CA3036414C

CA3036414C - Cyclic hybrid integrated process utilizing steam and solvent

Info

Publication number: CA3036414C
Application number: CA3036414A
Authority: CA
Inventors: Mathew D. Suitor; Jianlin Wang
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2019-03-12
Filing date: 2019-03-12
Publication date: 2020-08-25
Anticipated expiration: 2039-03-12
Also published as: CA3058775A1; CA3058775C; CA3036414A1

Abstract

A method of recovering bitumen from an underground reservoir penetrated by at least one well is described herein. The method includes injecting a first mobilizing fluid into the reservoir. The first mobilizing fluid has a volume that is less than about 20% by weight of a forecast injection volume of fluid to be injected into the reservoir. The method also includes injecting a first hydrocarbon solvent into the reservoir, the first hydrocarbon solvent having a volume equal to a remainder of the forecast injection volume of fluid to be injected into the reservoir, shutting the first hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir, and recovering bitumen of lowered viscosity from the reservoir.

Description

CYCLIC HYBRID INTEGRATED PROCESS UTILIZING STEAM AND SOLVENT
Technical Field [0001] The present disclosure relates generally to methods of recovering hydrocarbons, and more specifically to cyclic hybrid integrated processes utilizing solvent and other mobilizing fluids.
Background

[0002] This section is intended to introduce various aspects of the art that may be associated with the present disclosure. This discussion aims to provide a framework to facilitate a better understanding of particular aspects of the present disclosure.
Accordingly, it should be understood that this section should be read in this light, and not necessarily as an admission of prior art.

[0003] Historically commercial in-situ oil sands processes have included:
cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD), and steam-flood (SF).
These processes have extracted oil from underground reservoirs using steam.
The next generation of in-situ processes may use solvent-steam or pure solvent to extract oil from similar reservoirs. The benefits of these processes are lower energy intensity, lower water usage, ability to access previously uneconomic resource, and higher reservoir recovery rates.

[0004] In steam-based processes, increased temperature lowers the viscosity of oil allowing it to flow and be produced. In solvent-based process, the solvent dilutes the oil and lowers the viscosity of oil allowing it to flow.

[0005] Steam-based oil sands extraction processes use water sourced from nearby local supplies to fill central processing facilities (CPF). These sources of water may include: surface water, aquifers; freshwater or brackish, and produced water from other operations. For steam-based processes, the CPF is generally sized for the resources that are available and to bring steam online quickly.

[0006] In contrast, as production or extraction of solvent may not be possible at the oil extraction location, solvent generally needs to be transported to site.
Transportation can be by truck, train, or pipeline. Once the solvent has been brought to site, a high percentage of solvent (>75%) will be recycled and continuously used in the solvent processes. There is a commercial tradeoff with bringing solvent to site. The supply must be sized to balance cost, quantity required, and delivery dependability.
Therefore, due to inability to bring large quantity of solvent to site initially, there will be a longer time period for solvent processes to achieve plateau injection rates. This slower ramp to peak solvent injection leads to lower oil production and a decrease in economics.

[0007] Previous studies have shown that steam-based process and solvent-based processes can target the same resource. However, steam-based processes can have inferior performance in solvent specific resources due to thinner pay, lower bitumen saturation, and pressure restrictions and/or limitations. One of the primary reasons is due to heat losses to non-pay (e.g. cap rock, low bit-sat sands). The performance downgrade with steam processes would be more pronounced in mid-to-late life as the steam chamber grows. For solvent-based processes, heat in the near wellbore area could improve performance.

[0008] Accordingly, there is a need for improved methods of enhancing cyclic solvent processes with steam for bitumen recovery from oil sands reservoirs.
Summary

[0009] The present disclosure provides methods of recovering bitumen from an underground reservoir penetrated by at least one well. According to at least one aspect, the methods include injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid having a volume that is less than about 20% by weight of a forecast injection volume of fluid to be injected into the reservoir. The methods also include stopping injecting the first mobilizing fluid into the reservoir, injecting a first hydrocarbon solvent into the reservoir, the first hydrocarbon solvent having a volume equal to a remainder of the forecast injection volume of fluid to be injected into the reservoir, shutting the hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir, and recovering bitumen of lowered viscosity from the reservoir.

,

[0010] Injecting the first mobilizing fluid into the reservoir may increase a first pressure in the reservoir to a second pressure in the reservoir, the second pressure in the reservoir being less than about 80% of a lithostatic fracture pressure of the reservoir.

[0011] Injecting the first mobilizing fluid into the reservoir may include co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

[0012] The first mobilizing fluid and the first flow assurance solvent may be mixed to form a mixture, the mixture comprising between about 5% and 95% of the first flow assurance solvent by weight.

[0013] After co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, the methods may further include injecting a second mobilizing fluid into the reservoir.

[0014] Prior to injecting the first mobilizing fluid into the reservoir, the methods may further include injecting a second hydrocarbon solvent into the reservoir, shutting the second hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir, and recovering bitumen of lowered viscosity from the reservoir.

[0015] According to at least another aspect, the methods include injecting a first portion of a first hydrocarbon solvent into the reservoir, the first portion having a volume that is less than a forecast injection volume of fluid to be injected into the reservoir, stopping injecting the first portion of the first hydrocarbon solvent into the reservoir, injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid having a volume that is less than about 20% by weight of the forecast injection volume of fluid to be injected into the reservoir, injecting a second portion of the first hydrocarbon solvent into the reservoir, the second portion of the first hydrocarbon solvent having a volume equal to a remainder of the forecast injection volume of fluid to be injected into the reservoir, shutting the hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir, and recovering bitumen of lowered viscosity from the reservoir.

[0016] Stopping injecting the first hydrocarbon solvent into the reservoir may occur when a pressure in the well increases to a level indicating blocking in the well.

t.

[0017] Injecting the first mobilizing fluid into the reservoir may increase a first pressure in the reservoir to a second pressure of the reservoir, the second pressure in the reservoir being less than about 80% of a lithostatic fracture pressure of the reservoir.

[0018] Injecting the first mobilizing fluid into the reservoir may include co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

[0019] The first mobilizing fluid and the first flow assurance solvent may be mixed to form a mixture, the mixture comprising between about 5% and 95% of the first flow assurance solvent by weight.

[0020] After co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, the methods may further include injecting a second mobilizing fluid into the reservoir.

[0021] The present disclosure also provides methods of recovering bitumen from an underground reservoir penetrated by at least one well where the at least one well has production tubing and casing surrounding the production tubing forming a spacing between the production tubing and the casing. According to this aspect, the methods include injecting a first hydrocarbon solvent into the reservoir, shutting the first hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir, and recovering bitumen of lowered viscosity from the reservoir through the production tubing of the well. During the recovering bitumen of lowered viscosity from the reservoir, a first mobilizing fluid is injected into the reservoir through the spacing between the casing and the production tubing of the well, the mobilizing fluid having a volume that is less than about 20% by weight of a forecast injection volume of fluid to be injected into the reservoir.

[0022] According to another aspect, the methods include injecting a first hydrocarbon solvent into the reservoir, shutting the hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir, and recovering bitumen of lowered viscosity from the reservoir through the production tubing of the well.
Prior to recovering the bitumen from the reservoir, a first mobilizing fluid is injected into the reservoir down the production tubing of the well, the mobilizing fluid having a volume , that is less than about 20% by weight of a forecast injection volume of fluid to be injected into the reservoir.

[0023] Injecting the first mobilizing fluid into the reservoir may be initiated when a bottom-hole pressure of the well is less than a hydrostatic pressure first hydrocarbon solvent and/or a vaporization pressure of the first hydrocarbon solvent.

[0024] A volume of the first mobilizing fluid injected during the injecting the first mobilizing fluid into the reservoir may be in a range of about 10% to about 50% of a volume of bitumen recovered prior to the injecting the first mobilizing fluid into the reservoir.

[0025] Injecting the first mobilizing fluid into the reservoir through the spacing between the casing and the production tubing of the well may increase a first pressure in the reservoir to a second pressure of the reservoir, the second pressure in the reservoir being less than about 80% of a lithostatic fracture pressure of the reservoir.

[0026] Injecting the first mobilizing fluid into the reservoir may include co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

[0027] The first mobilizing fluid and the first flow assurance solvent may be mixed to form a mixture, the mixture comprising between about 5% and 95% of the first flow assurance solvent by weight.

[0028] After co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, the methods may include injecting a second mobilizing fluid into the reservoir.

[0029] Prior to injecting the first hydrocarbon solvent into the reservoir, the methods may further include injecting a second hydrocarbon solvent into the reservoir;, shutting the second hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir and recovering bitumen of lowered viscosity from the reservoir.

[0030] A volume of the first mobilizing fluid injected into the reservoir may be in a range of about 5% to about 50% of a volume of bitumen recovered prior to the injecting the first mobilizing fluid into the reservoir.

,

[0031] Injecting the first mobilizing fluid into the reservoir may be initiated when a production rate of the bitumen approaches a pre-determined economic rate.

[0032] Injecting the first mobilizing fluid into the reservoir may be initiated when a production rate of bitumen approaches a pre-determined fraction of an initial production rate of bitumen.

[0033] Injecting the first mobilizing fluid into the reservoir may be initiated when a production volume of fluids from the well approaches a pre-determined fraction of an injection volume of fluids into the well.

[0034] Recovering bitumen of lowered viscosity from the reservoir may have a duration in a range of between 5 and 20 times a duration of the injecting the first hydrocarbon solvent in the reservoir, and injecting the first mobilizing fluid into the reservoir is initiated about two-thirds into the duration of the recovering bitumen of lowered viscosity from the reservoir.

[0035] A volume of the first mobilizing fluid injected during the injecting the first mobilizing fluid into the reservoir may be in a range of about 5% to about 50%
of a volume of bitumen recovered prior to the injecting the first mobilizing fluid into the reservoir.

[0036] Injecting the first mobilizing fluid into the reservoir may include co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

[0037] According to another aspect, a method of recovering bitumen from an underground reservoir penetrated by at least one well when a first temperature and a first pressure of the reservoir are within a hydrate formation window is described herein. The method includes co-injecting a volume of a first mobilizing fluid and a volume of a first hydrocarbon solvent into the reservoir to adjust the first temperature of the reservoir to a second temperature of the reservoir, the second temperature of the reservoir being outside of a hydrate formation window, the volume of the first mobilizing fluid being less than about 40% by weight of the volume of the first hydrocarbon solvent. The method also includes shutting the first mobilizing fluid and the first hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir, and recovering bitumen of lowered viscosity from the reservoir.

[0038] According to any aspect described herein, the first mobilizing fluid may be steam.

[0039] According to any aspect described herein, the first mobilizing fluid may be water having a temperature greater than about 25 C.

[0040] According to any aspect described herein, the first mobilizing fluid may be water having a temperature in a range of about 50 C to about 75 C.

[0041] According to any aspect described herein, the first hydrocarbon solvent may comprise at least one of ethane, propane, butane, pentane, and di-methyl ether.

[0042] According to any aspect described herein, the second hydrocarbon solvent may include at least one of ethane, propane, butane, pentane, and di-methyl ether

[0043] According to any aspect described herein, the first flow assurance solvent may have a composition comprising at least 50 mol A. of a viscosity-reducing component, based upon total moles in the solvent composition; and at least 5 mol % of a high-aromatics component, based upon total moles in the solvent composition;
wherein the high-aromatics component comprises at least 60 wt. A. aromatics, based upon total weight of the high-aromatics component.

[0044] 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

[0045] 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.

[0046] FIG. 1A is a schematic cross sectional view of a underground reservoir, a vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam from along the horizontal wellbore after integrating solvent-based injection with cyclic steam stimulation processes;

[0047] FIG. 1B is a schematic cross sectional view of a underground reservoir, vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam from along the horizontal wellbore during a cyclic process;

[0048] FIG. 1C is a schematic cross sectional view of a underground reservoir, vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam from along the horizontal wellbore during a cyclic process;

[0049] FIG. 1D is a schematic cross sectional view of a underground reservoir, vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam from along the horizontal wellbore during a cyclic process;

[0050] FIG. 2 is a block diagram of a method of recovering bitumen from an underground reservoir, according to one embodiment;

[0051] FIG. 3 is a block diagram of a method of recovering bitumen from an underground reservoir, according to another embodiment;

[0052] FIG. 4 is a block diagram of a method of recovering bitumen from an underground reservoir, according to another embodiment;

[0053] FIG. 5 is a block diagram of a method of recovering bitumen from an underground reservoir, according to another embodiment; and

[0054] FIG. 6 is a graph comparing reservoir pressure over time for two extraction techniques: 1) seven cycles of CSS, and 2) four cycles of CSS followed by three cycles of CSP.

[0055] 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

[0056] 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.

[0057] 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.

[0058] 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."

[0059] 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.

[0060] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a range from 1 to 9.

[0061] "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.

[0062] 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.

[0063] "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.

[0064] 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 100 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 100. The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.

[0065] 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.

[0066] 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.

[0067] 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."

[0068] 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.

[0069] The term "forecast injection volume" as used herein means an anticipated or expected volume of a fluid to be injected into the reservoir.

=

[0070] The term "lithostatic fracture pressure" as used herein means a pressure at which the rock above the reservoir (overburden) fractures. The lithostatic fracture pressure is the relationship between depth and increasing stress required to fracture/fail rock. The deeper a well, the higher the stress required to fail rock.

[0071] 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.

[0072] 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.

[0073] "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, 6, and C," "one or more of A, 6, 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.

[0074] 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.

[0075] 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.

[0076] In spite of the technologies that have been developed, there remains a need in the field for methods of enhancing the recovery of bitumen.

[0077] Various approaches of enhancing solvent-based extraction processes with the addition of steam are described herein. The proposed approaches involve utilizing and integrating different steam processes and recovery mechanisms at different stages of solvent-based extraction processes to enhance the bitumen recovery from a reservoir.

[0078] Referring now to Figures 1A to 1D, illustrated therein are schematic cross sectional views of an underground reservoir, a vertical wellbore and a horizontal wellbore showing an example of dispersion of solvent and steam along the horizontal wellbore after integrating cyclic solvent processes (CSPs) with cyclic steam stimulation processes (CSSs).

[0079] For instance, FIG. 1A shows a schematic cross sectional view of an underground reservoir 100, a vertical wellbore 102 and a horizontal wellbore 104 showing an example of dispersion of solvent and steam along the horizontal wellbore after performing a single cycle of a CSS after 2 cycles of a CSP.

[0080] FIG. 1B is a schematic cross sectional view of an underground reservoir 110, a vertical wellbore 112 and a horizontal wellbore 114 showing an example of dispersion of solvent and steam along the horizontal wellbore after performing two cycles of a CSP after a single cycle of CSS and before n-3 cycles of the CSS.

[0081] FIG. 1C is a schematic cross sectional view of an underground reservoir 120, a vertical wellbore 122 and a horizontal wellbore 124 showing an example of dispersion of solvent and steam along the horizontal wellbore after performing two cycles of a CSS after a single cycle of a CSP and before n-3 cycles of the CSP.

[0082] FIG. 1D is a schematic cross sectional view of an underground reservoir 130, a vertical wellbore 132 and a horizontal wellbore 134 showing an example of dispersion of solvent and steam along the horizontal wellbore after two cycles of CSS
followed by n-2 cycles of a CSP.

[0083] In the aforementioned CSPs, solvents may be used to enhance the extraction of petroleum products from the reservoir. For instance, the solvent 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.

[0084] 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 mol% C2-05 hydrocarbons on a mass basis. The solvent may be greater than 50 mol% propane, optionally with diluent when it is desirable to adjust the properties of the injectant to improve performance.

[0085] 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.

[0086] 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.

[0087] 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.

[0088] 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.

[0089] 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).

[0090] In some embodiments, different steam processes and recovery mechanisms can be integrated with solvent-based extraction processes by initiating the steam processes prior to a first cycle of a solvent-based extraction process.

[0091] Referring now to FIG. 2, illustrated therein is a method 200 of recovering bitumen from an underground reservoir penetrated by at least one well. The method 200 includes at a step 202, injecting a first mobilizing fluid into the reservoir.
The first mobilizing fluid may be a solvent mixed with steam, or pure steam or water having a temperature above about 25 C. In some embodiments, the first mobilizing fluid may have a temperature in a range of about 50 C to about 75 C. In embodiments where the mobilizing fluid includes a solvent, the solvent can be any solvent described above with respect to the solvents that can be used during the solvent-based extraction processes.

[0092] At step 202, the volume of the first mobilizing fluid that is injected into the reservoir is less than about 20% by weight of a forecast injection volume of fluid to be injected into the reservoir. Herein, the term "forecast injection volume"
refers to an expect volume of fluid to be injected into the reservoir during a single cycle of a CSP.

[0093] The method 200 also includes at a step 204 stopping the injection of the first mobilizing fluid into the reservoir.

[0094] At a step 206, a first hydrocarbon solvent is injected into the reservoir. The first hydrocarbon solvent has a volume equal to a remainder of the forecast injection volume of fluid to be injected into the reservoir. The first hydrocarbon solvent may be a liquid or vapor solvent or a solvent mixed with steam. The first hydrocarbon solvent can be any solvent described above with respect to the solvents that can be used during the solvent-based extraction processes.

[0095] At a step 208, the first hydrocarbon solvent is shut into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir. Herein, the first hydrocarbon solvent is shut into the reservoir when the reservoir is capable of producing bitumen but is not producing bitumen.

[0096] At a step 210, bitumen of lowered viscosity is recovered from the reservoir.

[0097] In some embodiments, injecting the first mobilizing fluid into the reservoir increases a first pressure in the reservoir to a second pressure of the reservoir. In some embodiments, the second pressure in the reservoir may be less than about 80%
of a lithostatic fracture pressure of the reservoir.

[0098] In some embodiments, injecting the first mobilizing fluid into the reservoir may include co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir. Herein, co-injecting may include injecting one or more sequential slugs of the first mobilizing fluid and the first flow assurance solvent into the reservoir. For instance, co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir may include injecting 10 m3 of pure flow assurance solvent, for example, followed by injecting 10 m3 of a first mobilizing fluid (e.g. pure water or steam), for example.

[0099] In some embodiments, the flow assurance solvent may be a light catalytic gas oil (LCGO). In some embodiments, the flow assurance solvent may comprise at least 50 mol % of a viscosity-reducing component, based upon total moles in the solvent composition, and at least 5 mol % of a high-aromatics component, based upon total moles in the solvent composition, wherein the high-aromatics component comprises at least 60 wt. % aromatics, based upon total weight of the high-aromatics component.

= ,

[0100] In some embodiments, the first mobilizing fluid and the first flow assurance solvent may be mixed to form a mixture, the mixture comprising between about 5% and 95% of the first flow assurance solvent by weight.

[0101] In some embodiments, the method 200 may also include, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, injecting a second mobilizing fluid into the reservoir. The second mobilizing fluid may be a solvent mixed with steam, or pure steam or water.

[0102] In some embodiments, the method 200 may also include, prior to injecting the first mobilizing fluid into the reservoir, injecting a second hydrocarbon solvent into the reservoir, shutting the second hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

[0103] In some embodiments, different steam processes and recovery mechanisms can be integrated with solvent-based extraction processes by initiating the steam processes during to an injection cycle of a solvent-based extraction process.

[0104] Referring now to FIG. 3, illustrated therein is a method 300 of recovering bitumen from an underground reservoir penetrated by at least one well. The method 300 includes at a step 302 injecting a first portion of a first hydrocarbon solvent into the reservoir. Again, the first hydrocarbon solvent may be a liquid or vapor solvent or a solvent mixed with steam. The first hydrocarbon solvent can be any solvent described above with respect to the solvents that can be used during the solvent-based extraction processes.
The first portion has a volume that is less than a forecast injection volume of fluid to be injected into the reservoir.

[0105] At a step 304, injecting first hydrocarbon solvent into the reservoir is stopped. In some embodiments, injecting the first hydrocarbon solvent into the reservoir is stopped when a pressure in the well increases to a level indicating blocking in the well.
For instance, blocking in the well may be indicated by comparing a bottom hole pressure in the injection well to a reservoir pressure seen by an observation well or an adjacent production well. If the injection well has a significantly higher pressure than the reservoir . , , well, that could indicate blockage in the injection well. The blockage would generally be suspected or seen in two or three days.

[0106] For example, during injection, the bottom hole pressure of the injector well and the observed pressure in the reservoir (other than first injection cycle) may be within a preselected pressure range. If the difference between the bottom hole pressure of the injector well and the observed pressure in the reservoir is greater than 40%
for more than two, days that could be indicative of plugging.

[0107] At a step 306, a first mobilizing fluid is injected into the reservoir. The first mobilizing fluid has a volume that is less than about 20% by weight of the forecast injection volume of fluid to be injected into the reservoir. In some embodiments, injecting the first mobilizing fluid into the reservoir at step 306 may increase a first pressure in the reservoir to a second pressure of the reservoir, the second pressure in the reservoir being less than about 80% of a lithostatic fracture pressure of the reservoir. In some embodiments, injecting the first mobilizing fluid into the reservoir at step 306 may include co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.
In some embodiments, the first mobilizing fluid and the first flow assurance solvent may be mixed to form a mixture, the mixture comprising between about 5% and 95% of the first flow assurance solvent by weight.

[0108] At a step 308, a second portion of the first hydrocarbon solvent is injected into the reservoir. The second portion of the first hydrocarbon solvent has a volume equal to a remainder of the forecast injection volume of fluid to be injected into the reservoir. In some embodiments, the second portion of the forecast injection volume is in a range of about 3% to about 20% by weight, or in a range of about 5% to about 15% by weight, or about 10% by weight of the forecast injection volume.

[0109] At a step 310, the first hydrocarbon solvent is shut into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir. At step 312, the bitumen of lowered viscosity is recovered from the reservoir.

[0110] In some embodiments, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir at step 306, a second mobilizing fluid may be injected into the reservoir.

[0111] In some embodiments, different steam processes and recovery mechanisms can be integrated with solvent-based extraction processes by initiating the steam processes during a production cycle of a solvent-based extraction process.

[0112] Referring now to FIG. 4, illustrated therein is a method 400 of recovering bitumen from an underground reservoir penetrated by at least one well. In this method, the at least one well generally includes production tubing and casing surrounding the production tubing forming a spacing between the production tubing and the casing.

[0113] The method 400 includes at a step 402 injecting a forecast injection volume of a first hydrocarbon solvent into the reservoir. At a step 404, the hydrocarbon solvent is shut into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir.
At a step 406, bitumen of lowered viscosity is recovered from the reservoir through the production tubing of the well.

[0114] In some embodiments, during the recovery of bitumen from the reservoir, a first mobilizing fluid may be injected into the reservoir. In some embodiments, the first mobilizing fluid may be injected through the spacing between the casing and the production tubing of the well. In other embodiments, the first mobilizing fluid may be injected directly down the production tubing. When the first mobilizing fluid is injected down the casing, production of bitumen may continue. When the first mobilizing fluid is injected down the tubing, production of bitumen is generally halted. Injection pressures of the first mobilizing fluid are generally the same when the mobilizing fluid is injected down the tubing into the wellbore and/or reservoir when compared to when the first mobilizing fluid is injected down the casing into the wellbore and/or reservoir.

[0115] In these embodiments, the method 400 includes a step of stopping the production of the bitumen of lowered viscosity and a step of injecting the first mobilizing fluid directly down the production tubing. The mobilizing fluid may have a volume that is less than about 20% by weight of a forecast injection volume of a first hydrocarbon solvent to be injected into the reservoir.

[0116] In some embodiments, the step 402 of injecting the first mobilizing fluid into the reservoir may be initiated when a bottom-hole pressure of the well is less than a hydrostatic pressure of the first hydrocarbon solvent and/or a vaporization pressure of the . , first hydrocarbon solvent. It should be noted that hydrostatic pressure is generally the pressure that a fluid will flow to a surface without assistance of a pump or any form of artificial lift.

[0117] In some embodiments, the volume of the first mobilizing fluid injected during the step 402 of injecting the first mobilizing fluid into the reservoir is in a range of about 10% to about 50% of a volume of bitumen recovered prior to the injecting the first mobilizing fluid into the reservoir.

[0118] In some embodiments, injecting the first mobilizing fluid into the reservoir through the spacing between the casing and the production tubing of the well may increase a first pressure in the reservoir to a second pressure of the reservoir, the second pressure of the reservoir being less than about 80% of a lithostatic fracture pressure of the reservoir.

[0119] In some embodiments, injecting the first mobilizing fluid into the reservoir includes co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

[0120] In some embodiments, the first mobilizing fluid and the first flow assurance solvent are mixed to form a mixture, the mixture comprising between about 5%
and 95%
of the first flow assurance solvent by weight.

[0121] In some embodiments, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, injecting a second mobilizing fluid into the reservoir.

[0122] In some embodiments, different steam processes and recovery mechanisms can be integrated with solvent-based extraction processes by initiating the steam processes during a production cycle outside of completion of a solvent-based extraction process.

[0123] For instance, the method 400 may further include a step of, prior to injecting a forecast injection volume of the first hydrocarbon solvent into the reservoir, injecting a second hydrocarbon solvent into the reservoir, a step of shutting the second hydrocarbon solvent into the reservoir to lower the viscosity of at least a portion of the bitumen in the , .
reservoir; and a step of recovering bitumen of lowered viscosity from the reservoir. The second hydrocarbon solvent may be the same as the first hydrocarbon solvent or may be different from the first hydrocarbon solvent.

[0124] Injecting the first mobilizing fluid into the reservoir may be initiated when a bottom-hole pressure of the well is less than a hydrostatic pressure first hydrocarbon solvent and/or a vaporization pressure of the first hydrocarbon solvent.

[0125] The volume of the first mobilizing fluid injected into the reservoir may be in a range of about 5% to about 50% of the volume of bitumen recovered prior to the injecting the first mobilizing fluid into the reservoir.

[0126] Injecting the first mobilizing fluid into the reservoir through the spacing between the casing and the production tubing or directly down the production tubing may increase a first pressure in the reservoir to a second pressure of the reservoir, the second pressure in the reservoir being less than about 80% of a lithostatic fracture pressure of the reservoir.

[0127] In some embodiments, the steam processes may be initiated at the end of a production cycle of a solvent-based extraction process to enhance recovery of bitumen during the solvent-based extraction process.

[0128] For instance, method 400 may include injecting the first mobilizing fluid into the reservoir when a production rate of the bitumen approaches a pre-determined economic rate.

[0129] For instance, method 400 may include injecting the first mobilizing fluid into the reservoir when a production rate of the bitumen approaches a pre-determined fraction of an initial production rate of bitumen. For example, method 400 may include injecting the first mobilizing fluid into the reservoir when a production rate of the bitumen approaches one-third of an initial total fluid production rate (e.g. after a first injection cycle), where the initial total fluid production rate includes a total initial production rate of water, solvent, bitumen and gas produced up a casing gas system. In some embodiments, the initial total fluid production rate may be achieved using artificial lift or gas lift.

[0130] For instance, method 400 may include injecting the first mobilizing fluid into the reservoir when a production volume of fluids from the well approaches a pre-determined fraction of an injection volume into the well. For example, method 400 may include injecting the first mobilizing fluid into the reservoir when a produced volume of fluids from the well is about 80% of an injected volume of fluids into the well for a single cycle.

[0131] In some embodiments, the recovering bitumen may have a duration in a range of between 5 and 20 times a duration of the injecting the forecast injection volume of the first hydrocarbon solvent in the reservoir, and the injecting the first mobilizing fluid into the reservoir may be initiated about two-thirds into the duration of the recovering bitumen.

[0132] In some embodiments, a volume of the first mobilizing fluid injected during the injecting the first mobilizing fluid into the reservoir may be in a range of about 5% to about 50% of a volume of bitumen recovered prior to the injecting the first mobilizing fluid into the reservoir.

[0133] In some embodiments, the injecting the first mobilizing fluid into the reservoir either through the spacing between the casing and the production tubing or directly down the production tubing of the well may increase a first pressure in the reservoir to a second pressure of the reservoir, the second pressure in the reservoir being less than about 80% of a lithostatic fracture pressure of the reservoir.

[0134] In some embodiments, the injecting the first mobilizing fluid into the reservoir may include co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

[0135] In some embodiments, the first mobilizing fluid and the first flow assurance solvent may be mixed to form a mixture, the mixture comprising between about 5% and 95% of the first flow assurance solvent by weight.

[0136] In some embodiments, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, a second mobilizing fluid may be injected into the reservoir.

[0137] In some embodiments, steam and solvent may be co-injected through a wellbore into a reservoir to prevent the formation of hydrates in the wellbore. For instance, referring to FIG. 5, illustrated therein is a method 500 of recovering bitumen from an underground reservoir penetrated by at least one well when a first temperature and a first pressure of the reservoir are within a hydrate formation window. The method 500 includes a step 502 of co-injecting a volume of a first mobilizing fluid and a volume of a first hydrocarbon solvent into the reservoir to adjust the first temperature of the reservoir to a second temperature of the reservoir. The second temperature of the reservoir is generally outside of a hydrate formation window and the volume of the first mobilizing fluid is less than about 40% by weight of the volume of the first hydrocarbon solvent.

[0138] In a step 504, the first mobilizing fluid and the first hydrocarbon solvent are shut into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir.

[0139] At a step 506, the bitumen of lowered viscosity is recovered from the reservoir.

[0140] In some embodiments of the methods described herein, the different extraction technologies can specifically be implemented after four cycles of a CSS to improve the bitumen recovery from an underground reservoir.

[0141] FIG. 6 is a graph comparing reservoir pressure over time for two extraction techniques: 1) seven cycles of CSS, and 2) four cycles of CSS followed by three cycles of CSP. This example shows that CSPs can significantly lower the operating pressure and thus can mitigate fluid excursion and casingicaprock integrity issues.

[0142] 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 method of recovering bitumen from an underground reservoir penetrated by at least one well, the method comprising:
injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid having a volume that is less than 20% by weight of a forecast injection volume of fluid to be injected into the reservoir;
stopping injecting the first mobilizing fluid into the reservoir;
injecting a first hydrocarbon solvent into the reservoir, the first hydrocarbon solvent having a volume equal to a remainder of the forecast injection volume of fluid to be injected into the reservoir;
shutting the hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

2. The method of claim 1, wherein the injecting the first mobilizing fluid into the reservoir increases a first pressure in the reservoir to a second pressure in the reservoir, the second pressure in the reservoir being less than 80% of a lithostatic fracture pressure of the reservoir.

3. The method of claim 1 or claim 2, wherein the injecting the first mobilizing fluid into the reservoir includes co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

4. The method of claim 3, wherein the first mobilizing fluid and the first flow assurance solvent are mixed to form a mixture, the mixture comprising between 5% and 95%

of the first flow assurance solvent by weight.

5. The method of claim 3 or claim 4 further comprising, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, injecting a second mobilizing fluid into the reservoir.

6. The method of claim 1 further comprising, prior to injecting the first mobilizing fluid into the reservoir, injecting a second hydrocarbon solvent into the reservoir;
shutting the second hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

7. The method of claim 6, wherein the injecting the first mobilizing fluid into the reservoir increases a first pressure in the reservoir to a second pressure of the reservoir, the second pressure in the reservoir being less than 80% of a lithostatic fracture pressure of the reservoir.

8. The method of claim 6 or claim 7, wherein the injecting the first mobilizing fluid into the reservoir includes co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

9. The method of claim 8, wherein the first mobilizing fluid and the first flow assurance solvent are mixed to form a mixture, the mixture comprising between 5% and 95%

of the first flow assurance solvent by weight.

10. The method of claim 8 or claim 9 further comprising, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, injecting a second mobilizing fluid into the reservoir.

11. A method of recovering bitumen from an underground reservoir penetrated by at least one well, the method comprising:
injecting a first portion of a first hydrocarbon solvent into the reservoir, the first portion having a volume that is less than a forecast injection volume of fluid to be injected into the reservoir;
stopping injecting the first portion of the first hydrocarbon solvent into the reservoir;

injecting a first mobilizing fluid into the reservoir, the first mobilizing fluid having a volume that is less than 20% by weight of the forecast injection volume of fluid to be injected into the reservoir;
injecting a second portion of the first hydrocarbon solvent into the reservoir, the second portion of the first hydrocarbon solvent having a volume equal to a remainder of the forecast injection volume of fluid to be injected into the reservoir;
shutting the hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

12. The method of claim 11, wherein the stopping injecting the first hydrocarbon solvent into the reservoir occurs when a pressure in the well increases to a level indicating blocking in the well.

13. The method of claim 11 or claim 12, wherein the injecting the first mobilizing fluid into the reservoir increases a first pressure in the reservoir to a second pressure of the reservoir, the second pressure in the reservoir being less than 80% of a lithostatic fracture pressure of the reservoir.

14. The method of any one of claims 11 to 13, wherein the injecting the first mobilizing fluid into the reservoir includes co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

15. The method of claim 14, wherein the first mobilizing fluid and the first flow assurance solvent are mixed to form a mixture, the mixture comprising between 5% and 95%

of the first flow assurance solvent by weight.

16. The method of claim 14 or claim 15 further comprising, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, injecting a second mobilizing fluid into the reservoir.

17. A method of recovering bitumen from an underground reservoir penetrated by at least one well, the at least one well having production tubing and casing surrounding the production tubing forming a spacing between the production tubing and the casing, the method comprising:

injecting a first hydrocarbon solvent into the reservoir;
shutting the first hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir through the production tubing of the well;
wherein, during the recovering bitumen of lowered viscosity from the reservoir, a first mobilizing fluid is injected into the reservoir through the spacing between the casing and the production tubing of the well, the mobilizing fluid having a volume that is less than 20% by weight of a forecast injection volume of fluid to be injected into the reservoir.

18. A method of recovering bitumen from an underground reservoir penetrated by at least one well, the at least one well having production tubing and casing surrounding the production tubing forming a spacing between the production tubing and the casing, the method comprising:
injecting a first hydrocarbon solvent into the reservoir;
shutting the hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir through the production tubing of the well;
wherein, prior to recovering the bitumen from the reservoir, a first mobilizing fluid is injected into the reservoir down the production tubing of the well, the mobilizing fluid having a volume that is less than 20% by weight of a forecast injection volume of fluid to be injected into the reservoir.

19. The method of claim 17 or claim 18, wherein the injecting the first mobilizing fluid into the reservoir is initiated when a bottom-hole pressure of the well is less than a hydrostatic pressure first hydrocarbon solvent and/or a vaporization pressure of the first hydrocarbon solvent.

20. The method of any one of claims 17 to 19, wherein a volume of the first mobilizing fluid injected during the injecting the first mobilizing fluid into the reservoir is in a range of 10% to 50% of a volume of bitumen recovered prior to the injecting the first mobilizing fluid into the reservoir.

21. The method of any one of claims 17 to 20, wherein the injecting the first mobilizing fluid into the reservoir through the spacing between the casing and the production tubing of the well increases a first pressure in the reservoir to a second pressure of the reservoir, the second pressure in the reservoir being less than 80% of a lithostatic fracture pressure of the reservoir.

22. The method of any one of claims 17 to 21, wherein the injecting the first mobilizing fluid into the reservoir includes co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

23. The method of claim 22, wherein the first mobilizing fluid and the first flow assurance solvent are mixed to form a mixture, the mixture comprising between 5% and 95%

of the first flow assurance solvent by weight.

24. The method of claim 22 or 23 further comprising, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, injecting a second mobilizing fluid into the reservoir.

25. The method of claim 17 or claim 18 further comprising, prior to injecting the first hydrocarbon solvent into the reservoir, injecting a second hydrocarbon solvent into the reservoir;
shutting the second hydrocarbon solvent into the reservoir to lower viscosity of at least a portion of the bitumen in the reservoir; and recovering bitumen of lowered viscosity from the reservoir.

26. The method of claim 25, wherein the injecting the first mobilizing fluid into the reservoir is initiated when a bottom-hole pressure of the well is less than a hydrostatic pressure first hydrocarbon solvent and/or a vaporization pressure of the first hydrocarbon solvent.

27. The method of claim 25 or claim 26, wherein a volume of the first mobilizing fluid injected into the reservoir is in a range of 5% to 50% of a volume of bitumen recovered prior to the injecting the first mobilizing fluid into the reservoir.

28. The method of claim 18, wherein the injecting the first mobilizing fluid into the reservoir through the casing increases a first pressure in the reservoir to a second pressure of the reservoir, the second pressure in the reservoir being less than 80%
of a lithostatic fracture pressure of the reservoir.

29. The method of any one of claims 25 to 28, wherein the injecting the first mobilizing fluid into the reservoir includes co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

30. The method of claim 29, wherein the first mobilizing fluid and the first flow assurance solvent are mixed to form a mixture, the mixture comprising between 5% and 95%

of the first flow assurance solvent by weight.

31. The method of claim 29 or 30 further comprising, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, injecting a second mobilizing fluid into the reservoir.

32. The method of claim 17 or claim 18, wherein the injecting the first mobilizing fluid into the reservoir is initiated when a production rate of the bitumen approaches a pre-determined economic rate.

33. The method of claim 17 or claim 18, wherein the injecting the first mobilizing fluid into the reservoir is initiated when a production rate of bitumen approaches a pre-determined fraction of an initial production rate of bitumen.

34. The method of claim 17 or claim 18, wherein the injecting the first mobilizing fluid into the reservoir is initiated when a production volume of fluids from the well approaches a pre-determined fraction of an injection volume of fluids into the well.

35. The method of claim 17, wherein the recovering bitumen of lowered viscosity from the reservoir has a duration in a range of between 5 and 20 times a duration of the injecting the first hydrocarbon solvent in the reservoir, and the injecting the first mobilizing fluid into the reservoir is initiated two-thirds into the duration of the recovering bitumen of lowered viscosity from the reservoir.

36. The method of any one of claims 32 to 35, wherein a volume of the first mobilizing fluid injected during the injecting the first mobilizing fluid into the reservoir is in a range of 5% to 50% of a volume of bitumen recovered prior to the injecting the first mobilizing fluid into the reservoir.

37. The method of any one of claims 32 to 36, wherein the injecting the first mobilizing fluid into the reservoir includes co-injecting the first mobilizing fluid and a first flow assurance solvent into the reservoir.

38. The method of claim 37, wherein the first mobilizing fluid and the first flow assurance solvent are mixed to form a mixture, the mixture comprising between 5% and 95%

of the first flow assurance solvent by weight.

39. The method of claim 37 or 38 further comprising, after co-injecting the first mobilizing fluid and the first flow assurance solvent into the reservoir, injecting a second mobilizing fluid into the reservoir.

40. The method of any one of claims 1 to 39, wherein the first mobilizing fluid is steam.

41. The method of any one of claims 1 to 39, wherein the first mobilizing fluid is water having a temperature greater than 25 °C.

42. The method of claims 41, wherein the first mobilizing fluid is water having a temperature in a range of 50 °C to 75 °C.

43. The method of any one of claims 1 to 42, wherein the first hydrocarbon solvent comprises at least one of ethane, propane, butane, pentane, and di-methyl ether.

44. The method of any one of claims 6 to 10, 24 to 26 and 29 to 31, wherein the second hydrocarbon solvent comprises at least one of ethane, propane, butane, pentane, and di-methyl ether.

45. The method of any one of claims 1 to 16, wherein the first flow assurance solvent has a composition comprising:

at least 50 mol % of a viscosity-reducing component, based upon total moles in the solvent composition; and at least 5 mol % of a high-aromatics component, based upon total moles in the solvent composition;
wherein the high-aromatics component comprises at least 60 wt. % aromatics, based upon total weight of the high-aromatics component.