CA3037410C

CA3037410C - Integrated surveillance system for cyclic solvent dominated processes

Info

Publication number: CA3037410C
Application number: CA3037410A
Authority: CA
Inventors: Jianlin Wang; Mathew D. Suitor; Lu Dong; Nafiseh Dadgostar; Gordon D. Macisaac
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2019-03-20
Filing date: 2019-03-20
Publication date: 2020-05-26
Anticipated expiration: 2039-03-20
Also published as: CA3037410A1; CA3058854C; CA3058854A1

Abstract

Systems and methods for monitoring the composition of a produced fluid recovered in a bitumen recovery facility in real-time to predict a phase profile of the produced fluid in real-time are described herein. The systems include at least one flow rate sensor, density sensor, temperature sensor and pressure sensor positioned between a bottom hole of a wellbore and an end of a production stream, and one or more processors operatively coupled to each of the sensors. The one or more processors, collectively, are configured to determine a water-cut of the produced fluid in real-time, determine a solvent content of hydrocarbons of the produced fluid in real-time based on the water-cut, a hydrocarbon density correlation and a bitumen density correlation, and predict a phase profile of the produced fluid in real-time based on the temperature and pressure of the produced fluid. The systems are also configured to initiate actions for mitigating potential flow assurance disruptions based on the predicted phase profile of the produced fluid.

Description

INTEGRATED SURVEILLANCE SYSTEM FOR CYCLIC SOLVENT DOMINATED
PROCESSES
Technical Field [0001] The present disclosure relates generally to systems and surveillance methods of bitumen recovery operations, and more specifically, to systems and surveillance methods of bitumen recovery operations of cyclic solvent dominated processes.
Background

[0002] In the oil and gas industry, flow assurance refers to a cost-effective approach of producing and transporting a hydrocarbon stream from a reservoir (i.e. an underground reservoir) to a processing facility.

[0003] To ensure that the hydrocarbon stream is transported to the processing facility in a cost-effective manner, techniques such as network modelling and transient multiphase simulation may be used to monitor and predict fluid properties that might negatively influence flow assurance, such as the formation of solid deposits within the pipeline (e.g. gas hydrates, asphaltene, wax, scale, and naphthalenes).

[0004] The application of solvent as a primary injectant in cyclic solvent dominated recovery processes introduces challenges for real-time operational surveillance. For instance, it can be difficult to monitor the composition and phases of a hydrocarbon stream produced from an underground reservoir in real-time at various locations within a bitumen recovery facility because the operating conditions throughout the facility change and affect phases of the hydrocarbon stream. Accordingly, it is important to be able to monitor the composition of the hydrocarbon stream and operating conditions throughout the facility to predict the phases of the hydrocarbon stream to mitigate flow assurance disruptions.

Summary

[0005] The present disclosure provides systems and methods of recovering bitumen from a reservoir.

[0006] The systems includes systems for monitoring a composition of a produced fluid recovered during a cyclic recovery process in a bitumen recovery facility in real-time to predict a phase profile of the produced fluid in real-time are disclosed herein. The cyclic recovery process includes cyclic injection of a solvent through a wellbore into a reservoir and recovery of the produced fluid. The produced fluid includes hydrocarbons and water and the hydrocarbons include the solvent and bitumen from the reservoir. The system includes at least one flow rate sensor positioned at a first position of the facility between a bottom hole of the wellbore and an end of a production stream to measure a total flow rate of the produced fluid at the first position; at least one density sensor positioned at the first position of the facility to measure a density of the produced fluid at the first position;
at least one temperature sensor positioned at the first position of the facility to measure a temperature of the produced fluid at the first position; at least one pressure sensor positioned at the first position of the facility to measure a pressure of the produced fluid at the first position; and one or more processors operatively coupled to the at least one temperature sensor, the at least one pressure sensor, the at least one flow rate sensor and the at least one density sensor. The one or more processors, collectively, are configured to: determine a water-cut of the produced fluid in real-time at the first position based on the density of the produced fluid at the first position and an estimate of a density of the hydrocarbons of the produced fluid; determine a solvent content of the hydrocarbons of the produced fluid in real-time at the first position based on the water-cut of the produced fluid at the first position, a correlation relating a true density of the hydrocarbons of the produced fluid to an ideal mixing density of the hydrocarbons of the produced fluid, and a correlation relating the true density of the hydrocarbons of the produced fluid to the bitumen density of the produced fluid; and predict a phase profile of the produced fluid in real-time at the first position based on the temperature of the produced fluid at the first position, the pressure of the produced fluid at the first position and the solvent content of the hydrocarbons in the produced fluid at the first position.

, ,

[0007] The first position may be at or near the wellhead.

[0008] The system may also include at least one temperature sensor positioned at a second position of the facility to measure a second temperature of the produced fluid, at least one pressure sensor positioned at the second position of the facility to measure a second pressure of the produced fluid and the one or more processors may be further configured to predict a phase profile of the produced fluid in real-time at the second position based on the second temperature of the produced fluid at the second position, the second pressure of the produced fluid at the second position and the solvent content of the hydrocarbons in the produced fluid at the first position when the second position is downstream from the wellhead.

[0009] The estimate of the density of the hydrocarbons of the produced fluid may be determined based on one or more or historical production data, cycle progress, testing of produced fluids and sample history.

[0010] The one or more processors may be further configured to, when the phase profile of the produced fluid includes a significant fraction of heavy-liquid, add a flow assurance solvent to the production stream to adjust the composition of the produced fluid to have a phase profile without heavy-liquid.

[0011] The one or more processors may be further configured to, when the phase profile of the produced fluid includes a heavy liquid, heat a portion of the wellbore.

[0012] The one or more processors may be further configured to, based on the water-cut, temperature and pressure of the produced fluid at the first position and a hydrate prevention tool, indicate that a hydrate inhibitor is to be added to the injected solvent.

[0013] The hydrate inhibitor may be methanol.

[0014] The system may also include at least one temperature sensor positioned at a bottom hole of the wellbore to measure a bottom hole temperature; at least one pressure sensor positioned at the bottom hole of the wellbore to measure the bottom hole pressure;
and at least one pressure sensor positioned at an observation well of the facility to measure a reference pressure; and the one or more processors may be further configured , s to determine a pseudo-effective permeability of the reservoir based on the bottom hole temperature, the bottom hole pressure and the reference pressure.

[0015] The one or more processors may be further configured to track the pseudo-effective permeability of the reservoir over more than one cycle to detect plugging.

[0016] The one or more processors may be further configured to, when plugging is detected near the wellbore, determine if a mitigation action should be initiated.

[0017] The mitigation action may be adding a flow assurance solvent to the wellbore.

[0018] The mitigation action may be heating a portion of the wellbore.

[0019] The mitigation action may be a stimulation injection of flow assurance solvent into the reservoir.

[0020] The system may also include a heater for heating at least a portion of the wellbore.

[0021] The one or more processors may be further configured to measure an asphaltene content of a plurality of samples of the produced fluid, each sample taken from the produced fluid at a different time during a production cycle;
determine a cumulative asphaltene produced during the production cycle based on the asphaltenes content of the samples and a volume of bitumen produced during the production cycle;
compare the cumulative asphaltene to a native asphaltene content of the reservoir; and determine an asphaltene deposition in the reservoir.

[0022] The asphaltene deposition in the reservoir may indicate a net asphaltene content deposited in the reservoir, and the one or more processors may be further configured to take the mitigating action of adding a flow assurance solvent to the wellbore.

[0023] The asphaltene deposition in the reservoir may indicate a net asphaltene content deposited in the reservoir, and the one or more processors may be further configured to take the mitigating action of adding heating a portion of the wellbore.

[0024] The asphaltene deposition in the reservoir may indicate a net asphaltene content deposited in the reservoir, and the one or more processors may be further configured to take the mitigating action of adding a stimulation injection of flow assurance solvent into the reservoir.

[0025] The system may also include a display device operatively coupled to the one or more processors, and the one or more processors may be further configured to cause the display device to display a graphical representation of the phase profile of the produced fluid.

[0026] The methods include methods of monitoring a composition of a produced fluid recovered during a cyclic recovery process in a bitumen recovery facility in real-time to predict a phase profile of the produced fluid in real-time is also described herein. The cyclic recovery process includes cyclic injection of a solvent through a wellbore into a reservoir and recovery of the produced fluid. The produced fluid includes hydrocarbons and water, the hydrocarbons including the solvent and bitumen from the reservoir. The methods include measuring using at least one flow rate sensor positioned at a first position of the facility between a bottom hole of the wellbore and an end of a production stream a total flow rate of the produced fluid at the first position;
measuring using at least one density sensor positioned at the first position of the facility a density of the produced fluid at the first position; measuring using at least one temperature sensor positioned at the first position of the facility a local temperature of the produced fluid;
measuring using at least one pressure sensor positioned at the first position of the facility a local pressure of the produced fluid; determining a water content of the produced fluid in real-time based on the density of the produced fluid at the first position and an estimate of a density of the hydrocarbons of the produced fluid at the first position; determining a solvent content of the hydrocarbons of the produced fluid in real-time based on the water content of the produced fluid, a correlation relating a true density of the hydrocarbons of the produced fluid to an ideal mixing density of the hydrocarbons of the produced fluid, and a correlation relating the true density of the hydrocarbons of the produced fluid to the bitumen density of the produced fluid; and predicting a phase profile of the produced fluid in real-time based on the local temperature of the produced fluid, the local pressure of the produced fluid and the solvent content of the hydrocarbons in the produced fluid.

, . , ,

[0027] 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

[0028] 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.

[0029] Figure 1 is a schematic diagram exemplary of a solvent dominated process facility for recovering bitumen, according to one embodiment;

[0030] Figure 2 is a block diagram of a method of determining a composition of a produced fluid of the facility for recovering bitumen of FIG. 1, according to one embodiment;

[0031] Figure 3 is a graph showing the density calculated using an "ideal mixing"
relation as a function of measured hydrocarbon density, according to one embodiment;

[0032] Figure 4 is a graph showing a bitumen density correlation as a function of the measured hydrocarbon density, according to one embodiment;

[0033] Figure 5 is a graph showing a ternary phase diagram that is utilized to determine the phases present given the composition, temperature and pressure at a point in the recovery system, according to one embodiment;

[0034] Figure 6 is a graph showing a calculated effective permeability tracked for a single well cycle over cycle;

, .
, ,

[0035] Figure 7A is a graph showing the measured asphaltene content of samples taken over a single cycle;

[0036] Figure 7B is a graph showing cumulative produced asphaltene, inferred from the cumulative produced bitumen and the asphaltene distribution shown in FIG. 7A;
and

[0037] Figure 8 is a hydrate inhibitor dosage tool used to determine the hydrate inhibitor dosage required to mitigate hydrate formation in the production stream based on the composition, temperature and pressure, according to one embodiment.

[0038] 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

[0039] 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.

[0040] 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.

[0041] 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."

[0042] 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.

[0043] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a range from 1 to 9.

[0044] "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. '3/0 or higher);
- 30 wt. A 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.

[0045] 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.

[0046] "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 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.

[0047] 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.

[0048] 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.

[0049] 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.

. .

[0050] 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."

[0051] 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.

[0052] 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.

[0053] "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.

[0054] "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.

[0055] 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.

[0056] The term "asphaltenes" or "asphaltene content" refers to pentane insolubles (or the amount of pentane insoluble in a sample) according to ASTM D3279.
Other examples of standard ASTM asphaltene tests include ASTM test numbers D4055, D6560, and D7061.

[0057] As used herein, "phase profile" should be understood to mean the states of matter of different components of a fluid (for instance including liquid and gaseous states, or mixtures thereof) present at different operating conditions within a field operation.

[0058] As used herein, the term "light liquid" refers to one of two liquid phases formed in a solvent and bitumen system under specific composition, temperature and pressure conditions. The first liquid phase is termed a "light liquid" phase because it is characterized by lower asphaltene content, lower density and lower viscosity when compared to the other liquid phase of the solvent and bitumen system.

[0059] As used herein, the term "heavy liquid" refers to a second of two liquid phases formed in a solvent and bitumen system under specific composition, temperature and pressure conditions. The second liquid phase is termed a "heavy liquid"
phase because it is characterized by higher asphaltene content, higher density and higher viscosity when compared to the other liquid phase of the solvent and bitumen system.

[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 surveillance methods for bitumen recovery of solvent dominated process facilities.

[0066] Herein, a surveillance system that couples real-time field measurements and technical analysis to provide operational guidance is provided.

[0067] Referring now to Figure 1, illustrated therein is a schematic diagram of a layout of a facility 100 for a solvent dominated cyclic process for recovering bitumen from an underground reservoir 110, according to one embodiment. Herein, the underground reservoir 110 includes an injector/producer well 102 and a neighboring observation well 104. Facility 100 includes a collection of surface units 106 and a production pipeline 108.

[0068] Injector/producer well 102 is used to perform cyclic solvent injection and production operations to recover bitumen from underground 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 underground reservoir 110 via wellbore 102. Flow assurance solvent stored in the surface facilities (e.g. flow assurance solvent storage 116) may also be injected with the solvent into the underground reservoir 110.

[0069] In the aforementioned solvent dominated cyclic processes, solvents may be used to enhance the extraction of petroleum products from the reservoir 110.
In some embodiments, the solvent 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 C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics.

[0070] 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.

[0071] 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.

[0072] 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.

[0073] 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 C2-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.

[0074]
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.

[0075]
The solvent composition may comprise at least 5 mol '')/0 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).

[0076]
In the embodiment shown in Figure 1, during production cycles, a produced fluid is recovered from the underground 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 underground reservoir 110. The one or more units may include but are not limited to heaters, test separator(s), and the like.

. ,

[0077] Injector/producer wellbore 102 may include one or more flow rate sensor, density sensor, temperature sensor and pressure sensor positioned slightly downstream of the wellhead 114.

[0078] Neighboring observation wellbore 104 is a wellbore that can be used to observe changes in temperature, pressure of the reservoir 110 over a period.
Injector/producer well wellbore 104 may include one or more flow rate sensor, density sensor, temperature sensor and pressure sensor positioned between the underground reservoir 110 and the wellhead 114.

[0079] 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 underground reservoir 110 and to process the produced fluid from the underground reservoir. Surface facilitates 106 are generally positioned on pad and may include one or more flow rate sensor, density sensor, temperature sensor and pressure sensor positioned between the wellhead 114 and the production pipeline 108. For instance, in the embodiment shown in Figure 1, surface facilities 106 may further include one or more storage units 119, pumps 122 and/or one or more heaters 124 for processing fluids prior to injection into the wellbore 102. Facility 100 may also include an observational wellbore 104 and associated observational wellhead 118.

[0080] Production pipeline 108 generally refers to a collection of one or more units and associated 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.

[0081] Each of the one or more flow rate sensor, density sensor, temperature sensor and pressure sensor of the wellbore 102, observational wellbore 104 and system facilities 106, as well as the one or more pressure and temperature sensors distributed along the length of the production pipeline 108 is operatively coupled to one or more processors 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 the fluid composition using a density based approach yielding estimates of the solvent, bitumen and water volume in the produced stream. The one or more processors then use composition, pressure and temperature measurements to determine the phases present in the produced stream. If the phases present in the produced stream may lead to flow assurance issues, then the one or more processors may trigger one or more mitigation actions.

[0082] As noted above, the composition of the hydrocarbons in the produced fluid and the operating conditions within the facility 100 can be used to determine phases (i.e.
a physically distinctive form of a substance, such as the solid, liquid, and gaseous states of ordinary matter) present in the produced fluid. For instance, under certain operating conditions for a given solvent upon injection into the underground reservoir 110, the physical properties of the hydrocarbons in the produced fluid can change and/or additional hydrocarbon phases in the produced fluid may be present. Such changes can lead to flow assurance issues within the reservoir 110, wellbore 102, units within the surface facilities 106 and/or the production pipeline 108.

[0083] Turning now to Figure 2, illustrated therein is a block diagram of a method 200 of determining a composition of the produced fluid including hydrocarbons and water.
At steps 202, 204, 206 and 208, measurements of the total flow rate of the produced fluid, density (p) of the produced fluid, temperature of the produced fluid and pressure of the produced fluid are recorded at a first position of the facility 100 in real-time using one or more of the flow rate, density, temperature and pressure sensors of wellbore 102, the wellhead 114, and/or the surface facilities 106, respectively. In some embodiments, the first position of the facility 100 is a position at the wellhead 114 of the facility 100 or between the wellhead 114 and the production pipeline 108.

[0084] In a cyclic solvent process, the density of the hydrocarbons in the produced fluid (and the density of the bitumen) change over a production cycle as the solvent concentration in the produced fluid decreases. Therefore, to determine the composition of the produced fluid in real-time, initial estimates of the hydrocarbon density and the bitumen density of the produced fluid at a first position are necessary as well as a correlation relating a true density of the hydrocarbons of the produced fluid to the hydrocarbon density that would be computed using "ideal mixing". Sources for these estimates are described below.

[0085] First, at step 210, to determine a composition of the produced fluid at a first position of the facility 100, a density-based calculation is applied to determine the water-cut of the produced fluid at the first position. The density-based calculation is shown below as Equation (1):
PWH = PHC (Pwater PHC)(Pwater (1) where pWH is the density of the produced fluid at the first position (e.g.
wellhead 114), pHC
is the density of the hydrocarbons of the produced fluid, Pwater is the density of water and (pwater is the volume fraction of water.

[0086] In Equation (1), pHc is an estimate of the density of the hydrocarbons of the produced fluid and can be determined based on one or more of historical production data, cycle progress, testing of produced fluids and sample history.

[0087] At step 212, a subsequent calculation is performed to determine the solvent content of the total hydrocarbons in the produced fluid. The second calculation is shown below as Equation (2):
PHC ideal mix = PBit (PSolv PBit)(PSolv (2) where pHC_ideal_mix is the density of the hydrocarbons of the produced fluid at the first position under ideal mixing conditions, psoiv is the density of the solvent of the produced fluid at the first position, pBit is the density of the bitumen of the produced fluid at the first position, and cpsolv is the volume fraction of the of the solvent at the temperature and pressure conditions of the first position.

[0088] Turning now to Figure 3, illustrated therein is one example of a graph showing a relation of measured (i.e. true) hydrocarbon density to a hydrocarbon density calculated using an "ideal mixing" assumption. Ideal mixing implies there is no total volume change of the mixed fluid relative to the summation of the individual component volumes. The correlation shown in Figure 3 was developed using the results of sample analysis program from a solvent dominated process. The composition of each sample . .
was determined experimentally and the true density of the hydrocarbons of the produced fluid was measured in a laboratory under pressurized conditions. The true density of the hydrocarbons of the produced fluid can then be related the density calculated using the "ideal mixing" assumption and the measured composition of the hydrocarbons.

[0089] Figure 4 shows an example of a bitumen density correlation. In the embodiment shown therein, the results of a sample analysis program from a solvent dominated process were used to determine a relationship between the density of hydrocarbons of a produced fluid and the density of bitumen of the produced fluid. In the embodiment shown in Figure 4, the bitumen density of samples of the produced fluid were measured in the laboratory at flashed conditions (e.g. atmospheric pressure).

[0090] Figure 5 shows an example of a phase behaviour tool 500. The tool 500 can be applied to determine the phase(s) of the hydrocarbons present in the produced fluid at different operating conditions within a field operation. The diamonds shown in the tool 500 represent example operating conditions throughout a facility.

[0091] The phase behaviour tool 500 a solvent-bitumen system shown in Figure 5 is shown at a single pressure condition and for a single solvent (e.g.
propane), however, it should be noted that the tool 500 can be used to determine the phase(s) of the hydrocarbons present in the produced fluid over a range of operating conditions expected within the facility 100 (e.g. within the reservoir 110, wellbore 102, surface facilities 106 and the production pipeline 108).

[0092] The dashed-lines 502, 504 in Figure 5 represent a boundary between the single liquid hydrocarbon (L) and the two-phase hydrocarbon regime at two different temperatures, as indicated. For instance, dashed-line 502 represents a boundary between the single liquid hydrocarbon (L) and the two-phase hydrocarbon regime at 30 C and 1800 kPa and dashed-line 504 represents a boundary between the single liquid hydrocarbon (L) and the two-phase hydrocarbon regime at 4 C and 1300 kPa. The first light liquid (LL) phase and a second heavy liquid (HL) phase co-exist in the two-phase regime, as indicated. There is no region between L and LL+HL. The LL+HL region can be two different sizes depending on the temperature and pressure condition.

[0093] The phase regimes and viscosity shown in Figure 5 were determined from experimental phase behavior testing in field operating conditions. The plotted points represent real-time compositions determined from field measurements at locations within the facility 100, such as within the wellbore 102, within the surface facilities 106 or along the production pipeline 108. Points that fall within the two-phase region (HL
+ LL) are within favorable conditions for HL phase formation. The HL physical properties are generally significantly different from the L and LL and pose a risk for facility plugging or flow restriction.

[0094] In some embodiments such as but not limited to the facility 100 shown in Figure 1, the HL phase of the produced fluid can be mitigated by increasing a relative amount of flow assurance solvent and/or increasing the operating temperature of the facility 100. In view of Figure 5, each of these changes can shift the composition of the hydrocarbons of the produced fluid to the L region, which is more favourable for flow assurance.

[0095] Within the L region, the composition of the hydrocarbons in the produced fluid can be further controlled to improve performance (e.g. flow assurance) of the facility 100. For example, by increasing the solvent and/or flow assurance solvent content of the produced fluid, the viscosity of the hydrocarbons in the produced fluid would be decreased thereby lowering a required pressure differential require to transport the fluid.

[0096] In one specific example, the hydrocarbon composition of the produced fluid in a near wellbore region of the facility 100 in solvent dominated processes can be favourable for HL formation since the solvent concentration is high at certain times of the cyclic process. In this example, when the HL phase of the produced fluid forms, the asphaltenes can be deposited in pore spaces of the wellbore 102 and subsequently build-up over time. Near wellbore stimulation with flow assurance solvent can be one method to mitigate the near-wellbore plugging.

[0097] In this case the near well region can be favourable to HL
formation because injected solvent concentration will be high, and bitumen concentration can be low in later cycles. Also, HL formed at regions away from the wellbore will tend to migrate and accumulate in time in the near wellbore region.

. .

[0098] Furthermore, in low temperature solvent dominated processes (i.e.
processes where solvent is injected in liquid form rather than vapour form, generally around about 80 C or less), heating within the wellbore can passively heat the near wellbore region over time. The effect of this near wellbore heating can be to lower the viscosity of the HL or transition the phase regime to a LL region.

[0099] In another example, in a cyclic process where the flow rate of the produced fluid declines over a production cycle, it may be difficult to identify when the HL formation is inhibiting the hydrocarbon production rate. Herein, two methods are described for identifying HL build-up in the near wellbore region: (a) real-time tracking of a pseudo-effective permeability; and (b) asphaltene deposition within a reservoir.

[0100] With respect to real-time tracking of a pseudo-effective permeability, a pseudo-effective permeability (keff) of the reservoir 100 can be calculated using field measurements and applying rearranged form of Darcy's Law (Equation 3):
keff = i--LapQ 711" (3)

[0101] The real-time composition of the produced fluid, a measured bottom-hole (BH) pressure (e.g. by a pressure sensor positioned at a bottom of the wellbore 102) and a measured BH temperature (e.g. by a temperature sensor positioned at a bottom of the wellbore 102) are inputs to calculate an in-situ hydrocarbon viscosity (p) using a viscosity model calibrated for the facility 100.

[0102] A pressure difference from the production well measured at the bottom-hole to a reference pressure measurement, such as a pressure of the observation well 104, can be used as a proxy for the in situ pressure drop (AP). The difference between these two pressures is caused by pressure losses that occur while fluid is moving through the porous reservoir (and the wellbore). With the measured rate of production of the produced fluid (e.g. and the hydrocarbons), the pseudo-effective permeability can be calculated and tracked cycle-over-cycle, as shown in the graph provided in Figure 6. As shown, cycle 2 and cycle 3 show similar behavior to each other whereas cycle 4 shows different behavior (e.g. lower pseudo effective permeability at the same level of cycle progress, where cycle progress is measured as hydrocarbon recovery relative to the hydrocarbons injected per . .
, cycle). An earlier reduction of the pseudo-effective permeability is an indicator that a mitigation action should be initiated.

[0103] Mitigation actions to be initiated may include but are not limited to: a stimulation injection of flow assurance solvent to the near wellbore region, a wellbore circulation of flow-assurance solvent, co-injection of flow assurance solvent during the following injection cycle and a stimulation injection of flow assurance solvent into the reservoir.

[0104] With respect to asphaltene deposition within a reservoir, the asphaltene deposition in the reservoir can be inferred when the produced asphaltene is compared to native in-situ asphaltene (e.g. in reservoir 110). The produced asphaltene can be measured using an array of samples taken throughout a production cycle. Figure shows a trend of asphaltene content (wt%) as a function of the produced hydrocarbons recovery for a given cycle. The cumulative amount of asphaltene produced over each cycle can be inferred using the asphaltene content trend in Figure 7A and the produced bitumen volume. The resulting cumulative asphaltene produced over the cycle is shown in Figure 7B. The cumulative amount of asphaltene can then be compared to a theoretical case where the asphaltene content is constant and equal to the native bitumen.
As shown in Figure 7B, the measured cumulative asphaltene is lower than the theoretical native bitumen, thereby indicating there is net amount of asphaltene being deposited within the reservoir. If net asphaltene is deposited in the reservoir, the asphaltene deposition mitigations implemented may include a stimulation injection of flow assurance solvent to the near wellbore region, a wellbore circulation of flow-assurance solvent, co-injection of flow assurance solvent during the following injection cycle, etc.

[0105] In another example, hydrate formation occurs in systems with volatile hydrocarbons in the presence of water under certain temperature and pressure conditions. Severe plugging can occur within the flow lines leading to downtime where de-pressurization of the facility is often required to remove the hydrate plug. Methanol or other hydrate inhibitors can be added to the flow for passive mitigation. The hydrate envelope is a function of the temperature, pressure, the hydrocarbons composition and the hydrate inhibitor concentration.

[0106] Referring now to Figure 8, a variation of the hydrate envelop is shown therein. The iso-lines represent the required methanol-to-water volume fraction for a given operating condition within the facility where the operating condition is characterized by the temperature, pressure and fluid composition. The specific hydrate envelope for a given system can be measured experimentally or generated from known correlations.
Herein, real-time pressure and temperature measurements taken along production pipeline 108 can be used in conjunction with the real-time compositional estimate (see above) to determine the required hydrate inhibitor. A dosage of hydrate inhibitor can be determined on the worst case condition along the flow path. The real time monitoring may ensure the correct dosage and reduce the costs associated with the treatment.

[0107] 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.

[0108] 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.

[0109] For example, a computer monitor or other display device may be configured to display a graphical representation of determined phase profiles for the produced fluid.
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 phase behavior in different parts of the facility.

[0110] In another example, the one or more processors may be configured to determine phase profiles for the produced fluid and, based on the determined phase profiles, direct one or more mitigation actions outlined above. These mitigation actions may be directed through the control of one or more units within different parts of the facility. For instance, the one or more processor may be operatively coupled to a valve that can control the flow of a flow assurance solvent to the wellbore. In another example, the one or more processors may be operatively coupled to a heater that is capable of heating a portion of the wellbore.

[0111] 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.

[0112] 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.

[0113] 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 What is claimed is:

1. A system for monitoring a composition of a produced fluid recovered during a cyclic recovery process in a bitumen recovery facility in real-time to predict a phase profile of the produced fluid in real-time, the cyclic recovery process including cyclic injection of a solvent through a wellbore into a reservoir and recovery of the produced fluid, the produced fluid including hydrocarbons and water, the hydrocarbons including the solvent and bitumen from the reservoir, the system comprising:
at least one flow rate sensor positioned at a first position of the facility between a bottom hole of the wellbore and an end of a production stream to measure a total flow rate of the produced fluid at the first position;
at least one density sensor positioned at the first position of the facility to measure a density of the produced fluid at the first position;
at least one temperature sensor positioned at the first position of the facility to measure a temperature of the produced fluid at the first position; and at least one pressure sensor positioned at the first position of the facility to measure a pressure of the produced fluid at the first position;
one or more processors operatively coupled to the at least one temperature sensor, the at least one pressure sensor, the at least one flow rate sensor and the at least one density sensor, the one or more processors, collectively, configured to:
determine a water-cut of the produced fluid in real-time at the first position based on the density of the produced fluid at the first position and an estimate of a density of the hydrocarbons of the produced fluid;
determine a solvent content of the hydrocarbons of the produced fluid in real-time at the first position based on the water-cut of the produced fluid at the first position, a correlation relating a true density of the hydrocarbons of the produced fluid to an ideal mixing density of the hydrocarbons of the produced fluid and a correlation relating the true density of the hydrocarbons to a density of the bitumen of the produced fluid; and predict a phase profile of the produced fluid in real-time at the first position based on the temperature of the produced fluid at the first position, the pressure of the produced fluid at the first position and the solvent content of the hydrocarbons in the produced fluid at the first position.

2. The system of claim 1, wherein the first position is at or near the wellhead.

3. The system of claim 2 further comprising:
at least one temperature sensor positioned at a second position of the facility to measure a second temperature of the produced fluid; and at least one pressure sensor positioned at the second position of the facility to measure a second pressure of the produced fluid;
wherein the one or more processors are further configured to predict a phase profile of the produced fluid in real-time at the second position based on the second temperature of the produced fluid at the second position, the second pressure of the produced fluid at the second position and the solvent content of the hydrocarbons in the produced fluid at the first position when the second position is downstream from the wellhead.

4. The system of any one of claims 1 to 3, wherein the estimate of the density of the hydrocarbons of the produced fluid is determined based on one or more of historical production data, cycle progress, testing of produced fluids and sample history.

5. The system of any one of claims 1 to 4, wherein the one or more processors are further configured to, when the phase profile of the produced fluid includes a significant fraction of heavy-liquid, add a flow assurance solvent to the production stream to adjust the composition of the produced fluid to have a phase profile without heavy-liquid.

6. The system of claim 5, wherein the one or more processors are further configured to, when the phase profile of the produced fluid includes a heavy liquid, heat a portion of the wellbore.

7. The system of claim 1, wherein the one or more processors are further configured to, based on the water-cut, temperature and pressure of the produced fluid at the first position and a hydrate prevention tool, indicate that a hydrate inhibitor is to be added to the injected solvent.

8. The system of claim 7, wherein the hydrate inhibitor is methanol.

9. The system of any one of claims 1 to 8, wherein the system further comprises:
at least one temperature sensor positioned at a bottom hole of the wellbore to measure a bottom hole temperature;
at least one pressure sensor positioned at the bottom hole of the wellbore to measure the bottom hole pressure; and at least one pressure sensor positioned at an observation well of the facility to measure a reference pressure; and the one or more processors are further configured to determine a pseudo-effective permeability of the reservoir based on the bottom hole temperature, the bottom hole pressure and the reference pressure.

10. The system of claim 9, wherein the one or more processors are further configured to track the pseudo-effective permeability of the reservoir over more than one cycle to detect plugging.

11.The system of claim 10, wherein the one or more processors are further configured to, when plugging is detected near the wellbore, determine if a mitigation action should be initiated.

12.The system of claim 11, wherein the mitigation action is adding a flow assurance solvent to the wellbore.

13.The system of claim 11, wherein the mitigation action is heating a portion of the wellbore.

14.The system of claim 11, wherein the mitigation action is a stimulation injection of flow assurance solvent into the reservoir.

15.The system of claim 11, wherein the mitigation action is adding a flow assurance solvent to the wellbore, heating a portion of the wellbore or a stimulation injection of flow assurance solvent into the reservoir.

16.The system of any one of claims 1 to 15, further comprising a heater for heating at least a portion of the wellbore.

17.The system of any one of claims 1 to 16, wherein the one or more processors are further configured to:
measure an asphaltene content of a plurality of samples of the produced fluid, each sample taken from the produced fluid at a different time during a production cycle;
determine a cumulative asphaltene produced during the production cycle based on the asphaltenes content of the samples and a volume of bitumen produced during the production cycle;
compare the cumulative asphaltene to a native asphaltene content of the reservoir; and determine an asphaltene deposition in the reservoir.

18.The system of claim 17, wherein, when the asphaltene deposition in the reservoir indicates a net asphaltene content deposited in the reservoir, the one or more processors are further configured to take the mitigating action of adding a flow assurance solvent to the wellbore.

19.The system of claim 17, wherein, when the asphaltene deposition in the reservoir indicates a net asphaltene content deposited in the reservoir, the one or more processors are further configured to take the mitigating action of heating a portion of the wellbore.

20.The system of claim 17, wherein, when the asphaltene deposition in the reservoir indicates a net asphaltene content deposited in the reservoir, the one or more processors are further configured to take the mitigating action of adding a stimulation injection of flow assurance solvent into the reservoir.

21.The system of claim 17, wherein when the asphaltene deposition in the reservoir indicates a net asphaltene content deposited in the reservoir, the one or more processors are further configured to add a flow assurance solvent to the wellbore, heat a portion of the wellbore or add a stimulation injection of flow assurance solvent into the reservoir.

22. The system of any one of claims 1 to 21, wherein the system further comprises a display device operatively coupled to the one or more processors, and wherein the one or more processors are further configured to cause the display device to display a graphical representation of the phase profile of the produced fluid.

23.A method of monitoring a composition of a produced fluid recovered during a cyclic recovery process in a bitumen recovery facility in real-time to predict a phase profile of the produced fluid in real-time, the cyclic recovery process including cyclic injection of a solvent through a wellbore into a reservoir and recovery of the produced fluid, the produced fluid including hydrocarbons and water, the hydrocarbons including the solvent and bitumen from the reservoir, the method comprising:
measuring using at least one flow rate sensor positioned at a first position of the facility between a bottom hole of the wellbore and an end of a production stream a total flow rate of the produced fluid at the first position;

measuring using at least one density sensor positioned at the first position of the facility a density of the produced fluid at the first position;
measuring using at least one temperature sensor positioned at the first position of the facility a local temperature of the produced fluid;
measuring using at least one pressure sensor positioned at the first position of the facility a local pressure of the produced fluid;
determining a water content of the produced fluid in real-time based on the density of the produced fluid at the first position and an estimate of a density of the hydrocarbons of the produced fluid at the first position;
determining a solvent content of the hydrocarbons of the produced fluid in real-time at the first position based on the water-content of the produced fluid at the first position, a correlation relating a true density of the hydrocarbons of the produced fluid to an ideal mixing density of the hydrocarbons of the produced fluid and a correlation relating the true density of the hydrocarbons to a density of the bitumen of the produced fluid; and predicting a phase profile of the produced fluid in real-time based on the local temperature of the produced fluid, the local pressure of the produced fluid and the solvent content of the hydrocarbons in the produced fluid;
wherein the method further comprises at least one of the following steps:
when the phase profile of the produced fluid includes a heavy liquid, adding a flow assurance solvent to the production stream;
when the phase profile of the produced fluid includes a heavy liquid, heating a portion of the wellbore;
based on the water-content, temperature and pressure of the produced fluid at the first position and a hydrate prevention tool, adding a hydrate inhibitor to the injected solvent; and when the phase profile of the produced fluid includes a heavy liquid, adding a flow assurance solvent to the production stream, heating a portion of the wellbore or adding a hydrate inhibitor to the injected solvent.

24. The method of claim 23, wherein the first position is at or near the wellhead.

25. The method of claim 24 further comprising:
measuring using at least one temperature sensor positioned at a second position of the facility a second temperature of the produced fluid;
measuring using at least one pressure sensor positioned at the second position of the facility a second pressure of the produced fluid; and predicting a phase profile of the produced fluid in real-time at the second position based on the second temperature of the produced fluid at the second position, the second pressure of the produced fluid at the second position and the solvent content of the hydrocarbons in the produced fluid at the first position when the second position is downstream from the wellhead.

26. The method of any one of claims 23 to 25, wherein the estimate of the density of the hydrocarbons of the produced fluid is determined based on one or more or historical production data, cycle progress, testing of produced fluids and sample history.

27. The method of any one of claims 23 to 26 further comprising, when the phase profile of the produced fluid includes a heavy liquid, adding a flow assurance solvent to the production stream.

28. The method of any one of claims 23 to 26 further comprising, when the phase profile of the produced fluid includes a heavy liquid, heating a portion of the wellbore.

29. The method of any one of claims 23 to 26 further comprising, based on the water-content, temperature and pressure of the produced fluid at the first position and a hydrate prevention tool, adding a hydrate inhibitor to the injected solvent.

30. The method of any one of claims 23 to 26 further comprising, when the phase profile of the produced fluid includes a heavy liquid, adding a flow assurance solvent to the production stream, heating a portion of the wellbore or adding a hydrate inhibitor to the injected solvent.

31. The method of claim 23 or claim 30, wherein the hydrate inhibitor is methanol.

32.A method of monitoring a composition of a produced fluid recovered during a cyclic recovery process in a bitumen recovery facility in real-time to predict a phase profile of the produced fluid in real-time, the cyclic recovery process including cyclic injection of a solvent through a wellbore into a reservoir and recovery of the produced fluid, the produced fluid including hydrocarbons and water, the hydrocarbons including the solvent and bitumen from the reservoir, the method comprising:
measuring using at least one flow rate sensor positioned at a first position of the facility between a bottom hole of the wellbore and an end of a production stream a total flow rate of the produced fluid at the first position;
measuring using at least one density sensor positioned at the first position of the facility a density of the produced fluid at the first position;
measuring using at least one temperature sensor positioned at the first position of the facility a local temperature of the produced fluid;
measuring using at least one pressure sensor positioned at the first position of the facility a local pressure of the produced fluid;
determining a water content of the produced fluid in real-time based on the density of the produced fluid at the first position and an estimate of a density of the hydrocarbons of the produced fluid at the first position;

determining a solvent content of the hydrocarbons of the produced fluid in real-time at the first position based on the water-content of the produced fluid at the first position, a correlation relating a true density of the hydrocarbons of the produced fluid to an ideal mixing density of the hydrocarbons of the produced fluid and a correlation relating the true density of the hydrocarbons to a density of the bitumen of the produced fluid;
predicting a phase profile of the produced fluid in real-time based on the local temperature of the produced fluid, the local pressure of the produced fluid and the solvent content of the hydrocarbons in the produced fluid;
measuring, using at least one temperature sensor positioned at a bottom hole of the wellbore, a bottom hole temperature;
measuring, using at least one pressure sensor positioned at the bottom hole of the wellbore, the bottom hole pressure;
measuring, using at least one pressure sensor positioned at a observation well of the facility, a reference pressure;
determining a pseudo-effective permeability of the reservoir based on the bottom hole temperature, the bottom hole pressure and the reference pressure;
tracking the pseudo-effective permeability of the reservoir over more than one cycle to detect near wellbore plugging; and when near wellbore plugging is detected, determining if a mitigation action should be initiated;
wherein the method further comprises at least one of the following steps:
in response to determining if a mitigation action should be initiated, injecting flow assurance solvent into the wellbore during an injection cycle;
in response to determining if a mitigation action should be initiated, heating a portion of the wellbore to lower the viscosity of the fluid;

in response to determining if a mitigation action should be initiated, adding a stimulation injection of flow assurance solvent into the reservoir;
and in response to determining if a mitigation action should be initiated, injecting flow assurance solvent into the wellbore during an injection cycle, heating a portion of the wellbore to lower the viscosity of the fluid or adding a stimulation injection of flow assurance solvent into the reservoir.

33.The method of claim 32 further comprising, in response to determining if a mitigation action should be initiated, injecting flow assurance solvent into the wellbore during an injection cycle.

34.The method of claim 32 further comprising, in response to determining if a mitigation action should be initiated, heating a portion of the wellbore to lower the viscosity of the fluid.

35.The method of claim 32 further comprising, in response to determining if a mitigation action should be initiated, adding a stimulation injection of flow assurance solvent into the reservoir.

36.The method of claim 32 further comprising, in response to determining if a mitigation action should be initiated, injecting flow assurance solvent into the wellbore during an injection cycle, heating a portion of the wellbore to lower the viscosity of the fluid or adding a stimulation injection of flow assurance solvent into the reservoir.

37. The method of claim 33, wherein the heating a portion of the wellbore passively heats the near wellbore region of the facility.

38.A method of monitoring a composition of a produced fluid recovered during a cyclic recovery process in a bitumen recovery facility in real-time to predict a phase profile of the produced fluid in real-time, the cyclic recovery process including cyclic injection of a solvent through a wellbore into a reservoir and recovery of the produced fluid, the produced fluid including hydrocarbons and water, the hydrocarbons including the solvent and bitumen from the reservoir, the method comprising:
measuring using at least one flow rate sensor positioned at a first position of the facility between a bottom hole of the wellbore and an end of a production stream a total flow rate of the produced fluid at the first position;
measuring using at least one density sensor positioned at the first position of the facility a density of the produced fluid at the first position;
measuring using at least one temperature sensor positioned at the first position of the facility a local temperature of the produced fluid;
measuring using at least one pressure sensor positioned at the first position of the facility a local pressure of the produced fluid;
determining a water content of the produced fluid in real-time based on the density of the produced fluid at the first position and an estimate of a density of the hydrocarbons of the produced fluid at the first position;
determining a solvent content of the hydrocarbons of the produced fluid in real-time at the first position based on the water-cut of the produced fluid at the first position, a correlation relating a true density of the hydrocarbons of the produced fluid to an ideal mixing density of the hydrocarbons of the produced fluid and a correlation relating the true density of the hydrocarbons to a density of the bitumen of the produced fluid; and predicting a phase profile of the produced fluid in real-time based on the local temperature of the produced fluid, the local pressure of the produced fluid and the solvent content of the hydrocarbons in the produced fluid;
measuring an asphaltene content of a plurality of samples of the produced fluid, each sample taken from the produced fluid at a different time during a production cycle;

determining a cumulative asphaltene content produced during the production cycle based on the asphaltenes content of the samples and a volume of bitumen produced during the production cycle;
comparing the cumulative asphaltene content to a native asphaltene content of the reservoir; and determining an asphaltene deposition in the reservoir;
wherein the method further comprises at least one of the following step:
when the asphaltene deposition in the reservoir indicates a net asphaltene content deposited in the reservoir, adding a flow assurance solvent to the wellbore;
when the asphaltene deposition in the reservoir indicates a net asphaltene content deposited in the reservoir, heating a portion of the wellbore; and when the asphaltene deposition in the reservoir indicates a net asphaltene content deposited in the reservoir, adding a flow assurance solvent to the wellbore or heating a portion of the wellbore.

39.The method of claim 38 further comprising, when the asphaltene deposition in the reservoir indicates a nef asphaltene content deposited in the reservoir, adding a flow assurance solvent to the wellbore.

40. The method of claim 38 further comprising, when the asphaltene deposition in the reservoir indicates a net asphaltene content deposited in the reservoir, heating a portion of the wellbore.

41.The method of claim 38 further comprising, when the asphaltene deposition in the reservoir indicates a net asphaltene content deposited in the reservoir, adding a flow assurance solvent to the wellbore or heating a portion of the wellbore.

42.The method of any one of claims 23, 32 and 38 further comprising displaying a graphical representation of the phase profile of the produced fluid on a display device.