CA3038186C

CA3038186C - System to estimate chamber conformance in a thermal gravity drainage process using pressure transient analysis

Info

Publication number: CA3038186C
Application number: CA3038186A
Authority: CA
Inventors: Robin Gupta; Neal L. Adair; David M. Chorneyko
Original assignee: ExxonMobil Upstream Research Co
Current assignee: ExxonMobil Upstream Research Co
Priority date: 2019-03-27
Filing date: 2019-03-27
Publication date: 2020-10-27
Anticipated expiration: 2039-03-27
Also published as: CA3038186A1

Abstract

Systems and methods of estimating chamber conformance of a drainage chamber in a subterranean reservoir during a thermal gravity drainage process are disclosed herein. The system includes a plurality of pressure sensors distributed along an injector well, each sensor positioned outside a steel casing of the injector well and configured to measure a local pressure of a respective portion of the reservoir adjacent to the injector well. The system also includes one or more processors operatively coupled to each pressure sensor. The one or more processors is configured to receive the pressure of the portion of the chamber measured by each pressure sensor; determine a time to achieve pseudo steady state for each portion of the chamber when both the injector well and a producer well are shut-in; and, based on the time to achieve pseudo steady state for each portion of the chamber, estimate the chamber conformance along the injector well.

Description

SYSTEM TO ESTIMATE CHAMBER CONFORMANCE IN A THERMAL GRAVITY
DRAINAGE PROCESS USING PRESSURE TRANSIENT ANALYSIS
Technical Field [0001] The present disclosure relates generally to systems and methods of characterizing reservoirs during oil extraction processes, and more specifically, to systems and methods of estimating chamber conformance in thermal gravity drainage processes using pressure transient analysis.
Background

[0002] In the oil and gas industry, reservoir modeling involves the construction of a computer model of a petroleum reservoir for the purposes of improving estimation of reserves and making decisions regarding the development of the field, predicting future production, placing additional wells, and evaluating alternative reservoir management scenarios.

[0003] Reservoir characterization is the process of preparing a quantitative representation of a reservoir during oil extraction using data (e.g. reservoir parameters) from a variety of sources. These sources may include but are not limited to flow rates, pressure measurements and temperature measurements.

[0004] Current methods of estimating chamber volume during oil extraction processes include 4D seismic monitoring, which is time-lapsed seismic reservoir monitoring comparing two or more points in time. However, 4D seismic monitoring can be expensive and indirect.

[0005] Pressure fall off tests are typically used for estimating pressure drop in an injector wellbore following shut-in. The corollary test for producer wellbores is termed a build-up test. Fall off tests and build-up tests offer potential for estimating the total swept volume of a steam chamber and, therefore, chamber conformance. However, solid carbonaceous subterranean formations often exhibit a high degree of heterogeneity and anisotropy, which cannot be determined from standard pressure fall-off tests.

[0006] Accordingly, there is a need for improved systems and methods of surveilling bitumen recovery operations of thermal gravity drainage processes.
Summary

[0007] The present disclosure provides systems and methods of estimating chamber conformance of a drainage chamber in a subterranean reservoir during a thermal gravity drainage process as disclosed herein. The thermal gravity drainage process is operated in an injector well and a producer well, the injector well and the producer well being positioned within the drainage chamber. The system includes a plurality of pressure sensors distributed along the injector well, each sensor of the plurality of sensors positioned outside a steel casing of the injector well and configured to measure a local pressure of a respective portion of the reservoir adjacent to the injector well. The system also includes one or more processors operatively coupled to each pressure sensor of the plurality of pressure sensors. The one or more processors is, collectively, configured to receive the pressure of the portion of the chamber adjacent to the injector well as measured by each pressure sensor of the plurality of pressure sensors;
determine a time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well when both the injector well and the producer well are shut-in;
and, based on the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimate the chamber conformance along the injector well.

[0008] The one or more processors may be further configured to, during the step of estimating the chamber conformance along the injector well, estimate a total swept volume of the chamber and, based on the total swept volume of the chamber and the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimate the chamber conformance along the injector well.

[0009] The time to achieve pseudo steady state may be proportional to the volume of each portion of the chamber adjacent to the injector well.

[0010] The system may also include a flow rate sensor to measure a flow rate of injected fluid into the injector well and the one or more processors may be further configured to, during the step of estimating the chamber conformance along the injector well, estimate the total swept volume of the chamber over time based on the flow rate of injected fluid into the injector well.

[0011] The injected fluid may be steam.

[0012] The injected fluid may be a combination of steam and solvent.

[0013] The plurality of pressure sensors may be evenly distributed along the injector well.

[0014] The plurality of pressure sensors may be unevenly distributed along the injector well.

[0015] The plurality of pressure sensors may include at least 8 pressure sensors.

[0016] The thermal gravity drainage process may be a vapour extraction process.

[0017] The thermal gravity drainage process may be a solvent-assisted, steam-assisted gravity drainage process.

[0018] In some embodiments, another system to estimate chamber conformance of a drainage chamber in a subterranean reservoir during a thermal gravity drainage process is described herein. Again, in this system, the thermal gravity drainage process is operated in an injector well and a producer well, the injector well and the producer well being positioned within the drainage chamber. The system includes a plurality of pressure sensors distributed along the producer well, each sensor of the plurality of sensors configured to measure a pressure of a portion of the reservoir adjacent to the producer well. The system also includes one or more processors operatively coupled to each pressure sensor of the plurality of pressure sensors, the one or more processors, collectively, configured to: receive the pressure of the portion of the chamber adjacent to the producer well as measured by each pressure sensor of the plurality of pressure sensors; determine a time to achieve pseudo steady state for each portion of the chamber adjacent to the producer well when both the injector well and the producer well are shut-in; and based on the time to achieve pseudo steady state for each portion of the chamber adjacent to the producer well, estimate the chamber conformance along the producer well.

[0019] The one or more processors may be further configured to determine a liquid level in the reservoir between a horizontal segment of the injection wellbore and a horizontal segment of the production wellbore and, based on the liquid level, determine a pressure in the reservoir.

[0020] The plurality of pressure sensors may be evenly distributed along the producer well.

[0021] The plurality of pressure sensors may be unevenly distributed along the producer well.

[0022] The plurality of pressure sensors may include at least 8 pressure sensors.

[0023] In some embodiments, a method of estimating chamber conformance in a drainage chamber in a subterranean reservoir during a thermal gravity drainage process is described. The thermal gravity drainage process is operated in an injector well and a producer well and both of the injector well and the producer well are positioned within the drainage chamber. The method includes measuring a pressure of a portion of the reservoir adjacent to the injector well with each of a plurality of pressure sensors distributed along the injector well; receiving the pressure measurements at one or more processors operatively coupled to each pressure sensor of the plurality of pressure sensors; determining a time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well when both the injector well and the producer well are shut-in; and based on the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimating the chamber conformance along the injector well.

[0024] In some embodiments, a method of estimating chamber conformance in a drainage chamber in a subterranean reservoir during a thermal gravity drainage process is described. The thermal gravity drainage process is operated in an injector well and a producer well, the injector well and the producer well being positioned within the drainage chamber. The method includes measuring a pressure of a portion of the reservoir adjacent to the producer well with each of a plurality of pressure sensors distributed along the injector well; receiving the pressure measurements at one or more processors operatively coupled to each pressure sensor of the plurality of pressure sensors;

determining a time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well when both the injector well and the producer well are shut-in;
and, based on the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimating the chamber conformance along the injector well.

[0025] The method may also include determining a liquid level in the reservoir between a horizontal segment of the injection wellbore and a horizontal segment of the production wellbore and, based on the liquid level, determine a pressure in the reservoir.

[0026] The method may also include, in response to estimating the chamber conformance, performing at least one of: increasing an injection rate of a fluid to the injector wellbore to increase a total flow rate of fluids in the injector wellbore, decreasing an injection rate of a fluid to the injector wellbore to decrease the total flow rate of fluids in the injector wellbore, working over the injector wellbore to reduce skin formation, modifying a future wellbore design to improve conformance, and injecting a scale inhibitor into the injector wellbore to reduce a rate of scale formation. For instance, increasing an injection rate of a fluid to the injector wellbore to increase a total flow rate of fluids in the injector wellbore, decreasing an injection rate of a fluid to the injector wellbore to decrease the total flow rate of fluids in the injector wellbore, may include changing modifying heel/toe steam/solvent injection rates. An estimate of chamber conformance along the well may also influence flow partitioning and fluid injection rates to heel and toe for a given injector. Also, changes in chamber conformance with time may provide a sense of skin formation along the well and consequently influence skin remediation and its timing. Skin remediation may include working over a well to reduce skin. Working over the well may include but is not limited to injecting an acid into the injector wellbore, re-perforating the injector wellbore, and the like. Modifying future well designs to provide better conformance may include but is not limited to adding inflow control devices to systems for estimating chamber conformance, adding outflow control devices to systems for estimating chamber conformance, adjusting the placement of wells, and the like. Injecting a scale inhibitor may include injecting EDTA (ethylenediaminetetraacetic acid) or the like.

[0027] The method may also include, in response to estimating the chamber conformance, performing at least one of: a comparison of the chamber conformance to chamber volumes for several wells in a pad to provide insight into geology of the reservoir and fluid allocation (e.g. injection rate) among wells, and constrain a simulation to provide improve a recovery forecast.

[0028] These and other features and advantages of the present application will become apparent from the following detailed description taken together with the accompanying drawings. However, it should be understood that the detailed description and the specific examples, while indicating preferred embodiments of the application, are given by way of illustration only, since various changes and modifications within the spirit and scope of the application will become apparent to those skilled in the art from this detailed description.
Brief Description of the Drawings

[0029] For a better understanding of the various embodiments described herein, and to show more clearly how these various embodiments may be carried into effect, reference will be made, by way of example, to the accompanying drawings which show at least one example embodiment, and which are now described. The drawings are not intended to limit the scope of the teachings described herein.

[0030] FIG. 1 is a schematic diagram of a cross-sectional view of a system for extracting bitumen from a subterranean reservoir, according to one embodiment;

[0031] FIG. 2 is a schematic diagram of a top-down view of the system for extracting bitumen from a subterranean reservoir shown in FIG. 1;

[0032] FIG. 3 is a simplified process flow diagram for a method of estimating chamber conformance of a drainage chamber in a formation during thermal gravity drainage process, according to one embodiment;

[0033] FIG. 4 is a plot of pressure versus time in the pseudo steady state (PSS) part of a pressure transient analysis (PTA);

[0034] FIG. 5 is a log-log plot of PTA response showing derivative pressure versus time following producer shut-in;

[0035] FIG. 6 is a plot showing a comparison between PTA estimated conformance using the method of FIG. 3 with a conformance calculated using a reservoir simulator along the system 100;

[0036] FIG. 7 is a simplified process flow diagram for a method for determining a liquid level in a formation between a horizontal segment of an injection wellbore and a horizontal segment of a production wellbore, according to one embodiment;

[0037] FIG. 8 is a schematic illustration of an estimated liquid level between a pair of horizontal wellbores;

[0038] FIG. 9 is a plot of simulation results for local liquid level height as a function of local subcool during a simulated SAGD operation; and

[0039] FIG. 10 is a plot of simulation results for a local profile value as a function of time during a simulated SAGD operation.

[0040] The skilled person in the art will understand that the drawings, further described below, are for illustration purposes only. The drawings are not intended to limit the scope of the applicant's teachings in any way. Also, it will be appreciated that for simplicity and clarity of illustration, elements shown in the figures have not necessarily been drawn to scale. For example, the dimensions of some of the elements may be exaggerated relative to other elements for clarity. Further aspects and features of the example embodiments described herein will appear from the following description taken together with the accompanying drawings.
Detailed Description

[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 (%) aliphatics (which can range from 5 wt. % to 30 wt. %
or higher);
- 19 wt. % asphaltenes (which can range from 5 wt. % 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. % or higher);
and ¨ some amount of sulfur (which can range in excess of 7 wt. %), 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 10.00 API (density of 1,000 kg/m3 or 1 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" 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] 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.

[0054] "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.

[0055] "Pressure" is the force exerted per unit area by the fluid 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.

[0056] 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 3.0 (hundreds of meters). The resource is generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.

[0057] The term "drainage chamber" refers to a region of the reservoir whose pore space is primarily filled with a mobilizing fluid (e.g. steam) and a region along the edges of the steam chamber filled with low viscosity bitumen, other hydrocarbons, and condensed water.

[0058] The term "gravity drainage chamber" refers to a drainage chamber in a reservoir formed by displacing a mobilizing fluid through a horizontal wellbore (i.e. an injector wellbore) in the reservoir. The mobilizing fluid may be steam or another bitumen mobilizing fluid (e.g. solvents, surfactants, etc.). As the mobilizing fluid (e.g. steam) propagates radially from the injector wellbore into the reservoir, the viscosity of bitumen (and/or other hydrocarbons present in the reservoir) surrounding the wellbore is reduced providing for it to fall via gravity to a second horizontal wellbore (i.e. a producer wellbore) positioned beneath the injector wellbore.

[0059] The term "pressure transient analysis" refers to the analysis of pressure changes over time, especially variations in the volume of a produced fluid. In most well tests, a measured rate of fluid is allowed to flow from the formation via a wellbore being tested and the pressure at the formation is monitored over time. Then, the wellbore is closed and the pressure is monitored while the fluid within the formation equilibrates. The analysis of these pressure changes can provide information on boundary distances of the formation as well as reservoir properties such as kh (i.e. product of formation permeability, k, and producing formation thickness, h) and skin (i.e. a dimensionless factor calculated to determine the production efficiency of a well by comparing actual conditions with theoretical or ideal conditions).

[0060] The term "chamber conformance" refers to a distribution of the swept volume of a subterranean reservoir along a length of a horizontal wellbore. As a mobilizing fluid is injected into a horizontal wellbore and disperses radially out of the wellbore into the reservoir, the mobilizing fluid reduces the viscosity of bitumen and other hydrocarbons present in the reservoir. The mobilizing fluid also cleans neighboring rocks and leaves behind a low bitumen saturation region that is typically filled with the mobilizing fluid.

[0061] The term "gravity drainage process" refers to an oil recovery technique in which gravity acts as the main driving force for the displacement of oil into the wellbore and the voidage volume of oil in the reservoir is replaced by a mobilizing fluid. Gravity drainage processes for heavy oil recovery may include a steam-assisted gravity drainage (SAG D) process, a solvent-assisted-steam-assisted gravity drainage (SA-SAG D) process, a heated solvent vapor-assisted petroleum extraction (H-VAPEX) process, or any combination thereof.

[0062] The term "mobilizing fluid" includes steam as well as solvents and viscosity reducing agents such as but not limited to light hydrocarbons that are soluble in bitumen at reservoir temperatures and pressures that reduce the bitumen viscosity sufficient to enable it to flow under gravity.

[0063] 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.

[0064] 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.

[0065] "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.

[0066] 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.

[0067] 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.

[0068] In spite of the technologies that have been developed, there remains a need in the field for systems and methods of monitoring oil extraction processes.

[0069] Herein, systems and methods of estimating chamber conformance in a thermal gravity drainage process using pressure transient analysis is provided.

[0070] Referring now to Figures 1 and 2 a system 100 to estimate chamber conformance of a drainage chamber 102 in a subterranean formation 104 during a thermal gravity drainage process is provided. The thermal gravity drainage process is operated in an injector well 106 and a producer well 108. As shown in Figure 1, the injector well 106 and the producer well 108 are each positioned within the drainage chamber 102.

[0071] The thermal gravity drainage process operated in the system 100 includes injecting a mobilizing fluid (e.g. steam or a mixture of steam and solvent) through the injector well 106. The mobilizing fluid is generally pumped down from the surface through overburden and into injector wellbore 106 where it passes into the formation 104. In some instances, the mobilizing fluid can pass through one or more of a plurality of apertures provided in the wellbore casing of the injector wellbore 106. In other instances, injector wellbore 106 may include a screen on tubing rather than a perforated casing.
In these instances, a tubing-wrapped screen could have limited entry perforations, outflow control devices, slots, or the like.

[0072] Injector wellbore 106 may also be referred to as an injector well or, simply an injector. As the mobilizing fluid is injected, thermal energy from the mobilizing fluid is transferred to the formation 104. This thermal energy increases the temperature of petroleum products present in the formation 104 (e.g. heavy crude oil or bitumen), which reduces their viscosity and allows them to flow downwards under the influence of gravity towards the producer wellbore 108, where it passes into the producer wellbore 108.
Producer wellbore 108 may include a plurality of apertures provided in a wellbore casing thereof to provide for the petroleum products to enter the producer wellbore 108. Producer wellbore 108 may alternatively include a screen on tubing rather than a perforated casing.
In these instances, a tubing-wrapped screen could have limited entry perforations, outflow control devices, slots, or the like.

[0073] Producer wellbore 108 may also be referred to as a producer well or, simply as a producer. One or more artificial lift devices (not shown) (e.g.
electrical submersible pumps) may be used to pump fluids collected along the producer wellbore 108 up to the surface.

,

[0074] In the aforementioned thermal gravity process, solvents may be used to enhance the extraction of petroleum products from the formation 104. In some embodiments, the solvent used in the thermal gravity process may be a light hydrocarbon, a mixture of light hydrocarbons or dimethyl ether. In other embodiments, the solvent may be a C2-07 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics.

[0075] 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.

[0076] Additional injectants may include CO2, natural gas, C5+
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, C5+
hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water soluble solid particles, and solvent soluble solid particles.

[0077] 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-C7 alkane, a C2-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.

[0078]
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 C2-C30 alkane. The non-polar hydrocarbon may be a 05 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.

[0079]
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 (LCGO).

[0080]
As shown in Figure 1, as the mobilizing fluid enters the formation 104, drainage chamber 102 is formed. During normal operation, producer wellbore 108 acts as a producer (i.e. fluid is extracted from the formation 104 via the wellbore 108), but it will be appreciated that producer wellbore 108 may also act as an injector.
For example, during start-up of a thermal gravity drainage process, fluid may be pumped into both wellbores 106 and 108 to initially heat a portion of the formation 104 proximate to the wellbores 106 and 108, following which wellbore 108 may be transitioned to a producer by discontinuing the fluid flow therein.

[0081]
As the thermal gravity drainage process continues and mobilizing fluid is injected through the injector wellbore 106, petroleum products present in the formation 104 tend to flow downwards under the influence of gravity towards the producer wellbore 108 and a drainage chamber 102 forms and grows. Eventually, at a late phase of the thermal gravity drainage process, the drainage chamber 102 is exhausted and removal of additional petroleum products present in the formation 104 using the thermal gravity process becomes inefficient.

[0082] 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. As shown in Figure 2, a plurality of distributed pressure sensors 110 are distributed along one of the wellbores 106 and 108 (the producer wellbore 108 not shown in Figure 2, but is similar in this configuration with the injector wellbore 106 as shown in Figure 2). In some embodiments, the pressure sensors 110 are distributed along the injector wellbore 106.
In other embodiments, the pressure sensors 110 are distributed along the producer wellbore 108. In some embodiments, pressure sensors 110 may be regularly spaced along a producing interval (i.e. at least a portion of the producing wellbore 108) or placed according to a well log to capture the impact of reservoir heterogeneity.
Additionally, pressure sensors 110 may be placed inside a wellbore casing or outside the wellbore casing. In instances where the pressure sensors 110 are positioned inside the wellbore casing, models may be required to calculate a pressure change along the well.

[0083] Each pressure sensor may be a discrete unit, such as a quartz-based sensor, bubble tube, electromagnetic resonating element (ERE), electrical resonating diaphragm, and the like. Alternatively, a distributed pressure sensing system incorporating one or more distributed Fiber Bragg Grating pressure sensors may be used to obtain pressure data for each inflow location (e.g. along producer wellbore 108).
Alternatively, multiple individual Fabry Perot gauges connected to the same fiber optic trunkline may be used to obtain pressure data for the injector wellbore 106 and/or the producer wellbore 108. For example, a sensor system such as a SageWatchTM
Subsurface Surveillance System, available from SageRider, Inc., or the like may be used.

[0084] In some examples, the system 100 may include a distributed data acquisition system including one or more multi-function sensors capable of obtaining both pressure and temperature data. Accordingly, the same physical sensor apparatus may function as both a pressure sensor and as a temperature sensor to obtain pressure and temperature data for one or more locations along the wellbores 106 and/or 108.
For example, sensor systems such as CT-MORE, available from Core Laboratories of Houston, Texas, or CanePTIm Optical Pressure and Temperature Sensor, available from Weatherford International, or the like may be used.

[0085] As shown, two sensors of the plurality of pressure sensors 110 are separated by a spacing s. In some embodiments, the pressure sensors 110 are evenly distributed along the length of one or more of the wellbores 106 and 108 and the spacing s is the same along the length of the one or more of the wellbores 106 and 108. In other embodiments, the pressure sensors 110 can be unevenly distributed along one or more of the wellbores 106 and 108 such that a spacing s between any two pressure sensors varies along the one or more of the wellbores 106 and 108. In some embodiments, the spacing s of pressure sensors 110 along one or more of the wellbores 106 and 108 can be based on a heterogeneity of the reservoir. For instance, placement of the pressure sensors 110 along the length of the wellbore could be at regular intervals, or be specified by an understanding of the geology through logs or seismic.

[0086] In some embodiments, the plurality of pressure sensors 110 may include about 8 pressure sensors distributed along one of the wellbores 106,108. In some embodiments, the plurality of pressure sensors 110 can be distributed along a horizontal wellbore having a length of about 1 kilometer.

[0087] In some embodiments, injector wellbore 106 may also include a flow rate sensor to measure the flow rate of injected fluid into the injector well. The flow rate sensor may be provided at the surface of system 100. In some embodiments, production from multiple wells on a pad can be cycled through a test separator resulting in on the order of two tests per month of flow rate.

[0088] By obtaining pressure data for a number of locations or portions of chamber 102 adjacent to the wellbore 106 or wellbore 108 during shut-in conditions, chamber conformance of the chamber 102 can be estimated along the horizontal length of the wellbore 106 or the wellbore 108. This may provide for a more accurate and/or more detailed baseline model of the chamber 102 to be developed for the reservoir conditions along the wellbores. A more accurate model may enable the identification of conformance related issues and provide an opportunity to remedy these issues through control of production during the thermal gravity drainage process.

[0089] Figure 3 shows a method 300 of estimating chamber conformance for a drainage chamber along a horizontal well, according to one embodiment. Chamber conformance along the wellbores 106 or 108 is estimated based on a time (t) to reach pseudo steady-state (PSS) for each pressure sensor of the plurality of pressure sensors 110 during a build-up test, where both the injector wellbore 106 and the producer wellbore 108 are shut-in. Alternatively, in some embodiments, chamber conformance of the chamber 102 can be estimated based on a time (t) to reach pseudo steady-state (PSS) for each pressure sensor of the plurality of pressure sensors 110 during a fall-off test, where only one of the injector 106 and producer 108 are shut-in.

[0090] At a step 302, values of pressure for a plurality of portions of the chamber are measured using the plurality of pressure sensors 110 distributed along one of the injector wellbore 106 and the producer wellbore 108. As noted above, the pressure measurements are obtained during shut-in of one or more of the injector wellbore 106 and producer wellbore 108. It will be appreciated that the production and injection wellbores, 108 and 106, respectively, may be shut-in for a number of reasons, such as for periodic scheduled maintenance, or an unscheduled power outage.

[0091] At step 304, a total swept volume of the chamber 102 can be determined using the slope of pressure versus time in the PSS part of a pressure transient analysis.
An example of this type of plot is shown in Figure 4, where different plot lines therein represent different fall-off tests. The total swept volume of the chamber 102 can be determined based on the following Equation (1):
V = (1) where Qi is a flow rate of mobilizing fluid in the injector wellbore, Mc is a slope of the pressure versus time in a PSS flow regime, fl cc Bgs/Ct (and is reasonably constant with time), where Bgs is a steam formation volume factor (FVF); and Ct is total compressibility (which is dominated by steam condensation and fairly independent of phase saturations).

[0092] In some embodiments, 11 can be estimated from calibrating at least one fall-off test with a method of estimating chamber volume (e.g., 4D seismic, simulation or analogs). Following this, the total swept volume of the well can be estimated for other fall-off tests using PTA.

[0093] At step 306, a time to achieve pseudo steady state (tpss) for each portion of the chamber 102 adjacent to one of the injector wellbore 106 and the producer wellbore 108 is determined. For instance, in embodiments where the plurality of pressure sensors 110 are distributed along a length of the injector wellbore 106, a toss for each portion of the chamber 102 adjacent to the injector wellbore 106 is determined.
Conversely, in embodiments where the plurality of pressure sensors 110 are distributed along a length of the producer wellbore 108, a tpss for each portion of the chamber 102 adjacent to the producer wellbore 108 is determined.

[0094] The tpss can be determined based on the following Equation 2:
6 r,2 tPSSõ = ¨ (2) where n is hydraulic diffusivity, 6 is a shape factor and ri is a radius of the wellbore.

[0095] A plot showing the slope of a pressure derivative versus time graph can be used to estimate tpss. An example of this plot is shown in Figure 5, where different plot lines therein represent different volumes and the tpss is proportional to the chamber volume near the pressure measurement. It should be noted that the tPSS for each sensor of the pressure sensors 110 is proportional to local connected chamber volume.

[0096] At a step 308, once the total swept volume and the tPSS have been determined for each pressure sensor of the plurality of pressure sensors 110, the conformance of the chamber 102 can be estimated. For instance, to estimate the conformance of the chamber 102, the total swept volume of the chamber 102 can be distributed proportional to the tPSS for each pressure sensor 110 and the spacing s between them along the length of one of the injector wellbore 106 and the producer wellbore 108.

[0097] In some embodiments, the method 300 can detect locations of poor conformance along the well and corresponding pressure sensors at such locations show small tPSS or does not show the typical fall-off pressure derivative behavior.

[0098] Referring now to Figure 6, illustrated therein is an example plot showing a comparison of PTA estimated conformance using the method 300 described above with a conformance calculated from a commercially available reservoir simulator (e.g. EMP"er reservoir simulation) along a well pair. As shown therein, the chamber conformance estimated using the method 300 is very similar to the chamber conformance calculated using the reservoir simulator.

[0099] In embodiments where pressure sensors 110 are distributed along the length of the producer wellbore 108, an optional step 310 may be performed to estimate the chamber conformance of chamber 102. In these embodiments, the additional step 310 may be performed to remove the effects of liquid level change over producer wellbore 108 on the pressure transient response which is calculated from a pressure of the producer wellbore 108.

[0100] Step 310 requires information on an increasing liquid level over the shut-in period. This can be obtained from a method previously described in Canadian Patent Application 3020827. Briefly, referring to Figure 7, there is illustrated a method 700 for determining a liquid level in a formation between a horizontal segment of an injection wellbore and a horizontal segment of a production wellbore.

[0101] At 705, the producer wellbore and the injector wellbore (e.g.
wellbores 108 and 106, respectively) are shut-in. Optionally, the injector wellbore may undergo a gas purge in order to reduce the liquid level in the injector annulus to obtain a more accurate bottom hole pressure for the injector wellbore from a wellhead pressure gauge.
For example, an inert gas such as N2 may be pumped into the injector wellbore to displace any condensed vapour present in the injector wellbore into the reservoir.

[0102] At 710, values for local shut-in temperatures (i.e. a temperature measured after the wellbore has been shut-in) for a plurality of inflow zones (e.g.
each zone corresponding to a region or a portion of the producer wellbore 108 surrounding a sensor) are measured using one or more temperature sensors 220 distributed along the producer wellbore 108 (see Figure 8). Inflow locations 205 and outflow locations 210 are shown in Figure 8.

,

[0103] At 715, values for local shut-in pressures (i.e. a pressure measured after the wellbore has been shut-in) for a plurality of inflow zones are measured using one or more pressure sensors 230 distributed along the producer wellbore 108 (see Figure 9).

[0104] Optionally, at 720, values for local shut-in temperatures for a plurality of injection zones (e.g. each zone corresponding to a region or a portion of the injector wellbore 108 surrounding a sensor) may be measured using one or more temperature sensors distributed along the injector wellbore 106. Alternatively, a shut-in temperature for the injection zones may be estimated based on, e.g. wellhead measurements and/or a saturation curve for the injected fluid(s).

[0105] Optionally, at 725, values for local shut-in pressures for a plurality of injection zones are measured using one or more pressure sensors distributed along the injector wellbore 106. Alternatively, a shut-in pressure for the injection zones may be estimated based on, e.g. wellhead measurements and/or a saturation curve for the injected fluid(s), or any other suitable method.

[0106] For example, under saturated conditions, the saturation curve for the injection fluid can be used to determine the saturation pressure as a function of saturation temperature and injected solvent concentration:
Psat = f (Tsat, Concsowent) (3) Accordingly, under saturation conditions, a measurement of temperature provides a direct value for the saturation pressure. For example, for SA-SAGD, a temperature measurement and injected solvent concentration can be used to determine a pressure value.

[0107] As another example, for SAGD, assuming no pressure drop due to flow, and assuming that the injector wellbore is filled with steam, the static bottom hole pressure may be calculated using a pressure measurement taken at the wellhead and known steam properties:
Pbottom_hole = 'wellhead + (Psteam)(g)(h) (4) where n , steam is the density for steam and h is the height difference between the bottom hole location and the location of the wellhead measurement. Alternatively, if accumulated liquid is blown out with a gas (e.g. during a purge operation using N2 gas), r- steam may be replaced with pflas. Simulation results indicate that reservoir temperature/pressure at the injector is relatively uniform in areas of good steam conformance (i.e. where steam actually enters the formation). It will be appreciated that additional measurements (e.g.
temperatures measured for an observation well associated with the injector/producer wellpair) may optionally be used to correct the estimation of the injector pressure.

[0108] It will be appreciated that the production and injection wellbores may be shut-in for a number of reasons, such as for periodic scheduled maintenance, or an unscheduled power outage. Preferably, steps 710 to 725 may be performed during an otherwise scheduled shut-in, as this may limit non-production time for the recovery process.

[0109] At 730, a local shut-in liquid level is determined under static flow conditions for each of the plurality of inflow zones. Preferably, the shut-in liquid level for an inflow zone is based on the measured shut-in pressure at that inflow zone, and a shut-in pressure for an injection zone horizontally aligned with that inflow zone.

[0110] For example, with reference to Figure 8, the local liquid level hi above an inflow location or zone may be determined based on the local reservoir pressure P . res_i as measured at 715, the local pressure in the injector wellbore Pinu at a point above the local reservoir location (e.g. as measured at 725 or as otherwise determined/estimated), and the local density of the fluid (which may be an assumed value ¨ for example, the density of the fluid in the reservoir above the producer wellbore 108 may be estimated using Pres_inflow_i (or Pinflow_i), Tres_inflow_i (Or Tinflow_i), and a known or expected composition of the fluid). For example, the local liquid level hi may be determined using:
hi =Pres-inflow_i Pinj_i (5) PL
where g is the gravitational constant, and Pi, is the density of the liquid in the reservoir.
For example, density may be measured at the surface, either with online instruments or with collected samples, and these surface values may then be corrected to bottom hole conditions (e.g. by assuming that the surface composition is the same as the composition in the reservoir).

[0111]
For some processes (e.g. the injection of pure steam, or a pure solvent such as pentane, hexane, etc.), the local pressure in the injector wellbore PinD
may be assumed constant over the entire length of the wellbore (e.g. Pinj_i = Pinj).
In other processes, such as SA-SAGD or VAPEX, this assumption may be less accurate.
Alternatively, the pressure distribution along the injector may be estimated, e.g. using the injection pressure and a frictional flow model along the injection well.

[0112]
At 735, a local shut-in subcool value is determined for each of the plurality of inflow zones. Preferably, the shut-in subcool value for an inflow zone is based on a local saturation temperature of an injection fluid at the measured shut-in pressure at that inflow zone, and the measured shut-in temperature at that inflow zone. For example, for a SAGD or SA-SAGD process, the local shut-in subcool value for an inflow zone may be defined as the difference between the saturation temperature Tsat for steam at the local shut-in pressure P res_inflow at that zone (i.e. Tsat(Pres_inflow)) and the local shut-in temperature Tres_inflow at that zone:
Subcoolshut_ini = Tsat(Pres_inflow(shut¨in) i) (6) Tres_inflow(shut¨in)i As discussed above, the local shut-in pressure in the reservoir adjacent the inflow location Pres_inflow(shut¨in) may be assumed as being equal to a pressure value P .
inflow measured by a pressure sensor 230, or may be based on a measured pressure value Pinflow subject to an adjustment factor (e.g. to compensate for a pressure drop across the reservoir/wellbore interface).

[0113]
For a heated VAPEX (H-VAPEX) process, the local subcool value for an inflow zone may be defined as the difference between the saturation temperature Tsat for the solvent being used at the local shut-in pressure P res_inflow at that zone and the local shut-in temperature Tres_inflow at that zone.

[0114]
At 740, a local profile value is determined for each of the plurality of inflow zones. The local profile value ST for each inflow zone is based on the local shut-in subcool value for that inflow zone and the local shut-in liquid level for that inflow zone:

SUbC001shut_1n1 STi = (7) hi Combining equations (6) and (7):
= Tsat(Pres_inflow(shut¨in)i) Tres_inflow(shut¨inh STi (8) hi The local profile value STi can be characterized as the change in subcool required to move the liquid level by one meter (presuming the liquid level, h, is measured in meters, otherwise unit conversion would be required).

[0115] For example, Figure 10 illustrates an example plot of local profile values STi, from a simulated SAGD operation using injector and producer wellbores spaced 5m apart, where the liquid level was being held at about 2.5m. The different plot lines represent values taken for different times during the simulated operational life (i.e.
at 680 days of simulated operation, and at 1400 days, 2120 days, 2840 days, 3560 days, and (following a simulated shut-in) at 3602 days). In this illustrative example, there is a generally linear relationship between local liquid level heights (y axis) and local subcool values (x-axis) for locations in the reservoir below the local liquid level. For locations in the reservoir above the local liquid level, the Tsat-T slope is approximately zero.

[0116] At 745, flow is resumed in the producer wellbore and the injector wellbore.
It will be appreciated that flow may be resumed prior to steps 730, 735, and/or 740, as these steps may be performed anytime using the measurements taken during shut-in.

[0117] At 750, a local operating temperature (i.e. a temperature measured during operating conditions after flow in the wellbores has resumed) for an inflow zone is measured using one or more temperature sensors distributed along the producer wellbore 108.

[0118] At 755, a local operating pressure (i.e. a pressure measured during operating conditions after flow in the wellbores has resumed) for the inflow zone is measured using one or more pressure sensors distributed along the producer wellbore 108.

[0119] At 760, a local operating subcool value is determined for the inflow zone.
Like the shut-in subcool values determined at 735, the operating subcool value for an inflow zone is based on the measured operating temperature at that inflow zone. For example, for a SAGD or SA-SAGD process, the local operating subcool value for an inflow zone may be defined as the difference between the saturation temperature Tsat for steam at the local operating pressure P . inflow (Or Pres_inflow) at that zone (i.e.
Tsat(Pinflow)) and the local operating temperature Tinflow (or Tres_ inflow) at that zone.
inflow, Subcooloperatingi = Tsat(Pres_inflow(operating)i) (9) Tres_inflow(operating)i

[0120] At 765, a local operating liquid level is determined for the inflow zone. The local operating liquid level may be determined by taking the difference between the local operating subcool value for the inflow zone and the local shut-in subcool value for the inflow zone (determined at 735). Next, this change in the local subcool value and the local profile value (determined at 740) can be used to determine a change in the local liquid level. This change in the local liquid level can be applied to the local shut-in liquid level for the inflow zone (determined at 730) to estimate the local operating liquid level. For example:
Subcoo/deitai = Subcooloperatingi Subcoolshut_ini (10) SUbC0Oide1tai hdeltai = (11) STi hoperatingi = hdeltai hshut-ini (12)

[0121] Alternatively, equations (12), (1), and (7) may be combined to express the local operating liquid level as a function of the local operating subcool value and the local profile value:

Subcooloperatingi hoperatingi (13)

[0122] Optionally, steps 710 to 740 may be performed each time the wellbores are shut-in (e.g. during scheduled service interruptions) to determine updated local liquid levels based on pressures measured during static flow conditions. An advantage of periodically re-determining the local shut-in liquid levels is that this may improve the accuracy of the liquid levels estimated during operation, as the re-determined baseline local liquid levels may be more accurate than local liquid levels estimated following a significant time period following the prior shut-in.

[0123] Additionally, or alternatively, steps 710 to 740 may be performed each time the wellbores are shut-in (e.g. during scheduled service interruptions) to determine updated local profile values. An advantage of periodically re-determining the profile values is that the relationship between a subcool change and a change in the local liquid level may 'drift' over time during the recovery process.

[0124] For example, Figure 10 illustrates an example plot of a local profile value from a simulated SAGD operation using injector and producer wellbores spaced 5m apart, where the liquid level was being held at about 2.5m. In this example, the change in the local profile value (i.e. the slope of subcool/liquid level) (y-axis) as a function of operating time (x-axis) is generally monotonically increasing over the first 2,000 days or so, after which it may stabilize around a long-run value.

[0125] Preferably, after an updated local profile value is determined, the rate of 'drift' of the profile value (i.e. change in the local profile value as a function of operating time) may be estimated for the time period between the determination of the updated profile value and the prior profile value. This estimation of the 'drift' rate may be used as a factor during the liquid level determination at 765.

[0126] For example, the change in the local subcool value (i.e. the difference between the local operating subcool value for the inflow zone and the local shut-in subcool value for the inflow zone) may be scaled by an adjusted profile value (e.g.
the local profile value determined at 740 scaled by the expected 'drift' rate for the time duration since the last shut-in) to determine a change in the local liquid level. This change in the local liquid level can then be applied to the local shut-in liquid level for the inflow zone (determined at 730) to estimate the local operating liquid level.

[0127] Once the changing liquid level has been determined using the method 700, the pressure in the producer wellbore 108 can be determined as the sum of the reservoir pressure P
= res and the changing liquid level multiplied by a density of the liquid.

[0128] The various embodiments of the methods and systems described herein may be implemented using a combination of hardware and software. These embodiments may be implemented in part using computer programs executing on one or more programmable devices, each programmable device including at least one processor, an operating system, one or more data stores (including volatile memory or non-volatile memory or other data storage elements or a combination thereof), at least one communication interface and any other associated hardware and software that is necessary to implement the functionality of at least one of the embodiments described herein. For example, and without limitation, suitable computing devices may include one or more of a server, a network appliance, an embedded device, a personal computer, a laptop, a wireless device, or any other computing device capable of being configured to carry out some or all of the methods described herein.

[0129] In at least some of the embodiments described herein, program code may be applied to input data to perform at least some of the functions described herein and to generate output information. The output information may be applied to one or more output devices, for display or for further processing.

[0130] For example, a computer monitor or other display device may be configured to display a graphical representation of time to pseudo-steady state for a selected pressure sensor. In some embodiments, a schematic representation of the injector, producer, and formation may be displayed, along with a representation (e.g. a graph or chart) of chamber volume along the wellbore.

[0131] At least some of the embodiments described herein that use programs may be implemented in a high level procedural or object oriented programming and/or scripting language or both. Accordingly, the program code may be written in C, Java, SQL

or any other suitable programming language and may comprise modules or classes, as is known to those skilled in object oriented programming. However, other programs may be implemented in assembly, machine language or firmware as needed. In either case, the language may be a compiled or interpreted language.

[0132]
The computer programs may be stored on a storage media (e.g.
a computer readable medium such as, but not limited to, ROM, magnetic disk, optical disc) or a device that is readable by a general or special purpose computing device. The program code, when read by the computing device, configures the computing device to operate in a new, specific and predefined manner in order to perform at least one of the methods described herein.

[0133]
While the applicant's teachings described herein are in conjunction with various embodiments for illustrative purposes, it is not intended that the applicant's teachings be limited to such embodiments as the embodiments described herein are intended to be examples. On the contrary, the applicant's teachings described and illustrated herein encompass various alternatives, modifications, and equivalents, without departing from the embodiments described herein, the general scope of which is defined in the appended claims.

Claims

Claims We claim:

1. A system to estimate chamber conformance of a gravity drainage chamber in a subterranean reservoir during a thermal gravity drainage process, the thermal gravity drainage process operated in an injector well and a producer well, the injector well and the producer well being positioned within the gravity drainage chamber, the system comprising:
a plurality of pressure sensors distributed along the injector well, each sensor of the plurality of sensors positioned outside a steel casing of the injector well and configured to measure a local pressure of a respective portion of the reservoir adjacent to the injector well; and one or more processors operatively coupled to each pressure sensor of the plurality of pressure sensors, the one or more processors, collectively, configured to:
receive the pressure of the portion of the chamber adjacent to the injector well as measured by each pressure sensor of the plurality of pressure sensors;

determine a time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well when both the injector well and the producer well are shut-in; and based on the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimate the chamber conformance along the injector well.

2. The system of claim 1, wherein the one or more processors is further configured to, during the step of estimating the chamber conformance along the injector well, estimate a total swept volume of the chamber and, based on the total swept volume of the chamber and the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimate the chamber conformance along the injector well.

3. The system of claim 2, wherein the time to achieve pseudo steady state is proportional to the volume of each portion of the chamber adjacent to the injector well.

4. The system of claim 2, wherein the system further comprises a flow rate sensor to measure a flow rate of injected fluid into the injector well, and the one or more processors is further configured to, during the step of estimating the chamber conformance along the injector well, estimate the total swept volume of the chamber over time based on the flow rate of injected fluid into the injector well.

5. The system of claim 4, wherein the injected fluid is steam.

6. The system of claim 4, wherein the injected fluid is a combination of steam and solvent.

7. The system of any one of claims 1 to 6, wherein the plurality of pressure sensors are evenly distributed along the injector well.

8. The system of any one of claims 1 to 6, wherein the plurality of pressure sensors are unevenly distributed along the injector well.

9. The system of any one of claims 1 to 8, wherein the plurality of pressure sensors includes at least 8 pressure sensors.

10. The system of claim 5, wherein the thermal gravity drainage process is a vapour extraction process.

11. The system of claim 6, wherein the thermal gravity drainage process is a solvent-assisted, steam-assisted gravity drainage process.

12. A system to estimate chamber conformance of a gravity drainage chamber in a subterranean reservoir during a thermal gravity drainage process, the thermal gravity drainage process operated in an injector well and a producer well, the injector well and the producer well being positioned within the gravity drainage chamber, the system comprising:

a plurality of pressure sensors distributed along the producer well, each sensor of the plurality of sensors configured to measure a pressure of a portion of the reservoir adjacent to the producer well; and one or more processors operatively coupled to each pressure sensor of the plurality of pressure sensors, the one or more processors, collectively, configured to:
receive the pressure of the portion of the chamber adjacent to the producer well as measured by each pressure sensor of the plurality of pressure sensors;
determine a time to achieve pseudo steady state for each portion of the chamber adjacent to the producer well when both the injector well and the producer well are shut-in; and based on the time to achieve pseudo steady state for each portion of the chamber adjacent to the producer well, estimate the chamber conformance along the producer well.

13. The system of claim 12, wherein estimating the chamber conformance along the producer well includes:
determining a liquid level in the reservoir between a horizontal segment of the injection wellbore and a horizontal segment of the production wellbore; and based on the liquid level, determining a pressure in the reservoir.

14. The system of claim 13, wherein the one or more processors is further configured to, during the step of estimating the chamber conformance along the producer well, estimate a total swept volume of the chamber and, based on the total swept volume of the chamber and the time to achieve pseudo steady state for each portion of the chamber adjacent to the producer well, estimate the chamber conformance along the producer well.

15. The system of claim 14, wherein the time to achieve pseudo steady state is proportional to the volume of each portion of the chamber adjacent to the producer well.

16. The system of claim 14, wherein the system further comprises a flow rate sensor to measure the flow rate of injected fluid into the injector well and the one or more processors is further configured to, during the step of estimating the chamber conformance along the producer well, estimate the total swept volume of the chamber over time based on the flow rate of injected fluid into the injector well.

17. The system of claim 16, wherein the injected fluid is steam.

18. The system of claim 16, wherein the injected fluid is a combination of steam and solvent.

19. The system of any one of claims 12 to 18, wherein the plurality of pressure sensors are evenly distributed along the producer well.

20. The system of any one of claims 12 to 18, wherein the plurality of pressure sensors are unevenly distributed along the producer well.

21. The system of any one of claims 12 to 20, wherein the plurality of pressure sensors includes at least 8 pressure sensors.

22. The system of claim 17, wherein the thermal gravity drainage process is a vapour extraction process.

23. The system of claim 18, wherein the thermal gravity drainage process is a solvent-assisted, steam-assisted gravity drainage process.

24. A method of estimating chamber conformance in a drainage chamber in a subterranean reservoir during a thermal gravity drainage process, the thermal gravity drainage process operated in an injector well and a producer well, the injector well and the producer well being positioned within the gravity drainage chamber, the method comprising:
measuring a pressure of a portion of the reservoir adjacent to the injector well with each of a plurality of pressure sensors distributed along the injector well; and receiving the pressure measurements at one or more processors operatively coupled to each pressure sensor of the plurality of pressure sensors;

determining a time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well when both the injector well and the producer well are shut-in; and based on the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimating the chamber conformance along the injector well.

25. The method of claim 24, further comprising, during the step of estimating the chamber conformance along the injector well, estimating a total swept volume of the chamber and, based on the total swept volume of the chamber and the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimating the chamber conformance along the injector well.

26. The method of claim 25, wherein the time to achieve pseudo steady state is proportional to the volume of each portion of the chamber adjacent to the injector well.

27. The method of claim 25, further comprising, during the step of estimating the chamber conformance along the injector well, estimating the total swept volume of the chamber over time based on the flow rate of injected fluid into the injector well.

28. The method of claim 27, wherein the injected fluid is steam.

29. The method of claim 27, wherein the injected fluid is a combination of steam and solvent.

30. The method of any one of claims 24 to 29, wherein the plurality of pressure sensors are evenly distributed along the injector well.

31. The method of any one of claims 24 to 29, wherein the plurality of pressure sensors are unevenly distributed along the injector well.

32. The method of any one of claims 24 to 31, wherein the plurality of pressure sensors includes at least 8 pressure sensors.

33. The method of claim 28, wherein the thermal gravity drainage process is a vapour extraction process.

34. The method of claim 29, wherein the thermal gravity drainage process is a solvent-assisted, steam-assisted gravity drainage process.

35. The method of any one of claims 24 to 34, further comprising, in response to estimating the chamber conformance, performing at least one of: increasing an injection rate of a fluid to the injector wellbore to increase a total flow rate of fluids in the injector wellbore, decreasing an injection rate of a fluid to the injector wellbore to decrease the total flow rate of fluids in the injector wellbore, working over the injector wellbore to reduce skin formation, modifying a future wellbore design to improve conformance, and injecting a scale inhibitor into the injector wellbore to reduce a rate of scale formation.

36. The method of any one of claims 24 to 34, further comprising, in response to estimating the chamber conformance, performing at least one of: a comparison of the chamber conformance to chamber volumes for several wells in a pad to provide insight into geology of the reservoir and injection rate among wells, and constrain a simulation to provide improve a recovery forecast.

37. A method of estimating chamber conformance gravity drainage chamber in a subterranean reservoir during a thermal gravity drainage process, the thermal gravity drainage process operated in an injector well and a producer well, the injector well and the producer well being positioned within the gravity drainage chamber, the method comprising:
measuring a pressure of a portion of the reservoir adjacent to the producer well with each of a plurality of pressure sensors distributed along the injector well; and receiving the pressure measurements at one or more processors operatively coupled to each pressure sensor of the plurality of pressure sensors;
determining a time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well when both the injector well and the producer well are shut-in; and based on the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimating the chamber conformance along the injector well.

38. The method of claim 37, further comprising:
determining a liquid level in the reservoir between a horizontal segment of the injection wellbore and a horizontal segment of the production wellbore; and based on the liquid level, determining a pressure in the reservoir.

39. The method of claim 38, further comprising, during the step of estimating the chamber conformance along the injector well, estimating a total swept volume of the chamber and, based on the total swept volume of the chamber and the time to achieve pseudo steady state for each portion of the chamber adjacent to the injector well, estimating the chamber conformance along the injector well.

40. The method of claim 38, wherein the time to achieve pseudo steady state is proportional to the volume of each portion of the chamber adjacent to the injector well.

41. The method of claim 40, further comprising, during the step of estimating the chamber conformance along the injector well, estimating the total swept volume of the chamber over time based on the flow rate of injected fluid into the injector well.

42. The method of claim 41, wherein the injected fluid is steam.

43. The method of claim 41, wherein the injected fluid is a combination of steam and solvent.

44. The method of any one of claims 37 to 43, wherein the plurality of pressure sensors are evenly distributed along the injector well.

45. The method of any one of claims 37 to 43, wherein the plurality of pressure sensors are unevenly distributed along the injector well.

46. The method of any one of claims 37 to 45, wherein the plurality of pressure sensors includes at least 8 pressure sensors.

47. The method of claim 42, wherein the thermal gravity drainage process is a vapour extraction process.

48. The method of claim 43, wherein the thermal gravity drainage process is a solvent-assisted, steam-assisted gravity drainage process.