CA3046390A1 - Injection control in steam-solvent assisted process for hydrocarbon recovery - Google Patents

Abstract

In a process of recovering hydrocarbons from a subterranean reservoir with co-injection of steam and solvent, the fluid flow rate of steam is determined according to a method in which a first stream (steam) and a second stream (solvent) is mixed to form a third stream (mixture of steam and solvent); a temperature in the third stream is detected; and the steam flow rate is determined based on the detected temperature and a correlation between the detected temperature and the steam flow rate.

Description

INJECTION CONTROL IN STEAM-SOLVENT ASSISTED PROCESS FOR
HYDROCARBON RECOVERY
FIELD
[0001] The present disclosure relates generally to hydrocarbon recovery from subterranean reservoirs, and particularly to injection control in in situ steam-solvent hydrocarbon recovery.
BACKGROUND

[0002] Steam and a solvent can be co-injected into a subterranean reservoir of bituminous sands (also commonly referred to as oil sands) to assist, drive, or aid hydrocarbon recovery from the reservoir (referred to herein as a steam-solvent recovery process).

[0003] Typically, in a steam-solvent recovery process a desired ratio of solvent to steam (solvent-to-steam ratio, SSR) in the injection stream and the desired injection temperature and pressure are pre-determined, and the steam and solvent are mixed according to these pre-determined values before injection by separately controlling the injection rates of steam and the solvent so that the ratio of the solvent injection rate to the steam injection rate is the same as the desired solvent-to-steam ratio in the injection mixture. For example, for a given solvent injection rate (e.g. 15 t/d), the steam injection rate may be selected and controlled (e.g. selected to be 35 t/d) to obtain a weight percentage of the solvent (e.g. 30 wt% solvent) in the injection mixture that corresponds to the desired SSR (e.g. SSR=3:7). The ratio of solvent to steam (SSR) may be based on weight/mass, volume, mole, or a combination thereof, and may be expressed or indicated in the form of relative ratios, or percentages such as weight percentages, volume percentages, or molar percentages.

[0004] In a typical arrangement in a steam-solvent recovery process, an input stream of steam and an input stream of solvent may be provided through separate pipelines and mixed at a junction of the pipelines at surface before injection into the injection well, where the flow rate in each of the input pipeline is regulated to achieve a pre-selected target flow rate. The target flow rates are typically pre-determined according to the desired ratio of solvent to steam in the injection stream and injection temperature/pressure. For example, the target values of the required flow rates in the steam input pipeline and the solvent input pipeline for a given weight ratio of solvent to steam and given injection temperature can be pre-determined. A flow meter and one or more flow control valves are usually installed in each input pipeline for measuring and adjusting the flow rate in the pipeline. The flow control valve is controlled to adjust the flow rate based on the measured flow rate from the flow meter. For instance, when the measured flow rate is lower than the target value, the flow control valve is opened more to increase the flow rate until the flow rate reaches the target value.
When the measured flow rate is lower than the target value, the flow control valve is closed more to decrease the flow rate until the flow rate reaches the target value.
SUMMARY

[0005] It has been recognized that using the flow meter to control the steam injection rate may be inconvenient in some situations. For instance, the flow meter may need to be replaced during operation for various reasons, and replacing the flow meter can cause delay in production and incur significant costs.

[0006] It has also been recognized that it is not necessary to use a flow meter to measure the flow rate of steam in a steam-solvent recovery process, and the flow rate of the input steam stream may be conveniently controlled based on a measured temperature in the mixed steam and solvent to be injected.

[0007] Thus, an aspect of the present disclosure relates to a method of injecting steam and solvent into a subterranean reservoir to assist recovery of hydrocarbons therefrom. In this method, a first stream comprising steam and a second stream comprising a solvent is mixed to form a third stream comprising steam and the solvent for injection into the reservoir. A temperature in the third stream is detected. The flow rate of the first stream is controlled based on the detected temperature. The third stream is injected into the reservoir. The temperature in the third stream may be detected immediately after the mixing of the first stream and the second stream. The flow rate of the first stream may be determined indirectly based on the detected temperature without directly measuring the flow rate with a flow rate meter.
In an embodiment, the first stream may be supplied for mixing through a fluid conduit, which includes a flow meter for measuring a fluid flow rate through the fluid conduit within a particular range, but the actual flow rate of the first stream is outside this particular range. For example, the range of the flow meter may have a lower limit, and the flow rate of the first stream is below the lower limit. The method may include correlating the temperature in the third stream with the flow rate in the first stream. A
correlation between the temperature in the third stream and the flow rate in the first stream may be predetermined. The predetermined correlation may be stored and available to a controller for controlling the flow rate of the first stream. The steam in the first stream may have substantially constant pressure, temperature, and steam quality. The solvent in the second stream may have substantially constant pressure and temperature and may be supplied at a substantially constant rate. Controlling of the flow rate may comprise increasing the flow rate of the first stream when the detected temperature decreases, and decreasing the flow rate of the first stream when the detected temperature increases. The flow rate may be controlled to maintain the temperature in the third stream at a target temperature. The target temperature may be determined based on a target ratio of solvent to steam in the third stream.
The third stream may be injected into the reservoir through an injection well penetrating the reservoir.

[0008] In another aspect, a system for injecting steam and solvent into a subterranean reservoir is provided to assist recovery of hydrocarbons therefrom. The system comprises a first conduit for supplying a first stream comprising steam; a second conduit for supplying a second stream comprising a solvent; a third conduit connected to the first and second conduit for mixing the first and second streams to form a third stream and supplying the third stream comprising steam and the solvent for injection into the reservoir; a temperature sensor associated with the third conduit for detecting a temperature in the third stream; a flow regulator in the first conduit for regulating a flow rate of the first stream in the first conduit; and a controller connected to the temperature sensor and the flow regulator for controlling the flow regulator to adjust the flow rate, the controller configured and programmed to control the flow regulator based on the detected temperature. The system may comprise a steam source connected to the first conduit for supplying steam at constant temperature, pressure and steam quality. The system may comprise a solvent source connected to the second conduit for supplying the solvent at constant temperature and pressure at a constant rate. The temperature sensor may comprise a thermocouple or a resistance thermometer. The flow regulator may comprise a valve. The controller may comprise a processor or a computer. The third conduit may be in fluid communication with an injection well penetrating the reservoir for injecting the third stream into the reservoir through the injection well.

[0009] In a further aspect, there is provided a method of determining a fluid flow rate, which comprises mixing a first stream and a second stream to form a third stream, wherein the first stream flows at a first flow rate and the second stream flows at a second flow rate; detecting a temperature in the third stream; and determining the first flow rate based on the detected temperature and the second flow rate.

[0010] In another aspect, there is provided a method of regulating a fluid flow rate, comprising: mixing a first stream and a second stream to form a third stream, wherein the first stream has a first temperature and the second stream has a second temperature different from the first temperature; detecting a third temperature in the third stream; and adjusting the flow rate of the first stream in response to the detected third temperature to control the third temperature in the third stream.

[0011] 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

[0012] In the figures, which illustrate, by way of example only, embodiments of the present disclosure:

[0013] FIG. 1 is a schematic side view of a hydrocarbon reservoir and a pair of wells penetrating the reservoir for recovery of hydrocarbons.

[0014] FIG. 2 is a schematic partial end view of the reservoir and wells of FIG. 1.

[0015] 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.

[0016] FIG. 4 is schematic block diagram of a possible arrangement in the surface injection facility shown in FIG. 1, according to an embodiment of the present disclosure.

[0017] FIG. 5 is a flow chart for an example control process of the injection facility of FIG. 4, according to an embodiment of the present disclosure.

[0018] FIG. 6 is a schematic block diagram of a control system for performing the control process of FIG. 5, according to an embodiment of the present disclosure.

[0019] FIG. 7 is a schematic partial view of an example arrangement in a surface injection facility.
DETAILED DESCRIPTION

[0020] Selected embodiments of the present disclosure relate to methods of hydrocarbon recovery from a reservoir of bituminous sands assisted by co-injection of steam and solvent as mobilizing agents into the reservoir (referred to as steam-solvent recovery processes), and methods of control injection of steam and solvent into the reservoir.

[0021] In overview, it has been recognized by the present inventor(s) that the injection rate of steam in such a process may be conveniently controlled in response to a detected temperature in the injection mixture of steam and solvent, without the need to directly measuring the flow rate of steam before mixing with the solvent.

[0022] Conveniently, the injection control can be carried out without an operational flow meter installed in the steam supply line, or directly measuring the steam flow rate.

[0023] A control process described herein allows-continued recovery of hydrocarbons without interruption when the steam injection rate needs to be decreased or increased to outside the operational range of an installed flow meter in the steam supply line, as it is not necessary to replace the installed flow meter with a new flow meter with a different operational range.

[0024] A control process described herein also allows convenient automated control of the steam injection rate.

[0025] Further, it is possible to estimate the steam flow rate based on the detected temperature in the mixture of steam and solvent.

[0026] An example embodiment of the present disclosure relates to a steam-solvent recovery for recovering hydrocarbons from a subterranean reservoir as illustrated in FIGS. 1, 2 and 3.

[0027] FIGS. 1-3 schematically illustrate 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 steam-assisted-gravity-drainage (SAGD) operations, or a conventional steam-solvent recovery.

[0028] The reservoir formation 100 contains viscous or heavy hydrocarbons below an overburden 110. Under the native conditions before any treatment, a reservoir of bituminous sands is typically 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. 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.

[0029] As used herein in various embodiments, the term "reservoir" refers to a subterranean or underground formation containing recoverable hydrocarbons (oil); and the term "reservoir of bituminous sands" refers to such a formation wherein at least some of the hydrocarbons are viscous or immobile in their native state, and are disposed between or attached to sands.

[0030] 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, "viscous hydrocarbons", "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 the native in situ reservoir temperature. In this specification, the terms "hydrocarbons", "oil", and "bitumen" may be used interchangeably unless otherwise specified. Depending on the in situ density and viscosity of the hydrocarbons, the hydrocarbons may include, for example, a combination of oil, heavy oil, extra heavy oil, and bitumen. The term "oil" when used generally may include "light"
oil, hydrocarbons mobile at typical reservoir conditions. Heavy crude oil, for example, may include 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. Extra heavy oil, for example, may have a viscosity of over 10,000 mPa.s and about 10 API Gravity. The API Gravity of bitumen typically ranges from about 12 to about 6 or about 70 and the viscosity of bitumen is typically greater than about 1,000,000 mPa-s.

[0031] In example embodiments, 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 are drilled and completed for producing hydrocarbons from reservoir formation 100. As depicted in FIG. 1, the well pair may be positioned below and away from the overburden 110 and near the bottom of the pay zone or geological stratum in reservoir formation 100.

[0032] As is typical in a SAGD operation, 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. In different embodiments, the distance between the injection well 120 and the production well 130 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 "injector" and "producer", respectively.

[0033] 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, including steam and at least one solvent, into injection well 120, and will be further described in more detail below. 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.

[0034] As better illustrated in FIG. 4, the surface facility 140 includes a steam source such as a steam generation plant 402, and a supply line such as fluid pipe 404 connected to the steam generation plant 402 for supplying steam to injection well 120 for injection into the reservoir formation 100. A fluid flow regulator such as a valve 406 is provided in the fluid pipe 404 for regulating the fluid flow rate in the fluid pipe 404.
Devices and equipment for driving steam flow and measuring steam properties such as steam temperature and pressure may be provided in the steam generation plant 402 or along pipe 404, but for simplicity these devices and equipment are not shown in FIG. 4, as details of these devices and equipment are not necessary for understanding the present disclosure.

[0035] The surface facility 140 also includes a solvent source such as a solvent tank 412 and a supply line such as fluid pipe 414 for supplying the solvent to the injection well 120 for co-injection with steam. A flow regulator such as a valve 416 is provided in pipe 414 for regulating the fluid flow in pipe 414. A flow meter 418 is also provided to measure the fluid flow rate through pipe 414. Optionally, a pump 420 is provided to drive the fluid flow in pipe 414.

[0036] Valves 406, 416 may be any suitable fluid flow control valves for use under the particular operation conditions in a given embodiment. Existing valves used in steam and solvent supply lines in conventional steam-solvent recovery processes may be used. Valves 406 and 416 may be of the same type or be different, and may be selected so that valve 406 is suitable for controlling steam flow at the expected steam temperature and pressure ranges, and valve 416 is suitable for controlling flow of the particular solvent to be used.

[0037] Flow meter 418 may be any suitable fluid flow meter.

[0038] Optionally, surface facility 140 may include a heating facility (not separately shown) for pre-heating the solvent before injection.

[0039] Heating devices or heat insulation (not separately shown) may also be provided in one or more of the supply lines (e.g. pipes 404 and 414) for control or maintain the temperatures of the supplied fluids such as steam and solvents.

[0040] Both pipes 404 and 414 are connected to a mixing junction 422, which is connected to the injection well 120 through an input pipe 424, for mixing the steam and solvent before the mixture of steam and the solvent is injected into the reservoir formation 120.

[0041] As depicted, the mixing junction 422 is located at surface. However, in different embodiments, the mixing junction 422 may be located at surface, near or in the well head of injection well 120, or inside a section of the injection well 120. The input pipe 424 may be a separate pipe connected to the injection well, or may be a part of the injection well 210.

[0042] A temperature sensor 426 is provided at the mixing junction 422 or downstream of the mixing junction 422 along the input pipe 424 for measuring the temperature in the mixture of steam and the solvent to be injected. The temperature sensor 426 may be any suitable sensor for detecting and measuring the fluid temperature in the mixing junction 422 or in the input pipe 424 near the mixing junction 422. For example, the temperature sensor may be selected from thermocouples, resistance temperature detectors (RTD), thermistors, thermometers, infrared temperature sensors, digital temperature sensors such as semiconductor based temperature sensing integrated circuit (IC), and the like. When the mixing junction 422 is located downhole in the injection well 120, a distributed temperature sensing (DTS) device may also be used to detect the temperature or temperature changes in the mixture of steam and the solvent.

[0043] 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.

[0044] While not expressly depicted, it should be understood that each supply line may be connected to a corresponding source of supply, which may include, for example, 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.

[0045] Surface facility 150 may include a fluid transport pipeline for conveying produced fluids to a downstream facility (not shown) for processing or treatment.
Surface facility 150 also includes necessary and optional equipment (not separately shown) for producing fluids from production well 130, as can be understood by those skilled in the art.

[0046] 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.

[0047] 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.

[0048] 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 optionally recovery, of a selected solvent to be used in a steam-solvent recovery process as will be disclosed below.

[0049] 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.

[0050] 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 100 during a recovery process where a vapour chamber 360 has formed.

[0051] As illustrated, injection well 120 and production well 130, each have a casing 220, 230 respectively. An injector tubing 225 is positioned in injector casing 220 and connected to input pipe 424 for receiving the mixture of steam and the solvent to be injected into the reservoir formation 100. The use of injector tubing 225 can be understood by those skilled in the art, and will be described below.

[0052] 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.

[0053] As depicted in FIG. 3, injector casing 220 includes a slotted liner along the horizontal section of well 120 for injecting fluids into reservoir formation 100.

[0054] 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.

[0055] 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.

[0056] In operation, wells 120 and 130 may be operated to produce hydrocarbons from reservoir formation 100 according to a process disclosed herein.

[0057] 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.

[0058] Alternatively, steam and a solvent may be co-injected at the start of the production stage after the start-up stage.

[0059] 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.

[0060] Steam is supplied by steam generator 402 to junction 422 through pipe 404, and a solvent such as propane is supplied by solvent tank 412 to junction 422 through pipe 414, as illustrated in FIG.4. The steam flow may be driven by steam generator 402 and regulated by valve 406. The solvent flow may be driven by pump 420 and regulated by both valve 416 and pump 420. The solvent may be supplied to junction 422 in the liquid phase or gas phase, or in both phases. The solvent may be compressed during storage. In an embodiment, the solvent may be supplied to pipe 414 as a liquid. In a different embodiment, the solvent may be stored in a liquid state and supplied to pipe 414 as a vapor, or heated and vaporized in pipe 414 before the solvent is supplied to junction 422. The solvent flow rate is measured by flow meter 418. The temperature (T) in the mixed stream and solvent after junction 422 is detected by temperature sensor 426.

[0061] For steam-solvent co-injection, it is often necessary or desirable to control the solvent-to-steam ratio (SSR) in the injection stream for optimal production performance or other considerations.

[0062] As discussed earlier, it is possible in some cases to measure the flow rate of the input steam stream and the flow rate of the input solvent stream separately using flow meters installed in the input pipes 404 and 414 respectively, and regulate the flow rates using flow valves 406 and 416 to obtain the target SSR. For such a control process to work properly, a functional flow meter with the appropriate flow rate detection range is required for measuring the flow rate in pipe 404, and for measuring the flow rate in pipe 414. As depicted, a flow meter is not shown in the pipe 404 for the steam stream, in which case, this process of control is not possible. Even if a flow meter is installed in pipe 404, if at least some of the desired steam flow rates are outside the operation range of the flow meter, this process of control is also not adequate. It may be inconvenient or time-consuming to replace the existing flow meter with a flow meter with suitable detection range.

[0063] However, according to an embodiment of the present disclosure, the steam flow rate (R) in pipe 404 may be controlled with a control process such as process S500 illustrated in FIG. 5. It should be noted that the order of some of the actions described below with regard to process S500 may be rearranged without changing the result, as can be understood by those skilled in the art.

[0064] At S510, the target mixture temperature (Ti) is obtained or determined.

[0065] The target mixture temperature Tt may be determined based on the desired or target SSR in the injection mixture in pipe 424. For example, for given properties of the steam and solvent supplied by the steam and solvent sources (e.g. steam generator 402 and solvent tank 412), and a given target SSR (e.g., expressed as a target weight percentage of the solvent), the expected temperature in the steam-solvent mixture can be calculated as a function of the SSR.

[0066] For example, in a simple case, the temperature of a mixture of two fluids may be calculated as follows in Equation (1), assuming there is no phase change (e.g., no evaporation or condensation) and no other net energy loss/gain in the system during mixing:
1711 c1 4- M2 C2 T2, (1) where "m," represents the mass of each input fluid "i", "c" represents the specific heat of the input fluid, "7-1" represents the temperature of the input fluid before it is mixed with the other fluid, and "Tfinar is the temperature of the mixture of the two fluids.

[0067] For any given SSR (= Msolventdrnsteam = rsolventdrsteam), Equation (1) may be rewritten as:
Tr = [(rsolvenarstearrd C1 T1 + C2 T2,] rsteam = [(SSR) c/ T1 + c2 T2,) rsteam, (2) where rsolventi and rsteam are the injection rate of solvent and steam respectively.

[0068] Thus, in order to determine Tt, a target SSR (SSR) in the injection stream in pipe 414 may be determined. The SSR may be determined in consideration of a number of factors as will be understood by those skilled in the art, and further explained below.

[0069] As some flow Characteristics and thermodynamic properties of steam and solvent flows in pipe 404 and 414 can affect the dependency of Ton SSR, the actual relevant flow characteristics and thermodynamic properties may also be determined or obtained. For example, the steam temperature and pressure and steam quality may be measured or already known based on information obtained from the steam generation process at steam generator 402. It is also possible to measure actual steam temperature and pressure in pipe 404 using suitable temperature and pressure sensors (not shown) installed in pipe 404. The solvent temperature and pressure may be determined based on the storage temperature and pressure of the solvent in storage tank 412, but may also be measured in pipe 414 using suitable sensors (not shown). The flow rate of the solvent stream in pipe 414 can be directly measured using flow rate meter 418. Some of these quantities or operation parameters may be obtained based on estimation or modeling and do not need to be directly measured in some embodiments. For example, the flow rate of the solvent may be estimated based on the pumping speed of pump 420 when the flow meter 418 is omitted.

[0070] As can be appreciated by those skilled in the art, the target temperature Tt at temperature sensor 426 can be determined based on the target SSR (SSR), and the relevant flow and thermodynamic characteristics and properties determined/obtained as described above. For example, a person skilled in the art would understand how to calculate the target temperature Tt for a given SSR (on the basis of weight, volume, or molar percentages) and the relevant flow and thermodynamic information of the input streams. For example, the temperature of the mixture may be affected by the temperatures of the input steam and solvent, the SSR (or in weight/molar percentages of the solvent) in the mixture, the steam quality and the phase(s) of the input solvent and the phase(s) of the solvent in the mixture. As can be understood, the SSR
is directly dependent on the flow rates of input steam and solvent.

[0071] The target temperature Tt may be previously known, and may be a constant over a period of time, but may also be dynamically determined in real time from time to time, continuously, at regular intervals, or periodically based on detected or other input values that may fluctuate or change over time.

[0072] It is also possible to determine the correlation between the steam flow rate R
in pipe 404 and the temperature (T) in pipe 414 based on the known flow and thermodynamic characteristics/properties of the input streams. This correlation may be calculated based on a theoretical or a simulation model, or may be empirically determined based on experimental or field data, or may be based on both. For example, the correlation may be completely based on calculation using known flow dynamic and thermodynamic relationships and measured input data. The correlation may be completely based on testing using direct flow rate measurements under the same or similar flow and thermodynamic conditions. Some correlation information may be extrapolated from calculations or testing data for higher or lower flow rates.

[0073] For a given target SSRt, the target temperature Tt and target steam flow rate (Rt) corresponding to the target SSRt can be determined based on the correlation.

[0074] Optionally, a correlation between the temperature in pipe 414 as detected by sensor 426 (T) and the steam flow rate (R) in pipe 404 may be obtained or determined.

[0075] This correlation between T and R may be already known to the operator, may be pre-determined once before or during process S500, or may be determined repeatedly during process S500, as will be further discussed below. The correlation may be expressed as a formula (e.g. R = f (T), where "f' represents a mathematical function), a correlation (mapping) table or the like, and may be presented to the operator by any visual devices or calculated by a computer in real-time using an algorithm or routine.

[0076] For example, the correlation between T and R may be determined based on the relevant flow and thermodynamic characteristics of the steam flow and solvent flow in pipes 404 and 414. Relevant flow and thermodynamic characteristics of a flow may include the temperature, pressure, and flow rate, as wells the phase state or quality of the fluid (e.g. vapor or liquid). For a flow of saturated steam, the steam quality is relevant in this context as the steam quality is related to the total enthalpy of the steam stream and can affect the heat transfer and resulting temperature in the steam-solvent mixture after the steam and solvent is mixed. Steam quality refers to the proportion of steam (vapor) in a saturated mixture of steam (vapor) and condensate water (liquid).

[0077] An example of a mapping or correlation table showing the correlation between R and T (and SSR) can be found in TABLE I in the Examples below.

[0078] At S510 and S520, steam and the solvent can be continuously supplied to pipe 424 at junction 422 at the given solvent flow rate and an initial (unknown) steam flow rate, which may be typically below or slightly higher than the target steam flow rate (Rt), and at S520, the actual mixture temperature Ta in pipe 424 is detected at sensor 426.

[0079] At S530, the steam flow rate R in pipe 404 is adjusted based on the detected Ta, and the target temperature T.

[0080] For example, the difference (AT) between the detected temperature Ta and the target temperature Tt in pipe 424 may be calculated, where AT = Ta ¨ T.

[0081] If AT < 0, more steam is required to provide the target SSRt, the steam flow rate R in pipe 404 is increased by opening up the flow valve 406.

[0082] If AT > 0, less steam is required to provide the target SSRt, the steam flow rate R in pipe 404 is decreased by closing down the flow valve 406.

[0083] If AT = 0, or when AT is within an acceptable range, the steam flow rate does not need to be adjusted, and the steam flow rate R in pipe 404 may be maintained at a constant level, i.e., at the target temperature.

[0084] In practice, the temperature response to the steam flow rate adjustment may not be instantaneous, and a delay time may be required after any adjustment of the steam flow before the temperature T in pipe 424 is stabilized. For more accurate flow adjustments, AT should be calculated based on Ta detected at a time when the temperature T in pipe 424 is substantially stable.

[0085] The process from S510 to S530 or from S520 to S530 may be repeated until the co-injection operation is terminated or suspended, or the control process is no longer needed in the recovery process.

[0086] As can be appreciated by those skilled in the art, when the steam flow rate R
is adjusted to provide the target temperature Tt, it is expected that the SSR
in the injection stream in pipe 424 should be the corresponding target SSR, or is close to the target SSR t within an acceptable tolerance range. Therefore, the process S500 in effect adjusts the steam flow rate R to reach the target SSRt based on the detected Ta and a known correlation between R and SSR as reflected through Tt and the correlation between the mixture temperature and the steam flow rate.

[0087] As is apparent from the above description of process S500, to adjust the steam flow rate to control the SSR in the injection stream, it is not necessary for the operator of the surface facility 140 to know the exact flow rate in pipe 404, or how the flow rate R is directly correlated to SSR. It is sufficient that the corresponding target temperature in the injection mixture is known, which may be obtained based on the correlation between the SSR and T, since the correlation between SSR and T is dependent on R.

[0088] Process S500 may be performed manually, or automatically, or partially automatically.

[0089] For example, a control system such as the system 600 illustrated in FIG. 6 may be used to perform process S500.

[0090] As depicted, system 600 includes a controller 602, which may be connected to steam generator 402, valve 406, pump 420, valve 416, flow meter 418 and temperature sensor 426, for controlling the operation of valves 406, 416, and optionally steam generator 402. Controller 602 may optionally be connected to input devices or sensors (not shown) that can provide data or signal indicative of the properties of the solvent, such as temperature and other information, stored in solvent tank 412. The connection between any two devices may be wired or wireless, and may be direct or through one or more intermediate communication or control devices, as can be understood by those skilled in the art.

[0091] Controller 602 may include one or more processors such as microprocessors or computing units such as one or more central processing units (CPU) or specialized processing circuits units. In some embodiments, a general purpose computer may be used, and is specifically configured and programed to perform the some of the functions and methods described herein.

[0092] For example, in some embodiments, system 600 may include a PID
(proportional integral derivative) controller for controlling temperature, which is connected to sensor 426 to receive the detected temperature as a feedback input, and outputs a control signal to close or open valve 406 as the control element.
The target temperature value of Tt may be used as the set-point. The PID may be a digital PID or analog PID. In other embodiments, a PD (proportional-derivative) or PI
(proportional-integrated) controller may be used to control the valve 406 based on the detected temperature, depending on the particular application.

[0093] In some embodiments, a programmable controller such as programmable logic controller (PLC) may be included in system 600. A programmable automation controller (PAC) may also be included in system 600.

[0094] In some embodiments, system 600 may be configured as a distributed control system (DCS), and may include a supervisory control computer and a number of controller or control units.

[0095] System 600 may also be configured to provide advanced process control (APC). For example, system 600 may be configured to provide multivariable model predictive control (MPC), including nonlinear MPC. The APC system may be based in part on inferential measurements of some variables, such as one or more of the temperature and pressure of steam in pipe 404, the temperature of the solvent in pipe 414, and the flow rate of the solvent in pipe 414.

[0096] System 600 may be configured to provide continuous control of valve 406. It is also possible in some embodiments that system 600 is configured and programmed to provide sequential control where valve 406 is controlled and adjusted in time- or event-based automation sequences. For example, a triggering event for an automated control sequence may be a change of the target SSRt due to process considerations or any other reasons, a change in the solvent supply (e.g., batch change, truck change, temperature or flor rate change or the like), a change in the steam supply (e.g., a temperature or pressure change, or a change in steam quality), or the like. An automated control sequence may also be started at pre-defined times, or after a given time interval, or at regular time intervals.

[0097] System 600 and controller 602 may also be configured and programmed to provide simulation-based control or optimization of the control of valve 406 for controlling the target temperature Tt, and ultimately the SSR in the injection stream in pipe 424.

[0098] Suitable controllers may include controller or control systems available from HoneywellTM under the brand name UNISIMTm.

[0099] One or more reservoir simulation algorithms or software with fluid transport and heat transfer calculations may be used to provide used to provide needed information for control.

[00100] As depicted in FIG. 6, system 600 may also include a computer or processor readable storage media, such as memory 604, for storing both processor executable instructions and data needed to perform the control process S500 and optionally other functions or tasks. Memory 604 may include any suitable computer memory devices or storage devices. In particular, memory 604 may store thereon processor executable instructions, which when executed by a processor causes controller 602 to perform the control process S500.

[00101] System 600 may further include input/output (I/O) interface devices, communication devices (not separately shown) for communication with other connected devices, and for receiving input from a user and for outputting control signals or presenting information to the user.

[00102] In particular, during operation, control system 600 may receive input from a user for determining the target SSRt. Control system 600 may also communicate with the steam generator 402 or devices associated with the steam generator 402 to obtain operation parameters and information about the input steam, such as its temperature, pressure, steam quality, and the like.

[00103] If controller 602 is connected to input devices or sensors (not shown) associated with the solvent source or a solvent transportation line, such as the solvent tank 412 or pipe line 414, controller 602 may receive data or signal indicative of the properties of the solvent, such as temperature and other information, stored in the solvent source such as solvent tank 412, or the transported through the transportation line such as pipe line 414. Alternatively, such information about the solvent may be input by a user or operator.

[00104] Control system 600 may further communicate with flow meter 418, or optionally pump 420, to obtain the flow rate of the solvent stream in pipe 414.

[00105] Control system 600 may communicates with temperature sensor 426 directly or indirectly, through wired or wireless connections, to receive the temperature feedback from temperature sensor 426. Control system 600 may receive a digital or analogue signal from temperature sensor 426.

[00106] Optionally, control system 600 may be configured and programmed to receive an input of the target SSRt, and in response to receiving the target SSRt, determine the corresponding target Tt in pipe 424 based on the target SSRt and the current flow and thermodynamic parameters and characteristics, such as by calculation or by searching a data structure (e.g. mapping table) stored in system 600.
Optionally, system 600 may be configured and programmed to receive an input from a user or another device that indicates the target T.

[00107] System 600 may be configured and programmed to determine a correlation between the steam flow rate in pipe 404 and the temperature in pipe 414 based on stored information including the flow and thermodynamic parameters and characteristics described herein.

[00108] To better illustrate and understand how the target SSR (Rt) or target temperature (Tt) may be initially selected or set, an example recovery process is described below by way of background with reference to the well arrangement shown in FIGS. 1-3.

[00109] In an example recovery process, reservoir formation 100 may be 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, 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 injector casing 220 and injector 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.

[00110] 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.

[00111] Once fluid communication between injection well 120 and production well 130 has been achieved, oil (hydrocarbon) 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 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.

[00112] As the injected fluid heats up formation 100, viscous and 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 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 as is known to those skilled in the art.

[00113] 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. The fluid mixture generally drains downward along the edge of vapour chamber 360 towards the production well 130.

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.

[00114] 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 injectors and producers may be optimized for establishing start-up or based on reservoir conditions.

[00115] 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 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 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.

[00116] 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.

[00117] 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.

[00118] 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.

[00119] 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.

[00120] 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.

[00121] 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.

[00122] 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.

[00123] During a period in at least the production stage, steam and the solvent are co-injected into the reservoir to assist production and enhance hydrocarbon recovery.

[00124] 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.

[00125] 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.

[00126] 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%.

[00127] 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.

[00128] 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.

[00129] 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.

[00130] 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 to the highest chamber temperature discussed above.

[00131] A suitable solvent may be selected based on a number of considerations and factors as discussed in the literature. The solvent should be injectable as a vapour, and can dissolve at least one of the viscous hydrocarbons to be recovered from reservoir formation 100 in the steam-solvent recovery process for increasing mobility of the hydrocarbons. The solvent may be a viscosity-reducing solvent, which reduces the viscosity of the hydrocarbons in reservoir formation 100.

[00132] It is noted that with 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.

[00133] 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.

[00134] It is thus important to balance these considerations and factors, and select and control the ratio of the solvent to steam carefully to achieve optimal overall process performance and efficiency.

[00135] In a steam-solvent recovery process, both steam and a solvent are injected into the hydrocarbon reservoir to mobilize viscous hydrocarbons in the reservoir to assist recovery of hydrocarbons from the reservoir, the solvent-to-steam ratio (SSR) in the injection stream can be selected to optimize the production operation and efficiency. In particular, the SSR may be limited to an intermediate range to balance competing factors such as solvent usage, steam usage, energy utilization efficiency, oil recovery rate, oil recovery factor, and the like.
When selecting the optimal SSR, the steam-to-oil ratio (SOR) and the oil production rate should both be considered. When determining the optimal SSR, factors that can affect the range of optimal SSR in a particular case may include, but are not limited to, the enthalpy and quality of the steam stream to be injected, the solvent to be used, the temperature of the solvent before injection (or mixing with the steam prior to injection), the injection conditions (e.g., the pressure and temperature of injection at the injection well), downhole conditions (e.g., pressure and temperature) in the injection well and in the production well, heat loss in the piping and wellbore of the injection well, various operation parameters and constraints such as rates of production of various fluids from the reservoir including gas production rates.

[00136] 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 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 SSR (such as the molar ratio of injected solvent-to-steam) may be selected to balance its effects on hydrocarbon production performance and energy efficiency of the operation, thus optimizing overall performance and efficiency of the process. 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. The SSR may be varied, increased or decreased overtime.

[00137] 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.

[00138] In embodiments disclosed herein, steam and the solvent are co-injected from the same injection well.

[00139] The hydrocarbons in the reservoir of bituminous sands occur in a complex mixture containing 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.

[00140] Conveniently, an embodiment disclosed herein can allow convenient co-injection of steam and solvent to achieve a target SSR and temperature without using a flow meter to measure the flow rate of input steam stream.

[00141] 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.

[00142] A co-injected solvent may be any suitable solvent. For example, suitable solvents may include volatile hydrocarbon solvents such as butane or propane.
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. Suitable solvents may include diluents or condensates such as natural gas condensates or natural gas liquids. The diluent may be selected from diluents suitable for use as additives to the produced hydrocarbons to facilitate transportation of the produced hydrocarbons by pipeline. Such diluents may be already available on site at the surface facilities and thus can be conveniently used as needed with limited additional operating costs. The condensates may include condensates produced from the same reservoir formation or a different reservoir formation, and thus may also be readily available on site.

[00143] As can be appreciated by those skilled in the art, in at least some applications the amounts or ratio of the injected solvent to injected steam should be carefully selected and controlled as the ratio can significantly affect the overall performance and efficiency of the steam-solvent recovery process.

[00144] 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.

[00145] 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.

[00146] The solvent may be heated before or during injection to vaporize the solvent. For example, when the solvent is propane, it may be heated with hot water at a selected temperature such as, for example, about 100 C. In any event, the solvent is mixed and 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.

[00147] For example, where the selected solvent is propane, a solvent-steam mixture containing about 50 wt% to about 60 wt% propane and about 40 wt% to about 50 wt% steam may be injected at a suitable temperature, such as about 180 C
to about 215 C, and a suitable pressure such as about 3 MPa, e.g. 3.2 MPa. The suitable steam temperature before mixing may be determined, for example, through techniques known to persons of skill in the art based on parameters of the mixture components and the desired injection temperature. For example, the enthalpy per unit mass of the steam-propane mixture with about 50 wt% to about 60 wt% propane and about 40 wt% to about 60 wt% steam may be about 8820 to about 6650 kJ/kg.

[00148] Typically, the injection pressure may be initially determined and a suitable solvent and suitable injection temperature and ratio of the solvent to steam are selected for the target injection pressure.

[00149] The solvent-to-steam ratio (SSR) may also be expressed or indicated as molar concentrations or molar ratio, or weight concentrations or ratio, or volume concentrations or ratio.

[00150] For example, in selected embodiments, a molar ratio of the injected solvent to the injected steam in the injection fluid, also referred to as the mobilizing fluid, may be from 0.1 to 3. Alternatively, the injection fluid may include about 9.3 mol% to about 88 mol% solvent and about 12 mol% to about 91 mol% steam. The molar ratio may also be smaller than 0.1 or larger than 3, as long as a change in the steam injection rate is detectably reflected in the mixture temperature.

[00151] For co-injection of steam and propane, the injection fluid may include about 1 wt% to about 99 wt% propane and 99 wt% steam to about 1 wt% steam, such as about 20 to about 87 wt% propane and about 13 to about 80 wt% steam, or about 50 to about 60 wt% propane (corresponding to about 30 to about 40 mol%
propane) and about 50 to about 60 wt% steam. For co-injection of steam and butane, the injection fluid may include about 1 wt% to about 99 wt% butane and 99 wt%
steam to about 1 wt% steam, such as about 25 to about 90 wt% butane and about 10 to about 75 wt% steam, or about 50 to about 60 wt% butane and about 50 to about 40 wt%
steam.

[00152] In some embodiments, the injection fluid or mobilizing fluid may also include less than about 3 wt% methane based on the total weight of the fluid.
In selected embodiments, the injection fluid may include less than about 1 wt%
methane.

[00153] It is expected that co-injection of the solvent with steam may result in increased flow rate and drainage rate of the oil stream, which may lead to improved oil production performance, such as increased oil production rate, reduced cumulative steam to oil ratio (CSOR), or improved overall hydrocarbon recovery factor.

[00154] 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 recovery process. During a steam-solvent recovery process, it may be of economic benefit to gradually decrease/increase the solvent content and gradually increase/crease the steam content at different periods in the process.

[00155] Solvent injection is expected to result in increased mobility of at least some of the viscous or 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 hydrocarbons may be increased when they become more mobile, or when hydrocarbons attached to sands become easier to detach from the sands, or when immobile hydrocarbons become mobile, even if the viscosity or flow rate of the hydrocarbons has not changed. The mobility of hydrocarbons may also be increased by decreasing the viscosity of the hydrocarbons, or when the effective permeability, such as through bituminous sands, is increased. Additionally or alternatively, increasing hydrocarbon mobility may be achieved by heat transfer from solvent to hydrocarbons.

[00156] 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.

[00157] Conveniently, a steam-solvent recovery 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.

[00158] 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.

[00159] 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.

[00160] 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.

[00161] 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.

[00162] In some embodiments, before, during or after the blowdown phase, production of fluids from the reservoir through production well 130 may continue.

[00163] 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 hydrocarbons to be recovered from reservoir formation 100 in the steam-solvent recovery process for increasing mobility of the hydrocarbons.

[00164] 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 steam-solvent recovery process.

[00165] 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.
In some embodiments, a condensate or diluent may be beneficial.

[00166] 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.

[00167] 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.

[00168] 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.

[00169] 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.

[00170] 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.

[00171] 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.

[00172] 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.

[00173] 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.

[00174] 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.

[00175] 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).

[00176] Conveniently, a process as disclosed herein may reduce overall production costs and operation delay due to the time required to replace flow meters.

[00177] 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. For example, in an embodiment, the injection fluid or mixture may include both steam and the solvent at a molar ratio or molar concentrations discussed herein. 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. In additional embodiments, the relative amount of the solvent in the injection fluid/mixture may also be higher or lower than the ranges previously mentioned.

[00178] 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.

[00179] 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.

[00180] 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.

[00181] 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.

[00182] 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.

[00183] In some embodiments, it may not be necessary to recycle the injected solvent.

[00184] 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.

[00185] 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.

[00186] 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.

[00187] At the surface, the solvent may be delivered to the solvent tank 412 by a pipeline (not shown) or by transportation trucks. When a solvent pipeline is used, an on-site solvent storage tank (such as solvent tank 412) may be omitted. If trucks are used to deliver the solvent, the trucks may offload the solvent to one or more immobile solvent storage bullets. When propane is used as the solvent, the storage bullets may be bullets suitable for storing NGL.

[00188] In some embodiments, the solvent trucks may serve as the solvent source and the solvent may be supplied directly from a solvent track to inject well 120 through pipe 414. In such a case, the solvent injection may not be continuous over time, and the solvent may be batches. Such an arrangement may allow quick offloading of the solvent from the truck.

[00189] Suitable solvent bullets may be installed as immobile bullets for continuous injection of the solvent. In this case, the solvent may be initially transferred from transportation trucks to the bullets. For a medium scale surface injection facility, each solvent bullet may have a storage capacity of 50 metric tonnes. The bullet may also be specifically manufactured and configured for use with a selected solvent such as propane or NGL.

[00190] Pump 420 may be a standard fluid pump, or may be custom-designed and specifically made and configured to manage propane injection at a selected flow rate range, such as from about 40 t/d to about 80 t/d. In some cases, the solvent flow rate may be controlled by the pumping speed/rate.

[00191] In practice, when the solvent is supplied using trucks, the total amount of the delivered solvent may be determined by measuring the weight difference of each truck before and after unloading the solvent. With trucks with 25-ton storage capacity, two or more trucks a day may be sufficient to supply the solvent at an injection rate of 50 t/d.
[001921 _ The 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.
[00193] 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.
[00194] 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.
[00195] 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.
[00196] 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.
[00197] 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.
[00198] 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.
[00199] Other possible modifications and variations to the examples discussed above are also possible.
[00200] 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.
[00201] 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.
[00202] Generally, a number of factors may be considered when selecting a suitable solvent for use in various embodiments.
[00203] 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.
[00204] 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.
[00205] Another possible contributing factor is whether the solvent can reduce the viscosity of oil in the reservoir.
[00206] As can be appreciated, a common consideration for selecting the suitable solvent is cost versus benefits.
[00207] 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.
[00208] The ratio of injected solvent to steam may be provided in a number of ways. For example, a co-injection fluid comprising steam and a solvent may be characterised by the weight percentages of the solvent and steam in the fluid.
This metric may be convenient to use as the weight percentages or weight ratios do no vary when the pressure and temperature changes.
[00209] Alternatively, the relative amounts of the solvent and steam may be stated using the respective volume percentages of the components as measured at the standard temperature and pressure (STP), which is at 0 C and 1 atm. This metric is less convenient as the volume of each component in the fluid may change with the external or total pressure and temperature. This metric also can be misleading when the compared materials are in different phases at the STP. For example, this metric may not provide a meaningful range when the solvent is in the gas phase at the STP, as comparing the gas volume of the solvent to the liquid volume of water at STP is not very helpful.

[00210] A more intrinsic metric is likely the molar ratio or molar concentration (mol%) of the injected solvent to steam.
[00211] 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.
[00212] In some embodiments, the SSR may be increased over time during injection. When methane is also injected, the molar ratio of injected methane to injected steam may also increase over time.
[00213] 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.
[00214] 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.
[00215] A temperature in a production zone in the reservoir may be controlled to limit the temperature in the production zone to be below the bubble point temperature of the solvent in the produced fluid at a reservoir pressure. This may prevent re-boiling or refluxing of the solvent in the reservoir.
[00216] 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.

[00217] In an embodiment, a method of recovering hydrocarbons from a subterranean reservoir of bituminous sands includes injecting a mobilizing fluid into the reservoir for mobilizing viscous hydrocarbons in the reservoir and forming a reservoir fluid comprising mobilized hydrocarbons and condensed mobilizing fluid, and producing the reservoir fluid from the reservoir. The mobilizing fluid comprises about 40 wt% to about 70 wt% steam and about 30 wt% to about 60 wt% solvent. The solvent reduces viscosity of the viscous hydrocarbons and is more soluble in oil than in water, and has a partial pressure in the reservoir allowing the solvent to be transported as vapour with steam to a steam front. The mobilizing fluid may also include less than about 3 wt% methane, such as less than about 1 wt% methane. The mobilizing fluid may comprise about 50 wt% to about 60 wt% of the solvent. The solvent may comprise propane.
[00218] In another embodiment, a mobilizing fluid is used in a solvent-aided process to produce hydrocarbons from a subterranean reservoir of bituminous sands.
The mobilizing fluid comprises about 40 wt% to about 70 wt% steam; about 30 wt% to about 60 wt% solvent; and less than about 3 wt% methane. The solvent reduces viscosity of viscous hydrocarbons in the reservoir and is more soluble in oil than in water, and has a partial pressure in the reservoir allowing the solvent to be transported as vapour with steam to a steam front. The solvent may comprise propane or butane.
The mobilizing fluid may comprise about 50 wt% to about 60 wt% propane or butane.
The mobilizing fluid may comprise less than about 1 wt% methane.
[00219] 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 3wt% of methane, in the re-injected fluid may provide improved overall operational or economic efficiency.
[00220] In some embodiments, it may not be necessary to continuously measure the solvent flow rate or the temperatures in the supply lines. Instead, a correlation between the steam flow rate (or solvent flow rate) and the mixture temperature may be obtained based on prior measurements at the same conditions, or results extrapolated from measurements at different conditions such as at lower flow rates. For example, reference flow rates (base-line flow rates) at different mixture temperatures may be obtained based on previous measurements where both the steam injection rate and the solvent injection rate were directly measured or otherwise determined. In a subsequent process, as long as the conditions of the supplied steam and solvent remain the same or substantially similar and one of the steam and solvent injection rates is known (such as directly measured), the other one of the steam and solvent injection rates may be determined or extrapolated based on the reference flow rates and the mixture temperature.
[00221] In some embodiments, it may not be necessary to measure the absolute temperature in the mixture of steam and solvent, as a relative change in the mixture temperature may be used to control the steam or solvent flow to return the mixture temperature to the initially set value.
[00222] In some embodiments, the injected solvent may be pre-heated before mixing with the steam. The solvent may be pre-heated using any suitable heating or energy source. When the solvent is pre-heated or the solvent temperature is increased, the steam injection rate required to obtain the same target temperature in the injection mixture may be reduced, and consequently the target SSR may increase with pre-heated solvent. The control process should take into account of the fact that the correlations among the desired steam injection rate, the target SSR, and the target mixture temperature are dependent on the solvent injection temperature.
[00223] In some embodiments, the target temperature in the injection mixture may be selected based on the required thermal energy requirement at a given solvent temperature, without expressly determining the target SSR or any weight or volume percentages of the solvent or steam in the mixture.
[00224] Another factor to be considered in the control process is the steam quality. At a lower steam quality, more steam may be required to provide the same required thermal energy. That is, the correlation between the steam injection rate and the temperature in the injection mixture is dependent on the steam quality.
Thus, the steam injection rate may be adjusted based on a change in the steam quality, in order to provide the same thermal energy to the injection mixture, and maintain the same target temperature in the injection mixture.
[00225] In some embodiments, an additional additive may be included in the inject mixture (injection stream), in which case, a lower or higher steam injection rate may be required depending on the temperature of the additive before mixing, relative to the temperature of the solvent. For example, if the additive is pre-heated and has a temperature higher than the target mixture temperature, then less steam may be required. If the additive has a temperature below the target mixture, more steam may be required. As can be appreciated, the addition of an additive also changes the correlation between the mixture temperature and the steam injection rate.
[00226] In some embodiments, an additional additive may be included in the injection mixture for various reasons or considerations, including to reduce operation costs or to improve operation performance. For example, when the cost of generating steam becomes relatively high as compared to including another material as a thermal energy source in the mixture, the other material may be added to the injection mixture to reduce the required amount of steam to provide the required thermal energy.
The components in the injection mixture may be selected and adjusted to meet the target mixture temperature based on current economic considerations.
[00227] When the correlation between the mixture temperature and the steam injection rate (such as a baseline rate or reference rates) is established for given injection conditions, e.g., by simulation, calibration, testing, or combination thereof, steam injection rate may be controlled based on the detected mixture temperature, without determining or calculating the actual SSR (or any weight, volume, or molar percentage of steam or solvent) in the mixture.
[00228] As now can be appreciated, the embodiments described above may be modified for application in different contexts or more generally.
[00229] For instance, an example embodiment may be related to a method of determining a fluid flow rate in a conduit. The method may include mixing a first stream and a second stream to form a third stream, where the first stream flows at a first flow rate in a first conduit, and the second stream flows at a second flow rate in a second conduit. The mixed stream is flowing in a third conduit. The first and second streams have different temperatures. A temperature in the third stream in the third conduit is detected, and the first flow rate is determined based on the detected temperature in the third stream.
[00230] Another example embodiment may be related to a method of regulating a fluid flow rate in a conduit. In this method, a first stream and a second stream are mixed to form a third stream. The first stream has a first temperature and the second stream has a second temperature different from the first temperature. A third temperature in the third stream is detected, and the flow rate of the first stream is adjusted in response to the detected third temperature to control the third temperature in the third stream.
[00231] In some embodiments, instead of estimating the flow rate of steam, the solvent flow rate may be similarly estimated based on the mixture temperature when the steam flow rate is already known or can be directly measured but a flow meter is not readily available to measure the solvent flow rate into the mixing junction.
[00232] In some embodiments, the known or measured flow rate of the solvent (or steam) may vary and it is still possible to estimate the flow rate of steam (or solvent) based on the mixture temperature, as long as the correlation between the flow rates and the mixture temperature is known or not changing.
[00233] In some embodiments, it may be possible to control or regulate one of the two flow rates based on the mixture temperature even if the correlation is not expressly known or determined, as long as the correlation remains substantially unchanged over the control period.
[00234] To further illustrate embodiments of the present disclosure, some non-limiting and representative examples are discussed below.
[00235] Examples [00236] Example I
[00237] Computer simulations were conducted to predict the required flow rates in a method of controlling steam and solvent co-injection as described herein.

Representative simulation results are listed in Table I. The simulated solvent was propane. The SSR (solvent-to-steam ratio) shown Table I is the weight ratio.
The injection temperature (Tin) is the temperature of the mixture of steam and solvent immediately after mixing and before injection. The enthalpy shown in Table I
was the calculated enthalpy in the mixture of steam and solvent. The input steam had an initial temperature of 240 Co, pressure of 3.2 MPa, and steam quality of about 92%.
The input solvent (propane) had an initial temperature of 0 C .

TABLE I
Target Target Mixture Steam Propane Total Day Propane SSR t Temperature Rate (R) Rate Injection Enthalpy Rate (MJ/kg) wt% (wt) T(C ) (t/d) (t/d) (t/d) 1 0 0 240 290 0 290 2.64 11 10 9:1 235 160 18 178 2.37 21 20 4:1 233 100 25 125 2.11 31 30 7:3 231 70 29 99 1.84 41 40 3:2 225 50 33 83 1.58 51 50 1:1 218 30 28 58 1.32 61 60 2:3 206 20 28 48 1.05 71 70 3:7 163 15 28 43 0.8 81 80 1:4 109 15 53 68 0.53 91 80 1:4 108 15 50 65 0.53 [00238] Initially, from Day 1 to Day 10, the simulated process is a SAGD
process with injection of only steam. At Day 11, the simulated process was switched from the SAGD process to a steam-solvent recovery. From Day 11 to Day 50, the steam-solvent recovery is a steam-driven process, and from Day 61 to 91, the process is solvent driven.
[00239] As shown, the wt% for solvent propane was increased over time from wt% to 80 wt%, and the steam wt% was corresponding reduced from 100wt% to 20wt% over a period of more than 91 days.
[00240] As can be seen from Table I, as the steam wt% (and the SSR) decreased, the enthalpy of the solvent-steam mixture and the injection temperature both decreased correspondingly. There was strong correlation among the steam injection rate, the injection temperature (Tin), and the SSR. For example, Tim was about 240 C in the SAGD stage (pure steam injection), and about 108 C when the SSR was reduced to 1:4.
[00241] Example II

[00242] In a pilot process of transitioning from a SAGD process to a steam-solvent recovery, steam and propane were co-injected through an injection well in the steam-solvent recovery. The well arrangement used in the pilot was as illustrated in FIGS. 1-3. The steam input pipe connected to the injection well was equipped with a flow meter, which had a lower reading limit of 70 T/d. In the SAGD process, the steam flow rate was above 70 T/d, such as about 290 T/d, so the flow meter was used to measure the steam injection rate. After the transition from the SAGD process to the steam-solvent recovery, the steam injection rate was eventually reduced to below 70 T/d in order to achieve the target SSR. At this time, the steam and solvent injection facility was configured as illustrated in FIG. 7, and the steam flow rate was estimated using known correlation between the steam injection rate and the temperature in the mixture, which was detected at the location indicated as "Mixed Temp" in a circle. The SSR in the mixture was represented by the weight percentage of propane or steam.
The flow rate of the input solvent was directly measured using a flow meter (not shown) and was maintained at a constant rate.
[00243] In this particular case, it would have taken about 3 months to shut in the operation and install a new flow meter that was able to measure flow rates below 70 t/d, such as in the range of 15 t/d to 70t/d.
[00244] Instead of replacing the flow meter, the flow rate in the steam injection pipe was estimated using the expected correlation between the steam injection rate and the temperature of the steam-solvent mixture, which was measured using a temperature sensor as indicated in FIG. 7. The mixture temperature was also correlated to the SSR, and the target mixture temperature was determined based on the target SSR, which was in turn calculated using the steam flow rate and the solvent flow rate. Since the target SSR and the solvent flow rate were known (or fixed at a constant rate), a correlation between the measured mixture temperature and the steam flow rate could also be established. Thus, the steam flow rate was controlled based on the detected temperature to achieve the target SSR. The effectiveness of this control method was verified at higher injection rates.

[00245] To control the steam flow rate, the valve in the steam input pipe (see "valve" in FIG. 7) was manually adjusted to adjust the flow rate of steam until the target mixture temperature was achieved in the steam-solvent mixture, with the solvent injection rate held constant. It is expected that the valve may also be automatically controlled based on the detected mixture temperature.
[00246] In one test run, the solvent injection rate was held constant at 60 T/d, the steam injection rate was adjusted to achieve the target mixture temperature at 111 C , in which case the steam flow rate was estimated to be 15 T/d.
[00247] It was observed that the mixture temperature was sensitive and responsive to steam rate adjustment.
[00248] In another test run, the solvent injection rate was held constant at 40 T/d, and the steam injection rate was adjusted to reach a detected mixture temperature at 190 C . The estimated steam injection rate based on the known correlation between the SSR and the target (detected) temperature was 27 T/d. The steam injection flow rate at the same valve open position was later measured directly with a steam flow meter, and the directly measured steam flow rate was consistent with the estimated flow rate based on the correlation between the SSR and the detected temperature.
[00249] It should be noted that the above results are based on the particular tested conditions as specified above. Under different conditions and with different solvents, the results may vary.
[00250] The test results confirmed that there was a consistent and unique correlation between the steam or solvent weight percentage (hence the SSR) in the injection mixture and the mixture temperature, and that the mixture temperature is a monotonic function of the steam injection rate. Therefore, it can be expected that the steam injection rate can be controlled to achieve the desired SSR based on the detected mixture temperature when the solvent injection rate is known or constant.

[00251] CONCLUDING REMARKS
[00252] 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.
[00253] 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.
[00254] 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.
[00255] 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.
[00256] 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.
[00257] 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 of injecting steam and solvent into a subterranean reservoir to assist recovery of hydrocarbons therefrom, the method comprising:
mixing a first stream comprising steam and a second stream comprising a solvent to form a third stream comprising steam and the solvent for injection into the reservoir;
detecting a temperature in the third stream;
controlling a flow rate of the first stream based on the detected temperature;
and injecting the third stream into the reservoir.

2. The method of claim 1, wherein the temperature is detected immediately after the mixing of the first stream and the second stream.

3. The method of claim 1 or claim 2, wherein the flow rate of the first stream is determined indirectly based on the detected temperature without directly measuring the flow rate with a flow rate meter.

4. The method of any one of claims 1 to 3, wherein the first stream is supplied for mixing through a fluid conduit comprising a flow meter for measuring a fluid flow rate through the fluid conduit within a range, and the flow rate of the first stream is outside the range.

5. The method of claim 4, wherein the range of the flow meter has a lower limit, and the flow rate of the first stream is below the lower limit.

6. The method of any one of claims 1 to 5, further comprising correlating the temperature in the third stream with the flow rate in the first stream.

7. The method of any one of claims 1 to 5, wherein a correlation between the detected temperature and the flow rate in the first stream is predetermined.

8. The method of claim 7, wherein the predetermined correlation is stored and available to a controller for controlling the flow rate of the first stream.

9. The method of any one claims 1 to 8, wherein the steam in the first stream has substantially constant pressure, temperature, and steam quality.

10. The method of any one claims 1 to 9, wherein the solvent in the second stream has substantially constant pressure and temperature and is supplied at a substantially constant rate.

11.The method of any one of claims 1 to 10, wherein the controlling of the flow rate comprises increasing the flow rate of the first stream when the detected temperature decreases, and decreasing the flow rate of the first stream when the detected temperature increases.

12.The method of any one of claims 1 to 11, wherein the flow rate is controlled to maintain the temperature in the third stream at a target temperature.

13.The method of claim 12, wherein the target temperature is determined based on a target ratio of solvent to steam in the third stream.

14.The method of any one of claims 1 to 13, wherein the third stream is injected into the reservoir through an injection well penetrating the reservoir.

15.A system for injecting steam and solvent into a subterranean reservoir to assist recovery of hydrocarbons therefrom, the system comprising:
a first conduit for supplying a first stream comprising steam;
a second conduit for supplying a second stream comprising a solvent;
a third conduit connected to the first and second conduit for mixing the first and second streams to form a third stream and supplying the third stream comprising steam and the solvent for injection into the reservoir;

a temperature sensor associated with the third conduit for detecting a temperature in the third stream;
a flow regulator in the first conduit for regulating a flow rate of the first stream in the first conduit;
a controller connected to the temperature sensor and the flow regulator for controlling the flow regulator to adjust the flow rate, the controller configured and programmed to control the flow regulator based on the detected temperature.

16.The system of claim 15, comprising a steam source connected to the first conduit for supplying steam at constant temperature, pressure and steam quality.

17.The system of claim 15 or claim 16, comprising a solvent source connected to the second conduit for supplying the solvent at constant temperature and pressure at a constant rate.

18.The system of any one of claims 15 to 17, wherein the temperature sensor comprises a thermocouple or a resistance thermometer.

19.The system of any one of claims 15 to 18, wherein the flow regulator comprises a valve.

20.The system of any one of claims 15 to 19, wherein the controller comprises a processor or a computer.

21.The system of any one of claims 15 to 20, wherein the third conduit is in fluid communication with an injection well penetrating the reservoir for injecting the third stream into the reservoir through the injection well.

22.A method of determining a fluid flow rate, comprising:
mixing a first stream and a second stream to form a third stream, wherein the first stream flows at a first flow rate and the second stream flows at a second flow rate;
detecting a temperature in the third stream; and determining the first flow rate based on the detected temperature and the second flow rate.

23.A method of regulating a fluid flow rate, comprising:
mixing a first stream and a second stream to form a third stream, wherein the first stream has a first temperature and the second stream has a second temperature different from the first temperature;
detecting a third temperature in the third stream; and adjusting the flow rate of the first stream in response to the detected third temperature to control the third temperature in the third stream.