CA3147555A1 - Methods and systems for identifying a liquid level within a reservoir being produced via a thermally-stimulated gravity drainage process - Google Patents

Abstract

A method for identifying a liquid level within a reservoir from which hydrocarbon material is being produced by a thermally-stimulated gravity drainage-based hydrocarbon production process. The method comprising obtaining subsurface temperature data representative of subsurface temperatures of the reservoir and identifying a liquid level within the reservoir based on the obtained subsurface temperature data.

Description

METHODS AND SYSTEMS FOR IDENTIFYING A LIQUID LEVEL WITHIN A
RESERVOIR BEING PRODUCED VIA A THERMALLY-STIMULATED GRAVITY
DRAINAGE PROCESS
TECHNICAL FIELD
[0001] The present disclosure relates to identifying a liquid level within a reservoir whose hydrocarbon material is being produced via a thermally-stimulated gravity drainage process.
BACKGROUND

[0002] Steam assisted gravity drainage (SAGD) is an in-situ process for recovering heavy oil and bitumen from subsurface reservoirs. During SAGD, high pressure steam is injected via an injection well to heat the hydrocarbon material, thus reducing its viscosity. This causes the heated hydrocarbon material to drain into a production well where it can then be pumped to the surface. In order to pump the fluids to the surface, a pumping system, installed within the production well, is generally submersed within fluid received by the production well.

[0003] Many systems which effectuate the SAGD process include a fiber optic cable that extends from the surface of the well, through the vertical section and into the horizontal section. This fiber optic cable is capable of sensing various parameters in the well, such as temperature. By extending through the vertical and horizontal sections of the well, the fiber optic cable can provides distributed temperature sensing (DTS) such that the local temperature at various pints in the production wellbore can be detected. The fiber optic cable is typically permanently installed to allow continuous monitoring of the well throughout its operational lifetime, without the need to deploy additional instruments or stop well production.

[0004] During SAGD, the fiber optic cable is conventionally used to monitor the temperatures within the horizontal section of the well, for the purpose of, for example, to detect casing leaks or optimize operation. Despite the fact that the Date Recue/Date Received 2022-02-03 fiber optic cable extends from the surface through the vertical section and into the horizontal section, it is typically not used to monitor any parameters in the vertical section of the wellbore.

[0005] In SAGD processes, it is useful to know the location of the liquid level in the vertical section of the production well. Knowing the liquid level can help determine bottom hole pressure (BHP) and can be used to monitor the productivity and/or deliverability of the well. Accordingly, there is a need to conveniently identify the location of the liquid level in the vertical section of a SAGD
production well.
SUMMARY

[0006] In one aspect there is provided a method for identifying a liquid level within a reservoir from which hydrocarbon material is being produced by a thermally-stimulated gravity drainage-based hy-drocarbon production process.
The method comprising: obtaining subsurface temperature data representative of subsurface temperatures within the reservoir, and identifying a liquid level within the reservoir based on the obtained subsurface temperature data.

[0007] In some examples, the obtained temperature data comprises, for each one of a plurality of vertical depths from the surface, vertical depth-based subsurface temperature information.

[0008] In some examples, the vertical depth-based subsurface temperature information is vertical depth-based subsurface temperature information within a production well through which the hydrocarbon material is being produced.

[0009] In some examples, successive depths, of the plurality of depths, are spaced apart from each other by at least five (5) metres.

[0010] In some examples, the vertical depth-based subsurface temperature information includes: (i) temperature that is representative of the temperature of the reservoir at the vertical depth, and (ii) a temperature variability factor that is Date Recue/Date Received 2022-02-03 representative of the variability of the temperature of the reservoir at the vertical depth.

[0011] In some examples, the temperature variability factor is a standard deviation of a set of values defined by: (i) the temperature information that is representative of a temperature of the reservoir at the vertical depth and (ii) for each one of at least two shallower vertical depths, of the plurality of vertical depths, disposed immediately above the vertical depth, independently, the temperature information that is representative of the temperature of the reservoir at the shallower vertical depth.

[0012] In some examples, each one of (i) the temperature information, that is representative of the temperature of the reservoir at the vertical depth, and (ii) the temperature information for each one of the at least two shallower vertical depths, is defined relative to a standard, and the standard is a known temperature within the liquid.

[0013] In some examples, the temperature information, that is representative of the temperature of the reservoir at the vertical depth, is based on a relative difference between temperature that is sensed at the vertical depth and the standard, and, for each one of at least two shallower vertical depths, of the plurality of vertical depths, disposed immediately above the vertical depth, independently, the temperature information, that is representative of the temperature of the reservoir at the shallower vertical depth, is based on a relative difference between temperature that is sensed at the shallower vertical depth and the standard.

[0014] In some examples, the method further comprises, for each one of:
(i) the temperature that is sensed at the vertical depth, sensing the temperature with a respective temperature sensor, and (ii) for the temperature that is sensed at each one of the at least two shallower vertical depths, sensing the temperature with a respective temperature sensor.

Date Recue/Date Received 2022-02-03

[0015] In some examples, the respective temperature sensor is a fiber optic cable configured to sense temperatures along a length of the fiber optic cable.

[0016] In some examples, the known temperature within the liquid is a temperature representative of the temperature of the liquid within a pump disposed within the production well for effectuating production of the hydrocarbon material.

[0017] In some examples, the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which: (i) the temperature information is representative of a temperature of the reservoir which exceeds a predetermined value and (ii) the variability factor exceeds a predetermined value.

[0018] In some examples, the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which: (i) the temperature information is representative of a temperature of the reservoir which exceeds 10 /0 and (ii) the variability factor exceeds 60%.

[0019] In some examples, identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which: (i) the temperature information is representative of a temperature of the reservoir which exceeds 2.5% and (ii) the variability factor exceeds 300%.

[0020] In some examples, identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which: (i) the temperature information is representative of a temperature of the reservoir which exceeds 7% and (ii) the variability factor exceeds 100%.

[0021] In some examples, the method further comprises: in response to the determination that the vertical depth, from the surface, of the liquid level, is below Date Recue/Date Received 2022-02-03 a flow discharging communicator, through which a production-stimulating fluid is being discharged into the production well from the reservoir, by less a predetermined value, increasing the rate at which the hydrocarbon material is being produced from the reservoir via the production well.

[0022] In some examples, the method further comprises: in response to the determination that the vertical depth, from the surface, of the liquid level, is below a flow discharging, through which a production-stimulating fluid is being discharged into the production well from the reservoir, by less a predetermined value, presenting an indication of a potential injector flooding condition via an output device.

[0023] In some examples, the method further comprises: in response to the determination that the vertical depth, from the surface, of the liquid level, is above a flow receiving communicator, through which the hydrocarbon material is being conducted into the production well from the reservoir, by less than a predetermined value, decreasing the rate at which the hydrocarbon material is being produced from the reservoir via the production well.

[0024] In some examples, the method further comprises: in response to the determination that the vertical depth, from the surface, of the liquid level, is above a flow receiving, through which the hydrocarbon material is being conducted into the production well from the reservoir, by less than a predetermined value, presenting an indication of a potential steam coning condition via an output device.

[0025] In some examples, the plurality of vertical depths from the surface are depths from the surface relative to a well geometry and do not correspond to true vertical depths. The method further comprising: determining a true vertical depth (TVD) at the vertical depth of the liquid level based on the well geometry.

[0026] In some examples, the well geometry is obtained from a well directional survey.
Date Recue/Date Received 2022-02-03

[0027] In some examples, the method further comprises: determining a bottom hole pressure, wherein the bottom hole pressure is calculated by adding a surface casing pressure to the product of the true vertical depth, a gravitational constant and a fluid emulsion density, wherein the surface casing pressure is measured at the surface of the wellbore and the fluid emulsion density is a property of the fluid in the wellbore.

[0028] In some examples, the method further comprises: comparing the determined bottom hole pressure to a measured bottom hole pressure.

[0029] In some examples, the method further comprises: determining a volume of wellbore fluid in a vertical section of the production well based on the true vertical depth at the vertical depth of the liquid level, the geometry of the well, and a fluid emulsion density.

[0030] In some examples, the method further comprises: obtaining a total well production volume from a well test of the production well, and determining a reservoir capacity by subtracting the volume of wellbore fluid in the vertical section of the production well from the total well production volume.

[0031] In some examples, the method further comprises: injecting a chemical agent for stimulating production in response to determining that the reservoir capacity is below a low production threshold.

[0032] In some aspects, the present disclosure describes a system for identifying a liquid level within a reservoir from which hydrocarbon material is being produced by a thermally-stimulated gravity drainage-based hydrocarbon production process. The system comprises one or more processor devices and one or more memories storing machine-executable instructions which, when executed by the one or more processor devices, cause the system to perform any of the preceding example aspects of the method.

Date Recue/Date Received 2022-02-03

[0033] In some aspects, the present disclosure describes a system for identifying a liquid level within a reservoir from which hydrocarbon material is being produced by a thermally-stimulated gravity drainage-based hydrocarbon production process. The system comprises a temperature sensor, one or more processor devices, and one or more memories storing machine-executable instructions, which, when executed by the one or more processor devices, cause the system to obtain subsurface temperature data representative of subsurface temperatures within the reservoir, using the temperature sensor, and identify a liquid level within the reservoir based on the obtained subsurface temperature data.

[0034] In some examples, the temperature sensor is a distributed temperature sensing (DTS) device, configured to sense temperatures along a length of the DTS device.

[0035] In some examples, the distributed temperature sensing (DTS) device is a fiber optic cable.

[0036] In some example aspects, the present disclosure described a non-transitory computer-readable medium storing machine-executable instructions thereon. The instructions, when executed by one or more processors, cause the processor to perform any of the preceding example aspects of the method.

[0037] In some embodiments, the techniques described herein can be used to identify the liquid level in the vertical section of the production well. In this respect, the techniques use presently underutilized data obtained from existing fiber optic cables deployed in the vertical section of the production well. The techniques allow operators to monitor liquid level, bottom hole pressure, and well productivity/deliverability and identify possible issues within the injection and production wells based on the liquid level.
BRIEF DESCRIPTION OF THE DRAWINGS

Date Recue/Date Received 2022-02-03

[0038] Reference will now be made, by way of example, to the accompanying drawings which show example embodiments, and in which:

[0039] Figure 1 illustrates a schematic diagram of a well pair of a thermally-stimulated gravity drainage process for producing hydrocarbon material from a reservoir;

[0040] Figure 2 is a schematic illustration of a thermally-stimulated gravity drainage process implemented via a well pair; and

[0041] Figure 3 depicts a close-up of a portion of the vertical section of a production well within which a fiber optic cable is being used for enabling detection of the liquid level.

[0042] Similar reference numerals are used in different figures to denote similar components.
DETAILED DESCRIPTION

[0043] The present disclosure describes methods for identifying the liquid level within a reservoir from which hydrocarbon material is being produced by a thermally-stimulated gravity drainage-based hydrocarbon production process, and systems for implementing such methods. The liquid level is identified based on obtained subsurface temperature data that is representative of subsurface temperatures of the reservoir.

[0044] Figure 1 illustrates a schematic layout of a system 100 for carrying out a process for producing hydrocarbon material from a hydrocarbon-containing reservoir 116. In some embodiments, for example, the hydrocarbon-containing reservoir includes an oil sands reservoir, and the hydrocarbon material includes heavy hydrocarbon material, such as bitumen. In this respect, in some embodiments, for example, the reservoir is an oil sands reservoir.

[0045] The system 100 includes a pair of wells, 102, 114. Each of the wells 102, 114, independently, extends into the reservoir 116 from the surface 110.
The Date Recue/Date Received 2022-02-03 well 102 includes a respective vertical section 102A and a respective horizontal section 102B. The well 114 includes a respective vertical section 114A and a respective horizontal section 114B. The well 114 functions as an injection well and the well 102 functions as a production well. Production-stimulating fluid is injected via the injection well 114 to stimulate production of the hydrocarbon material via the production well 102. In some embodiments, for example, the producing of the hydrocarbon material via the production well 102 is effected while the production-stimulating fluid is being injected by the injection well 114. In this respect, in some embodiments, for example, the hydrocarbon production process is a continuous process.

[0046] In some embodiments, for example, a production-stimulating fluid is conducted via an injection string, disposed within the injection well 114, and injected into the reservoir via a flow discharging communicator 114C. In some embodiments, for example, the flow discharging communicator 114C is defined by a plurality of injection ports defined within a slotted liner that is hung from a casing string that is disposed within the injection well 114. In some embodiments, for example, the plurality of injection ports are disposed along a reservoir interface that defines the interface between the injection well 114 and the reservoir 116. In some embodiments, for example, the ports are disposed within a horizontal section 114B of the injection well 114.

[0047] In some embodiments, for example, the production well 102 includes a flow communicating receiver 102C for receiving fluid that is being conducted within the reservoir 116 in response to the injection of the production-stimulating fluid. In some embodiments, for example, the flow receiving communicator 102C is defined by a plurality of ports. In some embodiments, for example, the ports are defined within a slotted liner hung from a casing string that is disposed within the production well 104. In some embodiments, for example, the ports are disposed within a horizontal section 102B of the production well 102.

[0048] The hydrocarbon material is produced via the production well 102 by artificial lift, such as, for example, by a pumping system 106. In some Date Recue/Date Received 2022-02-03 embodiments, for example, the pumping system 106 is an electrical submersible pump (ESP). The ESP includes a motor that is located below the pump, such that the fluid being pumped can act as a coolant for the motor. The motor converts electrical energy into rotational energy which in turn causes the pump to rotate.
The pump converts the rotational energy into kinetic energy and causes the fluid to flow up and out of the well 102. In some embodiments, for example, the pump has an intake that is submersed within the fluid that is received by the production well.
If the intake is not submersed, the pump will not be able to draw in fluid to pump to the surface. A production string 112 (e.g. tubing) extends uphole from the pumping system 106 to the surface 110, for conducting fluid, discharged from the pumping system 106, to the surface 110.

[0049] Referring to Figure 2, a hydrocarbon production process can be implemented via the well pair, so long as fluid communication is effected between the wells 102, 114 via a communication zone 118 (i.e. fluid is conductible (for example, by flowing)) such that the injected production-stimulating fluid effects mobilization of the hydrocarbon material within the reservoir, and the mobilized hydrocarbon material is conducted to the production well 102 via the communication zone 118 for production via the production well 102. The conduction of the hydrocarbon material to the production well 102 is effected in response to an applied driving force (for example, application of a fluid pressure differential, or gravity, or both). In some embodiments, for example, the production-stimulating fluid functions as a drive fluid effecting conduction (or transport) of hydrocarbon material to the production well 102. In some embodiments, for example, the production-stimulating fluid functions as a heat transfer fluid, supplying heat to the hydrocarbon material, such that viscosity of the hydrocarbon material is sufficiently reduced (in such state, the hydrocarbon material is said to be mobilized), such that the hydrocarbon material can be conducted to the production well 102 by a driving force, such as, for example, a pressure differential or gravity. In some embodiments, for example, the production-stimulating fluid functions as both a drive fluid and a heating fluid. In some embodiments, for example, the hydrocarbon material is produced along with some of the injected production-stimulating fluid.
While the wells 102, 114 are disposed in fluid communication through the Date Recue/Date Received 2022-02-03 communication zone 118, production-stimulating fluid is injected into the reservoir 116 such that the hydrocarbon material is conducted to the well 102, via the communication zone 118, and produced through the well 102.

[0050] In some embodiments, for example, the production-stimulating fluid includes gaseous material, such as, for example, steam. In this respect, in those embodiments where the production-stimulating fluid functions as a heating fluid, in some of these embodiments, for example, at least a portion of the production-stimulating fluid that has heated the hydrocarbon material (as described above) become condensed, such that fluid that is being produced via the production well 102 includes hydrocarbon material and condensed production-stimulating fluid.
In those embodiments where the gaseous material includes steam, in some of these embodiments, for example, the condensed production-stimulating fluid includes water. In those embodiments where the condensed production-stimulating fluid includes water, the fluid being produced via the production well 102 is an emulsion.

[0051] In some embodiments, for example, the hydrocarbon production process includes a thermally-stimulated gravity drainage-based hydrocarbon production process that is implemented via the well pair. In such processes, the production-stimulating fluid is gaseous and effectuates mobilization of the hydrocarbon material by at least heating the hydrocarbon material. The mobilized hydrocarbon material displaces the production-stimulating fluid in response to density differences, with effect that the mobilized hydrocarbon material is conducted to the production well 102 for production via the production well 102.
This process, of conduction of the mobilized hydrocarbon material to the production well, is commonly referred to as "gravity drainage".

[0052] In systems which implement thermally-stimulated gravity drainage-based hydrocarbon production processes, the horizontal section 11413 of the injection well 114 is vertically spaced from the horizontal section 10213 of the production well 102, such that the horizontal section 11413 of the injection well 114 is disposed above the horizontal section 10213 of the production well 102, such as, for example, by at least three (3) metres, such as, for example, by at least five (5) Date Recue/Date Received 2022-02-03 metres. A production phase (i.e. when hydrocarbon material is being produced via the production well 102) of the thermally-stimulated gravity drainage-based hydrocarbon production process occurs after the communication zone 118 has been established for effectuating flow communication between the mobilized hydrocarbon material and the production well 102.

[0053] With respect to thermally-stimulated gravity drainage-based hydrocarbon production processes being implemented via the well pair, initially, the reservoir 116 has relatively low fluid mobility (such as, for example, due to the fact that the hydrocarbon material within the reservoir 116 is highly viscous) such that the communication zone 118 is not present. In order to enable the injected production-stimulating fluid (being injected through the injection well 114) to promote the conduction of the reservoir hydrocarbons, within the reservoir 102, to the production well 102, the communication zone 118 must be established. This establishing of the communication zone 118 includes establishing interwell communication between the wells 102, 114 through the interwell region 120. By establishing the interwell communication, the conduction of the mobilized hydrocarbon material, through the interwell region 120, is enabled such that the mobilized hydrocarbon material is received and produced by the production well 102. The interwell communication can be established during a "start-up" phase of the thermally-stimulated gravity drainage-based hydrocarbon production process.
In some embodiments, for example, during the start-up phase, the interwell region 120 is heated. In some embodiments, for example, the heat is supplied to the interwell region 120 by effecting circulation of a start-up phase fluid (such as steam, or a fluid including steam) in one or both of the wells 102, 114. The heat that is supplied to the interwell region 120 heats the reservoir hydrocarbons within the interwell region 120, thereby reducing the viscosity of the reservoir hydrocarbons. Eventually, the interwell region 120 becomes heated to a temperature such that the hydrocarbon material is sufficiently mobile (i.e.
the hydrocarbon material has been "mobilized") for displacement to the production well 102 by at least gravity drainage. In this respect, eventually, sufficient hydrocarbon material becomes mobilized, such that this space (the interwell region 120), previously occupied by immobile, or substantially immobile, hydrocarbon material, Date Recue/Date Received 2022-02-03 is disposed to communicate fluid between the injection well 114 and the production well 102 in response to a driving force, such that at least hydrocarbon material is conductible through this space in response to the driving force. Upon the interwell region 120 becoming disposed to communicate fluid between the injection well and the production well 102 in response to a driving force, such that at least hydrocarbon material is conductible through this space in response to the driving force, the interwell communication, between the wells 102, 114, is said to have become established. The development of this interwell communication signals completion of the start-up phase and conversion to a production phase.

[0054] Referring again to Figure 2, during the production phase of a thermally-stimulated gravity drainage-based hydrocarbon production process, the communication zone 118 effects flow communication between hydrocarbon material, mobilized in response to heating by the production-stimulating fluid injected from the injection well 114 (for example, by reduction in viscosity caused by the heating), and the production well 102, such that the mobilized hydrocarbon material is conductible to a bottom portion 118B of the communication zone 118, by at least gravity drainage (the conduction can also, for example, be promoted by a pressure differential that is established between the injected production-stimulating fluid and the production well 102, which can also, in some embodiments, be characterized as a "drive process" mechanism), as described above, such that liquid material 122, including the hydrocarbon material, accumulates within the bottom portion 118B of the communication zone 118, for subsequent production via the production well 102. In some embodiments, for example, and as described above, at least a portion of the production-stimulating fluid that has heated the hydrocarbon material (as described above) become condensed, such that, along with the mobilized hydrocarbon material, the condensed production-stimulating fluid gravity drains to the bottom portion 118B of the communication zone 118, with effect that the liquid material 122 also includes condensed production-stimulating fluid. In those embodiments where the production-stimulating fluid includes steam, the condensed production-stimulating fluid includes water, such that the liquid material 122, which accumulates within the bottom portion of the communication zone 118, includes an emulsion.

Date Recue/Date Received 2022-02-03

[0055] As described above, the conduction of the mobilized hydrocarbon material is effectuated by displacement of the injected production-stimulating fluid, by the mobilized hydrocarbon material, in response to density differences.
That portion of the communication zone 118, through which the mobilized hydrocarbon material is conducted via such displacement process (i.e. gravity drainage), can be referred to as a vapour chamber 118A. In those embodiments where the production-stimulating fluid includes steam, such vapour chamber 118A is commonly referred to as a "steam chamber". Relatedly, a liquid level 108 is defined between the accumulated liquid material 122 and the vapour chamber and characterized by a vertical depth "VDo" below the surface 110. Where the interface is defined at a vertical depth which intersects the production well 102, correspondingly, there is defined a liquid level 108 within the production well 102, defining the liquid level within the production well 102, and is also characterized by a vertical depth "VD1" below the surface 110, equal to that of vertical depth VD of the interface 108.

[0056] In some operational implementations, for example, the gas/liquid interface defined by the liquid level 108 corresponds to an interface defined within the interwell region 120, between the horizontal section 114B of the injection well 114 and the horizontal section 102B of the production well 102. In such operational implementations, the liquid material 122 is co-operatively emplaced relative to the injection well 114 such that there is an absence of interference, by the liquid material 122, to injection of the production-stimulating fluid into the reservoir via the injection well 114, while interference, by the liquid material 122, to short-circuiting by the production-stimulating fluid 102, is established. When the interface 108 is disposed above the injection well 114, the liquid material 122 interferes with injection of the production-stimulating fluid via the injection well 114, thereby interfering with production of the hydrocarbon material from the reservoir 116.
Under these conditions, the injection well 114 is referred to as being flooded. When the interface 108 is disposed below the production well, flow communication is established between the injector well 114 and the production well 102 such that the production-stimulating fluid, injected from the injector well 114, is conductible directly to the production well 102 without having transferred some of its heat to Date Recue/Date Received 2022-02-03 hydrocarbon material within the reservoir 116, thereby contributing to process inefficiencies.

[0057] In parallel, as the mobilized hydrocarbon material drains to the bottom portion 118B of the communication zone 118, space previously occupied by the hydrocarbon material within the reservoir 116 becomes occupied by the injected production-stimulating fluid, thereby exposing a fresh hydrocarbon material surface for receiving heat from the production-stimulating fluid (typically, by conduction).
This repeated cycle of heating, mobilization, drainage, and establishment of heat transfer communication between the production-stimulating fluid and a freshly exposed hydrocarbon material source results in the growth of the vapour chamber 118A (e.g. steam chamber) of the communication zone 118, with the freshly exposed hydrocarbon material being disposed along an edge of the vapour chamber. In some embodiments, for example, the growth of the vapour chamber 118A is upwardly, laterally, or both, and, typically, extends above the horizontal section 114B of the injection well 114.

[0058] In some embodiments, for example, where, in implementing the thermally-stimulated gravity drainage-based hydrocarbon production process, the production-stimulating fluid includes steam, the process that is effecting this production can be steam-assisted gravity drainage ("SAGD") or expanding solvent steam-assisted gravity drainage ("ES-SAGD").

[0059] Referring to Figure 3, a fiber optic cable 104 is also installed within the production well 102 for detecting the temperature of the fluids within the production well 102. The fiber optic cable extends from the surface 110, down through the vertical section 102A of the production well 102, and then extends into and along the horizontal section 102B of the production well 102. In some embodiments, for example, the fiber optic cable 104 can be mounted on a slave string 122 installed within the production well 102. In some embodiments, for example, the fiber optic cable 104 is deployed in the production well 102 via coiled tubing, which can allow the cable 104 to be deployed and removed for shorter surveys of the production well 102.
Date Recue/Date Received 2022-02-03

[0060] Liquid material will be emplaced within the vertical section 102A
of the production well 102. Gaseous material will be emplaced above the liquid material within the production well. Although the liquid level 108 can be relatively clearly delineated, there can be some downhole conditions which result in a foamy top at the liquid level 108. This foamy top is generally comprised of a dispersion of gas in a liquid phase with thin films of the liquid (lamella) acting as separators.

[0061] The fiber optic cable 104 can be designed to withstand the harsh downhole environments, for example high temperatures (e.g. up to 500 F) and high pressures (e.g. up to 5000 psi). The fiber optic cable 104 can be deployed downhole in order to obtain and monitor subsurface temperature data which is representative of subsurface temperature data of the reservoir 112, as is discussed below. The fiber optic cable 104 is generally a continuous cable that extends from the surface 110 into and along the vertical and horizontal sections of the production well such that the temperatures can be monitored from the surface, away from the harsh downhole environment. In this regard, a single piece of equipment, the fiber optic cable 104, can be deployed in the production well 102 and monitor temperatures using distributed temperature sensing (DTS) throughout the production well 102 during the operational life of the production well 102.

[0062] In many hydrocarbon producing systems, fiber optic cables 104 are deployed in the production well 102 primarily to monitor the temperatures in the horizontal section 102B of the production well 102. Such monitoring allows operators to identify leaks, monitor fluids and equipment in the horizontal section 102B and monitor fluid flow. In order to reach the horizontal section 102B, the fiber optic cable 104 must pass through the vertical section 102A. But, in typical operations, the portion of the fiber optic cable 104 in the vertical section 102A is not used and thus there is a substantial amount of information regarding the temperatures in the vertical section 102A that is underutilized.

[0063] Information about the depth of the liquid level 108 is used for a variety of purposes, for example, monitoring the performance of the SAGD system, Date Recue/Date Received 2022-02-03 identifying bottom hole pressure (BHP), and evaluating productivity and/or deliverability of the well.

[0064] The production well 102 will have surface controls which allow operators and engineers to monitor the various equipment and sensed data from the well. These surface controls can include a system controller that comprises a control and data acquisition system or other controller which allows operators and engineers to observe the sensed data from a variety of components in the production well 102 and the injection well 114. The production well 102 can have instruments or sensors, including the fiber optic cable 104, which can monitor various parameters in the well, for example, pressure, temperature, flow properties, pump speed, pump torque, motor frequency etc. These parameters can be sensed from the instrumentation and the resulting data can be sent to the system controller. The system controller can continuously, or in discrete intervals, receive the data from the down hole instruments, and store and monitor that data overtime.

[0065] Conventionally, the liquid level 108 is determined using "subcool".

Subcool represents a temperature difference between the injector and the producer well. In particular, subcool is determined as the difference between the steam saturation temperature of the steam injector and the production temperature of the producer. Although subcool is frequently used to determine the liquid level 108, it is often inaccurate and merely represents a proxy for the liquid level 108. The identification of subcool as corresponding to the liquid level 108 is generally based on rough estimates based on industry experience, but it can vary depending on other conditions within the production well 102.

[0066] Bottom hole pressure (BHP) has also been used to determine the liquid level 108 in a production well 102. BHP is the pressure that is measured at the bottom of the vertical section 102A of the production well 102. In most SAGD
operations, there is instruments, such as pressure sensors, deployed downhole, that can sense the BHP. The liquid level is generally calculated from BHP
using equation (1) below:

Date Recue/Date Received 2022-02-03 BHP¨Sur face Casing Pressure Liquid level = (1) emulsion densityxgravitational constant Where emulsion density is the density of the fluid in the well 102 and the gravitational constant is a constant value. Emulsion density is a known value and will vary depending on the composition of the fluid in the production well 102.
Surface casing pressure is a known value related to the pressure in the casing near the surface 110.

[0067] Bottom hole pressure itself is a useful parameter to monitor as it can indicate certain downhole conditions. For example, when BHP is too high, it could cause a weak formation to fracture, resulting in the loss of reservoir fluids.

However, instrumentation used to detect and monitor BHP is often inaccurate and as such, there can be times harmful operating conditions are missed or noticed too late due to inaccurate BHP readings.

[0068] In order to determine the liquid level 108 in the vertical section of the production well 102, the fiber optic cable 104 is used to gather a series of temperature measurements at various vertical depths in the vertical section 102A.
In some examples, the temperature measurements are detected at equally spaced depth intervals, for example every 1 meter, 5 meters or 10 meters. In other examples, the fiber optic cable 104 can detect the temperature measurements as a function of depth, such that the system controller can produce a temperature versus depth profile. The depth intervals, in which the temperature measurements are taken can be altered through the system controller, such that the temperature measurements can be taken at any desired depth interval. For example, in a deeper SAGD well, a depth interval of 5 meters can be sufficient, but for shallower SAGD
wells, it can be more appropriate to use smaller depth intervals.

[0069] The system 100 gathers the temperature measurements corresponding to each depth. Having gathered the temperature measurements corresponding to the various depths, each of the temperature measurements must be assessed. In assessing each temperature measurements, two variables are Date Recue/Date Received 2022-02-03 important: the change in temperature and a temperature variability factor, related to the surrounding temperatures.

[0070] Figure 3 depicts a close up of the vertical section 102A of the production well 102 along with three depths, D1, D2, and D3, for which the change in temperature and the variability factor will be discussed. Although Figure 3 only includes three different depths from which temperature is gathered, it will be understood that such depth interval would extend along the entire length of the vertical section 102A of the production well 102 such that the temperature throughout this length can be monitored. As an example, the change in temperature and the variability factor will be discussed with respect to the depth, Dl. The following relates to determining whether the liquid level occurs at D1, based on the change in temperature and the variability factor at Dl.

[0071] The change in temperature relates to a change at the depth being evaluated, in this case D1, compared to a standard, which can be a known temperature within the liquid. In some examples, the known temperature in the liquid is the temperature measured at the pump intake. In some examples, the pump intake temperature can be detected by a separate temperature sensor located at the pump intake. In other examples, the pump intake can be located at a known depth along the fiber optic cable 104. The known temperature in the liquid need not be pump intake temperature; it can be any temperature that is gathered from a depth in the vertical section 102A of the production well 102 that is known to be submersed in the fluid. Pump intake temperature can be convenient in this regard as the pump intake must always be submersed in the fluid in order for the pumping system to operate normally. The only time that the pump intake is not submersed, is either when the system 100 has been flushed or there is an issue with the system 100 such that it will not produce fluid. In either of these circumstances, the pump would likely be taken out of operation to evaluate the reasons that the pump intake was not submersed. As such, assuming that the system is operating normally, the pump intake temperature can typically be used as the known temperature in the liquid, as it will be submersed in the fluid during normal operation.

Date Recue/Date Received 2022-02-03

[0072] Change in temperature can be determined based on equation (2) below:
TemperatureFibre(D1)¨TemperatureKnown Change in Temperature(D1) =
(2) TemperatureKnown Where Change in Temperature(D1) is the change in temperature variable that is being evaluated at a depth=D1; Tennperaturenbre(D1) is the temperature detected by the fiber optic cable 104 at depth=D1; and TemperatureKnown is the known temperature in the liquid.

[0073] This change in temperature helps determine the liquid level because the temperature below the liquid level will likely vary a small amount, for example due to solids or particulates in the fluid, the fluid flow, the proximity of the fiber optic cable 104 to other downhole equipment etc. However, when the fiber optic cable 104 transitions from being submersed in the fluid into the gas above, there will be a change in temperature. By comparing each of the temperatures at the various depth intervals to the known temperature in the liquid, the system 100 can detect when such a change in temperature is sufficiently large to indicate where in the vertical section 102A, the fiber optic cable 104 transitions from being submersed in the fluid to being surrounded by a gaseous mixture. In transitioning between liquid and gas at the gas/liquid interface defined at the liquid level 108, the different states can have varying heat capacities, which can result in the change in temperature used to determine the location of the liquid level.

[0074] The variability factor of the temperatures around D1 is determined in relation to the temperatures gathered from the depths above Dl. In Figure 3, these depths are D2 and D3. The variability factor is calculated by taking the standard deviation of the sensed temperatures at depths D1, D2 and D3. IN some embodiments, the variability factor is calculated by taking the standard deviation of the changes in temperature at depths D1, D2, and D3 relative to the known temperature (e.g. pump intake temperature). Although the example of Figure 3 includes three depths (D1, D2, and D3), the variability factor can be determined based on more than three depths. The number of depths considered when Date Recue/Date Received 2022-02-03 determining the variability factor can be varied based on the depth of the well, the depth intervals at which temperature is being measured, the fluid composition in the well and other well parameters. However, at least three depths, including the depth being evaluated (i.e. D1), should be used in calculating the variability factor in order to adequately represent the fluctuating temperatures.

[0075] Standard deviation is a measure of the amount of variation or dispersion of a set of values. The variability factor evaluates the temperatures measured at the depths directly above the depth being analyzed (e.g. D1), but not those below that depth. The temperature fluctuations are likely to occur in the foamy top above the liquid level 108, in part due to the different phases in the foamy top (i.e. gas dispersed in liquid). In contrast, if the depths below D1 had fluctuating temperatures, this would likely be more indicative that the liquid level is somewhere below Dl. Thus, when evaluating whether the liquid level 108 is at depth D1, it is only necessary to evaluate the variability factor with respect to the depths above D1 (i.e. D2 and D3).

[0076] The change in temperature and the variability factor can be assessed at depths throughout the length of the vertical section 102A. For example, the temperatures can be gathered in discrete depth intervals. In some embodiments, the depth intervals will vary depending on the total depth of the production well 102. In an example embodiment, these depth intervals are 5 meters. In this regard, each of the change in temperature and the variability factor would be generated for each 5 meter depth interval. For example, where depth is measured from the surface 110 of the production wellbore, if D1= 100 meters, D2 and D3 would be 95 and 90 meters respectively. Having evaluated each of the depths in the vertical section 102A, the liquid level can be determined based on three possible conditions: a rapid change in temperature; high fluctuations in temperature above; and a combination thereof.

[0077] The first condition, a rapid change in temperature, is identified when the change in temperature at the depth, D1, is sufficiently large and there is some fluctuating temperatures above. In some examples, this condition is found when Date Recue/Date Received 2022-02-03 the temperature change at D1 is greater than 10% and the variability factor at is greater than 60%. Temperature in the vertical section 102A will generally be highest in the lower end of the vertical section 102A, where it is closer to the fluid that has been heated by the high pressure steam. Temperatures will gradually decline in the fluid above the bottom of the vertical section 102A, for example, due to heat being lost to the surroundings. However, this gradual decline in temperature measured above the lower end of the vertical section 102a will be relatively small compared to the change in temperature seen at the gas/liquid interface defined at the liquid level 108, where the fluid changes states.
Although this condition primarily relies on a large change in temperature at D1, there must also be some fluctuations in the temperatures above Dl. By monitoring both the change in temperature and the variability factor in this manner, the liquid level 108 will only be detected where there is a sufficiently large change in temperature and some variability in the temperatures above. This ensures that, for example, a single piece of "bad data" indicating a large change in temperature below the liquid level 108, does not result in an incorrect liquid level 108 identification. Table 1 below includes example temperature data that satisfies this first condition.
Table 1: Example temperature data for condition 1 (rapid change in temperature) Pump Intake Temp ( C) 192.55 Temperature Change in Temp Ref. Depth (m) ( C) from Intake (%) D3 494.2 168.97 12.25%
D2 499.2 169.58 11.93%
D1 504.2 168.35 12.57%
Variability factor (%) 61.50% ,

[0078] In the example data of Table 1, the known temperature in the liquid (in this case the pump intake temperature) is 192.55 C. In this example, the fiber optic cable 104 has been configured to gather temperatures along its length in meter intervals. In this example, D1 corresponds to a length of 504.2 meters of fiber optic cable 104; D2 corresponds to a length of 499.2 meters of fiber optic Date Recue/Date Received 2022-02-03 cable 104; and D3 corresponds to a length of 494.2 meters of fiber optic cable 104, each measured from the surface 110. Using equation (2) above, D1 has a corresponding change in temperature of 12.57% relative to the pump intake temperature. The variability factor is 61.50%, which is the standard deviation of the temperatures measured at D1, D2, and D3. In this example, at D1, the change in temperature is greater than 10% relative to the pump intake and the variability factor is greater than 60%. Accordingly, in this example, the liquid level 108 is located at a depth of 504.2 meters from the start of the fiber optic cable 104.

[0079] The second condition, high fluctuations in temperatures above, is identified where there is some change in temperature, that is smaller than the first condition, and a higher variability factor at that depth. In some examples, this condition is found when the temperature change at D1 is greater than 2.5% and the variability factor at D1 is greater than 300%. Although it is expected that, at the liquid level 108, there will be a relatively large change in temperature compared to the known temperature in the liquid, it is possible that such a temperature change will not be seen at the discrete depth interval. For example, when depths are being evaluated every 5 meters, it is possible that the liquid level 108 is actually somewhere in between the depths being evaluated. In this regard, if, for example, the depth at which a temperature is being gathered that is closest to the liquid level 108 is above the liquid level, it would likely be within the foamy top above the liquid level 108. This could result in the change in temperature compared to the known temperature in the liquid being smaller than is needed to indicate liquid level 108 itself. However, the fact that the depth is within the foamy top would result in much higher fluctuations in temperature, due to the foamy top around and above the depth being evaluated. In this regard, the liquid level can be identified where there is some small change in temperature detected along with a sufficiently high variability factor. Table 2 below includes example temperature data that satisfies this second condition.
Table 2: Example temperature data for condition 2 (fluctuations above) Pump Intake Temp ( C) 192.55 Date Recue/Date Received 2022-02-03 Temperature Change in Temp Ref. Depth (m) ( C) from Intake (0/0) D3 524.2 190.21 1.22%
D2 529.2 194.46 0.99%
D1 534.2 198.08 2.87%
Variability Factor (0/0) 393.92% ,

[0080] In the example data of Table 2, the known temperature in the liquid (in this case the pump intake temperature) is 192.55 C. In this example, the fiber optic cable 104 has been configured to gather temperatures along its length in meter intervals. In this example, D1 corresponds to a length of 534.2 meters of fiber optic cable 104; D2 corresponds to a length of 529.2 meters of fiber optic cable 104; and D3 corresponds to a length of 524.2 meters of fiber optic cable 104, each measured from the surface 110. Using equation (2) above, D1 has a corresponding change in temperature of 2.87% relative to the pump intake temperature. The variability factor is 393.92%, which is the standard deviation of the temperatures measured at D1, D2, and D3. In this example, at D1, the change in temperature is greater than 2.5% relative to the pump intake and the variability factor is greater than 300%. Accordingly, in this example, the liquid level 108 is located at a depth of 534.2 meters from the start of the fiber optic cable 104.

[0081] The third condition represents a combination of the first two conditions. In some examples, this condition is found when the temperature change at D1 is greater than 7% and the variability factor at D1 is greater than 100%. This condition represents a middle ground between the first two conditions, in which neither the change in temperature or the variability factor are sufficiently high on their own to indicate the liquid level, but the combination of these variables having moderate values (e.g. in between the values in the first two conditions) is sufficient to indicate the liquid level 108. Table 3 below includes example temperature data that satisfies this second condition.
Table 3: Example temperature data for condition 3 (moderate change in Date Recue/Date Received 2022-02-03 temperature and fluctuations above) Pump Intake Temp ( C) 192.55 Temperature Change in Temp Ref. Depth (m) ( C) from Intake (%) D3 454.2 180.42 6.30%
D2 459.2 182.51 5.21%
D1 464.2 178.11 7.50%
Variability Factor _. %)1111111111111111111111111111111 21:)9%

[0082] In the example data of Table 3, the known temperature in the liquid (in this case the pump intake temperature) is 192.55 C. In this example, the fiber optic cable 104 has been configured to gather temperatures along its length in meter intervals. In this example, D1 corresponds to a length of 464.2 meters of fiber optic cable 104; D2 corresponds to a length of 459.2 meters of fiber optic cable 104; and D3 corresponds to a length of 454.2 meters of fiber optic cable 104, each measured from the surface 110. Using equation (2) above, D1 has a corresponding change in temperature of 7.50% relative to the pump intake temperature. The variability factor is 220.09%, which is the standard deviation of the temperatures measured at D1, D2, and D3. In this example, at D1, the change in temperature is greater than 7% relative to the pump intake and the variability factor is greater than 100%. Accordingly, in this example, the liquid level 108 is located at a depth of 464.2 meters from the start of the fiber optic cable 104.

[0083] There is a need for each of these three conditions in order to overcome certain variables in the production well 102. For example, if the fiber optic cable 104 is installed on the outside of the production tubing 112, there can be some temperature lost between the fluid in the production tubing 112 and the fiber optic cable 104 through the material of the production tubing 112. This could present as a smaller change in temperature, such that the change in temperature is not large enough to trigger the first condition. In this regard, the second or third conditions would be triggered at the gas/liquid interface defined at the liquid level 108, where the fluctuating temperatures above, in combination with the smaller change in Date Recue/Date Received 2022-02-03 temperature, would be sufficiently large to indicate the liquid level.
Similarly, if there is less foam above the gas-liquid interface, for example due to less turbulence in the fluid, the variability factor can be too small to trigger the second condition, but in combination with a moderate (or substantial) change in temperature, either of the first or third conditions can be triggered.

[0084] The depth of the liquid level, determined based only on the temperatures gathered from the fiber optic cable 104, is based on the length of fiber optic cable 104. For example, a depth of 20 meters in the fiber optic cable 104 would represent 20 meters of length of fiber optic cable 104. However, in some SAGD operations, the vertical section 102A of the production well 102 is not perfectly vertical (i.e. has a slight incline/decline) and thus 20 meters of fiber optic cable 104 would be correspond with a true vertical depth (TVD) of 20 meters.
Thus, it can be beneficial to convert the depth of the liquid level as measured by through the fiber optic cable 104 into a true vertical depth. In this regard, a well directional survey can be used to obtain measurements that generate a 3-dimensional well path. Well directional surveys are generally completed for each SAGD well and provide a better understanding of the geometry of the well. Various parameters are obtained in the directional survey, including measured depth (i.e. the actual depth of the hole drilled to any point along the wellbore; inclination (e.g. an inclination of 0 would correspond to a true vertical well and an inclination of 90 would correspond to a true horizontal well), and hole direction. These parameters are gathered and then 3D coordinates can be generated to accurately depict the well geometry. In this regard, it is possible to obtain the TVD of the liquid level (i.e. the vertical depth below the surface 110) based on the well directional survey.

[0085] Identifying the liquid level in a production well 102 has a variety of benefits. In many SAGD operations, electrical submersible pumps (ESP) are used to pump the reservoir fluids to the surface. ESPs include a motor in line with a centrifugal pump, with the motor installed below the pump to allow the reservoir fluids to act as a coolant for the motor. In this regard, it can be important to know the liquid level to ensure that the ESP components are submersed in the fluid.
If, for example the liquid level was nearing the depth at which the pump intake or the Date Recue/Date Received 2022-02-03 motor are located, the system 100 can provide a notification or flag to operators and engineers that the liquid level is nearing or has reached impermissible depths.
In some examples, there can be threshold depth above the pumping system 106, below which operating the well can cause harm to the equipment or require further actions. In this regard, the system 100 can notify or alert operators and engineers when the liquid level is detected at or near this threshold depth.

[0086] Information about the liquid level 108 can also be generated over time. The fiber optic cable 104 can be permanently installed in the production wellbore such that temperatures can be gathered throughout the operational lifetime of the production wellbore. These temperatures measurements can be collected and stored in the system controller, allowing operators and engineers to monitor the temperatures, and resulting liquid level, throughout the operation of the production wellbore.

[0087] In some embodiments, for example, it can be useful to compare the liquid level 108 to the location of the flow discharging communicator used for injecting production-stimulating fluid. If the liquid level 108 is below the flow discharging communicator, there can be flooding in the injector. In this regard, in some embodiments, the system 100 can present an indication, such as an alert or notification, through the system controller, that there is potential injector flooding.
In other embodiments, the system 100 can increase the rate at which the hydrocarbon material is being produced in order to compensate for the injector flooding. If, on the other hand, the liquid level 108 is above the flow receiving communicator, there can be a steam coning condition such that production-stimulating fluid (e.g. steam) is leaking into the production well, resulting in the production-stimulating fluid being wasted. In this regard, in some embodiments, the system 100 can present an indication, such as an alert or notification, through the system controller, that there is potential steam coning condition. In other embodiments, the system 100 can decrease the rate at which the hydrocarbon material is being produced in order to compensate for the steam coning condition.

Date Recue/Date Received 2022-02-03

[0088] Knowing the liquid level 108 has other benefits to SAGD
operations.
Although bottom hole pressure (BHP) is often measured directly using downhole instruments, these instruments often provide inaccurate readings. However, BHP

can be determined using the liquid level. BHP generally corresponds to the weight of the fluid in the vertical section 102A of the production well 102.
Accordingly, equation (1) above can be re-arranged to determine BHP from liquid level, as follows:
BHP = (emulsion density x gravitational constant x D(jquid level) -I- Surface Casing Pressure Where emulsion density is a known property of the fluid in the well, gravitational constant is a constant that represents the force of gravity, TVaiquid level .s i the true vertical depth corresponding to the detected liquid level, and surface casing pressure is a known pressure measured in the casing at or near the surface.
BHP is conventionally monitored in order to ensure well integrity. For example, as a BHP
that is too high can cause weak formations to fracture and low BHP can result in an influx of formation fluids into the wellbore. Since BHP instrumentation often provides inaccurate BHP readings, the use of liquid level more accurately determine BHP will allow operators and engineers to monitor the well operation and more readily identify possible issues as a result of BHP being too low or too high.
The calculated BHP can also be used to verify the measured BHP from the downhole instruments, for example, to identify when certain instruments should be replaced.
Moreover, BHP can be calculated and monitored over time, such that concerning trends can be identified.

[0089] Another use for the detected liquid level 108 is well productivity and/or deliverability. Well testing is often done on SAGD wells in order to determine well productivity, announg other things. Well testing can be done using a variety of different well tests, such as flow tests, drill-stem tests, drawdown tests, multi-rate tests, productions tests, buildup tests etc. When determining well productivity, the well test is generally capable of providing the total volume of fluid available from the well. The total volume of fluid in the well can be broken out into two Date Recue/Date Received 2022-02-03 components: the volume of fluid in the reservoir 116; and the volume of fluid in the vertical section 102A. Using the liquid level 108, in addition to the emulsion density and the known well geometry, for example, obtained through the well directional survey, it is possible to determine the total volume of fluid in the vertical section 102A at a given time. Having determined the total volume of fluid in the vertical section 102A, the total volume of fluid in the reservoir 116 can easily be determined by subtracting the volume of fluid in the vertical section 102A
from the total well volume.

[0090] As the well operates, the volume of fluid within the vertical section 102A and the reservoir 116 will vary. Using liquid level, which can be monitored throughout the operation of the well, volume of fluid in the vertical and horizontal sections 102A, 102B can also be monitored over time. By monitoring these volumes over time, operators and engineers can observe trends and identify issues in the well operation. For example, the total well production can reflect normal operation (i.e. the well is producing the expected amount of fluid), however if the volume of fluid in the vertical section 102A is decreasing while the volume of fluid in the reservoir 116 remains the same, there can be some issues downhole that are causing no fluid to be drawn from the reservoir 116.

[0091] In addition to monitoring the volumes in the vertical section 102A
and the reservoir 116, the flow rates into and out of these sections can also be monitored. In this regard, lower or higher flow rates into or out of either the vertical section 102A or reservoir 116 can indicate certain issues or conditions within the well. For example, if the total flow rate of the well is reduced, a corresponding reduced flow rate from the vertical section 102A could indicate issues with the pumping system. Similarly, a corresponding reduction in the flow rate from the reservoir 116 could indicate issues arising within the reservoir 116 or the horizontal section 102B. Additionally, monitoring the flow rates and the volumes within the vertical section 102A and the reservoir 116 allows operators to evaluate whether there is sufficient fluid in the reservoir 116 to operate the well.
For example, once the fluid reservoir 116 reaches sufficiently low volume, it can no Date Recue/Date Received 2022-02-03 longer be useful to produce fluid from that reservoir 116, despite there being sufficient fluid in the vertical section 102A.

[0092]
The present disclosure can be embodied in other specific forms without departing from the subject matter of the claims. The described example implementations are to be considered in all respects as being only illustrative and not restrictive. Selected features from one or more of the above-described implementations can be combined to create alternative implementations not explicitly described, features suitable for such combinations being understood within the scope of this disclosure.
Date Recue/Date Received 2022-02-03

Claims (72)

WHAT IS CLAIMED IS:

1. A method for identifying a liquid level within a reservoir from which hydrocarbon material is being produced by a thermally-stimulated gravity drainage-based hydrocarbon production process, comprising:
obtaining subsurface temperature data representative of subsurface temperatures within the reservoir, and identifying a liquid level within the reservoir based on the obtained subsurface temperature data.

2. The method as claimed in claim 1, wherein the obtained temperature data comprises, for each one of a plurality of vertical depths from the surface, vertical depth-based subsurface temperature information.

3. The method as claimed in claim 2, wherein the vertical depth-based subsurface temperature information is vertical depth-based subsurface temperature information within a production well through which the hydrocarbon material is being produced.

4. The method as claimed in claim 2 or 3, wherein successive depths, of the plurality of depths, are spaced apart from each other by at least five (5) metres.

5. The method as claimed in any one of claims 2 to 4, wherein the vertical depth-based subsurface temperature information includes: (i) temperature that is representative of the temperature of the reservoir at the vertical depth, and (ii) a temperature variability factor that is representative of the variability of the temperature of the reservoir at the vertical depth.

6. The method as claimed in claim 5, wherein the temperature variability factor is a standard deviation of a set of values defined by: (i) the temperature information that is representative of a temperature of the reservoir at the vertical depth and (ii) for each one of at least two shallower vertical depths, of the plurality Date Recue/Date Received 2022-02-03 of vertical depths, disposed immediately above the vertical depth, independently, the temperature information that is representative of the temperature of the reservoir at the shallower vertical depth.

7. The method as claimed in claim 6, wherein each one of (i) the temperature information, that is representative of the temperature of the reservoir at the vertical depth, and (ii) the temperature information for each one of the at least two shallower vertical depths, is defined relative to a standard, and the standard is a known temperature within the liquid.

8. The method as claimed in claim 7, wherein the temperature information, that is representative of the temperature of the reservoir at the vertical depth, is based on a relative difference between temperature that is sensed at the vertical depth and the standard, and, for each one of at least two shallower vertical depths, of the plurality of vertical depths, disposed immediately above the vertical depth, independently, the temperature information, that is representative of the temperature of the reservoir at the shallower vertical depth, is based on a relative difference between temperature that is sensed at the shallower vertical depth and the standard.

9. The method as claimed in claim 8, further comprising, for each one of:
(i) the temperature that is sensed at the vertical depth, sensing the temperature with a respective temperature sensor, and (ii) for the temperature that is sensed at each one of the at least two shallower vertical depths, sensing the temperature with a respective temperature sensor.

10. The method as claimed in claim 9, wherein the respective temperature sensor is a fiber optic cable configured to sense temperatures along a length of the fiber optic cable.

11. The method as claimed in any one of claims 7 to 10, wherein the known temperature within the liquid is a temperature representative of the temperature of Date Recue/Date Received 2022-02-03 the liquid within a pump disposed within a production well for effectuating production of the hydrocarbon material.

12. The method as claimed in any one of claims 7 to 11, wherein the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which:
(i) the temperature information is representative of a temperature of the reservoir which exceeds a predetermined value and (ii) the variability factor exceeds a predetermined value.

13. The method as claimed in any one of claims 7 to 11, wherein the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which:
(i) the temperature information is representative of a temperature of the reservoir which exceeds 10% and (ii) the variability factor exceeds 60%.

14. The method as claimed in any one of claims 7 to 11, wherein the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which:
(i) the temperature information is representative of a temperature of the reservoir which exceeds 2.5% and (ii) the variability factor exceeds 300%.

15. The method as claimed in any one of claims 7 to 11, wherein the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which:
(i) the temperature information is representative of a temperature of the reservoir which exceeds 7% and (ii) the variability factor exceeds 100%.

16. The method according to any one of claims 2 to 15, wherein the plurality of vertical depths from the surface are depths from the surface relative to a well geometry and do not correspond to true vertical depths, the method further comprising:

Date Recue/Date Received 2022-02-03 determining a true vertical depth (TVD) at the vertical depth of the liquid level based on the well geometry.

17. The method as claimed in claim 16, wherein the well geometry is obtained from a well directional survey.

18. The method as claimed in claim 16 or 17, further comprising determining a bottom hole pressure, wherein the bottom hole pressure is calculated by adding a surface casing pressure to the product of the true vertical depth, a gravitational constant and a fluid emulsion density, wherein the surface casing pressure is measured at the surface of the wellbore and the fluid emulsion density is a property of the fluid in the wellbore.

19. The method as claimed in claim 18, further comprising comparing the determined bottom hole pressure to a measured bottom hole pressure.

20. The method as claimed in claim 18 or 19, further comprising determining a volume of wellbore fluid in a vertical section of the production well based on the true vertical depth at the vertical depth of the liquid level, the geometry of the well, and a fluid emulsion density.

21. The method as claimed in claim 20, further comprising obtaining a total well production volume from a well test of the production well, and determining a reservoir capacity by subtracting the volume of wellbore fluid in the vertical section of the production well from the total well production volume.

22. The method as claimed in claim 21, further comprising injecting a chemical agent for stimulating production in response to determining that the reservoir capacity is below a low production threshold.

23. The method as claimed in any one of claims 1 to 22, further comprising injecting a heating fluid into the reservoir for heating the hydrocarbon material such Date Recue/Date Received 2022-02-03 that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material.

24. The method as claimed in claim 23, wherein the heating fluid includes steam.

25. The method as claimed in any one of claims 1 to 24, wherein the hydrocarbon material includes bitumen.

26. The method as claimed in any one of claims 1 to 25, wherein the thermally-stimulated gravity drainage-based hydrocarbon production process is SAGD.

27. The method as claimed in any one of claims 1 to 25, wherein the thermally-stimulated gravity drainage-based hydrocarbon production process is ES-SAGD.

28. The method as claimed in any one of claims 2 to 15, further comprising, via an injection well, injecting a heating fluid into the reservoir for heating the hydrocarbon material such that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material, and, in response to the determination that the vertical depth, from the surface, of the liquid level, is below a flow discharging communicator, through which a production-stimulating fluid is being discharged into a production well from the reservoir, by less than a predetermined value, increasing the rate at which the hydrocarbon material is being produced from the reservoir via the production well.

29. The method as claimed in any one of claims 2 to 15, further comprising, via an injection well, injecting a heating fluid into the reservoir for heating the hydrocarbon material such that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material, and, in response to the determination that the vertical depth, from the surface, of the liquid level, is below a flow discharging communicator, through which a production-stimulating fluid is being discharged into the reservoir from the injection well, by less than a Date Recue/Date Received 2022-02-03 predetermined value, presenting an indication of a potential injector flooding condition via an output device.

30. The method as claimed in any one of claims 2 to 15, further comprising, via an injection well, injecting a heating fluid into the reservoir for heating the hydrocarbon material such that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material, and, in response to the determination that the vertical depth, from the surface, of the liquid level, is above a flow receiving communicator, through which the hydrocarbon material is being conducted into a production well from the reservoir, by less than a predetermined value, decreasing the rate at which the hydrocarbon material is being produced from the reservoir via the production well.

31. The method as claimed in any one of claims 2 to 15, further comprising, via an injection well, injecting a heating fluid into the reservoir for heating the hydrocarbon material such that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material, and, in response to the determination that the vertical depth, from the surface, of the liquid level, is above a flow receiving communicator, through which the hydrocarbon material is being conducted into a production well from the reservoir, by less than a predetermined value, presenting an indication of a potential steam coning condition via an output device.

32. The method as claimed in any one of claims 28 to 31, wherein the heating fluid includes steam.

33. The method as claimed in any one of claims 28 to 32, wherein the hydrocarbon material includes bitumen.

34. The method as claimed in any one of claims 28 to 33, wherein the thermally-stimulated gravity drainage-based hydrocarbon production process is SAGD.

Date Recue/Date Received 2022-02-03

35. The method as claimed in any one of claims 28 to 34, wherein the thermally-stimulated gravity drainage-based hydrocarbon production process is ES-SAGD.

36. A system for identifying a liquid level within a reservoir from which hydrocarbon material is being produced by a thermally-stimulated gravity drainage-based hydrocarbon production process, the system comprising:
one or more processor devices and one or more memories storing machine-executable instructions which, when executed by the one or more processor devices, cause the system to perform the method of any one of claims 1 to 35.

37. A system for identifying a liquid level within a reservoir from which hydrocarbon material is being produced by a thermally-stimulated gravity drainage-based hydrocarbon production process, the system comprising:
a temperature sensor, one or more processor devices, and one or more memories storing machine-executable instructions, which, when executed by the one or more processor devices, cause the system to obtain subsurface temperature data representative of subsurface temperatures within the reservoir, using the temperature sensor, and identify a liquid level within the reservoir based on the obtained subsurface temperature data.

38. The system as claimed in claim 37, wherein the temperature sensor is a distributed temperature sensing (DTS) device, configured to sense temperatures along a length of the DTS device.

39. The system as claimed in claim 38, wherein the distributed temperature sensing (DTS) device is a fiber optic cable.

40. The system as claimed in any one of claims 37 to 39, wherein the obtained temperature data comprises, for each one of a plurality of vertical depths from the surface, vertical depth-based subsurface temperature information.

Date Recue/Date Received 2022-02-03

41. The system as claimed in claim 40, wherein the vertical depth-based subsurface temperature information is vertical depth-based subsurface temperature information within a production well through which the hydrocarbon material is being produced

42. The system as claimed in claim 40 or 41, wherein successive depths, of the plurality of depths, are spaced apart from each other by at least five (5) metres.

43. The system as claimed in any one of claims 40 to 42, wherein the vertical depth-based subsurface temperature information includes: (i) temperature that is representative of the temperature of the reservoir at the vertical depth, and (ii) a temperature variability factor that is representative of the variability of the temperature of the reservoir at the vertical depth.

44. The system as claimed in claim 43, wherein the temperature variability factor is a standard deviation of a set of values defined by: (i) the temperature information that is representative of a temperature of the reservoir at the vertical depth and (ii) for each one of at least two shallower vertical depths, of the plurality of vertical depths, disposed immediately above the vertical depth, independently, the temperature information that is representative of the temperature of the reservoir at the shallower vertical depth.

45. The system as claimed in claim 44, wherein each one of (i) the temperature information, that is representative of the temperature of the reservoir at the vertical depth, and (ii) the temperature information for each one of the at least two shallower vertical depths, is defined relative to a standard, and the standard is a known temperature within the liquid.

46. The system as claimed in claim 45, wherein the temperature information, that is representative of the temperature of the reservoir at the vertical depth, is based on a relative difference between temperature that is sensed at the vertical depth and the standard, and, for each one of at least two shallower vertical depths, Date Recue/Date Received 2022-02-03 of the plurality of vertical depths, disposed immediately above the vertical depth, independently, the temperature information, that is representative of the temperature of the reservoir at the shallower vertical depth, is based on a relative difference between temperature that is sensed at the shallower vertical depth and the standard.

47. The system as claimed in claims 45 or 46, wherein the known temperature within the liquid is a temperature representative of the temperature of the liquid within a pump disposed within a production well for effectuating production of the hydrocarbon material.

48. The system as claimed in any one of claims 45 to 47, wherein the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which:
(i) the temperature information is representative of a temperature of the reservoir which exceeds a predetermined value and (ii) the variability factor exceeds a predetermined value.

49. The system as claimed in any one of claims 45 to 47, wherein the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which:
(i) the temperature information is representative of a temperature of the reservoir which exceeds 10% and (ii) the variability factor exceeds 60%.

50. The system as claimed in any one of claims 45 to 47, wherein the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid level, wherein the determined vertical depth is the vertical depth at which:
(i) the temperature information is representative of a temperature of the reservoir which exceeds 2.5% and (ii) the variability factor exceeds 300%.

51. The system as claimed in any one of claims 45 to 47, wherein the identifying a liquid level includes determining a vertical depth, from the surface, of the liquid Date Recue/Date Received 2022-02-03 level, wherein the determined vertical depth is the vertical depth at which:
(i) the temperature information is representative of a temperature of the reservoir which exceeds 7% and (ii) the variability factor exceeds 100%.

52. The system as claimed in any one of claims 40 to 51, wherein the plurality of vertical depths from the surface are depths from the surface relative to a well geometry and do not correspond to true vertical depths, further causing the system to determine a true vertical depth (TVD) at the vertical depth of the liquid level based on the well geometry.

53. The system as claimed in claim 52, wherein the well geometry is obtained from a well directional survey.

54. The system as claimed in claims 52 or 53, further comprising determining a bottom hole pressure, wherein the bottom hole pressure is calculated by adding a surface casing pressure to the product of the true vertical depth, a gravitational constant and a fluid emulsion density, wherein the surface casing pressure is measured at the surface of the wellbore and the fluid emulsion density is a property of the fluid in the wellbore.

55. The system as claimed in claim 54, further comprising comparing the determined bottom hole pressure to a measured bottom hole pressure.

56. The system as claimed in claims 54 or 55, further comprising, based on the true vertical depth at the vertical depth of the liquid level, the geometry of the well, and a fluid emulsion density, causing the system to determine a volume of wellbore fluid in a vertical section of the production well.

57. The system as claimed in claim 56, further comprising obtaining a total well production volume from a well test of the production well, and determining a reservoir capacity by subtracting the volume of wellbore fluid in the vertical section of the production well from the total well production volume.
Date Recue/Date Received 2022-02-03

58. The system as claimed in claim 57, further comprising injecting a chemical agent for stimulating production in response to determining that the reservoir capacity is below a low production threshold.

59. The system as claimed in any one of claims 37 to 58, further comprising injecting a heating fluid into the reservoir for heating the hydrocarbon material such that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material.

60. The method as claimed in claim 59, wherein the heating fluid includes steam.

61. The method as claimed in any one of claims 37 to 60, wherein the hydrocarbon material includes bitumen.

62. The method as claimed in any one of claims 37 to 61, wherein the thermally-stimulated gravity drainage-based hydrocarbon production process is SAGD.

63. The method as claimed in any one of claims 37 to 61, wherein the thermally-stimulated gravity drainage-based hydrocarbon production process is ES-SAGD.

64. The method as claimed in any one of claims 40 to 51, further comprising, via an injection well, injecting a heating fluid into the reservoir for heating the hydrocarbon material such that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material, and, in response to the determination that the vertical depth, from the surface, of the liquid level, is below a flow discharging communicator, through which a production-stimulating fluid is being discharged into a production well from the reservoir, by less than a predetermined value, increasing the rate at which the hydrocarbon material is being produced from the reservoir via the production well.

Date Recue/Date Received 2022-02-03

65. The method as claimed in any one of claims 40 to 51, further comprising, via an injection well, injecting a heating fluid into the reservoir for heating the hydrocarbon material such that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material, and, in response to the determination that the vertical depth, from the surface, of the liquid level, is below a flow discharging communicator, through which a production-stimulating fluid is being discharged into the reservoir from the injection well, by less than a predetermined value, presenting an indication of a potential injector flooding condition via an output device.

66. The method as claimed in any one of claims 40 to 51, further comprising, via an injection well, injecting a heating fluid into the reservoir for heating the hydrocarbon material such that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material, and, in response to the determination that the vertical depth, from the surface, of the liquid level, is above a flow receiving communicator, through which the hydrocarbon material is being conducted into a production well from the reservoir, by less than a predetermined value, decreasing the rate at which the hydrocarbon material is being produced from the reservoir via the production well.

67. The method as claimed in any one of claims 40 to 51, further comprising, via an injection well, injecting a heating fluid into the reservoir for heating the hydrocarbon material such that the hydrocarbon material is mobilized for stimulating the production of the hydrocarbon material, and, in response to the determination that the vertical depth, from the surface, of the liquid level, is above a flow receiving communicator, through which the hydrocarbon material is being conducted into a production well from the reservoir, by less than a predetermined value, presenting an indication of a potential steam coning condition via an output device.

68. The method as claimed in any one of claims 64 to 67, wherein the heating fluid includes steam.

Date Recue/Date Received 2022-02-03

69. The method as claimed in any one of claims 64 to 68, wherein the hydrocarbon material includes bitumen.

70. The method as claimed in any one of claims 64 to 69, wherein the thermally-stimulated gravity drainage-based hydrocarbon production process is SAGD.

71. The method as claimed in any one of claims 64 to 69, wherein the thermally-stimulated gravity drainage-based hydrocarbon production process is ES-SAGD.

72. A non-transitory computer-readable medium storing machine-executable instructions which, when executed by one or more processors, cause the processor to perform the steps of the method of any one of claims 1 to 35.

Date Recue/Date Received 2022-02-03