the reservoir. For example, the mobility of heavy hydrocarbons may be increased when they become more mobile, or when heavy hydrocarbons attached to sands become easier to detach from the sands, or when immobile heavy hydrocarbons become mobile, even if the viscosity or flow rate of the hydrocarbons has not changed. The mobility of heavy hydrocarbons may also be increased by decreasing the viscosity of the heavy hydrocarbons, or when the effective permeability, such as through bituminous sands, is increased. Additionally or alternatively, increasing heavy hydrocarbon mobility may be achieved by heat transfer from solvent to heavy hydrocarbons.

[00127] Additionally or alternatively, solvent may otherwise accelerate production.
For example, a non-condensable gas, such as methane, may propel a solvent, such as propane, downwards thereby enhancing lateral growth of the vapour chamber. For example, such propulsion may be part of a blowdown phase.

[00128] Conveniently, a solvent-steam process where solvent is co-injected with steam requires less steam as compared to the SAGD production phase. Injection of less steam may reduce water and water treatment costs required for production.

Injection of less steam may also reduce the need or costs for steam generation for an oil production project. Steam may be produced at a steam generation plant using boilers. Boilers may heat water into steam via combustion of hydrocarbons such as natural gas. A reduction in steam generation requirement may also reduce combustion of hydrocarbons, with reduced emission of greenhouse gases such as, for example, carbon dioxide.

[00129] Once the oil production process is completed, the operation may enter an ending or winding down phase, with a process known as the "blowdown" process.
The "blowdown" phase or stage may be performed in a similar manner as in a conventional SAGD process. During the blowdown stage, a non-condensable gas may be injected into the reservoir to replace steam or the solvent. For example, the non-condensable gas may be methane. In addition, methane may enhance hydrocarbon production, for example by about 10% within 1 year, by pushing the already injected solvent through the chamber.

[00130] Alternatively, in an embodiment a solvent may be continuously utilized through a blowdown phase, in which case it is possible to eliminate or reduce injection of methane during blowdown. In particular, it is not necessary to implement a conventional blowdown phase with injected methane gas, when a significant portion of the injected solvent can be readily recycled and reused. In some embodiments, during or at the end of the blowdown phase, methane or another non-condensable gas (NCG) may be used to enhance solvent recovery, where the injected methane or other non-condensable gas may increase solvent condensation and thus improve solvent recovery. For example, injected methane or other NCG may mobilize gaseous solvent in the chamber to facilitate removal of the solvent.

[00131] During the blowdown phase, oil recovery or production may continue with production operations being maintained. When methane is used for blowdown, oil production performance will decline over time as the growth of the vapour front in vapour chamber 360 slows under methane gas injection.

[00132] At the end of the production operation, the injection wells may be shut in but solvent (and some oil) recovery may be continued, followed by methane injection to enhance solvent recovery. The formation fluid may be produced until further recovery of fluids from the reservoir is no longer economical, e.g. when the recovered oil no longer justifies the cost for continued production, including the cost for solvent recycling and re-injection.

[00133] In some embodiments, before, during or after the blowdown phase, production of fluids from the reservoir through production well 130 may continue. An embodiment of the production control process disclosed herein may be used, or adapted to use, during the blowdown phase to control the produced gas phase such as methane when steam and methane are produced during the blowdown phase.

[00134] The solvent for injection may be selected based on a number of criteria.
As discussed above, the solvent should be injectable as a vapour, and can dissolve at least one of the heavy hydrocarbons to be recovered from reservoir formation 100 in the solvent-steam process for increasing mobility of the heavy hydrocarbons.

[00135] Conveniently, increased hydrocarbon mobility can enhance drainage of the reservoir fluid toward and into production well 130. In a given application, the solvent may be selected based on its volatility and solubility in the reservoir fluid. For example, in the case of a reservoir with a thinner pay zone (e.g., the pay zone thickness is less than about 8 m), or a reservoir having a top gas zone or water zone, the solvent may be injected in a liquid phase in the solvent-steam process.

[00136] Suitable solvents may include C3 to C5 hydrocarbons such as, propane, butane, or pentane. Additionally or alternatively, a C6 hydrocarbon such as hexane could be employed. A combination of solvents including C3-C6 hydrocarbons and one or more heavier hydrocarbons may also be suitable in some embodiments.
Solvents that are more volatile, such as those that are gaseous at standard temperature and pressure (STP), or significantly more volatile than steam at reservoir conditions, such as propane or butane, or even methane, may be beneficial in some embodiments.

[00137] For selecting a suitable solvent, the properties and characteristics of various candidate solvents may be considered and compared. For a given selected solvent, the corresponding operating parameters during co-injection of the solvent with steam should also be selected or determined in view the properties and characteristics of the selected solvent.

[00138] In particular, the injection temperature should be sufficiently high and the injection pressure should be sufficiently low to ensure most of the solvent will be injected in the vapour phase into the vapour chamber. In this context, injection temperature and injection pressure refer to the temperature and pressure of the injected fluid in the injection well, respectively. The temperature and pressure of the injected fluid in the injection well may be controlled by adjusting the temperature and pressure of the fluid to be injected before it enters the injection well. The injection temperature, injection pressure, or both, may be selected to ensure that the solvent is in the gas phase upon injection from the injection well into the vapour chamber.

[00139] Solvents may be selected having regard to reservoir characteristics such as, the size and nature of the pay zone in the reservoir, properties of fluids involved in the process, and characteristics of the formation within and around the reservoir. For example, a relatively light hydrocarbon solvent such as propane may be suitable for a reservoir with a relatively thick pay zone, as a lighter hydrocarbon solvent in the vapour phase is typically more mobile within the heated vapour chamber.

[00140] Additionally or alternatively, solvent selection may include consideration of the economics of heating a selected particular solvent to a desired injection temperature.

[00141] For example, as can be appreciated by those skilled in the art, lighter solvents, such as propane and butane, can be efficiently injected in the vapour phase at relatively low temperatures at a given injection pressure. In comparison, efficient pure steam injection in a SAGD process typically requires a much higher injection temperature, such as about 200 C or higher.

[00142] Heavier solvents typically also require a higher injection temperature. For example, pentane may need to be heated to about 190 C for injection in the vapour phase at injection pressures up to about 3 MPa. In comparison, a light solvent such as propane may be injected at temperatures as low as about 50 to about 70 C
depending on the reservoir pressure.

[00143] Different solvents or solvent mixtures may be suitable candidates.
For example, the solvent may be propane, butane, or pentane. A mixture of propane and butane may also be used in an appropriate application. It is also possible that a selected solvent mixture may include heavier hydrocarbons in proportions that are, for example, low enough that the mixture still satisfies the above described criteria for selecting solvents.

[00144] In some embodiments, the vapour pressure profile of the solvent may be selected such that the partial pressure of the solvent in a central (core) region of the vapour chamber is within about 0.25% to about 20% of the total gas pressure, or the vapour pressure of water/steam.

[00145] It may be desirable if the solvent and steam can vaporize and condense under similar temperature and pressure conditions, which will conveniently allow vapour of the solvent to initially rise up with the injected steam to penetrate the rock formation in the vapour chamber, and then condense with the steam to form a part of the mobilized reservoir fluid.

[00146] For example, in some embodiments, the solvent may have a boiling point that resembles the boiling point of water under the steam injection conditions such that it is sufficiently volatile to rise up with the injected steam in vapour form when penetrating the steam chamber and then condense at the edge of the steam chamber.
The boiling temperature of the solvent may be near the boiling temperature of water at the same pressure.

[00147] Conveniently, when the solvent has vaporization characteristics that resemble, closely match, those of water under the reservoir conditions, the solvent can condense when it reaches the steam front or the edge of the steam chamber, which is typically at a lower temperature such as at about 12 C to about 150 C. The condensed solvent may be soluble in or miscible with either the hydrocarbons in the reservoir fluid or the condensed water, so as to increase the drainage rate of the hydrocarbons in the fluid through the reservoir formation.

[00148] The condensed solvent is soluble in oil, and thus can dilute the oil stream, thereby increasing the mobility of oil in the fluid mixture during drainage. In some embodiments, the condensed solvent is also soluble in or miscible with the condensed water, which may lead to increased water flow rate by promoting formation of oil-in-water emulsions.

[00149] Without being limited to any particular theory, the dispersion of the solvent and the steam may facilitate the formation of an oil-in-water emulsion under suitable reservoir conditions and also increase the fraction of oil carried by the fluid mixture. As a result, more oil may be produced for the same amount of, or less, steam, which is desirable.

[00150] A possible mechanism for improving mobility of oil is that the solvent can act as a diluent due to its solubility in oil and optionally water, thus reducing the viscosity of the resulting fluid mixture. The solvent may interact at the oil surface to reduce capillary and viscosity forces.

[00151] A vapour mixture of steam and the solvent may be delivered into vapour chamber 360 using any suitable delivery mechanism or route. For example, injection well 120 may be conveniently used to deliver the vapour mixture. A mobilizing fluid or agent may be injected in the form of a mixture of steam and solvent (e.g., mixed ex-situ), or separate streams may be injected into the injection well 120 for mixing in the injection well 120.

[00152] Conveniently, a process as disclosed herein may reduce overall production costs while improving production performance, as compared to conventional SAGD processes or conventional SAP processes.

[00153] In some embodiments, injection pressure may be controlled using the same techniques as used in conventional SAGD or SAP. Alternatively, different or additional techniques may be used for injection pressure control during different stages or periods in the recovery operation.

[00154] In some embodiments, the solvent may be heated at the surface before injection. Additionally or alternatively, the solvent may be heated by co-injection with steam. The steam may be present in a sufficient amount and temperature to heat the injection mixture. Additionally or alternatively, the solvent may be heated downhole, such as by way of a downhole heater.

[00155] As discussed above, the solvent may be pre-heated at surface and delivered relatively hot into the injection well in some embodiments. In other embodiments, the solvent may be fed into the injection well without pre-heating at the surface.

[00156] In some embodiments, the solvent condensed in the reservoir may be recovered in the oleic phase, such as being produced with other produced fluids from the reservoir. Solvent vapour may also be recovered with a reservoir fluid in the gaseous phase. For example, a substantial portion of the recovered solvent may be recovered as a vapour from the recovered casing gas.

[00157] In some embodiments, additional or "make-up" solvent may be added to the injected fluid. The "make up" solvent may be the same as the recovered solvent, but may have a different composition as compared to the composition of the recovered solvent.

[00158] In some embodiments, an additive or chemical such as toluene may be injected during the production stage or post-production stage. Injection of toluene may help to reduce asphaltene precipitation. About 5 wt% toluene may be co-injected with steam or a solvent.

[00159] The recovered fluids from the reservoir may be separated at the surface, and the separated solvent may be used for re-ejection or other recycling purposes.

[00160] In some embodiments, it may not be necessary to recycle the injected solvent.

[00161] In some embodiments, a separate vertical well may be introduced into the reservoir for injection of a solvent, or steam and solvent.

[00162] In some embodiments, non-condensable gases (NCGs) may be generated in the reservoir such as due to heating. Additionally or alternatively, an NCG
may be injected as an additive in some embodiments. Conveniently, the presence of NCGs in the formation can enhance lateral dispersion of the solvent vapour to spread the solvent laterally into the reservoir formation. Increased lateral dispersion of the solvent is expected to assist lateral growth of the vapour chamber, and hence enhance oil production.

[00163] While in some of the above discussed embodiments a pair of wells is employed for injection and production respectively, it can be appreciated that an embodiment of the present disclosure may include a single well or unpaired wells. The single well, or an unpaired well, may be used alternately for injection or production. The single well may have a substantially horizontal or vertical section in fluid communication with the reservoir. The single well may be a well that is configured and completed for use in a cyclic steam stimulation (CSS) recovery process. With the use of a single well for injection and production, a temperature in the reservoir may be about 234 C to about 328 C and a pressure in the reservoir may be from about 0.5 MPa or from about 3.0 MPa to about 12.5 MPa.

[00164] To deliver a selected solvent to the production site, a modular natural gas liquid (NGL) injection system may be used. Such a modular system may be designed to be relocatable to other well pads.

[00165] At the surface, the solvent may be delivered by a pipeline or by trucks. If trucks are used to deliver the solvent, the trucks may offload the solvent, for example propane, to immobile NGL storage bullets, from which the solvent may be injected into the reservoir with one or more pumps. While the solvent may also be injected directly from mobile trucks into the injection well, quick offloading of the solvent from trucks may result in batch injection. Immobile bullets may be used if continuous injection of the solvent is desirable and the solvent is initially provided by trucks. For a medium scale facility, immobile 50-tonne solvent bullets may be used, which may be manufactured and configured specifically for propane storage. Additionally, injection pumps may be manufactured following a standard pump manufacture process, or may be custom-designed and made to manage propane injection from about 40 t/d to about 80 t/d. In practice, the amount of solvent delivered may be determined by measuring the weight of each truck before and after unloading to monitor the weight change. For propane injection at a rate of 50 t/d, two or more trucks may be sufficient.

[00166] Solvent, such as propane, may be mixed with steam upstream of a wellhead and the combined stream of steam and solvent may be injected into the reservoir through an injection well. An existing NGL injection module may be modified to allow the steam-solvent injection point to be in close proximity to the wellhead.

[00167] In an embodiment, a stand-alone skid may be provided. A solvent injection pump driver may be electrically driven with the electrical power supplied. In various embodiments, the injection of a suitable solvent may comprise an injection pattern. For example, the injection pattern may comprise simultaneous injection with the steam or staged (e.g., sequential) injection at selected time intervals and at selected locations within the SAGD operation (e.g., across multiple well pairs in a SAGD well pad). The injection may be performed in various regions of the well pad or at multiple well pads to create a target injection pattern to achieve target results at a particular location of the pad or pads. In various embodiments, the injection may be continuous or periodic. The injection may be performed through an injection well at various intervals along a length of the well.

[00168] In various other embodiments, the steam may be injected from one injection well and the solvent may be injected from another injection location (e.g., through a solvent delivery conduit). For example, in various embodiments, the injection may involve top loading of the solvent from another injection location. In various embodiments, an existing steam injection well may be converted or adapted for injecting a solvent, or a new injection well may be provided to inject the solvent. For example, the solvent may be injected from a nearby well drilled using Wedge WellTM
technology or through a new injection well located at the top of the reservoir formation (near overburden 110). The solvent may also be injected through a gas cap or overburden 110. Another possibility is to inject the mobilizing agent through a vertical well located in the vicinity of the vapour chamber. In various embodiments, the mobilizing agent may be injected at various stages of a thermal in situ recovery process such as SAGD. In various embodiments, the injection of a particular solvent (e.g., having a particular stability, vaporization property, etc.) may be tailored to the particular conditions of the reservoir or a reservoir portion into which the solvent is to be injected.

[00169] The solvent should be suitable for practical transportation and handling at surface facility conditions. For example, in various embodiments, the solvent may be selected such that it is possible to transport and store the solvent as a liquid prior to providing the solvent to an injection well or reservoir.

[00170] In some embodiments, the solvent may be a liquid or in solution prior to being injected into the injection well. Solvents that are in a liquid phase or in a solution at surface conditions may be easier to handle. The solvent may be injected as a liquid (pre-heated or at ambient temperature) or as a vapour at the wellhead or downhole, or the solvent may be injected as a liquid and vaporized at the wellhead, in the wellbore, or downhole. The solvent may at least partially vaporize at the temperature and pressure of the injection steam in the injection well such that the solvent is at least partially vaporized prior to contact with the reservoir of bituminous sands.

[00171] The solvent should also be suitable for use under the desired operating conditions, which include certain temperatures, pressures and chemical environments.
For example, in various embodiments, the solvent may be selected such that it is chemically stable under the reservoir conditions and the steam injection conditions and therefore can remain effective after being injected into the steam chamber.

[00172] The solvent may react with a material in the reservoir to improve mobility of oil. The reactions may involve water, bitumen, or sand/clays in the reservoir. Some materials in the sand or clay may act as a catalyst for the reaction. In some embodiments, a catalyst for a desired reaction involving the solvent may be co-injected with the solvent, or as part of an injected mobilizing fluid or agent.

[00173] While some of the example embodiments discussed herein refer to SAGD
well configuration and operations, it can be appreciated that a solvent may be similarly used in another steam-assisted recovery process such as CSS. In a CSS
operation, a single well may be used to alternately inject steam into the reservoir and produce the fluid from the reservoir. The single well may have a substantially horizontal or vertical section in fluid communication with the reservoir. The single well may be used in a cyclic steam recovery process. With the use of the single well for injection and production, a temperature in the reservoir may be about 234 C to about 328 C
and a pressure in the reservoir may be from about 0.5 MPa or from about 3.0 MPa to about 12.5 MPa.

[00174] Other possible modifications and variations to the examples discussed above are also possible.

[00175] Further, factors affecting the transportation of the solvent in the reservoir need to be considered. For example, for effective delivery of the solvent to the periphery of the vapour chamber, it is desirable that the solvent has a sufficient partial pressure in the steam chamber but can condense with steam at the periphery of the steam chamber.

[00176] As can be understood by a person skilled in the art, vapour pressure of a substance refers to the pressure exerted by a vapour in thermodynamic equilibrium with its condensed phases (solid or liquid) at a given temperature in a closed system. The vapour pressure of any substance usually increases non-linearly with temperature according to the Clausius¨Clapeyron relation. The vaporization characteristics of a substance may be expressed or indicated using vapour pressure curves or profiles which show the relation between the partial pressure of a substance and the temperature and total pressure. The composition of the mixture in which the substance is placed can also affect the partial pressure. In selected embodiments, the solvent may have a vapour pressure curve that does not deviate from the vapour pressure curve of water by, for example, about 10% to about 30% at a given condition. Vapour pressures of a given compound may be known, measured using known methods, or calculated based on known theories including, for example, equations such as the Clausius-Clapeyron equation, Antoine's equation, the Peng-Robinson (PR) equation, the Soave-Redlich-Kwong (SRK) equation, the Wagner equation, or other equations of state.

[00177] In some embodiments, such as when oil is recovered by a SAGD
process or SAP process, the solvent may have vaporization characteristics that resemble vaporization characteristics of water under reservoir conditions during SAGD, such as at reservoir temperature and pressure, and at steam injection conditions, such as at steam injection temperature and pressure.

[00178] Other factors that may affect selection of the solvent may include the type of well configuration (e.g., well pair or single well), the stage during which the solvent is injected (e.g., during or following start-up), the type of reservoir (e.g., reservoir depth, thickness, pressure containment characteristics, or extent of water saturation), or the like.

[00179] Generally, a number of factors may be considered when selecting a suitable solvent for use in various embodiments.

[00180] One factor is whether the solvent can increase the mobility of oil in the region. The mobility of oil may be increased when it is diluted, or when its viscosity is decreased, or when its effective permeability through the bituminous sands is increased.

[00181] Thus, for the solvent to effectively function in the reservoir fluid, its solubility should be considered. The solvent should be sufficiently soluble in oil, or at least some hydrocarbons in the reservoir. For example, a solvent may be more effective if it is more soluble in oil than in water, so that the condensed solvent will be mainly or mostly dissolved in the oil phase.

[00182] Another possible contributing factor is whether the solvent can reduce the viscosity of oil in the reservoir.

[00183] As can be appreciated, a common consideration for selecting the suitable solvent is cost versus benefits.

[00184] A further factor for selecting a mobilizing agent is whether the mobilizing agent can serve as a wetting agent to increase the flow rate of oil or the fluid mixture.
An additional factor is whether the mobilizing agent can act as an emulsifier for forming an oil-in-water emulsion. A further additional factor is whether the mobilizing agent can bring more hydrocarbons into the fluid mixture, thus increasing the fraction of oil carried by the fluid.

[00185] In various embodiments, steam and the solvent may be injected through multiple injection wells. For example, steam may be injected through a horizontal well as described above, but the solvent may be injected through a vertical well or another horizontal well.

[00186] As mentioned earlier, a mixture of solvents may be injected. In an embodiment, a first solvent is initially injected into the reservoir for a first period of time, and then a second solvent is injected into the reservoir for a second period of time after the first period. The second solvent may have a smaller molecular mass than the first solvent. For example, butane may be the first solvent and propane or methane may be the second solvent. The solvent may include a mixture of natural gas liquids.

[00187] During injection of steam and solvent, a reservoir pressure or the injection pressure may be reduced or decreased over time. The reservoir pressure may be reduced to increase the solubility of the solvent in oil.

[00188] During injection, the composition of the injected fluid mixture may be varied over time, both in terms of the solvent or other components and in terms of their concentrations in the mixture.

[00189] In some embodiments, the injection fluid may include a recycled fluid, such as steam or a solvent which is obtained from a reservoir fluid produced from the reservoir. In such cases, water and an injected solvent may be separated from oil and other components in the recovered reservoir fluid, and may be further treated before re-injection into the same reservoir or another reservoir. Further treatment may include purification and heating of the separated water or solvent. Typically, the recovered reservoir fluid may include some methane. Re-injection of produced methane into the reservoir may have some adverse effects. For example, as methane is typically not condensable at reservoir conditions, the methane gas in the vapour chamber may reduce heat transfer efficiency, hinder dispersion of steam and solvent vapour to the vapour chamber front, and reduce solubility of the solvent in oil at the chamber front.
However, it is expected that re-injection of a limited amount of methane would not significantly reduce production performance or efficiency in some embodiments.
For example, it may require additional equipment and operation costs to completely remove methane from a recycled fluid before re-injection into the reservoir. Allowing less than about 1 wt% of methane, or even less than about 3 wt% of methane, in the re-injected fluid may provide improved overall operational or economic efficiency.

[00190] In some embodiments, the solvent may include one or more C1-12 alkanes, a natural gas liquid, a condensate, a diluent, or a mixture thereof. The solvent may possibly include CO2 or H2. The solvent may also include up to 10 wt%
impurities.

[00191] The condensate or diluent may comprise 0-5% C3 alkane, 0-5% iso-C4 alkane, 0-5% n-C4 alkane, 40-50% C5 alkane, 15-25% C6 alkane, 10-20% C7 alkane, 0-15% C8 alkane, or 0-15% C9 alkane. Alternatively, the condensate or diluent may comprise 25-65% C3 alkane, 35-55% iso- and n-C4 alkanes, or 10-20% C5+ alkane.

[00192] In some embodiments, the solvent may be injected with steam in a mixture, where the solvent concentration in the mixture may be between 5 wt%
and 90 wt%, such as 5 wt% to 10 wt% or 50 wt% to 90 wt%. In a specific embodiment, the solvent concentration may be from 55 wt% to 65 wt%. The above weight percentages are based on the total weight of steam and the solvent in the mixture. In other words, the weight ratio of injected solvent to injected steam may be between 1/19 and 9/1, such as 1/19 to 1/9 or 1/1 to 9/1. In a specific embodiment, the weight ratio of injected solvent to injected steam may be between 1.2 and 1.9.

[00193] The amount of solvent gas in the produced fluid is affected by the liquid level of the liquid phase surrounding the production well. Indeed, a higher level of the liquid phase surrounding the production well reduces production of solvent gas, while a lower level of the liquid phase surrounding the production well increases production of solvent gas.

[00194] It was unexpected that solvent gas could be produced through the liquid phase when the liquid level is high since in normal SAGD steam would condense in the liquid phase and be produced as water. This discovery allows for convenient control of solvent gas recovery by adjusting the liquid level of the liquid phase surrounding the production well.

[00195] A skilled person in the art will know that the liquid level surrounding the production well may be altered by, for example, injection rate, injection pressure, flow control devices, pumps, emulsion pressure, completion design, sliding sleeves, etc., or any combination thereof.

[00196] In an embodiment, the flow rate of the fluid in the production well may be adjusted so as to raise or lower the liquid level of the liquid phase surrounding the production well. Accordingly, the flow rate of the fluid may be used to alter solvent gas production and more specifically alter the ratio of produced gas phase to produced liquid phase in the produced fluid.

[00197] For example, the flow rate of the fluid may be adjusted by adjusting the pumping speed of a pump (e.g. ESP) in the production well. An exemplary well completion including an ESP in the production well is illustrated in Fig. 7 and includes concentric tubing. The inner tube 112 allows for emulsion to be pumped to the surface facilities while the outer tube 113 allows for casing gas to flow on its own velocity to the surface facilities. Decreasing the pump speed results in a higher liquid level of the liquid phase surrounding the production well (Fig. 5) and reduced production of solvent in the gas phase. Conversely, increasing the pump speed results in a lower liquid level of the liquid phase surrounding the production well (Fig.4) and increased production of solvent in the gas phase. Therefore, the pump speed may be used to control the ratio of produced gas phase to produced liquid phase in the fluid produced from the reservoir.

[00198] It was also unexpectedly discovered that the solvent gas production rate was quite sensitive to the pump speed. For example, the ratio of produced gas phase to produced liquid phase may be reduced by more than 30% (based on volume) when the pump speed is reduced by less than about 5%, on the basis of daily averages of the production rates.

[00199] In an embodiment, the weight ratio of the produced gas phase to the produced liquid phase in the produced fluid may be from about 1/16 to about 1/5.

[00200] In an embodiment, the weight ratio between produced and injected solvent may be 0.5 ¨ 0.7 for maximum oil rates. In another embodiment, the weight ratio between produced and injected solvent may be between 0 and 0.4 for minimum production and recycling.

[00201] An optimal pump speed for controlling solvent gas production may be determined by varying the pump speed until a sensitive range is identified wherein small changes in pump speed result in significant changes to the ratio of produced gas phase to produced liquid phase in the produced fluid. For example, a reduction in pump speed of less than about 5% resulting in a reduction of the ratio of produced gas phase to produced liquid phase by more than about 30% (based on volume). In addition, the change in pump speed should have a lesser effect on the oil production rate.

[00202] In another embodiment, the flow rate of the fluid may be adjusted by altering the backpressure of the pump in the production well. For example, a choke valve on the surface emulsion line may be altered to maintain a desired backpressure in the production well.

[00203] For example, as illustrated in Fig. 7, a choke valve 111 may be provided downstream of the production well 130 for the liquid (emulsion) line.

[00204] In an alternative embodiment, two choke valves may be used to adjust the flow rates in both the gas line and the liquid line to control the downhole pressure and the fluid flow through the production well. In this embodiment, another choke valve (not shown) may be provided downstream of the production well in the gas line.

[00205] Increasing the backpressure will limit liquid flow resulting in a higher liquid level of the liquid phase surrounding the production well and reduced production of solvent in the gas phase. Conversely, decreasing the backpressure will increase liquid flow resulting in a lower liquid level of the liquid phase surrounding the production well increased production of solvent in the gas phase. Therefore, the backpressure may be used to control the ratio of produced gas phase to produced liquid phase in the fluid produced from the reservoir.

[00206] In an exemplary embodiment, a well pair operating under a SAGD
process may have a backpressure fixed at 2050 kPa and an ESP pump speed at 50-65 Hz while maintaining a temperature difference between the injection well and production well of 5 to 15*c. Upon transitioning from a SAGD process to a solvent-steam process, the pump speed at the fixed backpressure may be reduced as the solvent weight percent increases to raise the liquid level surrounding the production well. If gaseous solvent production increases, the pump speed may be reduced further to raise the liquid level and minimize gaseous solvent production. Alternatively, the backpressure may also be increased to limit the flow rate of the fluid, thus raising the liquid level and limiting gaseous solvent production. For example, at a backpressure of 2050 kPa and an ESP
pump speed of between 38 to 40 Hz, the casing gas flow may be as high as 400 m3/hr and include 80-90% of the injected solvent. By cutting pump speed to 38 Hz, the gaseous solvent production rate may be reduced by up to two thirds.
Alternatively, the backpressure could be fixed at 3400 kPa with an ESP pump speed between 42-46 Hz to control or reduce the gaseous solvent production. In this case, the emulsion flow rate is 6-7 m3/hr.

[00207] The liquid level of the liquid phase surrounding the production well may be approximated by the temperature difference between the injection well and production well. A rule of thumb estimation in the industry suggests that every 10 C of temperature difference between the injection well and production well equates to about 1 metre of liquid level height above the production well.

[00208] In actual well pairs, the horizontal sections of the injection well and production well may not be at the same horizontal level and may vary in vertical height as can be seen in Fig. 8. The dark shaded areas in Fig. 8 represent impermeable regions of the reservoir formation, while light shaded areas represent permeable regions. In FIG. 8, the vertical and horizontal distances are not to scale, as each unit box represents a meter in height and 50 meters in horizontal length. The liquid level is ideally maintained above the most elevated portions of the production well to avoid short circuiting. It should also be recognized that, due to variations in the formation and a number of other factors, the liquid level around the production well can also vary along the length of the production well (not necessarily corresponding to the elevation variation of the production well).

[00209] In an embodiment, the pump speed or backpressure may be adjusted to maintain a liquid level such that the temperature difference between the injection well and production well is between about 20 C and about 80 C, between about 30 C
and about 80 C, between about 30 C and about 60 C, or between about 30 C about 40 C.
The liquid level of the liquid phase therefore may be estimated to be between about 2 m to about 8 m, between about 3 m to about 8 m, between about 3 m to about 6 m, or between about 3 m to about 4 m, respectively, above the production well.

[00210] In an embodiment wherein the solvent comprises propane, the injection temperature may be between about 120 C and about 245 C and the production temperature may be between about 100 C and about 225 C or preferably between about 165 and about 205 C. In an embodiment, the lower end of the production temperature is about 140 C.

[00211] It may be desirable to control solvent gas production via the production well when the produced fluid comprises too much solvent gas. The flow rate of produced fluid may be reduced to increase the liquid level surrounding the production well thereby reducing the amount of produced solvent gas. It is also important that the flow rate of the produced fluid is controlled to ensure the liquid level remains below the injection well.

[00212] It may also be desirable to control solvent gas production in instances where the hydrocarbon recovery process employs solvent recycling. The amount of solvent gas for recycling and reinjection with fresh make-up solvent could be conveniently controlled.

[00213] Control of solvent gas production may also be used to effectively inventory solvent in the reservoir to mitigate adverse solvent price fluctuations.

[00214] In an embodiment, the production rate may be controlled to cycle through level building stages and draining stages. In the level building stage, the production rate is reduced to increase the liquid level around the production well. In the draining stage the production rate is increased to decrease the liquid level of the production well.

[00215] As used herein, the expression "production temperature", or the like, may be the production well heel temperature, average temperature along the production well or temperature at the hottest point in the production well.
Example 1

[00216] Fig. 6 is a graph illustrating solvent production control in an exemplary solvent-steam process over a 100-day period. The data for casing gas flow and oil production rate presented in Fig. 6 are based on daily averages of the production rates.
As can be seen in Fig. 6, small changes in pump speed resulted in significant changes to the casing gas flow but did not significantly affect the oil production rate.

[00217] Fig. 10 shows the instantaneous reduction in casing gas rate after pump speed reduction at day 25. When the speed of the ESP was lowered from 41 Hz to Hz, the casing gas flow instantaneously dropped from 300 m3/hr to 149 m3/hr (see Figs.
9 and 10). The daily average for casing gas produced on that day was 250 m3/hr as seen in Fig. 6. In the prior day, the daily average for the produced casing gas flow was about 323 m3/hr. In the subsequent day after the pump change the produced casing gas daily average was about 193 m3/hr. A decrease of about 23% was observed in the daily casing gas production due to the change in the pump speed. After further reduction in pump speed to 38 Hz, the daily average casing gas production rate was recorded at about 74 m3/hr. Thus, a reduction of about 78% could be achieved in 5 days by reducing the pump speed from 41 Hz to 38 Hz. However, during the same 5 day period, oil production was only reduced by about 32% (based on volume). The emulsion cooled significantly by about 30 C during this process cooling from 165 C to 135 C in 5 days, demonstrating the high liquid level accumulation on top of the producing well which restricted gaseous solvent produced via casing gas.

[00218] At day 85, the pump speed was altered by 2.5% resulting in a reduction of casing gas flow of about 44% (based on volume), on the basis of daily averages of the production rates, over the course of about one week as seen in Fig. 6 and summarized in Table 1. However, emulsion flow (i.e. liquid phase production) was only reduced by about 26% (based on volume), on the basis of daily averages of the production rates.
Table 1.
ESP Casing Current Emulsion T Emulsion Gas Speed Flow Flow Day Hz C t/d m3/hr 85 40.0 124.6 103.0 491.1 86 39.0 118.8 82.5 436.2 87 39.0 117.2 85.9 397.5 88 39.0 116.8 86.4 409.4 89 39.0 116.9 83.5 375.2 90 39.0 114.9 85.4 394.5 91 39.0 117.5 83.5 370.5 92 39.0 122.7 78.3 307.4 93 39.0 121.3 75.4 265.5 94 39.0 121.4 75.7 273.0 Example 2

[00219] Fig. 11 illustrates that the flow rate may be adjusted to maintain the same liquid level surrounding the production well in SAGD and a solvent-steam process, but the solvent-steam process has a higher differential between injection well and production well heel temperatures. In this simulated example, the injection temperature was greater than 235 C and the solvent concentration in the solvent-steam process was 8 wt% based on the total weight of steam and the solvent. The same liquid level in SAGD and the solvent-steam process was achieved, but the production well heel temperature for SAGD was 215 C while production well heel temperature for the solvent-steam process was 175 C.
Example 3

[00220] Simulations were conducted to illustrate optimization of solvent based operations through control of the temperature difference between the injection well and production well. This temperature difference was controlled by the liquid level surrounding the production well (or gas flow rate), which is controlled by pump speed.

[00221] The simulations were based on a model in which propane was used as the solvent and was co-injected with steam. For example, the injection pressure was maintained at 3100 KPa at a temperature of 237 C. When propane was co-injected (8 wt.%), the mixture temperature dropped by three degrees to 234 C. Production was controlled at an optimized bottom hole/ wellhead temperature by adjusting the pump speed which regulates both emulsion and casing gas flow. The operating parameters were optimized in the simulated propane-steam process to achieve 10% rate uplift and 20% cSOR reduction.

[00222] Rate uplift is defined as an annual average difference between the production rates of solvent/steam process vs. SAGD process. For example, Rõ is the average oil production rate in a solvent/steam co-injection recovery process, and RsAGD
is the average oil production rate in a SAGD process from the same reservoir and well configuration, the rate uplift may be calculated as: Rate uplift = (Rss ¨
RSAGD)/RSAGD.
RsAGD may be referred to as the reference baseline rate.

[00223] Fig. 12 shows a correlation between overall gas flow rate and average production well heel temperature for SAGD and a solvent-steam process. The model was history matched at a gas production rate of 2 t/d as a controlling factor.
A 32 C shift in production well heel temperature was observed with propane injection at 8 wt%. In comparison solvent-steam wells can be operated at a much cooler temperature then SAGD wells for the same gas production. Presence of solvent (propane) results in a dense gas phase which allows the solvent-steam well to achieve the same gas production limit (as SAGD) at a much cooler temperature. Variation in slope of gas production with heel temperature was also observed for SAGD and SAP processes suggesting the reduction in produced gas is more sensitive to SAGD than to SAP

process.

[00224] The simulation results in Fig. 13 indicate that there is a positive linear correlation between iSOR and cSOR in the simulated propane-steam process. The simulation results in Fig. 14 indicate that there is a negative correlation between rate uplift and the cSOR in the simulated propane-steam process. The rate uplift is the percentage increase in the oil production rate. The production well heel temperature may be selected based on the desired cSOR reduction and rate uplift. For example, from Figs. 13 and 14 it can be seen that to achieve 20% reduction in cSOR and 10% in rate uplift, the production well heel temperature in the simulated propane-steam process should be between about 182 C and about 195 C. Fig. 15 better shows the effects of the production well heel temperature on the cSOR and the rate uplift, from which it can also be observed that an optimum range for production well heel temperature is between 182 C -195 C (shown by the shaded area) to achieve the above noted cSOR
reduction and rate uplift.

[00225] Given the above results, in an embodiment of the present disclosure, the fluid flow rate in the production well may be adjusted to control the production well heel temperature so it is set in a range of 182 C to 195 C.
CONCLUDING REMARKS

[00226] Various changes and modifications not expressly discussed herein may be apparent and may be made by those skilled in the art based on the present disclosure. For example, while a specific example is discussed above with reference to a SAGD process, some changes may be made when other recovery processes, such as CSS, are used.

[00227] It will be understood that any range of values herein is intended to specifically include any intermediate value or sub-range within the given range, and all such intermediate values and sub-ranges are individually and specifically disclosed.

[00228] It will also be understood that the word "a" or "an" is intended to mean "one or more" or "at least one", and any singular form is intended to include plurals herein.

[00229] It will be further understood that the term "comprise", including any variation thereof, is intended to be open-ended and means "include, but not limited to,"
unless otherwise specifically indicated to the contrary.

[00230] When a list of items is given herein with an "or" before the last item, any one of the listed items or any suitable combination of two or more of the listed items may be selected and used.

[00231] Of course, the above described embodiments are intended to be illustrative only and in no way limiting. The described embodiments are susceptible to many modifications of form, arrangement of parts, details and order of operation. The invention, rather, is intended to encompass all such modification within its scope, as defined by the claims.

Claims (23)

WHAT IS CLAIMED IS:

1. A method for producing hydrocarbons from a subterranean reservoir, comprising:
injecting steam and a solvent into the reservoir to mobilize viscous hydrocarbons in the reservoir, wherein mobilized hydrocarbons drain towards a production zone, the production zone comprising a liquid phase comprising water and mobilized hydrocarbons, and a gas phase comprising the solvent;
producing a fluid comprising the liquid phase and the gas phase, through a production well, the production well penetrating the liquid phase in the production zone;
controlling a ratio of produced gas phase to produced liquid phase in the produced fluid, wherein the controlling comprises adjusting a flow rate of the fluid in the production well so as to raise or lower a liquid level of the liquid phase surrounding the production well, thus reducing or increasing flow of the solvent in the gas phase into the production well through the liquid phase in the production zone.

2. The method of claim 1, wherein the fluid is pumped through the production well and the flow rate is adjusted by altering a pump speed in the production well.

3. The method of claim 2, wherein the pump speed is reduced by less than about 5% to reduce the ratio of produced gas phase to produced liquid phase by more than about 30% based on volume.

4. The method of claim 1, wherein the flow rate is adjusted by altering a downhole pressure in the production well.

5. The method of claim 4, wherein altering the downhole pressure comprises adjusting a valve downstream of the production well.

6. The method of claim 1, wherein the flow rate is controlled to maintain the production temperature of the produced fluid at about 20°C to about 80°C
below the injection temperature.

7. The method of claim 6, wherein the solvent comprises propane, the injection temperature is about 120°C to about 245°C and the production temperature is about 100°C to about 225°C.

8. The method of claim 7, wherein the production temperature is about 165°C to about 205°C.

9. The method of claim 7, wherein the production temperature is at least about 140°C.

10. The method of any one of claims 6 to 9, wherein the production temperature is a temperature at a heel of the production well.

11. The method of claim 1, wherein the flow rate is controlled such that the liquid level is about 2 m to about 8 m above the production well.

12. The method of claim 1, wherein the flow rate is controlled such that the liquid level is about 3 m to about 4 m above the production well.

13. The method of any one of claims 1 to 12, wherein the produced fluid comprises an emulsion.

14. The method of any one of claims 1 to 12, wherein the gas phase further comprises at least one of steam and a non-condensable gas.

15. The method of any one of claims 1 to 14, wherein the mobilized hydrocarbons drain downward into the production zone.

16. The method of any one of claims 1 to 15, wherein the weight ratio of the gas phase to the liquid phase in the produced fluid is from about 1/16 to about 1/5.

17. The method of any one of claims 1 to 16, comprising adjusting the flow rate of the fluid in the production well to set the production well temperature at 182*c to 195*c.

18. The method of any one of claims 1 to 17, wherein the weight ratio of injected solvent to injected steam is 1/19 to 9/1.

19. The method of any one of claims 1 to 17, wherein the weight ratio of injected solvent to injected steam is 1.2 to 1.9.

20. The method of any one of claims 1 to 19, wherein the flow rate is adjusted so that the weight ratio of injected solvent to produced solvent is 0.5 to 0.7.

21. The method of any one of claims 1 to 19, wherein the flow rate is adjusted so that the weight ratio of injected solvent to produced solvent is 0.4 or lower.

22. The method of any one of claims 1 to 21, wherein the solvent comprises one or more C1-12 alkanes, a natural gas liquid, a condensate, a diluent, or a mixture thereof.

23. The method of any one of claims 1 to 22, wherein the liquid phase comprises water, mobilized hydrocarbons and the solvent.