CA2974714A1

CA2974714A1 - Methods of recovering viscous hydrocarbons from a subterranean formation

Info

Publication number: CA2974714A1
Application number: CA2974714A
Authority: CA
Inventors: Hamed R. Motahhari; Rahman Khaledi; Nima Saber
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2017-07-27
Filing date: 2017-07-27
Publication date: 2017-09-27
Anticipated expiration: 2037-07-27
Also published as: CA2974714C

Abstract

Methods of recovering viscous hydrocarbons from a subterranean formation. The methods include injecting a first solvent-steam vapor mixture into the subterranean formation for a first injection time period to maintain a target operating pressure within the subterranean formation. The methods also include transitioning, during a transition time period, from injecting the first solvent-steam vapor mixture to injecting a second solvent-steam vapor mixture, and further include injecting the second solvent-steam vapor mixture for a second injection time period. The methods further include producing mobilized viscous hydrocarbons from the subterranean formation. The first solvent has a first dew point temperature and is injected under near-azeotropic conditions. The second solvent has a second dew i)oint temperature that is less than the first dew point temperature.

Description

METHODS OF RECOVERING VISCOUS HYDROCARBONS FROM A
SUBTERRANEAN FORMATION
Field of the Disclosure [0001] The present disclosure relates to methods of recovering viscous hydrocarbons from a subterranean formation.
Background of the Disclosure

[0002]
Hydrocarbons often are utilized as fuels and/or as chemical feedstocks for manufacturing industries. Hydrocarbons naturally may be present within subterranean formations, which also may be referred to herein as reservoirs and/or as hydrocarbon reservoirs.
Such hydrocarbons may occur in a variety of forms, which broadly may be categorized herein as conventional hydrocarbons and unconventional hydrocarbons. A process utilized to remove a given hydrocarbon from a corresponding subterranean formation may be selected based upon one or more properties of the hydrocarbon and/or of the subterranean formation.

[0003]
As an example, conventional hydrocarbons generally have a relatively lower viscosity and extend within relatively higher fluid permeability subterranean formations. As such, these conventional hydrocarbons may be pumped from the subterranean formation utilizing a conventional oil well.

[0004] As another example, unconventional hydrocarbons generally have a relatively higher viscosity and/or extend within relatively lower fluid permeability subterranean formations. As such, a conventional oil well may be ineffective at producing unconventional hydrocarbons.
Instead, unconventional hydrocarbon production techniques may be utilized.

[0005] An example of an unconventional hydrocarbon production technique that may be utilized to produce viscous hydrocarbons from a subterranean formation includes a vapor extraction, or VAPEX, process, in which a solvent vapor is injected into the subterranean formation via an injection well. The solvent vapor contacts the viscous hydrocarbons, within the subterranean formation, dissolving and/or diluting the viscous hydrocarbons and generating reduced-viscosity hydrocarbons. The reduced-viscosity hydrocarbons also may be referred to herein as mobilized viscous hydrocarbons. The mobilized viscous hydrocarbons may flow, within the subterranean fatination, to a production well, which produces the mobilized viscous hydrocarbons from the subterranean formation.

[0006] In a variant of the VAPEX process, which may be referred to herein as heated VAPEX and/or as H-VAPEX, the solvent vapor is heated prior to injection into the subterranean formation. The heated solvent vapor condenses in the subterranean formation and both dissolves/dilutes and heats the viscous hydrocarbons to generate the mobilized viscous hydrocarbons. Heating of the viscous hydrocarbons may decrease the viscosity thereof and/or may increase relative solubility between the solvent and the viscous hydrocarbons, thereby enhancing production of the viscous hydrocarbons from the subterranean formation as mobilized viscous hydrocarbons.

[0007] In a variant of the H-VAPEX process, which may be referred to herein as azeotropic heated VAPEX, as Azeo H-VAPEX, and/or as AH-VAPEX, steam is co-injected with the solvent vapor as a solvent-steam vapor mixture. In the AH-VAPEX process, a relative proportion of steam and solvent injection may be determined based upon phase behavior of the solvent-steam vapor mixture at an operating pressure within the subterranean formation. More specifically, the relative proportion of steam and solvent may be selected to be at, or near, an azeotropic, or minimum boiling point, composition for the solvent-steam vapor mixture. The AH-VAPEX process is described in detail in Canadian Patent Application Publication No.
2,915,571.

[0008] Solvents utilized in the AH-VAPEX process generally may include hydrocarbon solvents that include 3 to 12 carbon atoms. However, medium-boiling hydrocarbon solvents, such as those with 5 to 9 carbon atoms, may provide the highest production rate of mobilized viscous hydrocarbons from the subterranean formation. In contrast, lower-boiling hydrocarbon solvents, such as those with 3 to 5 carbon atoms, may provide lower production rates of mobilized viscous hydrocarbons from the subterranean formation.

[0009] While medium-boiling hydrocarbon solvents may be effective at providing increased production rates, they generally are more difficult to obtain and/or more costly when compared to lower-boiling hydrocarbon solvents. In addition, they may cause higher energy use to produce viscous hydrocarbons from the subterranean formation due to their relatively higher saturation temperature. Lower-boiling hydrocarbon solvents may be more economical to obtain. In addition, they may cause lower energy use to produce viscous hydrocarbons from the subterranean formation due to their relatively lower saturation temperature.
However, they provide lower production rates and/or may facilitate formation of a second heavy liquid phase within the subterranean formation, thereby limiting overall production of the viscous hydrocarbons from the subterranean formation. These factors may cause the economics of the AH-VAPEX process to be unfavorable under certain conditions. Thus, there exists a need for improved methods of recovering viscous hydrocarbons from a subterranean formation.

Summary of the Disclosure

[0010] Methods of recovering viscous hydrocarbons from a subterranean formation. The methods include injecting a first solvent-steam vapor mixture into the subterranean formation for a first injection time period to maintain a target operating pressure within the subterranean formation. The first solvent-steam vapor mixture includes a first solvent and steam and has a first dew point temperature. A first solvent molar fraction of the first solvent in the first solvent-steam vapor mixture is 70%-100% of a first azeotropic solvent molar fraction of the first solvent-steam vapor mixture at the target operating pressure.

[0011] The methods also include transitioning, during a transition time period, from injecting the first solvent-steam vapor mixture to injecting a second solvent-steam vapor mixture. The second solvent-steam vapor mixture includes a second solvent and .steam and has a second dew point temperature. The second dew point temperature is less than the first dew point temperature.

[0012] The methods further include injecting the second solvent-steam vapor mixture into the subterranean formation for a second injection time period. = The methods also include producing mobilized viscous hydrocarbons from the subterranean fonnation during the injecting the first solvent-steam vapor mixture, during the transitioning, and/or during the injecting the second solvent-steam vapor mixture.
Brief Description of the Drawings

[0013] Fig. 1 is a schematic representation illustrating examples of a hydrocarbon production system that may include and/or utilize methods according to the present disclosure.

=

[0014] Fig. 2 is a flowchart depicting methods, according to the present disclosure, of recovering viscous hydrocarbons from a subterranean formation utilizing injection of a near-azeotropic solvent-steam vapor mixture.

[0015] Fig. 3 is a schematic plot illustrating deposited heavy fraction for mixtures of a viscous hydrocarbon with different solvents, each mixture having a concentration of solvent of 70 weight (wt.) % at 23 C, and onset solvent concentration to initiate heavy fraction formation for the mixtures of the viscous hydrocarbon with the different solvents.

[0016] Fig. 4 is a schematic plot illustrating dew point temperature as a function of solvent mole fraction for a plurality of solvent-steam vapor mixtures at a pressure of 0.5 MPa.

[0017] Fig. 5 is a schematic plot illustrating an example of an injectant composition vs. time that may be utilized with the methods of Fig. 2.

[0018] Fig. 6 is a schematic plot illustrating an example of another injectant composition vs.
time that may be utilized with the methods of Fig. 2.

[0019] Fig. 7 is a schematic plot illustrating an example of another injectant composition vs.
time that may be utilized with the methods of Fig. 2.

[0020] Fig. 8 is a schematic plot illustrating an example of mobilized viscous hydrocarbon production rate vs. time that may be generated by the methods of Fig. 2.
Detailed Description of the Embodiments

[0021] Figs. 1-8 provide examples of hydrocarbon production systems 10, of methods 200, and/or of data that may be utilized by and/or produced during performance of methods 200, according to the present disclosure. Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of Figs. 1-8, and these elements may not ' be discussed in detail herein with reference to each of Figs. 1-8.
Similarly, all elements may not be labeled in each of Figs. 1-8, but reference numerals associated therewith may be utilized herein for consistency. Elements, components, and/or features that are discussed herein with reference to one or more of Figs. 1-8 may be included in and/or utilized with any of Figs. 1-8 without departing from the scope of the present disclosure. In Figs. 1 and 2, elements that are likely to be included in a particular embodiment are illustrated in solid lines, while elements that are optional are illustrated in dashed lines. However, elements that are shown in solid lines may not be essential and, in some embodiments, may be omitted without departing from the scope of the present disclosure.

[0022] Fig. 1 is a schematic representation illustrating examples of a hydrocarbon production system 10 that may include and/or utilize methods according to the present disclosure.
Hydrocarbon production system 10, which also may be referred to herein as a system 10, includes an injection well 40 that includes an injection wellhead 44 and an injection wellbore 46 that extends within a subterranean formation 32. System 10 also includes a production well 50 that includes a production wellhead 54 and a production wellbore 56 that extends within the subterranean formation. Injection wellbore 46 also may be referred to herein as a wellbore 46.
Similarly, production wellbore 56 also may be referred to herein as a wellbore 56.
Wellbores 46/56 may extend within a subsurface region 30 and/or may extend between a surface region 20 and the subterranean formation. Subsurface region 30 may include an overburden 36 that extends between, or spatially separates, surface region 20 and subterranean formation 32.

[0023] As used herein, the phrase "subterranean formation" may refer to any suitable portion of the subsurface region that includes viscous hydrocarbons and/or from which mobilized viscous hydrocarbons may be produced utilizing the methods disclosed herein.
In addition to the viscous hydrocarbons, the subterranean formation also may include other subterranean strata, such as sand and/or rocks, as well as lower viscosity hydrocarbons, natural gas, and/or water.
The subterranean strata may form, define, and/or be referred to herein as a porous media, and the viscous hydrocarbons may be present, or may extend, within pores of the porous media.

[0024] As used herein, the phrase, "viscous hydrocarbons" may refer to any suitable carbon-containing compound and/or compounds that may be naturally occurring within the subterranean formation and/or that may have a viscosity that precludes their production, or at least economic production, utilizing conventional hydrocarbon production techniques and/or conventional hydrocarbon wells. Examples of such viscous hydrocarbons include heavy oils, oil sands, and/or bitumen.

[0025] As illustrated, wellbores 46/56 may include at least one vertical region 64 and at least one horizontal, or deviated, region 66. As also illustrated, the horizontal region of injection wellbore 46 may extend, within subterranean formation 32, vertically above the horizontal region of production wellbore 56.

[0026] During operation of system 10, and as discussed in more detail herein with reference to methods 200 of Fig. 2, injection well 40 may be utilized to inject an injected stream 42, which may be referred to herein as and/or may be a vapor mixture of steam and solvent, into subterranean formation 32 via wellbore 46. This also may be referred to herein as providing the injected stream to the subterranean formation. Injected stream 42 may flow from wellbore 46 into the subterranean formation, wherein the injected stream may contact, interact with, heat, dissolve, and/or dilute viscous hydrocarbons 34 that naturally may be present, or may occur, within the subterranean formation. The interaction between the viscous hydrocarbons and the injected stream may generate reduced-viscosity hydrocarbons 35 within the subterranean =
formation. Reduced-viscosity hydrocarbons 35 may flow, under the influence of gravity and within the subterranean formation, to production wellbore 56 as a produced stream 52, and production well 50 may convey the produced stream, via production wellbore 56, from the subterranean formation and/or to the surface region.

[0027] Injection of injected stream 42 and production of produced stream 52 may occur, may be performed, and/or may be performed continuously, over a long period of time, such as over many days, weeks, months, or years. Injection of injected stream 42 and production of produced stream 52 from the subterranean formation may generate a vapor chamber 38 therein; and this vapor chamber may grow, or increase in size and/or volume, responsive to injection of the injected stream and production of the produced stream, eventually reaching and/or contacting overburden 36. As used herein, the phrase "vapor chamber" may refer to any suitable region of the subterranean formation within which injection of the injected stream and production of the produced stream has depleted, at least substantially depleted, and/or depleted a producible fraction of naturally occurring viscous hydrocarbons.

[0028] As also illustrated in Fig. 1, system 10 may include an injected stream source 70 and a heating assembly 60. Injected stream source 70 may be configured to provide one or more suitable fluid streams to heating assembly 60. Heating assembly 60 may be configured to heat and/or combine the one or more fluid streams to produce and/or generate injected stream 42, which then may be provided to injection well 40. As discussed, the injected stream may be a vapor mixture of steam and solvent.

[0029] As illustrated in dashed lines in Fig. 1, system 10 also may be configured to recycle a portion of produced stream 52 as a recycled stream 80. Recycled stream 80 may include portions of injected stream 42 that are produced within produced stream 52 and may be re-=
injected into subterranean formation 32, such as via being provided to, or functioning as, injected stream source 70 and/or via being provided to heating assembly 60.

[0030] As illustrated, injected stream source 70 may include a first solvent source 72, a second solvent source 74, and/or a water/steam source 76. As discussed in more detail herein with reference to methods 200 of Fig. 2, system 10 may be configured to inject a first solvent-steam vapor mixture into the subterranean formation and subsequently to inject a second solvent-steam vapor mixture into the subterranean formation. Injected stream 42 may include the first solvent-steam vapor mixture when first solvent source 72 and water/steam source 76 provide corresponding streams to heating assembly 60. Similarly, injected stream 42 may include the second solvent-steam vapor mixture when second solvent source 74 and water/steam source 76 provide corresponding streams to heating assembly 60.

[0031] As also discussed herein with reference to methods 200 of Fig. 2, the first solvent-steam vapor mixture may be injected at, or near, azeotropic, or minimum boiling point, conditions for a given target operating pressure within the subterranean formation. Stated another way, a relative concentration of the first solvent and steam may be selected such that the first solvent-steam vapor mixture forms an azeotrope at the target operating pressure of the subterranean formation. Stated yet another way, the first solvent-steam vapor mixture may be injected as part of an AH-VAPEX process, examples of which are discussed herein.

[0032] For industrial applications, commercially available solvents generally are a mixture of hydrocarbon compounds rather than a pure single compound. Commercial gas condensate, diluents, and naphtha are among the used solvents. The phase behavior of these multicomponent solvents with steam is more complicated than that of single-component solvents with steam.
However, their phase behavior when mixed with steam may be considered as a superposition of the behavior of individual pure compounds. These systems exhibit a semi-azeotropic behavior with a minimum boiling characteristic similar to single compound solvents. The discussion herein involving azeotrope, azeotropic behavior, azeotropic solvent-steam vapor mixture, and near-azeotropic solvent-steam vapor mixture may be extended to a vapor mixture of a multicomponent solvent and steam vapor mixture by replacing the azeotrope point with the minimum boiling point of the multicomponent solvent and steam vapor mixture.

[0033] Solvents utilized in the AH-VAPEX process generally may include hydrocarbon solvents that include 3 to 12 carbon atoms. Examples of industrial solvents composed of these compounds are Natural gas liquids (NGL), liquefied petroleum gases (LPG), gas condensates, diluents, naphtha, and refinery products. Solvents and solvent mixtures composed of medium-boiling hydrocarbon solvents, such as those with 5 to 9 carbon atoms, may provide the highest production rate of mobilized viscous hydrocarbons from the subterranean formation. In contrast, solvents and solvent mixtures composed of lower-boiling hydrocarbon solvents, such as those with 3 to 5 carbon atoms, may provide lower production rates of mobilized viscous hydrocarbons from the subterranean formation. In addition, lower-boiling hydrocarbon solvent mixtures composed of solvents with 3-4 carbon atoms have a greater tendency to form a second heavy liquid phase when they are mixed with naturally occurring viscous hydrocarbons such as heavy oils, oil sands and/or bitumen.

[0034] Fig. 3 is a schematic plot illustrating the second heavy liquid phase formation tendency of normal, or straight-chain, alkane hydrocarbon compounds with 3 to 7 carbon atoms.
In Fig. 3, solvents with 3 carbon atoms are indicated as C3, solvents with 4 carbon atoms are indicated as nC4, etc.

[0035] In general, the lighter the hydrocarbon solvent compound is, the lower is the onset concentration of solvent to initiate the second heavy liquid phase formation.
For example, a mixture of a heavy oil and C3 will form two liquid phases (light-solvent rich and heavy) once the concentration of C3 solvent in the mixture of solvent and heavy oil is greater than approximately 20 weight percent. According to Fig. 3, at 23 C, approximately 45% of the heavy oil mass will deposit as the heavy fraction to the second heavy liquid phase in a mixture of C3 solvent and heavy oil with the concentration of C3 solvent in the mixture of solvent and heavy oil equal to 70 weight percent. In contrast, as another example, a mixture of a heavy oil and nC7 will form two liquid phases (light-solvent rich and heavy) once the concentration of nC7 solvent in the mixture of solvent and heavy oil is greater than approximately 56 weight percent.
According to Fig. 3, at 23 C, approximately 6% of the heavy oil mass will deposit as the heavy fraction to the second heavy liquid phase in a mixture of nC7 solvent and heavy oil with the concentration of nC7 solvent in the mixture of solvent and heavy oil equal to 70 weight percent.

[0036] In the AH-VAPEX process, in general, the second heavy liquid phase may be formed in the subterranean formation due to mixing of hydrocarbon solvents and naturally occurring viscous hydrocarbons such as heavy oils, oil sands and bitumen. In general, some or all of the formed second heavy liquid phase may segregate from the production stream, and/or may deposit in the subterranean formation and may not be produced. The formation and deposition of the second heavy liquid phase in the subterranean formation may cause reduction of the available viscous hydrocarbons resource volumes for production. A significant resource loss may be unfavorable, as it may adversely affect the economic viability of the viscous hydrocarbon recovery.

=
100371 In contrast, due to formation and deposition of the second heavy liquid phase, the produced viscous hydrocarbon from the subterranean formation may have some desirable properties in comparison to the naturally occurring viscous hydrocarbons in the subterranean formation. Hence, the AH-VAPEX process may provide a desired degree of in situ upgrading of the viscous hydrocarbons within the subterranean formation. Examples of desirable properties are a lower viscosity, a higher API , a lower heavy metal compound content, and/or a lower asphaltene content. A balance between resource loss and the degree of in situ upgrading of the viscous hydrocarbons may provide the most favorable economic performance of the AH-' VAPEX process.
100381 While medium-boiling hydrocarbon solvents may be effective at providing increased production rates, they generally are more difficult to obtain and/or more costly when compared to lower-boiling hydrocarbon solvents. In addition, they may cause higher energy use to produce viscous hydrocarbons from the subterranean formation due to their relatively higher saturation temperature. They also may cause a lower degree of in situ upgrading of viscous hydrocarbons within the subterranean formation. In contrast, they may prevent higher volumes of viscous hydrocarbons resource losses.
100391 Lower-boiling hydrocarbon solvents may be more economical to obtain. In addition, they may cause lower energy use to produce viscous hydrocarbons from the subterranean formation due to their relatively lower saturation temperature. However, they provide lower production rates and/or may facilitate a greater degree of formation of the second heavy liquid phase within the subterranean formation. Thus, injection of lower-boiling hydrocarbons may result in a higher degree of in situ upgrading of viscous hydrocarbons within the subterranean formation. In contrast, they also may cause greater volumes of resource losses, thereby limiting overall production of the viscous hydrocarbons from the subterranean formation.
[0040] As discussed herein, the AH-VAPEX process generally is performed utilizing medium-boiling hydrocarbon solvents. As also discussed, the AH-VAPEX process, when performed utilizing medium-boiling hydrocarbon solvents, is quite effective at producing mobilized viscous hydrocarbons within the subterranean formation; however, the medium-boiling hydrocarbon solvents may be costly. With this in mind, the present disclosure transitions from injection of the first solvent-steam vapor mixture, as part of the AH-VAPEX process, to injection of the second solvent-steam vapor mixture, which also may be part of the AH-VAPEX
process.
[0041] The first solvent in the solvent-steam vapor mixture may have a first dew point temperature, and the second solvent in the solvent-steam vapor mixture may have a second dew point temperature that is less than the first dew point temperature. Stated another way, the second solvent-steam vapor mixture may include a second solvent that is, on average, lighter and/or more volatile than the first solvent that is included in the first solvent-steam vapor mixture. Stated yet another way, an average number of carbon atoms in hydrocarbon molecules that comprise the second solvent may be less than an average number of carbon atoms in hydrocarbon molecules that comprise the first solvent.
[0042] This transition from the first solvent-steam vapor mixture to the second solvent-steam vapor mixture may provide several benefits over the prior art. As an example, the second solvent generally is cheaper to purchase, cheaper to obtain, and/or less valuable when compared to the first solvent. The transition from the first solvent-steam vapor mixture to the second solvent-steam vapor mixture decreases an overall volume of the first solvent that is utilized during =
production of the viscous hydrocarbons from the subterranean formation, thereby decreasing an overall cost of the production process.
[0043] As another example, injection of the second solvent-steam vapor mixture may provide a motive force for production of the first solvent, or of mobilized viscous hydrocarbons that include the first solvent, from the subterranean formation. In general, some of the injected first solvent may be retained within the subterranean formation and/or within the vapor chamber due to thermodynamic equilibrium conditions and fluid flow behaviors in a porous media that extends within the subterranean foiniation. The retained first solvent may be present in vapor and/or liquid phases. The injection of the second solvent in the second solvent-steam vapor mixture may dilute the retained first solvent in the vapor phase and strip and evaporate the retained first solvent in liquid phase to vapor phase as described herein.
Thus, the transition from the first solvent-steam vapor mixture to the second solvent-steam vapor mixture may increase recovery of the first solvent from the subterranean formation, thereby decreasing the overall cost of the production process.
[0044] As yet another example, and since the second dew point temperature is less than the first dew point temperature, the transition from the first solvent-steam vapor mixture to the second solvent-steam vapor mixture may decrease an overall energy requirement of the production process. More specifically, injection of the first solvent-steam vapor mixture may heat the subterranean formation to a first temperature. This may include storage of a significant amount of thermal energy within the subterranean formation. In contrast, injection of the second solvent-steam vapor mixture may permit the temperature of the subterranean formation to decrease to a second temperature that is less than the first temperature.

[0045] The first temperature and the second temperature of the subterranean formation may be directly related to the first dew point of the first solvent and the second dew point of the second solvent, respectively. In general, after the transition, the injected second solvent in the second solvent-steam vapor mixture may not condense within the subterranean formation before the temperature of the subterranean formation is reduced to the second temperature. During this period, the second solvent may act as a diluting and/or stripping agent and may change the thermodynamic equilibrium condition in the vapor chamber in favor of evaporation of the retained liquid first solvent. The latent heat of evaporation of the retained liquid first solvent may be provided by the stored thermal energy from the subterranean formation.
Thus, injection of the second solvent-steam vapor mixture facilitates recovery of a portion of the stored thermal energy from the subterranean formation by the decrease of the subterranean formation temperature from the first temperature to the second temperature and by the evaporation of the retained liquid first solvent.
[0046] As discussed in more detail herein, the transition from injection of the first solvent-steam vapor mixture to the second solvent-steam vapor mixture may occur in any suitable manner. As an example, the transition may include a step change in which system 10 ceases injection of the first solvent-steam vapor mixture concurrently with, or before, initiating injection of the second solvent-steam vapor mixture. As another example, the transition may include one or more staged, stepped, and/or ramped changes in solvent injection. As a more specific example, injection of the first solvent-steam vapor mixture may be ramped down and injection of the second solvent-steam vapor mixture concurrently may be ramped up. As another more specific example, injection of the first solvent-steam vapor mixture may be decreased in a series =
of steps and injection of the second solvent-steam vapor mixture concurrently may be increased in a series of steps.
[0047] Fig. 2 is a flowchart depicting methods 200, according to the present disclosure, of recovering viscous hydrocarbons from a subterranean formation utilizing injection of a near-azeotropic solvent-steam vapor mixture. Methods 200 may include selecting a target operating pressure at 205, selecting a first solvent at 210, and/or determining a first azeotropic solvent molar fraction for a first solvent-steam vapor mixture at 215. Methods 200 include injecting the first solvent-steam vapor mixture at 220 and transitioning at 225. Methods 200 also may include selecting a second solvent at 230, determining a second azeotropic solvent molar fraction for a second solvent-steam vapor mixture at 235, and/or ceasing injection of the first solvent-steam vapor mixture at 240. Methods 200 also include injecting the second solvent-steam vapor mixture at 245 and may include recovering the second solvent from the subterranean formation at 250. Methods 200 further include producing mobilized viscous hydrocarbons at 255 and may include separating a recycled solvent stream at 260.
[0048] Selecting the target operating pressure at 205 may include selecting any suitable target operating pressure for the subterranean formation during a remainder of methods 200, selecting a target operating pressure to be maintained, within the reservoir, by the injecting at 220, and/or selecting a target operating pressure to be maintained, within the reservoir, by the injecting at 245. The selecting at 205 may be based upon any suitable criteria. As an example, the selecting at 205 may be based, at least in part, on a vertical depth, within the subterranean formation, for the injecting at 220 and/or for the injecting at 245. Stated another way, the selecting at 205 may be based, at least in part, upon a vertical depth, within the subterranean formation, at which the injecting at 220 and/or the injecting at 245 are performed. As additional examples, the selecting at 205 may be based, at least in part, on one or more of a fracture pressure of the subterranean formation, a hydrostatic pressure within the subterranean formation, a lithostatic pressure within the subterranean formation, a gas cap pressure for a gas cap that extends within the subterranean formation, and/or an aquifer pressure for an aquifer that extends above and/or below the subterranean formation.
[0049] It is within the scope of the present disclosure that the target operating pressure may be constant, or at least substantially constant, during methods 200, during the injecting at 220, during the transitioning at 225, and/or during the injecting at 245.
Alternatively, it also is within the scope of the present disclosure that the target operating pressure may vary, may be varied, and/or may be systematically varied during methods 200, during the injecting at 220, during the transitioning at 225, and/or during the injecting at 245.
[0050] Examples of the target operating pressure include target operating pressures that are at least 5%, at least 10%, at least 20%, at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, at least 80%, at least 90%, at most 95%, at most 90%, at most 80%, at most 70%, at most 60%, at most 50%, at most 40%, at most 30%, at most 20%, and/or at most 10% of the fracture pressure of the subterranean formation. Additional examples of the target operating pressure include target operating pressures of at least 0.1 megapascals (MPa), at least 0.2 MPa, at least 0.3 MPa, at least 0.4 MPa, at least 0.6 MPa, at least 0.8 MPa, at least 1 MPa, at least 1.25 MPa, at least 1.5 MPa, at least 2 MPa, at least 2.5 MPa, at most 5 MPa, at most 4.5 MPa, at most 4 MPa, at most 3.5 MPa, at most 3 MPa, at most 2.5 MPa, and/or at most 2 MPa.
[0051] Selecting the first solvent at 210 may include selecting the first solvent based, at least in part, on the target operating pressure within the subterranean formation.
As an example, the selecting at 210 may include selecting such that the first solvent forms a first vapor at the target operating pressure. As another example, the selecting at 210 may include selecting such that the first solvent forms a first azeotropic, or near-azeotropic, vapor mixture with water at the target operating pressure.
[0052] The selecting at 210 may include selecting based, at least in part, on phase behavior of the first solvent and/or on phase behavior of mixtures of the first solvent and water. As an example, Fig. 4 is a schematic plot illustrating dew point temperature as a function of solvent mole fraction for a plurality of different water-solvent mixtures that form azeotropes 100 at a pressure of 0.5 MPa. These water-solvent mixtures include mixtures of water with butane (C4), or with pentane (C5), or with hexane (C6), or with heptane (C7), or with octane (C8), and or with nonane (C9). Fig. 4 illustrates phase behavior for non-nal-alkane hydrocarbon molecules;
however, it is within the scope of the present disclosure that any suitable hydrocarbon molecule, and corresponding phase behavior, may be utilized.
[0053] Thus, and for a target operating pressure of 0.5 MPa, the phase behavior illustrated in Fig. 4 may be utilized to select a solvent, or a relative concentration of water and solvent in a water-solvent mixture, that forms a vapor at the target operating pressure. As an example, a mixture of a solvent and water forms a vapor mixture when at a temperature that is above dew point temperature line 110 of Fig. 4.
[0054] Additionally or alternatively, the phase behavior illustrated in Fig. 4 may be utilized to select a solvent, or a relative concentration of water and solvent in a water-solvent vapor mixture, that forms an azeotrope at the target operating pressure. As an example, Fig. 4 illustrates that C4-C9 solvent-steam vapor mixtures form azeotropes 100 at corresponding relative solvent-steam compositions and at corresponding azeotropic dew point temperatures.

[0055] Determining the first azeotropic solvent molar fraction at 215 may include determining the first azeotropic solvent molar fraction in any suitable manner. As an example, the phase behavior illustrated in Fig. 4 may be utilized to determine the first azeotropic solvent molar fraction. As a more specific example, Fig. 4 illustrates that a vapor mixture of water and C7 solvent forms an azeotrope at 0.5 MPa and a molar composition of approximately 52% water and 48% heptane. Thus, the first azeotropic solvent molar fraction for the water-heptane vapor mixture at 0.5 MPa is approximately 48% heptane. A near-azeotropic vapor mixture of heptane and water contains 70-100% of the azeotropic heptane solvent molar fraction of the heptane-steam mixture. Stated another way, heptane molar fraction in a near-azeotropic vapor mixture of heptane and water is approximately 33.6-48 % heptane at 0.5 MPa.
[0056] Injecting the first solvent-steam vapor mixture at 220 may include injecting the first solvent-steam vapor mixture into the subterranean formation during a first injection time period.
The injecting at 220 also may include injecting the first solvent-steam vapor mixture to produce, generate, support, sustain, promote, and/or maintain the target operating pressure within the subterranean formation. As discussed herein, the first solvent-steam vapor mixture includes a first solvent and steam. As also discussed herein, the first solvent-steam vapor mixture is injected into the subterranean formation at azeotropic, or near-azeotropic, conditions. More specifically, the first solvent-steam vapor mixture may be injected such that a first solvent molar fraction of the first solvent in the first solvent-steam vapor mixture is within a threshold fraction of the first azeotropic solvent molar fraction of the first solvent-steam vapor mixture at the target operating pressure. Examples of the threshold fraction include threshold fractions of at least 70%, at least 80%, at least 90%, at least 95%, at most 100%, at most 95%, at most 90%, and/or at most 85% of the first azeotropic solvent molar fraction.
=

=
[0057] The first solvent-steam vapor mixture additionally or alternatively may include any suitable volumetric relative proportion of the first solvent and steam to be considered an azeotropic or near-azeotropic vapor mixture. As an example, an azeotropic vapor mixture of heptane and steam includes approximately 88 volume percent heptane and 12 volume percent steam in cold liquid equivalents calculated at standard temperature and pressure. As another example, a near-azeotropic vapor mixture of heptane and steam includes approximately 80-88 volume percent heptane and 12-20 volume percent steam in cold liquid equivalents calculated at standard temperature and pressure. In general, depending on the selected first solvent, the first solvent-steam vapor mixture may include at least 15 volume percent first solvent, at least 20 volume percent first solvent, at least 30 volume percent first solvent, at least 40 volume percent first solvent, at least 50 volume percent first solvent, at least 60 volume percent first solvent, at least 70 volume percent first solvent, at least 80 volume percent first solvent, at least 90 volume percent first solvent, at most 98 volume percent first solvent, at most 95 volume percent first solvent, at most 90 volume percent first solvent, at most 80 volume percent first solvent, at most 70 volume percent first solvent, at most 60 volume percent first 'solvent, at most 50 volume percent first solvent, at most 40 volume percent first solvent, at most 30 volume percent first solvent, and/or at most 20 volume percent first solvent in cold liquid equivalents calculated at standard temperature and pressure.
[0058] As additional examples, the first solvent-steam vapor mixture may include at least 2 volume percent steam, at least 3 volume percent steam, at least 5 volume percent steam, at least 10 volume percent steam, at least 20 volume percent steam, at least 30 volume percent steam, at least 40 volume percent steam, at least 50 volume percent steam, at least 60 volume percent steam, at least 70 volume percent steam, at least 80 volume percent steam, at most 85 volume =
percent steam, at most 80 volume percent steam, at most 70 volume percent steam, at most 60 volume percent steam, at most 50 volume percent steam, at most 40 volume percent steam, at most 30 volume percent steam, at most 20 volume percent steam, and/or at most 10 volume percent steam in cold liquid equivalents calculated at standard temperature and pressure.
[0059] The injecting at 220 may include injecting the first solvent-steam vapor mixture with, via, and/or utilizing an injection well that extends within the subterranean formation. Examples of the injection well are discussed herein with reference to injection well 40 of Fig. 1.
[0060] It is within the scope of the present disclosure that the injecting at 220 further may include generating the mobilized viscous hydrocarbons, within the subterranean formation, from the viscous hydrocarbons. As examples, the generating may include heating the viscous hydrocarbons with the first solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons, diluting the viscous hydrocarbons with a condensed first solvent of the first solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons, and/or dissolving the viscous hydrocarbons in the condensed first solvent of the first solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons.
[0061] The first solvent-steam vapor mixture may include any suitable first solvent and water, or steam, in any suitable relative concentration that is azeotropic, or near-azeotropic, at the target operating pressure. Examples of the first solvent include medium-boiling hydrocarbons including hydrocarbon molecules with at least 4, at least 5, at least 6, at least 7, at most 10, at most 9, at most 8, at most 7 carbon atoms, between 4-10 carbon atoms, and/or between 5-9 carbon atoms. The first solvent may include any suitable proportion, fraction, and/or percentage, of the medium-boiling hydrocarbons. As examples, the first solvent may include at least 40 weight percent, at least 50 weight percent, at least 60 weight percent, at least 70 weight percent, =
at least 80 weight percent, at least 90 weight percent, at most 99 weight percent, at most 95 weight percent, at most 90 weight percent, and/or at most 80 weight percent of the medium-boiling hydrocarbons. Stated another way, hydrocarbon molecules within the first solvent may have and/or define a first average carbon number of at least 4, at least 5, at least 6, at least 7, at least 8, at least 9, at most 10, at most 9, at most 8, at most 7, between 4-10, and/or between 5-9.
As used herein, the phrase "first average carbon number" refers to an average, or mean, number of carbon atoms within the hydrocarbon molecules that comprise the first solvent. Additional examples of the first solvent include hydrocarbons, alkanes, alkenes, alkynes, aliphatic compounds, naphthenic compounds, aromatic compounds, olefinic compounds, natural gas condensate, liquefied petroleum gas, and/or a crude oil refinery stream.
100621 It is within the scope of the present disclosure that the injecting at 220 may include injecting the first solvent-steam vapor mixture with any suitable steam quality. As examples, the steam quality may be at least 5%, at least 10%, at least 20%, at least 40%, at least 60%, at least 80%, at most 100%, at most 90%, and/or at most 80%.
[0063] The injecting at 220 may include injecting the first solvent-steam vapor mixture at any suitable injection temperature. As examples, the injection temperature may be at least 20 C, at least 30 C, at least 40 C, at least 50 C, at least 60 C, at least 70 C, at least 80 C, at least 90 C, at least 100 C, at least 150 C, at most 300 C, at most 250 C, at most 200 C, and/or at most 150 C. As additional examples, the injecting at 220 may include injecting with at least a threshold degree of superheat relative to a first saturation temperature of the first solvent-steam vapor mixture at the target operating pressure. Examples of the threshold degree of superheat include at least 1 C of superheat, at least 2 C of superheat, at least 5 C of superheat, at least 10 C of superheat, at least 20 C of superheat, at most 60 C of superheat, at most 50 C

=
of superheat, at most 40 C of superheat, at most 30 C of superheat, and/or at most 20 C of superheat.
[0064] The first solvent may have and/or define any suitable first dew point temperature. As examples, and at a pressure of 101.325 kilopascals, the first dew point temperature may be at least 20 C, at least 40 C, at least 60 C, at least 80 "C, at least 100 C, at least 120 C, at least 140 C, and/or at least 160 C.
[0065] Transitioning at 225 may include transitioning from the injecting at 220 to the injecting at 245 and may be performed during a transition time period. The second solvent-steam vapor mixture, which is injected during the injecting at 245, includes a second solvent and steam, and the second solvent has a second dew point temperature that is less than the first dew point temperature of the first solvent. As discussed in more detail herein, the transitioning at 225 may include transitioning in any suitable manner, including an abrupt transition, a step-change transition, a gradual transition, a graded transition, a continuous transition, and/or a stepped transition.
[0066] As an example, the transitioning at 225 may include the abrupt and/or step-change transition. Such a transition may be simple to implement but may increase a potential for generation of the second heavy liquid phase due to the injection of the second solvent-steam vapor mixture, or precipitation of asphaltenes, within the subterranean formation.
[0067] The abrupt and/or step-change transition may include ceasing the injecting the first solvent-steam vapor mixture and concurrently, or subsequently, initiating the injecting the second solvent-steam vapor mixture. The abrupt and/or step-change transition additionally or alternatively may include instantaneously, or at least substantially instantaneously, ceasing the injecting the first solvent-steam vapor mixture and/or instantaneously, or at least substantially instantaneously, initiating the injecting the second solvent-steam vapor mixture.
[0068]
An example of the abrupt and/or step transition is illustrated in Fig. 5.
As illustrated therein, and during first injection time period 90, an injectant, or injected stream, that is provided to the subterranean formation includes, primarily includes, and/or consists essentially of first solvent-steam vapor mixture 91. Then, and during transition time period 92, injection of the first solvent-steam vapor mixture ceases, and injection of the second solvent-steam vapor mixture is initiated. Subsequently, and during second injection time period 94, the injectant that is provided to the subterranean formation includes, primarily includes, and/or consists essentially of second solvent-steam vapor mixture 95. Fig. 5 illustrates transition time period 92 as being instantaneous, or nearly instantaneous. However, this is simply for illustrative purposes, and it is to be understood that the transition time period generally will be a finite time period.
[0069]
As another example, the transitioning at 225 may include the gradual, graded, and/or continuous transition. Such a transition may decrease a potential for formation of the second heavy liquid phase due to the injection of the second solvent-steam vapor mixture and/or for precipitation of asphaltenes within the subterranean formation.
[0070]
The gradual, graded, and/or continuous transition may include continuing the injecting the first solvent-steam vapor mixture subsequent to initiating the injecting the second solvent-steam vapor mixture. This may include decreasing, or systematically decreasing, a first flow rate of the first solvent-steam vapor mixture and increasing, systematically increasing, and/or concurrently increasing, a second flow rate of the second solvent-steam vapor mixture, such as to maintain the target operating pressure within the subterranean formation. Stated another way, the graded, gradual, and/or continuous transition may include injecting, or concurrently injecting, both the first solvent-steam vapor mixture and the second solvent-steam vapor mixture during the transition time period.
[0071] When the transitioning at 225 includes the gradual, graded, and/or continuous transition, it is within the scope of the present disclosure that a rate of change in the flow rates of the first and second solvent-steam vapor mixtures may be regulated and/or controlled in any suitable manner. As an example, a first rate of change of the first flow rate may be selected, or systematically selected, to provide a desired degree of in situ upgrading of the viscous hydrocarbons within the subterranean formation. As another example, a second rate of change of the second flow rate may be selected, or systematically selected, to provide a desired degree of in situ upgrading of the viscous hydrocarbons within the subterranean formation.
[0072] An example of the gradual, graded, and/or continuous transition is illustrated in Fig.
6. As illustrated therein, and during first injection time period 90, the injectant that is provided to the subterranean formation includes, primarily includes, and/or consists essentially of first solvent-steam vapor mixture 91. Then, and during transition time period 92, injection of the first solvent-steam vapor mixture gradually decreases, and injection of the second solvent-steam vapor mixture is initiated and gradually increases. Subsequently, and during second injection time period 94, the injectant that is provided to the subterranean formation includes, primarily includes, and/or consists essentially of second solvent-steam vapor mixture 95. Fig. 6 illustrates a linear change in the injectant composition during the transition time period; however, it is within the scope of the present disclosure that the injectant composition may change in any suitable gradual, graded, and/or continuous manner during the transition time period.
[0073] As yet another example, the transitioning at 225 may include the stepped transition.
This may include changing the first flow rate of the first solvent-steam vapor mixture and the second flow rate of the second solvent-steam vapor mixture, relative to one another, in a plurality of transition steps. This may include decreasing, or systematically decreasing, the first flow rate relative to the second flow rate during the, or during each of the, plurality of transition steps.
The plurality of transition steps may include any suitable number of transition steps, including at least 2, at least 4, at least 6, at least 8, at least 10, at least 15, at least 20, at most 25, at most 15, at most 10, and/or at most 6 transition steps. It is within the scope of the present disclosure that the plurality of transition steps may include a plurality of discrete and/or distinct transition steps, each occurring during a corresponding, or distinct, subset of the transition time period.
[0074] An example of the stepped transition is illustrated in Fig. 7. As illustrated therein, and during first injection time period 90, the injectant that is provided to the subterranean formation includes, primarily includes, and/or consists essentially of first solvent-steam vapor mixture 91. Then, and during transition time period 92, injection of the first solvent-steam vapor mixture gradually decreases in a series of steps, and injection of the second solvent-steam vapor mixture is initiated and gradually increases in a corresponding series of steps. Subsequently, and during second injection time period 94, the injectant that is provided to the subterranean formation includes, primarily includes, and/or consists essentially of second solvent-steam vapor mixture 95.
[0075] It is within the scope of the present disclosure that the transitioning at 225 may be initiated based upon and/or responsive to any suitable transition criteria.
Examples of the transition criteria include one or more of the first injection time period exceeding a threshold first injection time period, production of a predetermined volume of mobilized viscous hydrocarbons from the subterranean formation, contact between a vapor chamber, which is generated within the subterranean formation responsive to the injecting at 225 and/or to the producing at 255, with an overburden, fluid communication between the vapor chamber and a lean zone of the subterranean formation, fluid communication between the vapor chamber and a thief, sink, and/or injectant-retaining zone of the subterranean formation, detection of an unexpected pressure decrease within the subterranean formation, and/or detection of an unexpected loss of the first solvent-steam vapor mixture within the subterranean formation.
[0076] As used herein, the phrase "lean zone" may refer to a zone, or region, of the subterranean formation that does not include viscous hydrocarbons and/or that includes a lower saturation of viscous hydrocarbons when compared to a remainder of the subterranean formation.
As used herein, the phrases "thief zone," "sink zone," and/or "injectant-retaining zone" may refer to a zone, or region, of the subterranean formation that retains the injectant stream, that permits the injectant stream to escape from the vapor chamber, and/or that consumes, receives, and/or retains a relatively larger volume of the injectant stream, when compared to a remainder of the subterranean formation, to generate a given volume of mobilized viscous hydrocarbons.
[00771 Additional examples of the transition criteria include production and/or recovery of at least a threshold fraction of original oil in place from the subterranean formation. Examples of the threshold fraction include at least 10%, at least 20%, at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, and/or at least 80% of the original oil in place.
[0078] It is within the scope of the present disclosure that the transition criteria may include and/or be predeterIllined transition criteria that are established prior to initiation of the injecting at 220. Additionally or alternatively, it also is within the scope of the present disclosure that the transition criteria may include and/or be dynamic transition criteria that are established during the injecting at 220.

=
[0079] Selecting the second solvent at 230 may include selecting the second solvent based, at least in part, on the target operating pressure within the subterranean formation. As an example, the selecting at 230 may include selecting such that the second solvent forms a second vapor at the target operating pressure. As another example, the selecting at 230 may include selecting such that the second solvent forms a second azeotropic, or near-azeotropic, vapor mixture with water at the target operating pressure. The selecting at 230 may include selecting with, via, and/or utilizing phase behavior of the second solvent and/or on phase behavior of mixtures of the second solvent and water and may be at least substantially similar to the selecting at 210.
However, the selecting at 230 further may include selecting such that the second dew point temperature of the second solvent is less than the first dew point temperature of the first solvent, as discussed herein.
[0080] Determining the second azeotropic solvent molar fraction at 235 may include determining the second azeotropic molar fraction at the target operating pressure and in any suitable manner. As an example, and similar to the determining at 215, the phase behavior illustrated in Fig. 4 may be utilized to determine the second azeotropic solvent molar fraction.
[0081] Ceasing injection of the first solvent-steam vapor mixture at 240 may include ceasing the injecting at 220 during the transition time period. Additionally or alternatively, the ceasing at 240 may include ceasing the injecting at 220 prior to initiating the injecting at 245 and/or prior to the second injection time period.
[0082] Injecting the second solvent-steam vapor mixture at 245 may include injecting the second solvent-steam vapor mixture into the subterranean formation during the second injection time period. The injecting at 245 may be similar, or at least substantially similar, to the injecting =
at 220; however, and as discussed, the injecting at 245 may utilize a second solvent having a second dew point temperature that is less than a first dew point temperature of the first solvent.
[0083] The second solvent-steam vapor mixture may, but is not required to be, injected into the subterranean formation at azeotropic, or near-azeotropic, conditions. More specifically, the second solvent-steam vapor mixture may be injected such that a second solvent molar fraction of the second solvent in the second solvent-steam vapor mixture is within a threshold fraction of the second azeotropic solvent molar fraction of the second solvent-steam vapor mixture at the target operating pressure. Examples of the threshold fraction include threshold fractions of at least 70%, at least 80%, at least 90%, at least 95%, at most 100%, at most 95%, at most 90%, and/or at most 85% of the second azeotropic solvent molar fraction.
[0084] The second solvent-steam vapor mixture additionally or alternatively may include any suitable relative volume proportion of the second solvent and steam. As examples, the second solvent-steam vapor mixture may include at least 1 volume percent second solvent, at least 5 volume percent second solvent, at least 10 volume percent second solvent, at least 20 volume percent second solvent, at least 30 volume percent second solvent, at least 40 volume percent second solvent, at least 50 volume percent second solvent, at least 60 volume percent second solvent, at least 70 volume percent second solvent, at least 80 volume percent second solvent, at least 90 volume percent second solvent, at least 98 volume percent second solvent, at most 99 volume percent second solvent, at most 98 volume percent second solvent, at most 95 volume percent second solvent, at most 90 volume percent second solvent, at most 80 volume percent second solvent, at most 70 volume percent second solvent, at most 60 volume percent second solvent, at most 50 volume percent second solvent, at most 40 volume percent second solvent, at most 30 volume percent second solvent, at most 20 volume percent second solvent, at most 10 =
volume percent second solvent, at most 5 volume percent second solvent, and/or at most 2 volume percent second solvent in cold liquid equivalents calculated at standard temperature and pressure. As additional examples, the second solvent-steam vapor mixture may include at least 1 volume percent steam, at least 2 volume percent steam, at least 5 volume percent steam, at least 10 volume percent steam, at least 20 volume percent steam, at least 30 volume percent steam, at least 40 volume percent steam, at least 50 volume percent steam, at least 60 volume percent steam, at least 70 volume percent steam, at least 80 volume percent steam, at least 90 volume percent steam, at least 95 volume percent steam, at least 98 volume percent steam, at most 99 volume percent steam, at most 95 volume percent steam, at most 90 volume percent steam, at most 80 volume percent steam, at most 70 volume percent steam, at most 60 volume percent steam, at most 50 volume percent steam, at most 40 volume percent steam, at most 30 volume percent steam, at most 20 volume percent steam, at most 10 volume percent steam and/or at most 2 volume percent steam in cold liquid equivalents calculated at standard temperature and pressure.
[0085] The injecting at 245 may include injecting the second solvent-steam vapor mixture with, via, and/or utilizing an injection well that extends within the subterranean formation.
Examples of the injection well are discussed herein with reference to injection well 40 of Fig. 1.
[0086] It is within the scope of the present disclosure that the injecting at 245 further may include generating the mobilized viscous hydrocarbons, within the subterranean formation, from the viscous hydrocarbons. As examples, the generating may include heating the viscous hydrocarbons with the second solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons, diluting the viscous hydrocarbons with a condensed second solvent of the second solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons, and/or dissolving =
the viscous hydrocarbons in the condensed second solvent to generate the mobilized viscous hydrocarbons.
[0087] The second solvent-steam vapor mixture may include any suitable second solvent and water, or steam, in any suitable relative concentration that may be, but is not required to be, azeotropic, or near-azeotropic, at the target operating pressure. Examples of the second solvent include lower-boiling hydrocarbons including hydrocarbon molecules with at least 3, at least 4, at least 5, at most 7, at most 6, at most 5, at most 4 carbon atoms, between 3-7 carbon atoms, and/or between 3-6 carbon atoms. The second solvent may include any suitable proportion, fraction, and/or percentage, of the lower-boiling hydrocarbons. As examples, the second solvent may include at least 40 weight percent, at least 50 weight percent, at least 60 weight percent, at least 70 weight percent, at least 80 weight percent, at least 90 weight percent, at most 99 weight percent, at most 95 weight percent, at most 90 weight percent, and/or at most 80 weight percent of the lower-boiling hydrocarbons. Stated another way, hydrocarbon molecules within the second solvent may have and/or define a second average carbon number of at least 3, at least 4, at least 5, at most 7, at most 6, at most 5, at most 4, between 3-7, and/or between 3-6. The second average carbon number may be determined in a manner that is at least substantially similar to the first average carbon number, which is discussed herein.
Additional examples of the second solvent include hydrocarbons, alkanes, alkenes, alkynes, aliphatic compounds, naphthenic compounds, aromatic compounds, olefinic compounds, natural gas condensate, liquefied petroleum gas, and/or a crude oil refinery stream.
[0088] It is within the scope of the present disclosure that the injecting at 245 may include injecting the second solvent-steam vapor mixture with any suitable steam quality. As examples, =
the steam quality may be at least 5%, at least 10%, at least 20%, at least 40%, at least 60%, at least 80%, at most 100%, at most 90%, and/or at most 80%.
[0089] The injecting at 245 may include injecting the second solvent-steam vapor mixture at any suitable injection temperature. As examples, the injection temperature may be at least 20 C, at least 30 C, at least 40 C, at least 50 C, at least 60 C, at least 70 C, at least 80 C, at least 90 C, at least 100 C, at most 300 C, at most 250 C, at most 200 C, and/or at most 150 C. As additional examples, the injecting at 220 may include injecting with at least a threshold degree of superheat relative to a second saturation temperature of the second solvent-steam vapor mixture at the target operating pressure. Examples of the threshold degree of superheat include at least 1 C of superheat, at least 2 C of superheat, at least 5 C of superheat, at least 10 C of superheat, at least 20 C of superheat, at most 60 C of superheat, at most 50 C
of superheat, at most 40 C of superheat, at most 30 C of superheat, and/or at most 20 C of superheat.
[0090] The second solvent may have and/or define any suitable second dew point temperature. As examples, and at a pressure of 101.325 kilopascals, the second dew point temperature may be at least -50 C, at least -30 C, at least -10 C, at least 0 C, at least 10 C, at least 30 C, at least 50 C, at least 70 C, at least 90 C, and/or at least 110 C.
[0091] As discussed, the second dew point temperature of the second solvent is less than the first dew point temperature of the first solvent. It is within the scope of the present disclosure that a difference between the first dew point temperature and the second dew point temperature may have any suitable magnitude. As examples, the difference between the first dew point temperature and the second dew point temperature may be at least 10 C, at least 30 C, at =
least 50 C, at least 70 C, at least 90 C, at least 110 C, at least 130 C, at least 150 C, at least 170 C, at least 190 C, and/or at least 210 C at 101.325 kilopascals.
[0092] In general, the transition time period is subsequent to the first injection time period.
In addition, the second injection time period is subsequent to both the first injection time period and the transition time period.
[0093] The first injection time period, the transition time period, and the second injection time period may have any suitable temporal relation. As an example, and as illustrated in Fig. 5, the first injection time period may be distinct from the second injection time period. As another example, and as also illustrated in Fig. 5, the first injection time period may be distinct from the transition time period. As yet another example, and as illustrated in Figs. 6-7, the first injection time period may be at least partially concurrent with the transition time period and/or may include the transition time period. As another example, and as illustrated in Fig. 5, the second injection time period may be distinct from the transition time period. As yet another example, and as illustrated in Figs. 6-7, the second injection time period may be at least partially concurrent with the transition time period and/or may include the transition time period.
[0094] The first injection time period, the transition time period, and the second injection time period additionally or alternatively may have any suitable duration. As examples, the first injection time period may be less than the transition time period, at least substantially equal to the transition time period, greater than the transition time period, and/or at least a threshold multiple of the transition time period. As additional examples, the second injection time period may be less than the transition time period, at least substantially equal to the transition time period, greater than the transition time period, and/or at least the threshold multiple of the transition time period. Examples of the threshold multiple include threshold multiples of at least 5, at least 10, at least 25, at least 50, and/or at least 100. As additional examples, the first injection time period may be less than, at least substantially equal to, and/or greater than the second injection time period.
[0095] It is within the scope of the present disclosure that the first injection time period, the transition time period, and/or the second injection time period may be selected and/or established in any suitable manner. As examples, one or more of these time periods may be systematically selected to provide a desired level of in situ upgrading of the viscous hydrocarbons, to provide a predetermined amount of first solvent recovery from the subterranean formation, to provide a predetermined amount of heat recovery from the subterranean formation, and/or to decrease a potential for loss of the first solvent within the subterranean formation.
[0096] Recovering the second solvent from the subterranean formation at 250 may include recovering at least a portion, or fraction, of the second solvent from the subterranean formation in any suitable manner and may be performed subsequent to the second injection time period.
As an example, the recovering at 250 may include producing the second solvent from the subterranean formation, such as during the producing at 255. As another example, the recovering at 250 may include injecting a non-condensable gas into the subterranean formation to facilitate production of the second solvent from the subterranean formation.
[0097] Producing mobilized viscous hydrocarbons at 255 may include producing the mobilized viscous hydrocarbons from the subterranean formation as a produced mobilized viscous hydrocarbon stream. This may include producing with, via, and/or utilizing a production well, such as production well 50 of Fig. 1, that may be spaced-apart and/or distinct from the injection well that is utilized during the injecting at 220 and/or during the injecting at 245. The producing at 255 may be perfomied during, concurrent with, and/or at least substantially =
concurrent with the injecting at 220, the transitioning at 225, and/or the injecting at 245. The producing at 255 also may include producing the first solvent from the subterranean formation, producing the second solvent from the subterranean formation, producing water from the subterranean formation, and/or producing steam from the subterranean formation.
[0098] The producing at 255 is schematically illustrated in Fig. 8. As illustrated therein, the mobilized viscous hydrocarbon production rate may be highest during first injection time period 90 and prior to transition time period 92 since, as discussed, the medium-boiling solvent utilized during the first injection time period may provide enhanced viscous hydrocarbon recovery when compared to the lower-boiling solvent utilized during second injection time period 94. However, when considered in the context of the overall economics of viscous hydrocarbon recovery from the subterranean formation, methods 200 may provide a significant improvement over methods that inject the medium-boiling solvent but that do not transition to injection of the lower-boiling solvent.
[0099] Separating the recycled solvent stream at 260 may include separating the first solvent, as a first recycled solvent, and/or separating the second solvent, as a second recycled solvent, from the mobilized viscous hydrocarbons that are produced during the producing at 255. When methods 200 include the separating at 260, the first recycled solvent and/or the second recycled solvent may be re-injected into the subterranean formation, such as during the injecting at 220 and/or during the injecting at 245, respectively.
[0100] In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, it is within the scope of the present disclosure that the order of the =
blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently.
[0101] As used herein, the term "and/or" placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with "and/or" should be construed in the same manner, i.e., "one or more" of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the "and/or" clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to "A and/or B,"
when used in conjunction with open-ended language such as "comprising" may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B
only (optionally including entities other than A); in yet another embodiment, to both A and B
(optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.
[0102] As used herein, the phrase "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, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, 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.
[0103] In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally.
[0104] As used herein the terms "adapted" and "configured" mean that the element, component, or other subject matter is designed and/or intended to perform a given function.
Thus, the use of the terms "adapted" and "configured" should not be construed to mean that a given element, component, or other subject matter is simply "capable of' performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may

37 additionally or alternatively be described as being configured to perform that function, and vice versa.
[0105] As used herein, the phrase, "for example," the phrase, "as an example," and/or simply the term "example," when used with reference to one or more components, features, details, structures, embodiments, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, embodiment, and/or method is an illustrative, non-exclusive example of components, features, details, structures, embodiments, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, embodiment, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, embodiments, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, embodiments, and/or methods, are also within the scope of the present disclosure.
Industrial Applicability [0106] The methods disclosed herein are applicable to the oil and gas industries.
[0107] It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite "a" or "a first" element or the equivalent thereof, such claims should be understood to

38 include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.
[0108] It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.

39

Claims

1. A method of recovering viscous hydrocarbons from a subterranean formation utilizing injection of a near-azeotropic solvent-steam vapor mixture, the method comprising:
injecting, during a first injection time period, a first solvent-steam vapor mixture into the subterranean formation to maintain a target operating pressure within the subterranean formation, wherein:
(i) the first solvent-steam vapor mixture includes a first solvent and steam;
(ii) the first solvent has a first dew point temperature; and (iii) a first solvent molar fraction of the first solvent in the first solvent-steam vapor mixture is 70%-100% of a first azeotropic solvent molar fraction of the first solvent-steam vapor mixture at the target operating pressure;
transitioning, during a transition time period, from the injecting the first solvent-steam vapor mixture to injecting a second solvent-steam vapor mixture, wherein:
the second solvent-steam vapor mixture includes a second solvent and steam;
and (ii) the second solvent has a second dew point temperature that is less than the first dew point temperature;
injecting, during a second injection time period, the second solvent-steam vapor mixture into the subterranean formation; and during at least one of the injecting the first solvent-steam vapor mixture, the transitioning, and the injecting the second solvent-steam vapor mixture, producing mobilized viscous hydrocarbons from the subterranean formation as a produced mobilized viscous hydrocarbon stream.

2. The method of claim 1, wherein at least one of:
(i) the injecting the first solvent-steam vapor mixture includes injecting via an injection well that extends within the subterranean formation; and (ii) the injecting the second solvent-steam vapor mixture includes injecting via the injection well.

3. The method of claim 2, wherein the injection well includes an at least substantially horizontal injection well region, which extends within the subterranean formation, and further wherein the injecting via the injection well includes injecting from the at least substantially horizontal injection well region.

4. The method of any one of claims 1-3, wherein the injecting the first solvent-steam vapor mixture and the injecting the second solvent-steam vapor mixture include generating the mobilized viscous hydrocarbons from the viscous hydrocarbons.

5. The method of claim 4, wherein the generating includes at least one of:
(i) heating the viscous hydrocarbons with at least one of the first solvent-steam vapor mixture and the second solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons;
(ii) diluting the viscous hydrocarbons with at least one of a condensed first solvent of the first solvent-steam vapor mixture and a condensed second solvent of the second solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons; and (iii) dissolving the viscous hydrocarbons in at least one of the condensed first solvent of the first solvent-steam vapor mixture and the condensed second solvent of the second solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons.

6. The method of any one of claims 1-5, wherein the first solvent includes a first plurality of hydrocarbon molecules that includes at least 50 weight percent hydrocarbons with 5-9 carbon atoms.

7. The method of any one of claims 1-6, wherein the injecting the first solvent-steam vapor mixture includes injecting with at least one of:
(i) a steam quality of at least 5%; and (ii) a steam quality of 10%-100%.

8. The method of any one of claims 1-7, wherein, during the injecting the first solvent-steam vapor mixture, the method further includes:
(i) separating a recycled first solvent from the produced mobilized viscous hydrocarbon stream; and (ii) re-injecting the recycled first solvent into the subterranean formation.

9. The method of any one of claims 1-8, wherein the injecting the first solvent-steam vapor mixture includes injecting at an injection temperature of at least one of:
(i) at least 30 °C and at most 250 °C;
(ii) at least 80 °C and at most 150 °C.

10. The method of any one of claims 1-9, wherein the second solvent includes a second plurality of hydrocarbon molecules that includes at least 50 weight percent hydrocarbons with 3-6 carbon atoms.

11. The method of any one of claims 1-10, wherein the method further includes:
separating a recycled second solvent from the produced mobilized viscous hydrocarbon stream; and (ii) re-injecting the recycled second solvent into the subterranean formation.

12. The method of any one of claims 1-11, wherein the second solvent-steam vapor mixture includes at least 20 weight percent hydrocarbons with at least 4 carbon atoms.

13. The method of any one of claims 1-12, wherein the injecting the second solvent-steam vapor mixture includes injecting such that a second solvent molar fraction of the second solvent in the second solvent-steam vapor mixture is 70%-100% of a second azeotropic solvent molar fraction of the second solvent-steam vapor mixture at the target operating pressure.

14. The method of claim 13, wherein the method further includes determining the second azeotropic solvent molar fraction at the target operating pressure.

15. The method of any one of claims 13-14, wherein a second solvent molar fraction of the second solvent-steam vapor mixture is at least one of:

(i) 80%-100% of the second azeotropic solvent molar fraction; and (ii) 90%-100% of the second azeotropic solvent molar fraction.

16. The method of any one of claims 1-15, wherein the second solvent-steam vapor mixture includes 1-99 volume percent second solvent and 1-99 volume percent steam in cold liquid equivalents calculated at standard temperature and pressure.

17. The method of any one of claims 1-16, wherein the injecting the second solvent-steam vapor mixture includes injecting with at least one of:
(i) 1-50 °C superheat relative to a saturation temperature of the second solvent-steam vapor mixture at the target operating pressure; and (ii) 1-20 °C superheat relative to the saturation temperature of the second solvent-steam vapor mixture at the target operating pressure.

18. The method of any one of claims 1-17, wherein at least one of the first solvent and the second solvent includes at least one of:
(i) a hydrocarbon;
(ii) an alkane;
(iii) an alkene;
(iv) an alkyne;
(v) an aliphatic compound;
(vi) a naphthenic compound;
(vii) an aromatic compound;

(viii) an olefinic compound;
(ix) natural gas condensate;
(x) liquefied petroleum gas; and (xi) a crude oil refinery stream.

19. The method of any one of claims 1-18, wherein the first dew point temperature is at least one of:
(i) at least 20 °C at 101.325 kilopascals;
(ii) at least 40 °C at 101.325 kilopascals;
(iii) at least 60 °C at 101.325 kilopascals;
(iv) at least 80 °C at 101.325 kilopascals;
(v) at least 100 °C at 101.325 kilopascals;
(vi) at least 120 °C at 101.325 kilopascals;
(vii) at least 140 °C at 101.325 kilopascals; and (vi) at least 160 °C at 101.325 kilopascals.

20. The method of any one of claims 1-19, wherein the second dew point temperature is at least one of:
(i) at least -50 °C at 101.325 kilopascals;
(ii) at least -30 °C at 101.325 kilopascals;
(iii) at least -10 °C at 101.325 kilopascals;
(iv) at least 0 °C at 101.325 kilopascals;
(v) at least 10 °C at 101.325 kilopascals;

(vi) at least 30 °C at 101.325 kilopascals;
(vii) at least 50 °C at 101.325 kilopascals;
(viii) at least 70 °C at 101.325 kilopascals;
(ix) at least 90 °C at 101.325 kilopascals; and (x) at least 110 °C at 101.325 kilopascals.

21. The method of any one of claims 1-20, wherein a difference between the first dew point temperature and the second dew point temperature is at least one of:
(i) at least 10 °C at 101.325 kilopascals;
(ii) at least 30 °C at 101.325 kilopascals;
(iii) at least 50 °C at 101.325 kilopascals;
(iv) at least 70 °C at 101.325 kilopascals;
(v) at least 90 °C at 101.325 kilopascals;
(vi) at least 110 °C at 101.325 kilopascals;
(vii) at least 130 °C at 101.325 kilopascals;
(viii) at least 150 °C at 101.325 kilopascals;
(ix) at least 170 °C at 101.325 kilopascals;
(x) at least 190 °C at 101.325 kilopascals; and (xi) at least 210 °C at 101.325 kilopascals.

22. The method of any one of claims 1-21, wherein the transitioning includes ceasing the injecting the first solvent-steam vapor mixture and subsequently initiating the injecting the second solvent-steam vapor mixture.

23. The method of any one of claims 1-22, wherein the transitioning includes continuing the injecting the first solvent-steam vapor mixture subsequent to initiating the injecting the second solvent-steam vapor mixture.

24. The method of claim 23, wherein the transitioning includes decreasing a first flow rate of the first solvent-steam vapor mixture while increasing a second flow rate of the second solvent-steam vapor mixture.

25. The method of any one of claims 1-24, wherein the method includes injecting both the first solvent-steam vapor mixture and the second solvent-steam vapor mixture during the transition time period.

26. The method of any one of claims 24-25, wherein the transitioning includes:
systematically decreasing the first flow rate of the first solvent-steam vapor mixture; and concurrently with the systematically decreasing, systematically increasing the second flow rate of the second solvent-steam vapor mixture.

27. The method of claim 26, wherein a first rate of change of the first flow rate is systematically selected to provide a desired degree of in situ upgrading of the viscous hydrocarbons.

28. The method of any one of claims 26-27, wherein a second rate of change of the second flow rate is systematically selected to provide a desired degree of in situ upgrading of the viscous hydrocarbons.

29. The method of any one of claims 24-28, wherein the transitioning includes changing the first flow rate of the first solvent-steam vapor mixture and the second flow rate of the second solvent-steam vapor mixture relative to one another in a plurality of transition steps.

30. The method of claim 29, wherein the plurality of transition steps includes at least one of:
(i) at least 2 transition steps;
(ii) at least 4 transition steps;
(iii) at least 6 transition steps;
(iv) at least 8 transition steps;
(v) at least 10 transition steps;
(vi) at least 15 transition steps; and (vii) at least 20 transition steps.

31. The method of any one of claims 29-30, wherein the plurality of transition steps includes a plurality of discrete transition steps.

32. The method of any one of claims 29-31, wherein the changing includes systematically decreasing the first flow rate of the first solvent-steam vapor mixture relative to the second flow rate of the second solvent-steam vapor mixture during the plurality of transition steps.

33. The method of any one of claims 1-32, wherein the method includes initiating the transitioning responsive to transition criteria.

34. The method of claim 33, wherein the transition criteria includes at least one of:
the first injection time period exceeding a threshold first injection time period;
(ii) production of a predetermined volume of mobilized viscous hydrocarbons;
(iii) contact between a vapor chamber and an overburden, wherein the vapor chamber is generated within the subterranean formation responsive to at least one of the injecting the first solvent-steam vapor mixture and the producing the mobilized viscous hydrocarbons;
(iv) fluid communication between the vapor chamber and a lean zone of the subterranean formation;
(v) fluid communication between the vapor chamber and a thief zone of the subterranean formation;
(vi) detection of an unexpected pressure decrease within the subterranean formation;
and (vii) detection of an unexpected loss of the first solvent-steam vapor mixture within the subterranean formation.

35. The method of any one of claims 33-34, wherein the transition criteria includes at least one of:

production of at least 10% of original oil in place from the subterranean formation;
(ii) production of at least 20% of original oil in place from the subterranean formation;
(iii) production of at least 30% of original oil in place from the subterranean formation;
(iv) production of at least 40% of original oil in place from the subterranean formation;
(v) production of at least 50% of original oil in place from the subterranean formation;
(vi) production of at least 60% of original oil in place from the subterranean formation;
(vii) production of at least 70% of original oil in place from the subterranean formation; and (viii) production of at least 80% of original oil in place from the subterranean formation.

36. The method of any one of claims 1-35, wherein the second injection time period is subsequent to the first injection time period.

37. The method of any one of claims 1-36, wherein at least one of the first injection time period, the transition time period, and the second injection time period is at least one of:

(i) systematically selected to provide a desired level of in situ upgrading of the mobilized viscous hydrocarbons;
(ii) systematically selected to provide a predetermined amount of recovery of the first solvent from the subterranean formation;
(iii) systematically selected to provide a predetermined amount of recovered heat from the subterranean formation; and (iv) systematically selected to decrease a potential for loss of the first solvent within the subterranean formation.

38. The method of any one of claims 1-37, wherein the method includes at least one of:
(i) ceasing the injecting the first solvent-steam vapor mixture during the transition time period; and (ii) ceasing the injecting the first solvent-steam vapor mixture prior to the second injection time period.

39. The method of any one of claims 1-37, wherein the method further includes selecting the target operating pressure.

40. The method of claim 39, wherein the target operating pressure is based, at least in part, upon a vertical depth, within the subterranean formation, for the injecting the first solvent-steam vapor mixture and also for the injecting the second solvent-steam vapor mixture.

41. The method of any one of claims 39-40, wherein the target operating pressure is based, at least in part, on at least one of:
(i) a fracture pressure for the subterranean formation;
(ii) a hydrostatic pressure within the subterranean formation;
(iii) a lithostatic pressure within the subterranean formation;
(iv) a gas cap pressure for a gas cap within the subterranean formation;
and (v) an aquifer pressure for an aquifer that at least one of extends below the subterranean formation and extends above the subterranean formation.

42. The method of any one of claims 39-41, wherein the method further includes selecting the first solvent based, at least in part, on the target operating pressure.

43. The method of claim 42, wherein the selecting the first solvent includes selecting such that the first solvent forms a first vapor at the target operating pressure.

44. The method of any one of claims 42-43, wherein the selecting the first solvent includes selecting such that the first solvent forms a first azeotropic vapor mixture with water at the target operating pressure.

45. The method of claim 44, wherein the method further includes determining the first azeotropic solvent molar fraction at the target operating pressure.

46. The method of any one of claims 39-45, wherein the method further includes selecting the second solvent based, at least in part, on the target operating pressure.

47. The method of claim 46, wherein the selecting the second solvent includes selecting such that the second solvent forms a second azeotropic vapor mixture with water at the target operating pressure.

48. The method of any one of claims 1-47, wherein the target operating pressure is at least substantially constant during the injecting the first solvent-steam vapor mixture, during the transitioning, and during the injecting the second solvent-steam vapor mixture.

49. The method of any one of claims 1-48, wherein the method further includes systematically varying the target operating pressure at least one of:
(i) during the injecting the first solvent-steam vapor mixture;
(ii) during the transitioning; and (iii) during the injecting the second solvent-steam vapor mixture.

50. The method of any one of claims 1-49, wherein the target operating pressure is at least 5% and at most 95% of the fracture pressure of the subterranean formation.

51. The method of any one of claims 1-50, wherein the target operating pressure is at least one of:
(i) at least 0.3 megapascals and at most 4 megapascals; and (ii) at least 1 megapascal and at most 2.5 megapascals.

52. The method of any one of claims 1-51, wherein, subsequent to the second injection time period, the method further includes recovering at least a portion of the second solvent from the subterranean formation.

53. The method of claim 52, wherein the recovering includes producing the second solvent from the subterranean formation.

54. The method of any one of claims 52-53, wherein the recovering includes injecting a non-condensable gas into the subterranean formation to facilitate production of the second solvent from the subterranean formation.

55. The method of any one of claims 1-54, wherein the producing includes producing at least one of:
(i) during at least two of the injecting the first solvent-steam vapor mixture, the transitioning, and the injecting the second solvent-steam vapor mixture; and (ii) during each of the injecting the first solvent-steam vapor mixture, the transitioning, and the injecting the second solvent-steam vapor mixture.

56. The method of any one of claims 1-55, wherein the producing includes producing via a production well that extends within the subterranean formation.

57. The method of claim 56, wherein the production well includes an at least substantially horizontal production well region, and further wherein the producing includes producing via the at least substantially horizontal production well region.

58. The method of claim 57, wherein the at least substantially horizontal production well region extends, within the subterranean formation, vertically below the at least substantially horizontal injection well region.

59. The method of any one of claims 1-58, wherein the producing further includes at least one of:
producing the first solvent from the subterranean formation;
(ii) producing the second solvent from the subterranean formation; and (iii) producing water from the subterranean formation.

60. The method of any one of claims 1-59, wherein the first solvent-steam vapor mixture is at least one of:
80%-100% of the first azeotropic solvent molar fraction of the first solvent-steam vapor mixture at the target operating pressure; and (ii) 90%-100% of the first azeotropic solvent molar fraction of the first solvent-steam vapor mixture at the target operating pressure.

61. The method of any one of claims 1-60, wherein the first solvent-steam vapor mixture includes 15-98 volume percent first solvent and 2-85 volume percent steam in cold liquid equivalents calculated at standard temperature and pressure.

62. The method of any one of claims 1-61, wherein the injecting the first solvent-steam vapor mixture includes injecting with at least one of:
(i) 1-50 °C superheat relative to a saturation temperature of the solvent-steam vapor mixture at the target operating pressure; and (ii) 1-20 °C superheat relative to the saturation temperature of the solvent-steam vapor mixture at the target operating pressure.