CA3058854C - Systems and methods for providing real-time solvent conformance along a wellbore and within a reservoir - Google Patents

Abstract

Systems and methods for estimating solvent conformance along a wellbore during a solvent dominated bitumen recovery process are described. The system includes a plurality of temperature sensors distributed along a length of the wellbore, a mass flow meter positioned upstream of a leading outflow region of the wellbore and one or more processors operatively coupled to each temperature sensor and the mass flow meter. The one or more processors are configured to receive a measured temperature of the solvent during injection of the solvent to the reservoir, receive a mass flow rate of the solvent from the mass flow meter; estimate a background temperature along the length of the wellbore, estimate a heat transfer coefficient of the wellbore based on the measured temperatures, and select a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that fits the measured temperatures of the solvent during injection of the solvent from the wellbore to the reservoir.

Description

SYSTEMS AND METHODS FOR PROVIDING REAL-TIME SOLVENT
CONFORMANCE ALONG A WELLBORE AND WITHIN A RESERVOIR
FIELD
[0001] This disclosure relates generally to solvent-dominated bitumen recovery processes, and more specifically to systems and methods for providing real-time solvent conformance along a wellbore and within a reservoir during bitumen recovery processes.
BACKGROUND

[0002] In the oil and gas industry, down-hole monitoring of horizontal wells and observation (0B) wells is used to monitor reservoir solvent conformance and wellbore conformance (the latter which is also referred to as wellbore utilization).

[0003] In cyclic recovery processes, mapping a distribution of injected solvent along the wellbore and within the reservoir is important to cycle injection strategy. Poor solvent conformance along the wellbore and within the reservoir can lead to challenged reservoir management characterized by lower bitumen and solvent recovery.

[0004] If non-uniform conformance is mapped along the wellbore or within the reservoir, the injection parameters of the solvent, such as but not limited to the flow rate, volume targets and the composition, can be adjusted to alter the conformance.
For example, lowering the injection rate of the solvent generally lowers the finger growth rate in the reservoir, effectively reducing the length of dominate finger(s), thereby improving the overall solvent conformance. In another example, adding flow assurance solvent as an injectant can enhance the mixing between the solvent and bitumen within the reservoir.
The enhanced mixing may result in a more uniform solvent front and even distribution of solvent within the reservoir. Furthermore, if wellbore is designed with active controls then the controls can be adjusted to manipulate the distribution of solvent within the wellbore.
SUMMARY

[0005] The present disclosure provides systems and methods for providing real-time solvent conformance along a wellbore and within a reservoir during bitumen recovery process operations.

[0006] In accordance with one broad aspect of this disclosure, a system for estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility is provided. The cyclic recovery process includes cyclic injection of a solvent through a plurality of outflow regions of the wellbore into a reservoir and recovery of a produced fluid from the reservoir. The produced fluid includes solvent, bitumen, water and methane. The system includes a plurality of temperature sensors distributed along a length of the wellbore. Each temperature sensor is configured to measure a temperature of the solvent during injection at a location of the temperature sensor within the wellbore. The plurality of temperature sensors includes at least two leading temperature sensors positioned between a wellhead of the wellbore and a leading outflow region of the plurality of outflow regions. The system also includes a mass flow meter positioned upstream of the leading outflow region of the wellbore. One or more processors are operatively coupled to each temperature sensor and the mass flow meter.
The one or more processors, collectively, are configured to receive a measured temperature of the solvent during injection from each of the plurality of temperature sensors distributed along the wellbore, receive a mass flow rate of the solvent from the mass flow meter, estimate a background temperature along the length of the wellbore, where the estimate of the background temperature is based on an assumption that heat transfer propagates radially from the wellbore from the beginning of injection, estimate a heat transfer coefficient of the wellbore based on the measured temperatures of the solvent at the two leading temperature sensors and the mass flow rate, and select a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that best-fits the measured temperatures from each of the plurality of temperature sensors. The mass distribution provides the estimate of real-time solvent conformance along the wellbore, commonly termed the wellbore utilization, during the cyclic recovery process.

[0007] In accordance with one broad aspect of this disclosure, a system for estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility is provided. The cyclic recovery process includes cyclic injection of a solvent through a plurality of outflow regions of the wellbore into a reservoir and recovery of a produced fluid from the reservoir. The produced fluid includes solvent, bitumen, water and methane. The system includes a plurality of temperature sensors distributed along a length of the wellbore. Each temperature sensor is configured to measure a temperature of the solvent during injection at a location of the temperature sensor within the wellbore. The plurality of temperature sensors includes at least two leading temperature sensors positioned between a wellhead of the wellbore and a leading outflow region of the plurality of outflow regions. The system also includes a mass flow meter positioned upstream of the leading outflow region of the wellbore. One or more processors are operatively coupled to each temperature sensor and the mass flow meter.
The one or more processors, collectively, are configured to receive a measured temperature of the solvent during injection from each of the plurality of temperature sensors distributed along the wellbore, receive a mass flow rate of the solvent from the mass flow meter, estimate a background temperature along the length of the wellbore, where the estimate of the background temperature is based on an assumption that heat transfer propagates radially from the wellbore from the beginning of injection, receive a manual entry of an estimate of a heat transfer coefficient of the wellbore, and select a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that best-fits the measured temperatures of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors, the mass distribution providing the estimate of real-time solvent conformance along the wellbore during the cyclic recovery process.

[0008] In some embodiments, the estimate of the heat transfer coefficient is based on fully developed steady flow of the solvent along the wellbore.

[0009] In some embodiments, the estimate of the heat transfer coefficient is based on at least one of empirical correlations, practical experience or system calibration.

[0010] In some embodiments, the two leading temperature sensors are spaced apart by a pre-determined distance.

[0011] In some embodiments, the two leading temperature sensors are spaced apart by distance in a range of about 10 meters to about 100 meters.

[0012] In some embodiments, the plurality of temperatures sensors includes the two leading temperature sensors and one temperature sensor for each outflow region of the plurality of outflow regions along the wellbore.

[0013] In some embodiments, the system also includes one or more observation wells for estimating solvent conformance within the reservoir during the cyclic recovery process, the solvent conformance within the reservoir being based on the estimate of the real-time solvent conformance along the wellbore.

[0014] In some embodiments, the solvent conformance within the reservoir is estimated by extrapolating a measurement from the one or more observation wells using a lengthwise distribution of the real-time solvent conformance along the wellbore.

[0015] In some embodiments, each of the one or more observation wells is drilled into an expected solvent conformance region of the reservoir.

[0016] In some embodiments, each of the one or more observation wells includes one or more perforations, a bottom-hole temperature sensor and a bottom-hole pressure sensor to detect an arrival of a pressure and temperature front caused by the cyclic injection of the solvent.

[0017] In some embodiments, each of the one or more observation wells includes a vertically distributed heater and a vertically distributed thermal fibre for detecting a change in temperature as the injected solvent contacts the observation well during injection.

[0018] In some embodiments, each of the observation wells includes one or more passive seismic geophones for detecting micro-seismic signals caused by movement of fluid within the reservoir.

[0019] In some embodiments, the system also includes one or more seismic sources positioned on a ground surface within a planar footprint of the reservoir for generating seismic waves; and one or more seismic receivers positioned on the surface of the bitumen recovery facility for recording the seismic waves after they have passed through the reservoir to estimate the solvent conformance within the reservoir.

[00201 In some embodiments, during injection of the solvent, the one or more observation wells include a flow assurance solvent to inhibit plugging within the one or more observation wells during the cyclic injection of the solvent through the wellbore into a reservoir.
[0021] In accordance with another broad aspect of this disclosure, a method of estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility is described. The cyclic recovery process includes cyclic injection of a solvent through a plurality of outflow regions of the wellbore into a reservoir and recovery of a produced fluid from the reservoir. The produced fluid includes solvent, bitumen and water. The method includes receiving at one or more processors a measured temperature of the solvent during injection of the solvent from the wellbore to the reservoir from each of a plurality of temperature sensors distributed along the wellbore, the plurality of temperature sensors including at least two leading temperature sensors positioned between a wellhead of the wellbore and a leading outflow region of the wellbore; receiving a mass flow rate of the solvent from a mass flow meter positioned upstream of the leading outflow region of the wellbore; estimating a background temperature along the length of the wellbore based on an assumption that heat transfer propagates radially from the wellbore from the beginning of injection;
estimating a heat transfer coefficient of the wellbore based on the measured temperatures of the solvent at the at least two leading temperature sensors and the mass flow rate; and selecting a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that best-fits the measured temperatures of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors, the mass distribution providing the estimate of real-time solvent conformance during the cyclic recovery process.
[0022] In accordance with another broad aspect of this disclosure, a method of estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility is described. The cyclic recovery process includes cyclic injection of a solvent through a plurality of outflow regions of the wellbore into a reservoir and recovery of a produced fluid from the reservoir. The produced fluid includes solvent, bitumen and water. The method includes receiving at one or more processors a measured temperature of the solvent during injection of the solvent from the wellbore to the reservoir from each of a plurality of temperature sensors distributed along the wellbore, the plurality of temperature sensors including at least two leading temperature sensors positioned between a wellhead of the wellbore and a leading outflow region of the wellbore, receiving a mass flow rate of the solvent from a mass flow meter positioned upstream of the leading outflow region of the wellbore; estimating a background temperature along the length of the wellbore based on an assumption that heat transfer propagates radially from the wellbore from the beginning of injection;
receiving a manual entry of an estimate of a heat transfer coefficient of the wellbore; and selecting a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that best-fits the measured temperatures of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors, the mass distribution providing the estimate of real-time solvent conformance during the cyclic recovery process.
[0023] In some embodiments, the method includes providing one or more observation wells in the bitumen recovery facility; and estimating a solvent conformance within the reservoir during the cyclic recovery process, the solvent conformance within the reservoir being based on the estimate of the real-time solvent conformance along the wellbore.
[0024] In some embodiments, providing one or more observation wells in the bitumen recovery facility includes drilling the one or more observation wells into an expected solvent conformance region of the reservoir.
[0025] In some embodiments, the method includes detecting an arrival of a pressure and temperature front at one or more of the observation wells, the pressure and temperature front caused by the cyclic injection of the solvent; wherein each of the one or more observation wells includes one or more perforations, a bottom-hole temperature sensor and a bottom-hole pressure sensor for detecting the arrival of the pressure and temperature front.

[0026] In some embodiments, the method includes detecting a change in temperature within one or more of the observation wells as the injected solvent contacts the one or more of the observation wells during injection, wherein each of the one or more observation wells includes a vertically distributed heater and a vertically distributed thermal fibre for detecting the change in temperature within the one or more of the observation wells.
[0027] In some embodiments, the method includes detecting micro-seismic signals caused by movement of fluid within the reservoir by one or more passive seismic geophones.
[0028] In some embodiments, the method includes generating seismic waves by one or more seismic sources positioned on a ground surface within a planar footprint of the reservoir; and recording seismic waves by one or more seismic receivers positioned on the surface of the bitumen recovery facility after the seismic waves have passed through the reservoir to estimate the solvent conformance within the reservoir.
[0029] In some embodiments, the method includes, during the cyclic injection of the solvent, adding a flow assurance solvent to the one or more observation wells to inhibit plugging within the one or more observation wells.
[0030] In some embodiments, the adding the flow assurance solvent to the one or more observation wells occurs when a hydrostatic pressure of the one or more observation wells is less than or equal to a predicted reservoir pressure.
[0031] It will be appreciated by a person skilled in the art that a system or method disclosed herein may embody any one or more of the features contained herein and that the features may be used in any particular combination or sub-combination.
[0032] These and other aspects and features of various embodiments will be described in greater detail below.

BRIEF DESCRIPTION OF THE DRAWINGS
[0033] For a better understanding of the described embodiments and to show more clearly how they may be carried into effect, reference will now be made, by way of example, to the accompanying drawings in which:
[0034] Figure 1 is simplified schematic representation of a hydrocarbon production system that may include and/or be utilized with methods, according to the present disclosure.
[0035] Figure 2 is a schematic diagram of a top-down view of the system for extracting bitumen from a subterranean reservoir shown in Figure 1.
[0036] Figure 3 is a process flowchart demonstrating a method to determine wellbore utilization, according to one embodiment.
[0037] Figure 4 is an example of measured and calculated temperature distributions along a wellbore for different mass flowrate distributions.
[0038] The drawings included herewith are for illustrating various examples of articles, methods, and systems of the teachings of the present specification and are not intended to limit the scope of what is taught in any way.
DESCRIPTION OF EXAMPLE EMBODIMENTS
[0039] Various systems, methods and compositions are described below to provide an example of an embodiment of each claimed invention. No embodiment described below limits any claimed invention and any claimed invention may cover systems and methods that differ from those described below. The claimed inventions are not limited to systems, methods and compositions having all of the features of any one system, method or composition described below or to features common to multiple or all of the systems, methods or compositions described below. It is possible that system, method or composition described below is not an embodiment of any claimed invention.
Any invention disclosed in a system, method or composition described below that is not claimed in this document may be the subject matter of another protective instrument, for example, a continuing patent application, and the applicant(s), inventor(s) and/or owner(s) do not intend to abandon, disclaim, or dedicate to the public any such invention by its disclosure in this document.
[0040] Furthermore, it will be appreciated that for simplicity and clarity of illustration, where considered appropriate, reference numerals may be repeated among the figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the example embodiments described herein. However, it will be understood by those of ordinary skill in the art that the example embodiments described herein may be practiced without these specific details. In other instances, well-known methods, procedures, and components have not been described in detail so as not to obscure the example embodiments described herein. Also, the description is not to be considered as limiting the scope of the example embodiments described herein.
[0041] To promote an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and no limitation of the scope of the disclosure is hereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. For the sake of clarity, some features not relevant to the present disclosure may not be shown in the drawings.
[0042] At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent.
Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.
[0043] As one of ordinary skill would appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name only. In the following description and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus, should be interpreted to mean "including, but not limited to."
[0044] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.
[0045] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a range from 1 to 9.
[0046] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
- 19 weight (wt.) percent ( /0) aliphatics (which can range from 5 wt. % to 30 wt. %
or higher);
- 19 wt. % asphaltenes (which can range from 5 wt. A to 30 wt. % or higher);
- 30 wt. % aromatics (which can range from 15 wt. % to 50 wt. % or higher);
- 32 wt. % resins (which can range from 15 wt. % to 50 wt. A) or higher);
and - some amount of sulfur (which can range in excess of 7 wt. /0), based on the total bitumen weight.
[0047] In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.
[0048] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 oil g/cm3).
An extra heavy oil, in general, has an API gravity of less than 10.0 API
(density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen.
[0049] The term "viscous oil" as used herein means a hydrocarbon, or mixture of hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
at initial reservoir conditions. Viscous oil includes oils generally defined as "heavy oil" or "bitumen." Bitumen is classified as an extra heavy oil, with an API gravity of about 10 or less, referring to its gravity as measured in degrees on the API Scale. Heavy oil has an API gravity in the range of about 22.3 to about 10 . The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.
[0050] In-situ is a Latin phrase for "in the place" and, in the context of hydrocarbon recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For example, in-situ temperature means the temperature within the reservoir. In another usage, an in-situ oil recovery technique is one that recovers oil from a reservoir within the earth.
[0051] The term "subterranean formation" or refers to the material existing below the Earth's surface. The subterranean formation may comprise a range of components, e.g. minerals such as quartz, siliceous materials such as sand and clays, as well as the oil and/or gas that is extracted. The subterranean formation may be a subterranean body of rock that is distinct and continuous. The terms "reservoir" and "formation"
may be used interchangeably.
[0052] The term "wellbore" as used herein means a hole in the subsurface made by drilling or inserting a conduit into the subsurface. A wellbore may have a substantially circular cross section or any other cross-sectional shape. The term "well,"
when referring to an opening in the formation, may be used interchangeably with the term "wellbore."

[0053] The term "cyclic process" refers to an oil recovery technique in which the injection of a viscosity reducing agent into a wellbore to stimulate displacement of the oil alternates with oil production from the same wellbore and the injection-production process is repeated at least once. Cyclic processes for heavy oil recovery may include a cyclic steam stimulation (CSS) process, a liquid addition to steam for enhancing recovery (LASER) process, a cyclic solvent process (CSP), or any combination thereof.
[0054] A "fluid" includes a gas or a liquid and may include, for example, a produced or native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold water, or a mixture of these among other materials.
[0055] "Facility" or "surface facility" is one or more tangible pieces of physical equipment through which hydrocarbon fluids are either produced from a subterranean reservoir or injected into a subterranean reservoir, or equipment that can be used to control production or completion operations. In its broadest sense, the term facility is applied to any equipment that may be present along the flow path between a subterranean reservoir and its delivery outlets. Facilities may comprise production wells, injection wells, well tubulars, wellbore head equipment, gathering lines, manifolds, pumps, compressors, separators, surface flow lines, steam generation plants, processing plants, and delivery outlets. In some instances, the term "surface facility"
is used to distinguish from those facilities other than wells.
[0056] "Pressure" is the force exerted per unit area by the gas on the walls of the volume. Pressure may be shown in this disclosure as pounds per square inch (psi), kilopascals (kPa) or megapascals (MPa). "Atmospheric pressure" refers to the local pressure of the air.
[0057] A "subterranean reservoir" is a subsurface rock or sand reservoir from which a production fluid, or resource, can be harvested. A subterranean reservoir may interchangeably be referred to as a subterranean formation. The subterranean formation may include sand, granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy oil (e.g., bitumen), oil, gas, or coal, among others. Subterranean reservoirs can vary in thickness from less than one foot (0.3048 meters (m)) to hundreds of feet (hundreds of meters). The resource is generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.
[0058] The term "asphaltenes" or "asphaltene content" refers to pentane insolubles (or the amount of pentane insoluble in a sample) according to ASTM 03279.
Other examples of standard ASTM asphaltene tests include ASTM test numbers D4055, D6560, and D7061.
[0059] The term "conformance" refers to the distribution of a fluid, such as but not limited to a solvent, along a length of an object or a space. For instance, "wellbore conformance" refers to the distribution of a fluid along the wellbore and may also be referred to as "wellbore utilization". In another example, "reservoir conformance" refers to the distribution of a fluid through a subterranean reservoir.
[0060] The articles "the," "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended to include, optionally, multiple such elements.
[0061] As used herein, the terms "approximately," "about,"
"substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.
[0062] "At least one," in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one" refers, whether related or unrelated to those entities specifically identified.

Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at least one of A and/or B") may refer, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities).
In other words, the phrases "at least one," "one or more," and "and/or" are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C," "at least one of A, B, or C,"
"one or more of A, B, and C," "one or more of A, B, or C" and "A, B, and/or C" may mean A
alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C
together, and optionally any of the above in combination with at least one other entity.
[0063] Where two or more ranges are used, such as but not limited to 1 to 5 or 2 to 4, any number between or inclusive of these ranges is implied.
[0064] As used herein, the phrases "for example," "as an example," and/or simply the terms "example" or "exemplary," when used with reference to one or more components, features, details, structures, methods and/or figures according to the present disclosure, are intended to convey that the described component, feature, detail, structure, method and/or figure is an illustrative, non-exclusive example of components, features, details, structures, methods and/or figures according to the present disclosure.
Thus, the described component, feature, detail, structure, method and/or figure is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, methods and/or figures, including structurally and/or functionally similar and/or equivalent components, features, details, structures, methods and/or figures, are also within the scope of the present disclosure. Any embodiment or aspect described herein as "exemplary" is not to be construed as preferred or advantageous over other embodiments.
[0065] In spite of the technologies that have been developed, there remains a need in the field for systems and methods for monitoring solvent conformance along a wellbore and within a reservoir during bitumen recovery in solvent dominated process facilities.

[0066] Referring now to Figure 1, illustrated therein is a schematic diagram of a layout of a facility 100 for performing solvent dominated processes for recovering bitumen from a subterranean (e.g. underground) reservoir 110, according to one embodiment.
Herein, the subterranean reservoir 110 includes an injector/producer well 102 and, optionally, a neighboring observation well 104. Facility 100 also includes a collection of surface facilities 106 and a production pipeline 108.
[0067] Injector/producer well 102 is used to perform cyclic solvent injection and production operations to recover bitumen from the subterranean reservoir 110.
In the embodiment shown in Figure 1, during injection cycles, solvent stored in the surface facilities 106 (e.g. solvent storage unit 112) is injected through a wellhead 114 and into the subterranean reservoir 110 via wellbore 102. Flow assurance solvent stored in one or more of the surface facilities 106 (e.g. flow assurance solvent storage 116) may also be injected with the solvent into the subterranean reservoir 110.
[0068] In the solvent dominated cyclic processes described herein, solvents are used to enhance the extraction of petroleum products (e.g. bitumen) from subterranean reservoir 110. In some embodiments, the solvent(s) used in the solvent dominated cyclic processes may be a light hydrocarbon, a mixture of light hydrocarbons or dimethyl ether.
In other embodiments, the solvent may be a 02-C7 alkane, a C2-07 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics.
[0069] In other embodiments, the solvent may be a light, but condensable, hydrocarbon or mixture of hydrocarbons comprising ethane, propane, butane, or pentane.
The solvent may comprise at least one of ethane, propane, butane, pentane, and carbon dioxide. The solvent may comprise greater than 50% C2-05 hydrocarbons on a mass basis. The solvent may be greater than 50 mass% propane, optionally with diluent when it is desirable to adjust the properties of the injectant to improve performance.
[0070] Additional injectants may include 002, natural gas, 05+
hydrocarbons, ketones, and alcohols. Non-solvent injectants that are co-injected with the solvent may include steam, non-condensable gas, or hydrate inhibitors. The solvent composition may comprise at least one of diesel, viscous oil, natural gas, bitumen, diluent, 05+
hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water soluble solid particles, and solvent soluble solid particles.
[0071] To reach a desired injection pressure of the solvent composition, a viscosifier may be used in conjunction with the solvent. The viscosifier may be useful in adjusting solvent viscosity to reach desired injection pressures at available pump rates.
The viscosifier may include diesel, viscous oil, bitumen, and/or diluent. The viscosifier may be in the liquid, gas, or solid phase. The viscosifier may be soluble in either one of the components of the injected solvent and water. The viscosifier may transition to the liquid phase in the reservoir before or during production. In the liquid phase, the viscosifiers are less likely to increase the viscosity of the produced fluids and/or decrease the effective permeability of the formation to the produced fluids.
[0072] The solvent composition may comprise (i) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and (ii) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane. The solvent composition may have a Hansen hydrogen bonding parameter of 0.3 to 1.7 (or 0.7 to 1.4). The solvent composition may have a volume ratio of the polar component to non-polar component of 10:90 to 50:50 (or 10:90 to 24:76, 20:80 to 40:60, 25:75 to 35:65, or 29:71 to 31:69). The polar component may be, for instance, a ketone or acetone. The non-polar component may be, for instance, a 02-07 alkane, a 02-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics. For further details and explanation of the Hansen Solubility Parameter System see, for example, Hansen, C. M. and Beerbower, Kirk-Othmer, Encyclopedia of Chemical Technology, (Suppl. Vol. 2nd Ed), 1971, pp 889-910 and "Hansen Solubility Parameters A User's Handbook" by Charles Hansen, CRC Press, 1999.
[0073] The solvent composition may comprise (i) an ether with 2 to 8 carbon atoms;
and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms. Ether may have 2 to 8 carbon atoms. Ether may be di-methyl ether, methyl ethyl ether, di-ethyl ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether. Ether may be di-methyl ether. The non-polar hydrocarbon may a 02-030 alkane. The non-polar hydrocarbon may be a 02-alkane. The non-polar hydrocarbon may be propane. The ether may be di-methyl ether and the hydrocarbon may be propane. The volume ratio of ether to non-polar hydrocarbon may be 10:90 to 90:10; 20:80 to 70:30; or 22.5:77.5 to 50:50.
[0074] The solvent composition may comprise at least 5 mol % of a high-aromatics component (based upon total moles of the solvent composition) comprising at least 60 wt. % aromatics (based upon total mass of the high-aromatics component). One suitable and inexpensive high-aromatics component is gas oil from a catalytic cracker of a hydrocarbon refining process, also known as a light catalytic gas oil (LOGO).
[0075] In the embodiment shown in Figure 1, during production cycles, a produced fluid is recovered from the subterranean reservoir 110 via wellbore 102 and wellhead 114.
The produced fluid generally includes hydrocarbons and water, where the hydrocarbons include at least a portion of the injected solvent and bitumen from the subterranean reservoir 110.
[0076] Injector/producer wellbore 102 may include one or more flow rate sensor, density sensor, temperature sensor and/or pressure sensor positioned slightly downstream of the wellhead 114. The positioning of these components is described in further detail below.
[0077] Neighboring observation wellbore 104 is a wellbore that may be included in the facility 100 and used to observe changes in temperature and/or pressure within the subterranean reservoir 110, for instance over a period of time. It should be noted that, although Figure 1 shows a single neighboring observation wellbore 104, facility 100 may include more than one neighboring observation wellbore 104.
[0078] Each neighboring observation wellbore 104 may include one or more temperature sensor(s) and/or pressure sensor(s) positioned between the subterranean reservoir 110 and the observation wellhead 118. In some embodiments, the neighboring observation wellbores 104 may be used to estimate solvent conformance within the subterranean reservoir 110 during the cyclic recovery process. In some embodiments, the solvent conformance within the subterranean reservoir 110 may also be inferred based on an estimate of the real-time solvent conformance along the wellbore 102, as described further below.
[0079] Each of the one or more neighboring observation wellbores 104 may be drilled into an expected solvent conformance region of the subterranean reservoir 110.
[0080] Further, each of the one or more neighboring observation wellbores may include one or more perforations (not shown), a bottom-hole temperature sensor 126, and a bottom-hole pressure sensor 128 to detect an arrival of a pressure and temperature front of the subterranean reservoir 110 caused by the cyclic injection of the solvent into the wellbore 102.
[0081] Each of the one or more neighboring observation wellbores 104 may also include a vertically distributed heater 130 and/or a vertically distributed thermal fibre 132 for detecting a change in temperature of the neighboring observation wellbore 104 as the injected solvent passes through the wellbore 102 into the subterranean reservoir 110 and passes towards and/or contacts a bottom-hole portion of the neighboring observation wellbore 104. Each of the vertically distributed heater 130 and/or a vertically distributed thermal fibre 132 is generally positioned between the observational well wellhead 118 and the expected solvent conformance region 125 of the subterranean reservoir 110.
[0082] Each of the neighboring observation wellbores 104 may also include one or more passive seismic geophones 134 for detecting micro-seismic signals caused by movement of fluid within the subterranean reservoir 110. The one or more passive seismic geophones 134 are distributed vertically along the observation wellbores 104.
The geophones record acoustic signals associated with micro-seismic events occurring within the subterranean reservoir 110. The characteristics of the acoustic signals are processed to calculate the three-dimensional coordinates of the micro-seismic event origin. Multiple events can be plotted in three-dimensional space to collectively to describe a region within the subterranean reservoir 110 affected by fluid movement (e.g.
solvent injection).

[0083] In some embodiments, facility 100 may also include one or more seismic sources 140 for generating seismic waves. Seismic sources 140 may be positioned on a ground surface within a planar footprint of the subterranean reservoir 110 for generating seismic waves. The seismic sources 140 may each include one or more seismic receivers 142 positioned on the surface of the facility 100 for recording the seismic waves after they have passed through the subterranean reservoir 110 to estimate the solvent conformance within the subterranean reservoir 110. Typical seismic sources include, but are not limited to, seismic vibrators, "thumper" trucks or dynamite. In general, a seismic source generates seismic waves that travel through the subterranean. Within the subterranean the boundaries between regions with different acoustic impedance cause a portion of the source signal to reflect back toward the surface. The reflected signal is recorded by the seismic receivers, commonly referred to as geophones, for further processing and spatial correlation. The solvent chamber can be distinguished as a unique region within the subterranean reservoir because the fluid properties of the solvent are different than the surrounding, resulting in an impedance contrast relative to the surrounding undisturbed medium. For a solvent process, such as CSP, the solvent may be in the liquid phase at higher pressure during early cycle production, or in mixed liquid and gas phases during low pressure late cycle production. In either situation, the impedance contrast is measurable and solvent chamber can be visualized by comparing a monitoring shoot to the undisturbed baseline seismic survey.
[0084] In some embodiments, the one or more neighboring observation wellbores 104 may also include a storage unit (not shown) for injecting flow assurance solvent into the neighboring observation wellbores 104 during injection of the solvent into the wellbore 102 and subterranean reservoir 110. Injection of the flow assurance solvent into the one or more neighboring observation wellbores 104 during injection of the solvent into the wellbore 102 and subterranean reservoir 110 may inhibit plugging within the one or more neighboring observation wellbores 104 during the cyclic injection of the solvent through the wellbore 102 into subterranean reservoir 110.
[0085] Surface facilities 106 generally refers to the collection of one or more units and associated pipeline on the surface that are used to process one or more of the solvent, flow assurance solvent or the like before injection into the subterranean reservoir 110 and to process the produced fluid collected from the subterranean reservoir 110.
Surface facilitates 106 are generally positioned on a pad and may include one or more flow rate sensor, density sensor, temperature sensor and/or pressure sensor positioned between the wellhead 114 and the production pipeline 108. For instance, as shown in the embodiment shown in Figure 1, surface facilities 106 may include one or more storage units 112 and 116, pumps 122 and/or one or more heaters 124 for processing fluids prior to injection into the wellbore 102. Surface facilities 106 may also include one or more storage units 119 for processing fluids after their production from the subterranean reservoir 110 via wellbore 102. In the embodiment shown in Figure 1, storage units 116 may also be for processing fluids after production from the wellbore 102.
[0086] Production pipeline 108 generally refers to a pipeline that carry produced fluids from the pad to a central processing facility where solvent, bitumen and water are separated from the produced fluid. Production pipeline 108 generally includes one or more pressure and temperature sensors distributed along its length.
[0087] Referring to Figure 2, the elements as shown in this figure that are numbered the same as in Figure 1 have the same meaning as in Figure 1. Figure 2 shows a schematic diagram of a top-down view of wellbore 102 of the facility 100. As shown, wellbore 102 includes a plurality of temperature sensors 150 distributed along a length of the wellbore 102. Each temperature sensor 150a...n of the plurality of temperature sensors 150 is configured to measure a temperature of the solvent during injection of the solvent from the wellbore 102 to the subterranean reservoir 110.
[0088] Wellbore 102 also includes a plurality of outflow regions 152 configured to provide for the solvent injected into the wellbore 102 to pass from the wellbore 102 to the subterranean reservoir 110, and for the produced fluids collected from the subterranean reservoir 110 to pass from the subterranean reservoir 110 to the wellbore 102.
[0089] The plurality of temperature sensors 150 includes at least two leading temperature sensors 150a and 150b positioned between wellhead 114 of the wellbore 102 and a leading outflow region 152a of the wellbore 102. The two leading temperature

- 20 -sensors 150a and 150b are spaced apart by a spacing s. Spacing s can be in a range of about 1 meter to about 100 meters, or about 10 meters to about 100 meters.
[0090] In some embodiments, the plurality of temperature sensors 150 may be regularly spaced along the length of wellbore 102. In other embodiments, the plurality of temperature sensors 150 may be irregularly spaced along the length of wellbore 102.
Temperature sensors 150 may be placed inside a wellbore casing of wellbore 102 or may be placed outside the wellbore casing of wellbore 102.
[0091] Facility 100 also includes at least one mass flow meter 154 positioned upstream of the leading outflow region 152a of the wellbore 102. Although the mass flow meter 154 is shown in Figure 2 as being positioned downstream of the wellhead 114, it should be understood that the flow meter 154 may be positioned upstream of the wellhead 114 among the surface facilities 106. In some embodiments, the system 100 includes a second mass flow meter (not shown) upstream of the production pipeline 108 to measure a mass flow rate of produced fluids collected from the subterranean reservoir 110 via the wellbore 102.
[0092] Optionally, the facility 100 may also include one or more flow rate sensors, density sensors, temperature sensors and pressure sensors within one or more of the system facilities 106 to measure flow rates of fluids, both solvent before injection into the wellbore 102 and produced fluids after collection from the wellbore 102.
[0093] Each one of the one or more flow rate sensors, density sensors, temperature sensors and pressure sensors of the facility 100, including but not limited to the flow rate sensor 154 and each of the plurality of temperature sensors 150 distributed along the length of the wellbore 102, is operatively coupled to one or more processors (not shown) such that data (e.g. measurements) collected by the sensors is transmitted to the one or more processors for analysis. The one or more processors is configured to perform calculations that estimate real-time solvent conformance along the wellbore 102 and/or to measure solvent conformance in the subterranean reservoir 110.

- 21 -[0094] Referring now to Figure 3, illustrated therein is a block diagram of a method 300 of estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility.
[0095] During injection of solvent into the wellbore 102 and into the subterranean reservoir 110, the dominant heat transfer mechanism of the solvent to its surroundings is convective heat transfer.
[0096] Applying an energy balance to a section of the wellbore, the equation for one-dimensional steady convective heat transfer is given as:
dTrn [0097] ¨ ¨(is ¨ im) (1) dx mCp [0098] where x is a length along the wellbore direction; T,õ is the fluid temperature;
T, is the surface/surrounding temperature, also referred to as the background temperature; P is a perimeter of the tubing cross section (where P = n-D); m is the mass flow rate of the solvent; Cp is the heat capacity of the solvent; and h is a heat transfer coefficient.
[0099] To estimate the real-time solvent conformance along the wellbore, the processor acts to determine the mass flow rate (or the relative mass flow rate) at different points along the wellbore at a single point in time during injection.
[00100] At a step 305, the processor(s) receive a measured temperature of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors distributed along the wellbore.
[00101] At a step 310, the processor(s) receive a mass flow rate of the solvent from the mass flow meter. As noted above, the mass flow meter 154 is positioned upstream of the two leading temperature sensors 150a and 150b, which are each respectively positioned upstream of a leading outflow regions 152a of the plurality of outflow regions 152 of the wellbore 102. Accordingly, the positioning of the mass flow meter 154 with respect to the temperature sensors 150a and 150b and the leading outflow region 152a provides for the mass flow rate of the solvent to be measured before the loss of any mass

- 22 -of the solvent to the subterranean reservoir 110. It should be noted that steps 305 and 310 can be performed in any order.
[00102] Once the temperatures at each outflow region and the mass flow rate at the mass flow meter are received, the unknowns in the energy balance equation (1) presented above are the heat transfer coefficient and the background temperature.
[00103] At a step 315, the processor(s) estimate a distribution of background temperatures, Ts, defined above, along the wellbore. The estimate of the background temperature at discrete points along the wellbore is based on an assumption that from the beginning of injection to anytime thereafter heat transfers via one-dimensional radial conduction from the wellbore surface to the surrounding reservoir.
[00104] At a step 320, the processor(s) estimates a heat transfer coefficient of the wellbore based on the measured temperatures of the solvent at the two leading temperature sensors and the mass flow rate. Assuming fully developed steady flow, the heat transfer coefficient can be estimated from temperature measurements by the two leading temperature sensors, which are positioned in a section of the well where there is no mass change. In another embodiment, the processor(s) may be programmed to ignore this estimation of the heat transfer coefficient and a heat transfer coefficient may be manually provided to the processor(s). Manually entry of a heat transfer coefficient may be based on one or more of user experience, imperial correlations or the like.
[00105] At a step 325, the processor(s) selects a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that best-fits the measured temperatures of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors. The mass distribution is then an estimate of real-time solvent conformance along the wellbore during the cyclic recovery process.
[00106] An example of the computed and measured temperature distributions are shown in Figure 4. In Figure 4, the circular dots on the plot show a plurality of temperature measurements from a field experiment. The solid lines marked as 402 and 404 are each computed temperature distributions. In this example, two computed cases are shown.

- 23 -The line marked as 402 assumes uniform conformance along the wellbore and the line marked as 404 is a best-fit conformance. The best-fit, as it applies here, refers to the general fitness of the computed temperature distribution when compared to the measured data. Best-fit can be determined using a least-squares approach or other statistical fitness methods. The outflow locations are indicated with vertical dashed lines 406.
The relative percentage of the total mass flow is labelled at each of the five outflow locations along the wellbore for each of the computed cases, as indicated. The uniform case shows 20%
of the total mass flow at each outflow location. The best-fit conformance yields a non-uniform distribution with 22% of the mass flow equally distributed through the first four outflow locations and the remaining 12% at fifth outflow location. For this example, as shown, the lowest mass flows occur at the toe of the wellbore, while the rest of the wellbore is relatively uniform.
[00107] It should be noted that methods of estimating reservoir solvent conformance are also disclosed herein. Specifically, these methods build upon the method described above for estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility.
[00108] Reservoir solvent conformance can be estimated by applying a technical analysis of the measurements from one or more observation wells. In the present disclosure, as described above, observation wells can be provided (i.e.
drilled) into an anticipated solvent chamber region, prior to injecting solvent into the reservoir via the wellbore.
[00109] During injection of the solvent, the one or more observation wells are monitored and responses of the bottom-hole pressure (BHP) and bottom-hole temperature (BHT) can be inferred as solvent arrival at the bottom of the observation well.
In some embodiments, solvent arrival can be confirmed by analyzing a temperature response along the vertical thermal fiber. In other embodiments, each of the one or more observation wells includes one or more perforations for detecting the arrival of the solvent and/or a pressure and temperature front accompanying arrival of the solvent.

- 24 -[00110] A three-dimensional map, consistent with the above measurements, may be generated from the locatable events (e.g. bottom-hole pressures (BHP) and bottom-hole temperatures (BHT)) and the event origins interpreted from the from the PS system.
[00111] During the cyclic process, the reservoir pressure changes, leading to both gas and liquids within the chamber (i.e. swept portion of the reservoir).
Traditional 3D
seismic processes as applied to thermal bitumen recovery processes generally rely on a significant impedance difference between the gas within the swept portion of the reservoir and any unswept bitumen.
[00112] In the methods described herein, during a cyclic solvent process when the chamber pressure is high (i.e. during early cycle production) the liquid within the chamber with a high solvent concentration can be visualized based on a much lower impedance difference (relative to traditional seismic processes described above) between the solvent and unswept bitumen. Alternatively, the swept region can be visualized during low pressure periods (i.e. late cycle production) due to the large impedance contrast between the gas within the swept chamber and the unswept bitumen.
[00113] In some embodiments, three-dimensional (30) mapping of reservoir solvent conformance may be achieved through difference mapping of 3D seismic shoots relative to a baseline shoot, which is taken prior to subterranean disturbance caused by production processes. A baseline shoot generally refers to an initial seismic survey that is taken prior to any subterranean activity taking place. The purpose is to visualize the undisturbed geology so that a monitoring survey taken at a later date with the purpose of visualizing changes to the subterranean (i.e. visualize the solvent distribution).
[00114] In some embodiments, 30 mapping can be achieved by generating seismic waves by one or more seismic sources positioned on a surface of the bitumen recovery facility and recording seismic waves (e.g. intensity and/or magnitude) by one or more seismic receivers positioned on the surface of the bitumen recovery facility after the seismic waves have passed through the reservoir. In some embodiments, the magnitude of the seismic waves can be used to estimate the solvent conformance within the reservoir. As noted above, typical seismic sources include, but are not limited to, seismic

- 25 -vibrators, "thumper" trucks or dynamite. The seismic source(s) generate seismic waves that travel through the subterranean. Within the subterranean the boundaries between regions with different acoustic impedance cause a portion of the source signal to reflect back toward the surface. The reflected signal is recorded by the seismic receivers, commonly referred to as geophones, for further processing and spatial correlation. The solvent chamber can be distinguished as a unique region within the subterranean reservoir because the fluid properties of the solvent are different than the surrounding, resulting in an impedance contrast relative to the surrounding undisturbed medium. For a solvent process, such as CSP, the solvent may be in the liquid phase at higher pressure during early cycle production, or in mixed liquid and gas phases during low pressure late cycle production. In either situation, the impedance contrast is measurable and solvent chamber can be visualized by comparing a monitoring shoot to the undisturbed baseline seismic survey.
[00115] In some embodiments, micro-seismic signals caused by movement of fluid within the reservoir can be detected by one or more passive seismic geophones positioned within the observation well bores. In these embodiments, seismic waves are not generated as previously described. Rather, the micro-seismic signals generated by movement within the reservoir (e.g. movement of fluid) are received by the geophones.
The signal origin (in three-dimensional space) can be computed based on the characteristics of the measured signal. The accumulation of events during an injection period leads to a map of fluid (i.e. solvent) within the reservoir.
[00116] In some embodiments, during the cyclic injection of the solvent, a flow assurance solvent may be added to the one or more observation wells to inhibit plugging within the one or more observation wells. In some embodiments, adding the flow assurance solvent to the one or more observation wells occurs when the bottom-hole pressure of the OB well is sufficient to prevent the flow assurance fluid from leaking off into the reservoir. The purpose is to maintain a full fluid column of flow assurance solvent which then prevent/limits the reservoir fluid from flowing into the OB well during the remainder of the injection.

- 26 -[00117]
While the above description describes features of example embodiments, it will be appreciated that some features and/or functions of the described embodiments are susceptible to modification without departing from the spirit and principles of operation of the described embodiments. For example, the various characteristics which are described by means of the represented embodiments or examples may be selectively combined with each other. Accordingly, what has been described above is intended to be illustrative of the claimed concept and non-limiting. It will be understood by persons skilled in the art that other variants and modifications may be made without departing from the scope of the invention as defined in the claims appended hereto. The scope of the claims should not be limited by the preferred embodiments and examples, but should be given the broadest interpretation consistent with the description as a whole.

- 27 -

Claims (30)

Claims What is claimed is:

1. A
system for estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility, the cyclic recovery process including cyclic injection of a solvent through a plurality of outflow regions of the wellbore into a reservoir and recovery of a produced fluid from the reservoir, the produced fluid including solvent, bitumen and water, the system comprising:
a plurality of temperature sensors distributed along a length of the wellbore, each temperature sensor configured to measure a temperature of the solvent during injection of the solvent from the wellbore to the reservoir, the plurality of temperature sensors including at least two leading temperature sensors positioned between a wellhead of the wellbore and a leading outflow region of the plurality of outflow regions;
a mass flow meter positioned upstream of the leading outflow region of the wellbore; and one or more processors operatively coupled to each temperature sensor and the mass flow meter, the one or more processors, collectively, configured to:
receive a measured temperature of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors distributed along the wellbore;
receive a mass flow rate of the solvent from the mass flow meter;
estimate a background temperature along the length of the wellbore, the estimate of the background temperature being based on an assumption that heat transfer propagates radially from the wellbore from the beginning of the injection of the solvent from the wellbore to the reservoir;
estimate a heat transfer coefficient of the wellbore based on the measured temperatures of the solvent at the two leading temperature sensors and the mass flow rate; and select a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that best-fits the measured temperatures of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors, the mass distribution providing the estimate of real-time solvent conformance along the wellbore during the cyclic recovery process.

2. A
system for estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility, the cyclic recovery process including cyclic injection of a solvent through a plurality of outflow regions of the wellbore into a reservoir and recovery of a produced fluid from the reservoir, the produced fluid including solvent, bitumen and water, the system comprising:
a plurality of temperature sensors distributed along a length of the wellbore, each temperature sensor configured to measure a temperature of the solvent during injection of the solvent from the wellbore to the reservoir, the plurality of temperature sensors including at least two leading temperature sensors positioned between a wellhead of the wellbore and a leading outflow region of the plurality of outflow regions;
a mass flow meter positioned upstream of the leading outflow region of the wellbore; and one or more processors operatively coupled to each temperature sensor and the mass flow meter, the one or more processors, collectively, configured to:
receive a measured temperature of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors distributed along the wellbore;
receive a mass flow rate of the solvent from the mass flow meter;
estimate a background temperature along the length of the wellbore, the estimate of the background temperature being based on an assumption that heat transfer propagates radially from the wellbore from the beginning of the injection of the solvent from the wellbore to the reservoir;
receive a manual entry of an estimate of a heat transfer coefficient of the wellbore; and select a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that best-fits the measured temperatures of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors, the mass distribution providing the estimate of real-time solvent conformance along the wellbore during the cyclic recovery process.

3. The system of claim 1, wherein the estimate of the heat transfer coefficient is based on fully developed steady flow of the solvent along the wellbore.

4. The system of claim 2, wherein the estimate of the heat transfer coefficient is based on empirical correlations.

5. The system of any one of claims 1 to 4, wherein the two leading temperature sensors are spaced apart by a pre-determined distance.

6. The system of any one of claims 1 to 5, wherein the two leading temperature sensors are spaced apart by distance in a range of about 10 metres to about metres.

7. The system of any one of claims 1 to 6, wherein the plurality of temperatures sensors includes the two leading temperature sensors and one temperature sensor for each outflow region of the plurality of outflow regions along the wellbore.

8. The system of any one of claims 1 to 7, further comprising one or more observation wells for estimating solvent conformance within the reservoir during the cyclic recovery process, the solvent conformance within the reservoir being based on the estimate of the real-time solvent conformance along the wellbore.

9. The system of claim 8, wherein the solvent conformance within the reservoir is estimated by extrapolating a measurement from the one or more observation wells using a lengthwise distribution of the real-time solvent conformance along the wellbore.

10. The system of claim 9, wherein each of the one or more observation wells is drilled into an expected solvent conformance region of the reservoir.

11. The system of any one of claims 8 to claim 10, wherein each of the one or more observation wells includes one or more perforations, a bottom-hole temperature sensor and a bottom-hole pressure sensor to detect an arrival of a pressure and temperature front caused by the cyclic injection of the solvent.

12. The system of claim 11, wherein each of the one or more observation wells includes a vertically distributed heater and a vertically distributed thermal fibre for detecting a change in temperature as the injected solvent contacts the observation well during injection.

13. The system of any one of claims 8 to 12, wherein each of the observation wells includes one or more passive seismic geophones for detecting micro-seismic signals caused by movement of fluid within the reservoir.

14. The system of any one of claims 8 to 13, further comprising:
one or more seismic sources positioned on a ground surface within a planar footprint of the reservoir for generating seismic waves; and one or more seismic receivers positioned on the surface of a bitumen recovery facility for recording the seismic waves after they have passed through the reservoir to estimate the solvent conformance within the reservoir.

15. The system of any one of claims 8 to 14, wherein, during injection of the solvent, the one or more observation wells include a flow assurance solvent to inhibit plugging within the one or more observation wells during the cyclic injection of the solvent through the wellbore into the reservoir.

16.A method of estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility, the cyclic recovery process including cyclic injection of a solvent through a plurality of outflow regions of the wellbore into a reservoir and recovery of a produced fluid from the reservoir, the produced fluid including solvent, bitumen and water, the method comprising:
receiving at one or more processors a measured temperature of the solvent during injection of the solvent from the wellbore to the reservoir from each of a plurality of temperature sensors distributed along the wellbore, the plurality of temperature sensors including at least two leading temperature sensors positioned between a wellhead of the wellbore and a leading outflow region of the wellbore;
receiving a mass flow rate of the solvent from a mass flow meter positioned upstream of the leading outflow region of the wellbore;
estimating a background temperature along the length of the wellbore based on an assumption that heat transfer propagates radially from the wellbore from the beginning of the injection of the solvent from the wellbore to the reservoir;
estimating a heat transfer coefficient of the wellbore based on the measured temperatures of the solvent at the at least two leading temperature sensors and the mass flow rate; and selecting a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that best-fits the measured temperatures of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors, the mass distribution providing the estimate of real-time solvent conformance during the cyclic recovery process.

17.
The method of claim 16, wherein the estimating the heat transfer coefficient is based on fully developed steady flow of the solvent along the wellbore.

18. A method of estimating real-time solvent conformance along a wellbore during a cyclic recovery process in a bitumen recovery facility, the cyclic recovery process including cyclic injection of a solvent through a plurality of outflow regions of the wellbore into a reservoir and recovery of a produced fluid from the reservoir, the produced fluid including solvent, bitumen and water, the method comprising:
receiving at one or more processors a measured temperature of the solvent during injection of the solvent from the wellbore to the reservoir from each of a plurality of temperature sensors distributed along the wellbore, the plurality of temperature sensors including at least two leading temperature sensors positioned between a wellhead of the wellbore and a leading outflow region of the wellbore;
receiving a mass flow rate of the solvent from a mass flow meter positioned upstream of the leading outflow region of the wellbore;
estimating a background temperature along the length of the wellbore based on an assumption that heat transfer propagates radially from the wellbore from the beginning of the injection of the solvent from the wellbore to the reservoir;
receiving a manual entry of an estimate of a heat transfer coefficient of the wellbore; and selecting a mass distribution along the wellbore based on the heat transfer coefficient to yield a calculated temperature distribution that best-fits the measured temperatures of the solvent during injection of the solvent from the wellbore to the reservoir from each of the plurality of temperature sensors, the mass distribution providing the estimate of real-time solvent conformance during the cyclic recovery process.

19. The method of claim 18, wherein receiving the manual entry of the estimate of the heat transfer coefficient is based on empirical correlations.

20. The method of any one of claims 16 to 19, wherein the two leading temperature sensors are spaced apart by a pre-determined distance.

21. The method of any one of claims 16 to 20, wherein the two leading temperature sensors are spaced apart by distance in a range of about 10 metres to about metres.

22. The method of any one of claims 16 to 21, wherein the plurality of temperatures sensors includes the two leading temperature sensors and one temperature sensor for each outflow region of the plurality of outflow regions along the wellbore.

23. The method of any one of claims 16 to 22, further comprising:
providing one or more observation wells in the bitumen recovery facility; and estimating a solvent conformance within the reservoir during the cyclic recovery process, the solvent conformance within the reservoir being based on the estimate of the real-time solvent conformance along the wellbore.

24. The method of claim 23, wherein the providing one or more observation wells in the bitumen recovery facility includes drilling the one or more observation wells into an expected solvent conformance region of the reservoir.

25. The method of claim 23 or claim 24 further comprising detecting an arrival of a pressure and temperature front at one or more of the observation wells, the pressure and temperature front caused by the cyclic injection of the solvent;
wherein each of the one or more observation wells includes one or more perforations, a bottom-hole temperature sensor and a bottom-hole pressure sensor for detecting the arrival of the pressure and temperature front.

26. The method of claim 25 further comprising detecting a change in temperature within one or more of the observation wells as the injected solvent contacts the one or more of the observation wells during injection, wherein each of the one or more observation wells includes a vertically distributed heater and a vertically distributed thermal fibre for detecting the change in temperature within the one or more of the observation wells.

27. The method of any one of claims 23 to 26 further comprising detecting micro-seismic signals caused by movement of fluid within the reservoir by one or more passive seismic geophones.

28. The method of any one of claims 23 to 27 further comprising:
generating seismic waves by one or more seismic sources positioned on a ground surface within a planar footprint of the reservoir; and recording seismic waves by one or more seismic receivers positioned on the surface of the bitumen recovery facility after the seismic waves have passed through the reservoir to estimate the solvent conformance within the reservoir.

29. The method of any one of claims 23 to 28 further comprising, during the cyclic injection of the solvent, adding a flow assurance solvent to the one or more observation wells to inhibit plugging within the one or more observation wells.

30. The method of claim 29, wherein the adding the flow assurance solvent to the one or more observation wells occurs when a hydrostatic pressure of the one or more observation wells is less than or equal to a predicted reservoir pressure.