CA2972068A1

CA2972068A1 - Recovery of heavy oil from a subterranean reservoir

Info

Publication number: CA2972068A1
Application number: CA2972068A
Authority: CA
Inventors: Rahman Khaledi; Hamed R. Motahhari
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2017-06-28
Filing date: 2017-06-28
Publication date: 2017-08-31
Anticipated expiration: 2037-06-28
Also published as: CA2972068C

Abstract

The present disclosure to provide systems and methods. for regulation of asphaltene production in a solvent-based recovery process and selecting a hydrocarbon solvent mixture composition of a hydrocarbon solvent mixture, including systems and methods for improving bitumen recovery in a solvent-based recovery process by utilizing a near- azeotropic steam/hydrocarbon solvent injection process which includes determining a target asphaltene content for a reservoir heavy oil product stream produced from a subterranean reservoir and tailoring the steam and hydrocarbon solvent composition and content for maximization of desired asphaltene control and injecting the tailored the steam and hydrocarbon solvent composition into the subterranean reservoir at near azeotropic conditions.

Description

RECOVERY OF HEAVY OIL FROM A SUBTERRANEAN RESERVOIR
BACKGROUND
Field of Disclosure [0001] The present disclosure relates to production of a bitumen product from a subterranean reservoir with improved control of asphaltene content and improved bitumen recovery in a solvent-based recovery process.
Description of Related Art [00021 This section is intended to introduce various aspects of the art.
This discussion is believed to facilitate a better understanding of particular aspects of the present techniques.
Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
[0003] Modern society is greatly dependent on the use of hydrocarbon resources for fuels and chemical feedstocks. Subterranean rock formations that can be termed -reservoirs" may contain resources such as hydrocarbons that can be recovered. Removing hydrocarbons from the subterranean reservoirs depends on numerous physical properties of the subterranean rock formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the subterranean rock formations, and the proportion of hydrocarbons present, among other things.
[0004] Easily produced sources of hydrocarbons are dwindling, leaving less conventional sources to satisfy future needs. As the costs of hydrocarbons increase, less conventional sources become more economical. One example of less conventional sources becoming more economical is that of oil sand production. The hydrocarbons produced from less conventional sources may have relatively high viscosities, for example, ranging from 1000 centipoise (cP) to 20 million cP with American Petroleum Institute (API) densities ranging from 8 degree ( ) API, or lower, up to 200 API, or higher. The hydrocarbons recovered from less conventional sources may include heavy oil. However, the hydrocarbons produced from the less conventional sources may be difficult to recover using conventional techniques. For example, the heavy oil may be sufficiently viscous that economical production of the heavy oil from a subterranean formation (also referred to as a "subterranean reservoir" herein) is precluded.
[0005]
Several conventional recovery processes, such as but not limited to thermal recovery processes, have been utilized to decrease the viscosity of the heavy oil. Decreasing the viscosity of the heavy oil may decrease a resistance of the heavy oil to flow and/or permit production of the heavy oil from the subterranean reservoir by piping, flowing, and/or pumping the heavy oil from the subterranean reservoir. While each of these recovery processes may be effective under certain conditions, each possess inherent limitations.
[0006]
One of the conventional recovery processes utilizes steam injection. The steam injection may be utilized to heat the heavy oil to decrease the viscosity of the heavy oil.
Water and/or steam may represent an effective heat transfer medium, but the pressure required to produce saturated steam at a desired temperature may limit the applicability of steam injection to high pressure operation and/or require a large amount of energy to heat the steam.
[0007]
Another of the conventional recovery processes utilizes cold and/or heated solvents. Cold and/or heated solvents may be injected into a subterranean reservoir as liquids and/or vapors to decrease the viscosity of heavy oil present within the subterranean reservoir.
Traditionally, pure (i.e., single-component), or at least substantially pure, propane is injected into the subterranean reservoir as the cold and/or heated solvent. The injected propane may dissolve the heavy oil, dilute the heavy oil, and/or transfer thermal energy to the heavy oil.
Utilizing the cold and/or heated solvents may suffer from limited injection temperature and/or pressure operating ranges, and/or an inability to effectively decrease the viscosity of the heavy oil.
[0008] In general, the conventional recovery processes may not decrease the viscosity of the heavy oil present within the subterranean reservoir. For example, certain heavy oil may not be soluble within the solvents utilized in a conventional recovery process; a substantial fraction of the heavy oil present in a subterranean reservoif may comprise asphaltenes.
Asphaltenes may not be soluble in the solvent used and thus the asphaltenes may not be produced from the subterranean reservoir. Under certain conditions, it may be desirable to produce at least a fraction of the asphaltenes from the subterranean reservoir; it may be

- 2 -desirable to regulate an asphaltene content of the heavy oil produced from the subterranean reservoir.
[0009] A need exists for improved technology, including technology that may address one or more of the above described disadvantages. For example, a need exists for regulating asphaltene production in a solvent-based recovery processes; a need exists for selecting a composition of a hydrocarbon solvent mixture.
=
SUMMARY
[0010] It is an object of the present disclosure to provide systems and methods for regulation of asphaltene production in a solvent-based recovery process and selecting a hydrocarbon solvent mixture composition of a hydrocarbon solvent mixture. It is an object of the present disclosure to provide systems and methods for improving bitumen recovery in a solvent-based recovery process by utilizing a near-azeotropie steam/hydrocarbon solvent injection process.
[0011] In an embodiment of the present invention is a process for recovery of heavy oil from a subterranean reservoir, the process comprising:
a) determining a target subterranean reservoir operating pressure;
b) determining a target subterranean reservoir operating temperature;
c) determining a target asphaltene content for a produced reservoir heavy oil product stream from the subterranean reservoir;
d) adjusting the composition of a hydrocarbon solvent mixture to achieve the asphaltene content in step c) under the conditions of steps a) and b);
e) determining the azeotropic/minimum dew point steam content of the hydrocarbon solvent mixture in the vapor phase under the conditions of steps a) and b);
f) at an actual subterranean reservoir operating pressure and an actual subterranean reservoir operating temperature, co-injecting a reservoir injection mixture in the vapor phase into the subterranean reservoir comprising steam and the hydrocarbon solvent mixture, wherein the hydrocarbon solvent molar fraction of the combined steam and

- 3 -hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture as determined in step e);
g) recovering a reservoir heavy oil stream from the subterranean reservoir;
and h) producing a bitumen product stream from the reservoir heavy oil product stream.
[0012] The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood. Additional features will also be described herein.
DESCRIPTION OF THE DRAWINGS
[0013] These and other features, aspects and advantages of the present disclosure will become apparent from the following description and the accompanying drawings, which are briefly discussed below.
[0014] Figure 1 is a schematic representation of examples of a hydrocarbon production system.
=
[0015] Figure 2 is a plot of the phase behavior for a steam-hexane system.
[0016] Figure 3 is a series of contour plots comparing reservoir properties for heated pentane (C5 H-VAPEX) and heated pentane with steam at the azeotropic concentration (C5 Azeotropic H-VAPEX), at the same operating pressure.
[0017] Figure 4 is a graph of cumulative solvent to oil ratio (CS010R) versus time for H-VAPEX and Azeotropic H-VAPEX utilizing C5 and C7 injection.
[0018] Figure 5 is a graph of cumulative produced oil over retained solvent versus time for Heated Vapex and Azeotropic H-VAPEX utilizing C5 and C7 injection.
[0019] Figure 6 is a graph of oil recovery versus time for H-VAPEX and Azeotropic Heated Vapex utilizing C5 and C7 injection.
[0020] Figure 7 is a graph of semi-azeotropic behavior of a steam-multicomponent solvent (diluent) system.
[0021] Figure 8 is a graph of cumulative solvent to oil ratio (CS010R) versus time in high

- 4 -=
and low initial water saturation reservoir conditions.
[0022] Figure 9 is a graph of produced oil to retained solvent versus time in high and low initial water saturation reservoir conditions.
[0023] Figure 10 is a graph of collective dew point temperature plots for vapor mixtures of individual hydrocarbon solvents of C4-C9 with water as a function of solvent mole fraction.
[0024] Figure 11 is a bar graph illustrating heavy end component deposition within a subterranean reservoir for various single-component hydrocarbon solvents.
[0025] Figure 12 is a table illustrating an average saturation temperature for three different hydrocarbon solvent mixtures.
[0026] Figure 13 is a bar graph illustrating heavy end component deposition within the subterranean reservoir for the three different hydrocarbon solvent mixtures of Figure 12.
DETAILED DESCRIPTION
[0027] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein, are contemplated as would normally occur to one skilled in the art to which the disclosure relates.
It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.
[0028] At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication of issued patent.
Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.
[0029] A -hydrocarbon" is an organic compound that primarily includes the elements

- 5 -hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. However, the techniques described herein are not limited to heavy oils, but may also be used with any number of other subterranean reservoirs.
Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.
[00301 "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-p) like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.)% aliphatics (which can range from 5 Wt.% - 30 wt.%, or higher);
19 wt.% asphaltenes (which can range from 5 wt.% -30 wt.%, or higher);
30 wt.% aromatics (which can range from 15 wt.% - 50 wt.%, or higher);
32 wt.% resins (which can range from 15 wt.% - 50 wt.%, or higher); and some amount of sulfur (which can range in excess of .7 wt.%).
[0025] The percentage of the hydrocarbon types found in bitumen can vary. In addition bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt.% to in excess of 0.7 wt.%. The metals content, while small, may be removed to avoid contamination of synthetic crude oil. Nickel can vary from less than 75 ppm (parts per million) to more than 200 ppm. Vanadium can range from less than 200 ppm to more than 500 ppm.
[0026] The term "heavy oil" includes bitumen, as well as lighter materials that may be found in a sand or carbonate reservoir. "Heavy oil" includes oils that are classified by the American Petroleum Institute (API), as heavy oils, extra heavy oils, or bitumens. Thus the term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about 1000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more or 1,000,000 cP or more.
In general, a heavy oil has an API gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3

- 6 -or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than 10.0 API
(density greater than 1,000 kg/m3 or greater than 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water, and bitumen. The recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluids by steam, hot water flooding, or gravity is possible.
The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.
A heavy oil may include heavy end components and light end components.
100271 The term "asphaltenes" or "asphaltene content" refers to pentane insolubles (or the amount of pentane insoluble in a sample) according to ASTM D3279. Other examples of standard ASTM asphaltene tests include ASTM test numbers D4055, D6560, and D7061.
[0028] "Heavy end components" in heavy oil may comprise a heavy viscous liquid or solid made up of heavy hydrocarbon molecules. Examples of heavy hydrocarbon molecules include, but are not limited to, molecules having greater than or equal to 30 carbon atoms (C30+). The amount of molecules in the heavy hydrocarbon molecules may include any number within or bounded by the preceding range. The heavy viscous liquid or solid may be composed of molecules that, when separated from the heavy oil, have a higher density and viscosity than a density and viscosity of the heavy oil containing both heavy end components and light end components. For example, in Athabasca bitumen, about 70 weight (wt.) % of the bitumen contains C30+ molecules with about 18 wt. % of the Athabasca bitumen being classified as asphaltenes. The heavy end components may include asphaltenes in the form of solids or viscous liquids.
[0029] "Light end components" in heavy oil may comprise those components in the heavy oil that have a lighter molecular weight than heavy end components. The light end components may include what can be considered to be medium end components.
Examples of light end components and medium end components include, but are not limited to, light and medium hydrocarbon molecules having greater than or equal to 1 carbon atom and less than 30 carbon atoms. The amount of molecules in the light and medium end components may include any number within or bounded by the preceding range. The light end components and medium end components may be composed of molecules that have a lower density and viscosity than a density and viscosity of heavy end components from the heavy

- 7 -oil.
[0030] A
"fluid" includes a gas or a liquid and may include, for example, a produced or native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold water, or a mixture of these among other materials. -Vapor" refers to steam, wet steam, and mixtures of steam and wet steam, any of which could possibly be used with a solvent and other substances, and any material in the vapor phase.
[0031]
"Facility" or "surface facility" is a tangible piece of physical equipment through which hydrocarbon fluids are either produced from a subterranean reservoir or injected into a subterranean reservoir, or equipment that can be used to control production or completion operations. In its broadest sense, the term facility is applied to any equipment that may be present along the flow path between a subterranean reservoir and its delivery outlets.
Facilities may comprise production wells, injection wells, well tubulars, wellbore head equipment, gathering lines, manifolds, pumps, compressors, separators, surface flow lines, steam generation plants, processing plants, and delivery outlets. In some instances, the term "surface facility" is used to distinguish from those facilities other than wells.
[0032]
"Pressure" is the force exerted per unit area by the gas on the walls of the volume.
Pressure may be shown in this disclosure as pounds per square inch (psi), kilopascals (kPa) or megapascals (MPa). -Atmospheric pressure" refers to the local pressure of the air.
"Absolute pressure" (psia) refers to the sum of the atmospheric pressure (14.7 psia at standard conditions) plus the gauge pressure. "Gauge pressure" (psig) refers to the pressure measured by a gauge, which indicates only the pressure exceeding the local atmospheric pressure (i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia).
The term "vapor pressure" has the usual thermodynamic meaning. For a pure component in an enclosed system at a given pressure, the component vapor pressure is essentially equal to the total pressure in the system. Unless otherwise specified, the pressures in the present disclosure are absolute pressures.
[0033] A
"subterranean reservoir" is a subsurface rock or sand reservoir from which a production fluid, or resource, can be harvested. A
subterranean reservoir may interchangeably be referred to as a subterranean formation. The subterranean formation may include sand, granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy oil

- 8 -(e.g., bitumen), oil, gas, or coal, among others. Subterranean reservoirs can vary in thickness from less than one foot (0.3048 meters (m)) to hundreds of feet (hundreds of meters). The resource is generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.
[0034] "Thermal recovery processes- include any type of hydrocarbon recovery process that uses a heat source to enhance the recovery, for example, by lowering the viscosity of a hydrocarbon. The processes may use injected mobilizing fluids, such as but not limited to hot water, wet steam, dry steam, or solvents alone, or in any combination, to lower the viscosity of the hydrocarbon. Any of the thermal recovery processes may be used in concert with solvents. For example, thermal recovery processes may include cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD), steam flooding,, in-situ combustion and other such processes.
[0035] "Solvent-based recovery processes" include any type of hydrocarbon recovery process that uses a solvent, at least in part, to enhance the recovery, for example, by diluting or lowering a viscosity of the hydrocarbon. Solvent-based recovery processes may be used in combination with other recovery processes, such as, for example, thermal recovery processes.
In solvent-based recovery processes, a solvent is injected into a subterranean reservoir. The solvent may be heated or unheated prior to injection, may be a vapor or liquid and may be injected with or without steam. Solvent-based recovery processes may include, but are not limited to, solvent assisted cyclic steam stimulation (SA-CS S), solvent assisted steam assisted gravity drainage (SA-SAGD), solvent assisted steam flood (SA-SF), vapor extraction process (VAPEX), heated vapor extraction process (H-VAPEX), cyclic solvent process (CSP), heated cyclic solvent process (H-CSP), solvent flooding, heated solvent flooding, liquid extraction process, heated liquid extraction process, solvent-based extraction recovery process (SEP), thermal solvent-based extraction recovery processes (TSEP), and any other such recovery process employing solvents either alone or in combination with steam. A
solvent-based recovery process may be a thermal recovery process if the solvent is heated prior to injection into the subterranean reservoir. The solvent-based recovery process may employ gravity drainage.
[0036] Steam to Oil Ratio ("SOR") is the ratio of a volume of steam (in cold water equivalents) required to produce a volume of oil. Cumulative SOR ("CSOR") is the average volume of steam (in cold water equivalents) over the life of the operation required to produce

- 9 -a volume of oil. Instantaneous ("ISOR") is the instantaneous rate of steam (in cold water equivalents) required to produce a volume of oil. SOR, CSOR, and ISOR are calculated at standard temperature and pressure ("STP", 15 C and 100kPa or 60 F and 14.696 psi).
[0037] Likewise, Solvent to Oil Ratio ("5010R") is the ratio of a volume of solvent (in cold liquid equivalents) required to produce a volume of oil. Cumulative 5010R
(-CSõIOR") is the average volume of solvent (in cold liquid equivalents) over the life of the operation required to produce a volume of oil. Instantaneous ("IS,,IOR") is the instantaneous rate of solvent required to produce a volume of oil. SolOR, CS010R, and ISolOR are calculated at STP.
[0038] "AzeotropC means the thermodynamic azeotrope as described further herein.
[0039] A "wellbore" is a hole in the subsurface made by drilling or inserting a conduit into the subsurface. A wellbore may have a substantially circular cross section or any other cross-sectional shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. The term "well," when referring to an opening in the formation or reservoir, may be used interchangeably with the term "wellbore." Further, multiple pipes may be inserted into a single wellbore, for example, as a liner configured to allow flow from an outer chamber to an inner chamber.
[0040] "Permeability" is the capacity of a structure to 'transmit fluids through the interconnected pore spaces of the structure. The customary unit of measurement for permeability is the milliDarcy (mD).
[0041] "Reservoir matrix" refers to the solid porous material forming the structure of the subterranean reservoir. The subterranean reservoir is composed of the solid reservoir matrix, typically rock or sand, around pore spaces in which resources such as heavy oil may be located. The porosity and permeability of a subterranean reservoir is defined by the percentage of volume of void space in the rock or sand reservoir matrix that potentially contains resources and water.
[0042] The term "existing" as it may refer to the temperature, the pressure, an asphaltene content, density, viscosity, composition, or mixture component content (collectively the "variables") as used herein, including the claims, refers to the value of the particular variable as it exists during the operating window of analysis and/or measuring of the variables in order

- 10 -to determine changes to be made in the process.
[0043] The term "target" as it may refer to the temperature, the pressure, an asphaltene content, density, viscosity, composition, or mixture component content (collectively the "variables") as used herein, including the claims, refers to the projected value of particular variable as would be modified or maintained in order to determine changes to be made in the process.
[0044] The term "actual" as it may refer to the temperature, the pressure, an asphaltene content, density, viscosity, composition, or mixture component content (collectively the "variables") as used herein, including the claims, refers to the actual value of particular variable as modified or maintained at the time of revisions in the variable(s) in the process.
The actual value of a variable may be the same or different from either the existing value or the target value of that particular variable.
[0045] A "solvent extraction chamber" is a region of a subterranean reservoir containing heavy oil that forms around a well that is injecting solvent into the subterranean reservoir.
The solvent extraction chamber has a temperature and a pressure that is generally at or close to a temperature and pressure of the solvent injected into the subterranean reservoir. The solvent extraction chamber may form when heavy oil has, due to heat from the solvent, dissolution within the solvent, combination with the solvent, and/or the action of gravity, at least partially mobilized through the pore spaces of the reservoir matrix. The mobilized heavy oil may be at least partially replaced in the pore spaces by solvent, thus forming the solvent chamber. In practice, layers in the subterranean reservoir containing heavy oil may not necessarily have pore spaces that contain 100 percent (%) heavy oil and may contain only 70 - 80 volume (vol.) % heavy oil with the remainder possibly being water. A
water and/or gas containing layer in the subterranean reservoir may comprise 100% water and/or gas in the pore spaces, but generally contains 5 - 70 vol.% gas and 20 - 30 vol.% water with any remainder possibly being heavy oil.
[0046] A "vapor chamber" is a solvent extraction chamber that includes a vapor, or vaporous solvent. Thus, when the solvent is injected into the subterranean reservoir as a vapor, a vapor chamber may be formed around the well.
[0047] A "compound that has five or more carbon atoms" or -05+"may include any

- 11 -suitable single chemical species that may include five or more carbon atoms. A
-compound that has five or more carbon atoms" also may include any suitable mixture of chemical species. Each of the chemical species in the mixture of chemical species may include five or more carbon atoms and each of the chemical species in the mixture of chemical species also may include the same number of carbon atoms as the other chemical species in the mixture of chemical species. For example, a compound that has five carbon atoms may include a pentane, n-pentane, a branched pentane, cyclopentane, a pentene, n-pentene, a branched pentene, cyclopentene, a pentyne, n-pentyne, a branched pentyne, cyclopentyne, methylbutane, dimethylpropane, ethylpropane, and/or any other hydrocarbon with five carbon it) atoms. A compound with six carbon atoms, seven carbon atoms, or eight carbon atoms may include a single chemical species with six carbon atoms, seven carbon atoms, or eight carbon atoms, respectively, and/or may include a mixture of chemical species that each include six carbon atoms, seven carbon atoms, or eight carbon atoms, respectively.
[0048] The terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.
These terms when used in reference to a quantity or amount of a material, or a specific characteristic of the material, refer to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.
[0049] The articles "the", "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.
[0050] 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

- 12 -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 or, equivalently "at least one of A and/or B") may refer, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases "at least one," "one or more," and "and/or" are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C," "at least one of A, B, or C," "one or more of A, B, and C," "one or more of A, B, or C" and "A, B, and/or C- may mean A alone, B alone, C
alone, A and B
together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.
[0051] 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 to A only (optionally including entities other than B); to B only (optionally including entities other than A); to both A and B (optionally including other entities).
These entities may refer to elements, actions, structures, steps, operations, values, and the like.
[0052] 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

- 13 -=
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 additionally or alternatively be described as being configured to perform that function, and vice versa.
[0053] 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.
[0054] Any of the ranges disclosed may include any number within and/or bounded by the range given.
[0055] In the illustrative figures herein, in general, elements that are likely to be included 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. Thus, an element shown in solid lines may be omitted without departing from the scope of the present disclosure.
[0056] Figures 1-13 provide illustrative, non-exclusive examples of systems according to the present disclosure, components of systems, data that may be utilized to select a composition of a hydrocarbon solvent mixture and or a reservoir injection mixture that may be utilized with systems, and/or methods, according to the present disclosure, of operating and/or utilizing systems. Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of Figures 1-13, and these elements may not be discussed in detail herein with reference to each of Figures 1-13. Similarly, all elements may not be labeled in each of Figures 1-13, but associated reference .numerals may be utilized for

- 14 -consistency. Elements, components, and/or features that are discussed herein with reference to one or more of Figures 1-13 may be included in and/or utilized with any of Figures 1-13 without departing from the scope of the present disclosure.
[0057] Figure 1 is a schematic representation of a hydrocarbon production system 10 that may be utilized with, may be included in, and/or may include the systems and methods according to the present disclosure. Hydrocarbon production system 10 may include an injection well 30 and a production well 70 that extend within a subterranean reservoir 24 that is present within a subsurface region 22 and/or that extend between a surface region 20 and the subterranean reservoir 24. Hydrocarbon production system 10 may include a surface facility 40. Surface facility 40 may be configured to receive a reservoir heavy oil product stream 72 from production well 70. A reservoir heavy oil product stream 72 may be produced from the subterranean reservoir 24. Surface facility 40 may be configured to provide a reservoir injection mixture 32 to injection well 30.
[0058] The reservoir injection mixture 32 may be in liquid form, vapor form, or both.
The reservoir injection mixture preferably is comprised of a steam and hydrocarbon solvent mixture. When the hydrocarbon solvent mixture is a vaporous hydrocarbon solvent mixture 32, the solvent-based recovery process may be referred to as, or may be, a vapor extraction process (VAPEX). Hydrocarbon solvent mixture 32 also may be, or may be referred to as, a liquid-vapor hydrocarbon solvent mixture 32 that includes a liquid and a vapor. In a preferred embodiment, the steam and hydrocarbon solvent mixture is within 30%+/-, 20%+/-, or 10%+/- of the azeotropic solvent molar fraction of the steam and the solvent as measured at the reservoir operating pressure. Alternatively, the steam and hydrocarbon solvent mixture is 70-110%, 70-100%, 80-100%, or 90 to 100% of the azeotropic solvent molar fraction of the steam and the solvent as measured at the reservoir operating pressure. In another preferred embodiment, the reservoir injection mixture is comprised of at least 80% by weight of the steam and hydrocarbon solvent mixture. In other preferred embodiments, the reservoir injection mixture is comprised of at least 90% or 95% by weight of the steam and hydrocarbon solvent mixture, more preferably, is comprised essentially of the steam and hydrocarbon solvent mixture.
[0059] In preferred embodiments, at least 90%, at least 95%, or essentially all (by weight) of the reservoir injection mixture is injected into the subterranean reservoir in vapor form.

- 15 -[0060] When the solvent-based recovery process is performed using heated solvent, the solvent-based recovery process may be referred to as a high temperature solvent (and/or vapor) solvent-based recovery process. The heated solvent may be injected into the subterranean reservoir at an injection temperature and an injection pressure.
The injection temperature may be at, or near, a saturation temperature for the heated solvent at the injection pressure. When more than one solvent is utilized, the extraction process may be referred to as a multi-solvent-based recovery process and/or a multi-component solvent-based recovery process, which, at elevated temperatures, may be referred to as a high temperature multi-component solvent-based recovery process, which may be a high temperature multi-component vapor extraction process.
[0061] Once provided to subterranean reservoir 24, reservoir injection mixture 32 may combine with bituminous hydrocarbon deposit 25 within a solvent extraction chamber 60, may dissolve in bituminous hydrocarbon deposit 25, and/or may dissolve bituminous hydrocarbon deposit 25, thereby decreasing the viscosity of the bituminous hydrocarbon deposit. When reservoir injection mixture 32 is a vaporous hydrocarbon solvent mixture, solvent extraction chamber 60 may be referred to as a vapor chamber 60. The vaporous hydrocarbon solvent mixture may condense within vapor chamber 60. When reservoir injection mixture 32 condenses, the hydrocarbon solvent mixture may release latent heat (or latent heat of condensation), transfer thermal energy to the subterranean reservoir, and/or generate a condensate 34. Condensation of the reservoir injection mixture 32 may heat a bituminous hydrocarbon deposit 25 that may be present within the subterranean reservoir, thereby decreasing a viscosity of the bituminous hydrocarbon deposit.
[0062] The bituminous hydrocarbon deposit 25 may include bitumen, gaseous hydrocarbons, asphaltenes, and/or water. The reservoir injection mixture 32 and/or condensate 34 also may combine with, mix with, be dissolved in, dissolve, and/or dilute bituminous hydrocarbon deposit 25, further decreasing the viscosity of the bituminous hydrocarbon deposit.
[0063] The energy transfer between the reservoir injection mixture 32 and bituminous hydrocarbon deposit 25 and/or the mixing of reservoir injection mixture 32 and/or condensate 34 with bituminous hydrocarbon deposit 25 may generate reduced-viscosity hydrocarbons 74, which may flow to production well 70. After flowing to production well 70, a reservoir

- 16 -heavy oil product stream 72 is produced from the subterranean reservoir. The reduced-viscosity hydrocarbons 74 may have a lower viscosity than the hydrocarbons within the subsurface reservoir 24 had before the reservoir injection mixture 32 was injected into the subterranean reservoir 24. The reservoir heavy oil product stream 72 may comprise reduced-viscosity hydrocarbons 74, asphaltenes, gaseous hydrocarbons, water, reservoir injection mixture 32, and/or condensate 34 in any suitable ratio and/or relative proportion.
[0064] The systems and methods according to the present disclosure may be utilized to control and/or regulate a product hydrocarbon stream composition of the reservoir heavy oil product stream 72. The systems and methods according to the present disclosure may be utilized to control and/or regulate a portion of the bituminous hydrocarbon deposit 25 that is produced from the subterranean reservoir 24. A hydrocarbon solvent mixture composition of the hydrocarbon solvent mixture may be controlled, regulated, and/or varied such that a first portion of the bituminous hydrocarbon deposit becomes reduced-viscosity hydrocarbons 74 and/or is produced with the reservoir heavy oil product stream 72. The hydrocarbon solvent mixture composition may be controlled, regulated, and/or varied such that a second portion of the bituminous hydrocarbon deposit remains within the subterranean reservoir, does not become reduced-viscosity hydrocarbons 74, and/or is not produced with the reservoir heavy oil product stream 72. The first portion of the bituminous hydrocarbon deposit may have a lower asphaltene content than the bituminous hydrocarbon deposit and may be referred to as an upgraded portion of the bituminous hydrocarbon deposit. The second portion of the bituminous hydrocarbon deposit may have a higher asphaltene content than the bituminous hydrocarbon deposit and also may be referred to as a retained portion of the bituminous hydrocarbon deposit. The first portion of the bituminous hydrocarbon deposit may be different from the second portion of the bituminous hydrocarbon deposit.
[0065] The systems and methods according to the present disclosure may be discussed in the context of determining, adjusting, and/or regulating the asphaltene content of the product hydrocarbon stream. It is to be understood that adjusting and/or regulating the asphaltene content of the product hydrocarbon stream may include regulating the proportion of the asphaltenes from the bituminous hydrocarbon deposit that are retained within the subterranean reservoir and/or that are not produced with the product hydrocarbon stream.
[0066] Surface facility 40 may process the reservoir heavy oil product stream 72 and/or

- 17 -=

may separate the reservoir heavy oil product stream 72 into one or more component streams prior to the product hydrocarbon stream being conveyed from the surface facility 40. Surface facility 40 may separate reservoir heavy oil product stream 72 into a bitumen product stream 42, a gaseous hydrocarbon product stream 44, an asphaltene product stream 48, a separated surplus solvent stream 49, and/or a water product stream 46, which may include water 29.
The bitumen product stream 42 may include bitumen and/or asphaltenes. The gaseous hydrocarbon product stream 44 may include gaseous hydrocarbons. The asphaltene product stream 48 may include asphaltenes. The separated solvent stream 49 may include a portion of hydrocarbon solvent mixture 32 that was produced with the reservoir heavy oil product stream 72. The surplus solvent stream 49 may be referred to as an undesired solvent stream, an unwanted solvent stream, and/or an excess solvent stream. Surplus solvent stream 49 may be generated as a result of adjustments to the hydrocarbon solvent mixture composition.
Surplus solvent stream 49 may be generated as a result of removing some of the solvents in the reservoir heavy oil product stream 72 that are not wanted or desired to be in the hydrocarbon solvent mixture 35 or the reservoir injection mixture 32.
100671 Surface facility 40 may generate a hydrocarbon solvent mixture 35 from any suitable source. Surface facility 40 may receive a supplemental solvent stream 31 and/or may supply at least a portion of the hydrocarbon solvent mixture 35 recovered from the reservoir heavy oil product stream 72 as a part of the reservoir injection stream 32 to injection well 30.
Surface facility 40 may separate at least a portion of gaseous hydrocarbon product stream 44, hydrocarbon solvent mixture 35, and/or condensate 34 from the reservoir heavy oil product stream 72. Surface facility 40 may recycle and/or re-inject a portion of the gaseous hydrocarbon product stream 44, separated hydrocarbon solvent mixture 35, and/or separated condensate 34 into injection well 30 as components of the reservoir injection mixture 32.
The hydrocarbon solvent mixture 35 may additionally include a supplemental solvent stream 31. The composition of the supplemental solvent stream 31 may be similar in composition to the hydrocarbon solvent mixture 35 wherein its main purpose is to add additional solvent to the hydrocarbon solvent mixture 35 for the reservoir injection mixture 32.
Alternatively, the supplemental solvent stream 31 may be tailored to adjust the composition of the overall hydrocarbon solvent mixture 35 for the reservoir injection mixture 32, as well as additionally supply additional solvent to the overall process to make up for losses in the subterranean

- 18 -reservoir and/or losses due to the surface facility processing and solvent recovery.
[0068] Conventional recovery processes that utilize an injected vapor stream to decrease the viscosity of hydrocarbons may utilize a pure (i.e., single-component), or at least substantially pure, injected vapor stream that comprises a light hydrocarbon, such as propane.
In contrast, the systems and methods according to the present disclosure may utilize a hydrocarbon solvent mixture 35. The hydrocarbon solvent mixture 35 may include a heavy hydrocarbon fraction that comprises, consists of, or consists esspntially of hydrocarbons with five or more carbon atoms ("C5+"). The heavy hydrocarbon fraction may comprise greater than 10 mole percent, greater than 20 mole percent, greater than 30 mole percent, greater than 40 mole percent, greater than 50 mole percent, greater than 60 mole percent, greater than 70 mole percent, or greater than 80 mole percent of hydrocarbon solvent mixture 35. The heavy hydrocarbon fraction may comprise less than 99 mole percent, less than 95 mole percent, less than 90 mole percent, less than 80 mole percent, less than 70 mole percent, less than 60 mole percent, or less than 50 mole percent of hydrocarbon solvent mixture 35.
Suitable ranges may include combinations of any upper and lower amount of mole percentage listed above or any number within the mole percentages listed above.
[0069] The heavy hydrocarbon fraction may include at least a first compound that has five or more carbon atoms and a second compound that has more carbon atoms than the first compound. The first compound and the second compound each may comprise at least 10 mole percent of hydrocarbon solvent mixture 35. For example, the first and/or second compounds may comprise at least 20 mole percent, at least 30 mole percent, at least 40 mole percent, at least 50 mole percent, at least 60 mole percent, at least 70 mole percent, or at least 80 mole percent of hydrocarbon solvent mixture 35. Suitable ranges of the carbon atoms or mole percent of the first compound and the second compound may include combinations of any upper and lower amount listed above or any number within or bounded by the aforementioned ranges.
[0070] The heavy hydrocarbon fraction may comprise any suitable hydrocarbon molecules, materials, and/or compounds. For example, the heavy hydrocarbon fraction may comprise one or more of alkanes, n-alkanes, branched alkanes,.alkenes, n-alkenes, branched alkenes, alkynes, n-alkynes, branched alkynes, aromatic hydrocarbons, and/or cyclic hydrocarbons.

- 19 -[0071] The hydrocarbon solvent mixture 35 may include a light hydrocarbon fraction that may include hydrocarbons with fewer than five carbon atoms, such as hydrocarbons with one carbon atom, two carbon atoms, three carbon atoms, and/or four carbon atoms ("C1-C4").
The light hydrocarbon fraction (when present) may, but is not required to, comprise a minority portion of the hydrocarbon solvent mixture. For example, the light hydrocarbon fraction may comprise at least 5 mole percent, at least 10 mole percent, at least 15 mole percent, at least 20 mole percent, at least 30 mole percent, at least 40 mole percent, at least 50 mole percent, or at least 60 mole percent of the hydrocarbon solvent mixture.
The light hydrocarbon fraction may comprise less than 70 mole percent, less than 60 mole percent, less than 50 mole percent, less than 40 mole percent, less than 30 mole percent, less than 20 mole percent, less than 15 mole percent, or less than 10 mole percent of the hydrocarbon solvent mixture. Suitable ranges may include combinations of any upper and lower amount of hydrocarbon fraction ranges listed above or any number within or bounded by the hydrocarbon fraction ranges listed above.
[0072] The hydrocarbon solvent mixture 35 may comprise any suitable number of compounds and/or chemical species. For example, the hydrdcarbon solvent mixture may include a third compound that may include more carbon atoms than the second compound.
When the hydrocarbon solvent mixture includes the third compound, the third compound may comprise any suitable portion, or fraction, of the hydrocarbon solvent mixture. The third compound may comprise at least 20 mole percent, at least 30 mole percent, at least 40 mole percent, at least 50 mole percent, at least 60 mole percent, or at least 70 mole percent of the hydrocarbon solvent mixture. The hydrocarbon solvent mixture 35 may include alkanes, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and/or olefin hydrocarbons. In general, normal alkanes may have a highest tendency of causing phase separation of asphaltenes, with a decreasing tendency for phase separation being observed when moving from iso-alkanes to naphthenic hydrocarbons to aromatic hydrocarbons.
[0073] A
hydrocarbon solvent mixture composition of hydrocarbon solvent mixture 35 may be selected such that the vapor pressure of the hydrocarbon solvent mixture at the stream temperature is less than a threshold maximum pressure of the subterranean reservoir. This may prevent damage to the subterranean reservoir and/or escape of hydrocarbon solvent mixture 35 from the subterranean reservoir. The threshold maximum pressure may include,

- 20 - =

for example, a characteristic pressure of the subterranean reservoir, such as a fracture pressure of the subterranean reservoir, a hydrostatic pressure within the subterranean reservoir, a lithostatic pressure within the subterranean reservoir, a gas cap pressure for a gas cap that is present within the subterranean reservoir, and/or an aquifer pressure for an aquifer that is located above and/or under the subterranean reservoir.
[0074] In preferred embodiments, the reservoir injection mixture 32 is comprised of steam 50 and the hydrocarbon solvent mixture 35. The reservoir injection mixture 32 is injected into subterranean reservoir 24 at a stream temperature: Steam 50 for use as part of the reservoir injection mixture 32 can be added from an external source, such as from a boiler, or can be produced, in full or in part, from within the surface facility 40 from waste heat generated from the overall recovery process, including waste heat generated form separating the reservoir heavy oil product stream 72 into the various component streams as shown in Figure 1 as described herein. At least a portion of the, water product stream 46 was optionally be used to produce the steam required for the reservoir injection mixture 32.
[0075] The following paragraphs disclose preferred compositional and operating ranges for injecting a near-azeotropic mixture of steam 50 and the hydrocarbon solvent mixture 35 which is utilized as the reservoir injection mixture 32 in the processes as further disclosed herein.
[0076] For practical purposes, the selection of the solvent molar fraction and the operating pressure constrains the temperature of the vapor phase assuming saturated conditions.
[0077] In practice, as will become more apparent by the description below, one may select a hydrocarbon solvent mixture 35 (also referred to as "solvent" or "solvent mixture"
herein) that has a favorable operating temperature and solvent molar fraction at the azeotrope condition when combined with steam 50. A favorable operating temperature is a temperature that results in economic production rates while delivering adequate or good thermal efficiency. A favorable solvent molar fraction is one that reduces the Solvent to Oil Ratio (SolOR) as compared, for instance, with a heated VAPEX process.
[0078] A physical phenomenon that increases the SoiOR for heated VAPEX
and therefore reduces the efficiency of the process is that when a heated solvent is injected, it vaporizes all

-21 -the in-situ water, including a large fraction of the bound or irreducible water, in the vicinity of the injector.
[0079] As a result of this vaporization, at the boundary of the VAPEX
chamber, both water and solvent condense together under conditions that are at or close to the azeotrope.
This is a lower temperature than that of the injected heated solvent.
Furthermore, because the boundary is relatively narrow, the idealistic benefits of a solvent-only process with no flowing water are not practically achieved.
[0080] An important feature of the azeotrope pressure-temperature conditions is that the two fluids largely behave as a single fluid. That is, both fluids condense together in the same molar ratios of concentrations as they exist in the gas. Additionally, there is no tendency for either fluid to preferentially flash from the liquid state into the vapor state (i.e. vaporize additional in-situ water in the vicinity of the injector well). As such, the combined fluids can behave effectively as a single fluid with modified properties compared to either single fluid.
[0081] Water is a very effective working fluid for transferring heat whereas hydrocarbon solvents tend to be relatively inefficient working fluids for that purpose.
Conversely, hydrocarbon solvents are very effective viscosity reducing agents for heavy oils whereas water is practically immiscible. However, mixtures of hydrocarbons and water at the azeotrope behave largely as a single fluid with beneficial qualitative features of both the water and the hydrocarbon solvent mixture.
[0082] Without intending to be bound by theory, a near optimal injection ratio of solvent and steam vapor, where the fluid enters the reservoir, may be a .ratio that is at or close to the azeotrope for the solvent-water mixture. Consider the case of injecting a mixture of water and hexane at 2.5 MPa. As shown in Figure 2, the molar fraction of solvent at the azeotrope is approximately 0.64 or 64% so that the water molar fraction is 0.36 or 36%.
On mass basis, this converts to a 10.5% water fraction and on a volumetric basis this converts to a 7% water fraction. The heat of vaporization of hexane at the azeotrope temperature is approximately 220 kJ/kg and that for water is about 2000 kJ/kg. The combined fluids have an effective heat capacity of about 410 kJ/kg. As a result, the mass of fluid required to deliver the same heat to the reservoir is approximately half and accordingly the operating solvent-to-oil ratio would be expected to be about half

-22 -[0083] If hexane vapor at 2.5 MPa is injected into the reservoir it will be at a temperature of 220 C (see Figure 2). As the hot hydrocarbon vapor enters the reservoir and enters pore spaces with liquid water, the water will vaporize and a fraction ofthe solvent will condense.
The temperature will also decline until the water-hydrocarbon system in vapor phase finds an equilibrium point near the azeotrope. At that point, any additional condensation will result in the water and solvent condensing with the mole fraction ratio of the azeotrope. The solvent-steam mixture that progresses to the boundary of the vapor chamber will be a mixture at or close to the azeotrope. This phenomenon has several of important implications:
[0084] 1. A significant volume of reservoir rock will be increased in temperature to as much as 220 C which is an additional heat sink compared to injection at the azeotrope temperature of 182 C.
[0085] 2. Due to the hotter injection fluids and conductive heating in the vicinity of the producer, produced fluids will be at a higher temperature. Hence more heat will be produced back from the reservoir which is less thermally efficient.
[0086] 3. Vaporized solvent is condensing in the reservoir in order to vaporize water which is then carrying the heat to the boundary of the steam chamber, which is not effectively using the benefits of the solvent. That is, as described above, hydrocarbon solvents tend to be relatively inefficient working fluids for transferring heat but are very effective viscosity reducing agents.
[0087] 4. A region will develop around the injector which is nearly completely water free (sometimes called a desiccation zone). It is possible that this could be advantageous in some circumstances. However it could also be a disadvantage due to factors such as salt or scale deposition and pore plugging, fines movement causing pore plugging and a shift from a water wet system to an oil wet system resulting in less favorable residual oil saturations and relative penneabilities.
[0088] Practical implications of using near-azeotropic injection are partly illustrated by the results of some analyses that are provided in Tables 1 and 2. Table 1 shows the azeotropic temperatures and molar concentrations for pentane, hexane and heptane at 1 MPa and 2.5 MPa pressures. Table 1 also provides mass fractions, standard volumetric fractions and enthalpies for steam and solvent at their respective, ideal partial pressures for the

- 23 -, azeotropic temperature. It can be seen from Table 1 that the azeotrope molar concentration of steam increases significantly from lighter to heavier solvents. However, for a given solvent there is limited variation with pressure. It can also be seen from Table 1 that the heat of vaporization for the combined fluids increases much more substantially for heavier solvents at the azeotrope than it does for the lighter solvents. Table 2 lists an assumed injected solvent-to-oil ratio (SolOR) for each of the cases shown in Table 1. For illustrative purposes, the assumed SolOR increases with solvent type and pressure proportionally to the difference between the azeotrope operating temperature and an assumed initial reservoir temperature of 7 C. The fifth and sixth columns of the Table 2 show the equivalent combined steam to oil ratio (SOR) and SoiOR when operating with azeotropic injection. In all cases, the required solvent recirculation is significantly reduced. For pentane, it is estimated to be about a 23%
reduction at 1 MPa. The benefit is predicted to increase with pressure and with the use of heavier solvents. The required solvent recycling is predicted to be reduced by 50% or more for heavier solvents.
Table 1. Properties for steam-solvent Design Parameters Azeotrope Pro-serties (Approximate) Steam-Solvent Ratios Thermal Properties Steam Solvent Steam Solvent Steam Solvent Steam Heat Solvent Heat Combined Solvent Pressure Temperature Molar Molar Mass Mass Volume Volume of of Fluid Heat of Fraction Fraction Fraction Fraction Fraction Fraction Vaporization Vaporization Vaporization Mpa deg. C. kJ kg kkkg k.fkg Pentane 1 116 0.16 0.84 0.045 0.955 0.029 Hexane 1 140.5 0.34 0.66 0.097 0.903 , 0.066 0934 2142 270 452 Heptane 1 155.7 0.54 046 0.174 0.826 0.125 0.875 2095 226 551 Pentane 2.5 157.7 0.20 0.80 0.059 0.941 0.038 0.962 2089 208 318 Hexane 2.5 182 0.36 0.64 0.105 0.895 0.071 0.929 2006 220 408 Heptane 2.5 196.9 0.54 0.46 0.174 0.826 0.125 0.875 1951 210 513 Table 2. Representative Solvent-only and Isotropic Steam-Solvent Ratios Solvent Pressure _ Temperature Solvent-only . Azeotrope Combined S,OR Reduction Mpa deg. C. S,OR _ Steam SOR Solvent S,OR %
Pentane . 1 116 8.8 0.20 6.8 23 Hexane I 140.5. 12.1 0.49 . 7.0 42 Heptane I 155.7 15.6 0.86 6.0 61 .
Pentane 2.5 157.7 18.6 0.46 11.9 36 Hexane , 2.5 18/ 19.4 0.78 10.1 48 Heptane 1 2.5 196.9 21.4 1.18 8.3 61

- 24 -Simulation Results [0089] The concept described herein is examined by a numerical simulation in a typical Athabasca reservoir. Figure 3 shows the reservoir properties, map for single component solvent H-VAPEX (n-05 or normal-pentane) and Azeotropic H-VAPEX ("AH-VAPEX") at the same operating pressure condition. As seen in the temperature map, the average temperature in the depleted zone for AH-VAPEX with no near wellbore heating is lower than the H-VAPEX case. It is also noted from the water saturation map that in AH-Vapex, the co-injected steam at the azeotropic concentrations inhibited the vaporization of the initial in-situ water and minimized solvent condensation to provide the " required energy for water vaporization. The improvement in SoiOR for this case is shown in Figure 4.
Figure 4 also shows the improvement in the SõIOR for AH-VAPEX in azeotropic steam-nC7 (steam-normal-heptane) system. As described above, the azeotropic systems for heavier solvents results in a higher energy content in the injected azeotropic fluid compared to lighter solvents and therefore results in a higher reduction in SolOR, as is shown Table 1 and Table 2 and in Figure 4.
[0090] The vaporized in-situ water in H-VAPEX in the depleted zone is replaced with hydrocarbon liquid phase which is mainly condensed liquid solvent. Prevention (or limitation) of in-situ water vaporization in the AH-VAPEX results in reduction of liquid hydrocarbon phase in the depleted chamber and therefore reduction in solvent retention in the depleted reservoir. This is seen in the liquid phase saturation map in Figure 3 as a reduced residual liquid phase saturation region within depleted chamber in AH-VAPEX
compared to H-VAPEX. The reduction in solvent retention in reservoir is reflected in Figure 5 in terms of an increase in produced oil-to-retained solvent ratio (PBRSR). It is noted that nC7 AH-VAPEX has a higher increase in PBRSR compared to the nC5 AH-VAPEX. The oil recovery rates in the azeotropic H-VAPEX and H-VAPEX is generally similar as shown in Figure 6.
[0091] For field applications, the commercially available solvents are generally 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 the single compound solvents.
However, their phase behavior when mixed with steam can be considered as superposition of

- 25 -individual pure compounds behavior. These systems exhibit a semi-azeotropic behavior with a minimum boiling characteristic similar to single compound solvents. Figure 7 shows the semi-azeotropic behavior of steam-diluent system. The minimum dew point temperature in this system is the co-condensation point of steam-solvent components at a semi-azeotropic water concentration similar to azeotropic point in a single component solvent-steam system.
Figures 8 and 9 show the enhancement effects in S,,IOR and PBRSR of semi-azeotropic steam-diluent AH-VAPEX compared to diluent H-VAPEX. Figures 8 and 9 also compare the SolOR and PBRSR improvement in a high initial water saturation reservoir (lean reservoir, So=0.61), compared to an Athabasca reservoir with typical initial water saturation (So=0.87).
Oil saturation of "So" is a fraction of oil volume based on pore volume.
[0092]
Potential advantages in terms of efficiency of near-azeotropic injection in AH-VAPEX relative to heated VAPEX include:
1. The average temperatures in the vapor chamber are reduced while the temperature at the chamber boundary remains near the azeotrope temperature.
2. The temperatures at the top of the steam chamber will also be reduced resulting in less heat loss to the overburden.
3. There is virtually no thermodynamic tendency to vaporize water (mobile, immobile or bound) within the vapor chamber. This eliminates (or reduces) the complexities and potential problems associated with a dry (or desiccation) zone.
4. Preventing in-situ water (mobile, immobile or bound) vaporization in the near-azeotropic injection results in a reduction of the liquid hydrocarbon phase in the depleted chamber, reduction in solvent concentration in the vapor phase in the depleted chamber, and therefore a reduction in solvent retention in reservoir.
5. Since water is a much more effective thermal working fluid than hydrocarbon solvents, the combined fluids have a greater average working enthalpy associated with the condensation of the vapor.
6. Oil rates from the process will remain largely unchanged since in either process water is condensing at the boundary with the solvent at similar water to solvent ratios.

- 26 -7. Heat loss from the wellbore can result in significant condensation of fluids. An additional volume or molar concentration of water can be added to the injected stream at surface such that water preferentially condenses in the wellbore and injection at the sand face is then near the azeotrope.
8. It may also be advantageous to inject vapor at the sand face with a water concentration marginally above the azeotrope concentration so that, for example, in later life, primarily water condenses at the top of the reservoir. In particular, solvent that condenses on the top of the steam chamber and drains down is not as effective as solvent that condenses on the oil interface. If one injects above the steam azeotrope concentration, it will be water that condenses first at the top of the steam chamber. As a result, the optimal molar fraction of steam may start at or near the azeotrope and increase with time. There will likely be a reduction in the volume of vapor being injected into the reservoir which may allow for smaller wellbore sizes and tubulars.
[0093] Since thermal separation will be required in order to recycle solvent, process facilities may be designed to flash water at a desired concentration.
[0094] Overall, advantages of near-azeotropic injection may include reductions in the solvent-to-oil ratio (S010R) relative to solvent-only heated VAPEX, a potentially broader applicability to higher initial water saturation resources, a reduction in solvent storage, and an improvement in the produced oil-to-retained solvent ratio.
100951 The hydrocarbon solvent mixture (or "solvent") may be a fluid of a lower viscosity and lower density than those of the viscous oil being recovered. Its viscosity may, for example, be 0.2 to 5 cP (centipoise) at room temperature and at a pressure high enough to make it liquid. Its density may be, for example, 450 to 950 kg/m3 at 15 C and at a pressure high enough to make it liquid. The mixture or the blend of solvent and viscous oil may have a viscosity and a density that is in between those of the solvent and the viscous oil. The solvent may or may not precipitate asphaltenes if its concentration exceeds a critical concentration.
[0096] The hydrocarbon solvent mixture may be a single hydrocarbon compound or a mixture of hydrocarbon compounds having a number of carbon atoms in the range of CI to C30+. The hydrocarbon solvent mixture may have at least one hydrocarbon in the range of C3

- 27 -to C12 and this at least one hydrocarbon may comprise at least 50 wt. % of the solvent. The mixture may have aliphatic, naphthenic, aromatic, and/or elefinic fractions.
[0097] The hydrocarbon solvent mixture may comprise at least at least 50 wt. % of one or more C3-C17 hydrocarbons, at least 50 wt. % of one or more C4-C10 hydrocarbons, at least 50 -- wt. % of one or more C5-C7 hydrocarbons. The hydrocarbon solvent mixture may comprise a natural gas condensate or a crude oil refinery naphtha.
[0098] The hydrocarbon solvent mixture may comprise alkanes, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and/or olefin hydrocarbons. In general, normal alkanes may have a highest tendency of causing phase separation of asphaltenes, with a -- decreasing tendency for phase separation being observed when moving from iso-alkanes to naphthenic hydrocarbons to aromatic hydrocarbons.
[0099] Upon selecting an operating temperature range (for instance 60-140 C), a solvent may be selected that has a vapor pressure that does not exceed a selected maximum pressure.
[00100] The hydrocarbon solvent mixture may be chosen to be compatible with the desired -- reservoir operating pressure such that economics of the process will be optimized through a combination maximizing the producing oil rate, minimizing the injected solvent to oil ratio, minimizing the injected steam to oil ratio, maximizing the produced oil-to-retained solvent ratio, and selecting lower cost-of-supply solvents.
[00101] The steam may have a quality (defined as the wt. % of total steam present as -- steam vapour, and the remainder as liquid) of at least 5%, or 10-100%. The steam may be present in a near-azeotropic injection stream in an amount of 2-85 vol. % and solvent may be present in an amount of 15-98 vol. /0, both calculated at standard temperature and pressure (STP) and in cold liquid equivalents. The volume percentage range must be determined for each solvent at given pressure. By way of example, the cold liquid equivalent volume -- percentage range for C4 is 2-7 vol% and for C17 is 80-85 vol%.
[00102] The solvent molar fraction may be decreased over time.
[00103] The steam and solvent may be injected with other .components, such as: diesel, aromatic light catalytic gas oil, or another solvent, to provide flow assurance, or C07, natural gas, C3+ hydrocarbons, ketones, or alcohols.

- 28 -=
[00104] The process may further comprise separating and reusing the solvent and water in a separation, purification, revaporization and reinjection facility.
[00105] The gravity drainage process may involve directional drilling to place two horizontal wells in the viscous oil reservoir ¨ a lower well and an upper well positioned above it. The solvent and steam may be injected into the upper well to dilute and reduce the viscosity of the viscous oil. The viscous oil, solvent, and condensed steam will then drain downward through the reservoir under the action of gravity and flow into the lower production well, whereby these fluids can be pumped to the surface. At the surface of the well, all or a fraction of the solvent or a mixture of reduced-viscosity hydrocarbons may be separated from the produced fluids and reused as the solvent for injection with the steam. All or a fraction of the solvent or reduced-viscosity hydrocarbons may also remain mixed with the oil to aid in transport to a refinery or an upgrader.
[00106] Light hydrocarbon gases may also be separated from the produced fluids and may include hydrocarbons and/or carbon compounds with four or fewer carbon atoms, such as methane, ethane, propane, and/or butane. Light hydrocarbon gases may be used upstream in the process, for instance, as fuel to heat the solvent and steam prior to injection.
[00107] The operating pressure for the process may be informed by many external factors such as needing to be close to the pressure of nearby water zones, gas zones or other operations such that the injected fluids do not migrate away from the production well and unwanted fluids do not migrate to the production well. Additionally, the potential for formation fracturing may limit the maximum pressure. As such, the choice of solvent may be driven by the acceptable range of operating pressures.
[00108] A threshold maximum pressure also may be related to and/or based upon the characteristic pressure of the subterranean reservoir. The reservoir operating pressure may be 5-95% of a fracture pressure of the reservoir, or 0.2 to 4 MPa, or 1 to 2.5 MPa.
[00109] The injection temperature of the hydrocarbon solvent mixture and steam, when it is injected into the injection well, may be affected by the selection of the molar concentration of the steam and the solvent once the optimal solvent has been selected. The thermodynamic phase behavior will dictate that injection temperature is the saturation temperature corresponding to the molar concentration of the steam and the solvent in absence of any =

- 29 -degrees of superheat. The molar concentration of the steam will most often be higher than the azeotropic concentration in order to most efficiently manage heat losses.
Correspondingly, the temperature will be higher than the azeotropic temperature as well. The injection temperature of the hydrocarbon solvent mixture and steam may be 30-250 C or 80-150 C. Conversely, the actual subterranean reservoir operating temperature may be 30-250 C or 80-150 C.
[00110] The heat of vaporization of the hydrocarbon solvents is much smaller than steam.
Therefore, one may add excess steam to an azeotropic mixture of hydrocarbon vapor and steam. The thermodynamic phase behavior dictates that the excess steam will condense first to provide the required energy for heat losses. By way of example, a mixture of steam and hydrocarbon vapor may be prepared at a central processing facility with a solvent molar fraction (X1) less than the azeotropic vapor solvent molar fraction (Xaz) and a temperature (Ti) greater than the azeotropic temperature (Taz). As the mixture flows through the pipelines toward the wellhead, some of excess steam will condense due to heat losses. At the wellhead, the vapor mixture may have a higher solvent molar fraction (X2, i.e.
X2>X1>Xaz) and a lower temperature (T2, i.e. T2<T1). At the wellhead, preferably X2>Xaz and T2>Taz.
As the mixture flows down the well, some of the excess steam will again condense due to heat losses. At the sand face, the vapor mixture may have a solvent molar fraction (X3) where X3>X2 and a temperature (T3) where T3<T2. Preferably, at the sand face X3>Xaz and T3>Taz. In this way, one can inject the mixture at the sand face with some extra steam as compared to an azeotropic mixture to provide the energy required to account for heat losses to the overburden. Heaters can also be utilized on the surface or downhole to add some degree of superheat to the solvent and vapor mixture in order to ensure single phase flow.
Examples are surface heaters and downhole electrical heaters. Therefore, the solvent and steam vapor mixture may be injected at 1-50 C or 1-20 C of superheat, measured at the sand face, with respect to the saturation temperature of the solvent molar fraction at the reservoir operating pressure.
[00111] As described above, near-azeotropic injection of solvent and steam means using a solvent molar fraction of 70-100% of the azeotropic solvent, molar fraction.
Simulation results have shown than the total injected energy per volume of bitumen produced and the bitumen production rate are not be considerably affected by varying the composition of the

- 30 -injected fluid in this range. As an example, for C5 (pentane) one may inject with a solvent molar fraction of 0.62-0.88, and for C9 (nonane) one may inject with a solvent molar fraction of 0.13-0.18, both at a pressure of 500 kPa. These compositions translate to different dew point temperature ranges for each solvent, and as illustrated in Figure 10, namely, 87-119 C
for C5, and 145-147 C for C9. In general, as pressure increases the temperature range corresponding to 70% to 100% (or other ranges) of the azeotropic solvent molar fraction becomes narrower.
[00112] Separation of the produced fluid may be effected in any suitable separation system or structure, such as a single stage separation vessel, a multistage distillation assembly, a liquid-liquid separation or extraction assembly and/or any suitable gas-liquid separation, or extraction assembly.
[00113] Purification of the solvent may be effected in any suitable system or structure, such as any suitable liquid-liquid separation or extraction assembly, any suitable gas-liquid separation or extraction assembly, any suitable gas-gas separation or extraction assembly, a single stage separation vessel, and/or any suitable multistage distillation assembly.
[00114] Vaporization of the solvent may be effected by any suitable system or structure above ground or downhole.
[00115] The injection well may be spaced apart from the production well. The production well may extend at least partially below the injection well, may extend at least partially vertically below the injection well, and/or may define a greater distance (or average distance) from the surface when compared to the injection well. At least a portion of the production well may be parallel to, or at least substantially parallel to, a corresponding portion of the injection well. At least a portion of the injection well, and/or of the production well, may include a horizontal, or at least substantially horizontal, portion.
[00116] The process may include preheating or providing thermal energy to at least a portion of the subterranean reservoir in any suitable manner. The preheating may include electrically preheating the subterranean reservoir, chemically preheating the subterranean reservoir, and/or injecting a preheating steam stream into the subterranean reservoir. The preheating may include preheating any suitable portion of the subterranean reservoir, such as a portion of the subterranean reservoir that is proximal to the injection well, a portion of the

- 31 -subterranean reservoir that is proximal to the production well, and/or a portion of the subterranean reservoir that defines a vapor chamber that receives the solvent and steam.
[00117] Heating the solvent may include directly heating the solvent in a surface region or using the co-injection with the steam.
[00118] Condensing the solvent and steam within the subterranean reservoir may include condensing any suitable portion of the solvent and steam to release a latent heat of condensation of the solvent and steam, heat the subterranean reservoir, heat the viscous oil, and/or generate the reduced-viscosity hydrocarbons within the subterranean reservoir. The condensing may include condensing a majority, at least 50 wt. %, at least 60 wt. cY0, at least 70 wt. %, at least 80 wt. %, at least 90 wt. %, at least 95 wt. %, at least 99 wt. %, or substantially all of the solvent and steam within the subterranean reservoir.
The condensing may include regulating a temperature within the subterranean reservoir to facilitate, or permit, the condensing.
[00119] Producing the reduced-viscosity hydrocarbons may include producing the reduced-viscosity hydrocarbons via any suitable production well, which may extend within the subterranean reservoir and/or may be spaced apart from the injection well.
This may include flowing the reduced-viscosity hydrocarbons from the subterranean reservoir, through the production well, and to, proximal to, and/or toward the surface region.
[00120] The producing may include producing asphaltenes. The asphaltenes may be present within the subterranean reservoir and/or within the viscous oil. The asphaltenes may be produced as a portion of the reduced-viscosity hydrocarbons (and/or the reduced-viscosity hydrocarbons may include, or comprise, asphaltenes). The injecting may include injecting into a stimulated region of the subterranean reservoir that includes asphaltenes, and the producing may include producing at least a threshold fraction of the asphaltenes from the stimulated region. This may include producing at least 10 wt. c1/0, at least 20 wt. %, at least 30 wt. %, at least 40 wt. %, at least 50 wt. %, at least 60 wt. %, at least 70 wt. %, at least 80 wt.
%, or at least 90 wt. % of the asphaltenes that are, or were, present within the stimulated region prior to the injecting. The fractions of the asphaltenes that are produced and left in the reservoir is a function of the operating temperature, pressure and the choice of solvents. The

- 32 -=

determination of these parameters may be influenced by the fraction of asphaltenes that is produced and associated value of the produced hydrocarbons.
[00121] Recycling the solvent may include recycling the solvent in any suitable manner.
The recycling may include separating at least a separated portion of the solvent from the reduced-viscosity hydrocarbon mixture and/or from the reduced-viscosity hydrocarbons. The recycling also may include utilizing at least a recycled portion of the solvent as, or as a portion of, the hydrocarbon solvent mixture and/or returning the recycled portion of the condensate to the subterranean reservoir via the injection well. The recycling may include purifying the recycled portion of the solvent prior to utilizing the recycled portion of the solvent and/or prior to returning the recycled portion of the solvent to the subterranean reservoir. =
1001221 The properties of the azeotropic mixture which condenses at the boundary of the vapour chamber are strongly influenced by the lightest hydrocarbons present in the injected solvent so the recycling process may have facilities designed to specifically remove the lightest components.
[00123] Pressures, such as the previously discussed pressures, may be measured and/or determined in any suitable manner. As examples, pressure may be measured with a downhole pressure sensor, calculated from any suitable property and/or characteristic of the subterranean reservoir, and/or estimated, such as via modeling the subterranean reservoir.
The threshold maximum pressure may be selected to correspond in any suitable or desired manner to one or more of these measured or calculated characteristic pressures. For example, the disclosed threshold maximum pressure may be selected to be, to be greater than, to be less than, to be within a selected range of, to be a selected percentage of, to be within a selected constant of, etc. one or more of these measured or calculated characteristic pressures. The threshold maximum pressure may be a user-selected, or operator-selected, value that does not directly correspond to a measured or calculated pressure.
[00124] The threshold maximum pressure also may be related to and/or based upon the characteristic pressure of the subterranean reservoir. The threshold maximum pressure may be less than 95%, less than 90%, less than 85%, less than 80%, less than 75%, less than 70%, less than 65%, less than 60%, less than 55%, or less than 50% of the characteristic pressure

- 33 -for the subterranean reservoir. The threshold maximum pressure may be at least 20%, at least 25%, at least 30%, at least 35%, at least 40%, at least 45%, at least 50%, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, or at least 80% of the characteristic pressure for the subterranean reservoir. Suitable ranges may include combinations of any upper and lower amount of percentage ranges listed above or any number within or bounded by the percentage ranges listed above.
100125] Examples of vapor pressures for hydrocarbon solvent mixtures 32 include vapor pressures that are greater than a lower threshold pressure of at least 0.2 megapascals (MPa), at least 0.3 MPa, at least 0.4 MPa, at least 0.5 MPa, at least 0.6 MPa, at least 0.7 MPa, at least 0.8 MPa, at least 0.9 MPa, at least 1 MPa, at least 1.1 MPa, at least 1.2 MPa, at least 1.3 MPa, at least 1.4 MPa, at least 1.5 MPa, at least 1.6 MPa, at least 1.7 MPa, at least 1.8 MPa, at least 1.9 MPa, at least 2 MPa, at least 2.1 MPa, at least 2.2 MPa, at least 2.3 MPa, at least 2.4 MPa, and/or at least 2.5 MPa. The vapor pressure for the hydrocarbon solvent mixture may be less than an upper threshold pressure that is less than 3 MPa, less than 2.9 MPa, less than 2.8 MPa, less than 2.7 MPa, less than 2.6 MPa, less than 2.5 MPa, less than 2.4 MPa, less than 2.3 MPa, less than 2.2 MPa, less than 2.1 MPa, less than 2 MPa, less than 1.9 MPa, less than 1.8 MPa, less than 1.7 MPa, less than 1.6 MPa, less than 1.5 MPa, less than 1.4 MPa, less than 1.3 MPa, less than 1.2 MPa, less than 1.1 MPa, less than 1 MPa, less than 0.9 MPa, less than 0.8 MPa, less than 0.7 MPa, less than 0.6 MPa, less than 0.5 MPa, less than 0.4 MPa, and/or less than 0.3 MPa. Suitable ranges may include combinations of any upper and lower amount of pressure ranges listed above or any number within or bounded by the pressure ranges listed above.
[00126] Examples of stream temperatures of hydrocarbon solvent mixture 32 when it is injected into injection well 30 include stream temperatures of at least 30 degrees ( ) Celsius (C), at least 35 C, at least 40 C, at least 45 C, at least 50 C, at least 55 C, at least 60 C, at least 65 "C, at least 70 C, at least 75 C, at least 80 'V, at least 85 C, at least 90 "C, at least 95 C, at least 100 C, at least 105 "C, at least 110 C, at least 115 C, at least 120 'V, at least 125 'V, at least 130 C, at least 135 C, at least 140 'V, at least 145 C, at least 150 'V, at least 155 C, at least 160 C, at least 165 C, at least 170 C, at least 175 C, at least 180 C, at least 185 C, at least 190 'V, at least 195 C, at least 200 C, at least 205 C, and/or at least 210 C.
Additionally or alternatively, the stream temperature also may be less than 250 C, less than

- 34 -240 C, less than 230 'C, less than 220 C, less than 210 "C, less than 200 C, less than 190 C, less than 180 "C, less than 170 C, less than 160 C, less than 150 C, less than 140 C, less than 130 C, less than 120 C, less than 110 "C, less than 100 C, less than 90 C, less than 80 C, less than 70 C, less than 60 C, less than 50 C, and/or less than 40 C.
Suitable ranges may include combinations of any upper and lower amount of temperature ranges listed above or any number within or bounded by the temperature ranges listed above.
[00127] Injection well 30 may include any suitable structure that may form a fluid conduit to convey hydrocarbon solvent mixture 32 to, or into, subterranean reservoir 24 and/or to, or into, solvent extraction chamber 60. Production well 70 may include any suitable structure that may form a fluid conduit to convey the reservoir heavy oil product stream 72 from subterranean reservoir 24 to, toward, and/or proximal, surface region 20. As an example, and as illustrated in Fig. 1, injection well 30 may be spaced apart from production well 70.
Production well 70 may extend at least partially below injection well 30, may extend at least partially vertically below injection well 30, and/or may define a greater distance (or average distance) from surface region 20 when compared to injection well 30. At least a portion of production well 70 may be parallel to, or at least substantially parallel to, a corresponding portion of injection well 30. At least a portion of injection well 30, and/or of production well 70, may include a horizontal, or at least substantially horizontal, portion.
[00128] Bituminous hydrocarbon deposit 25 may include and/or be any suitable subterranean hydrocarbon deposit that may include bitumen and/or asphaltenes.
Bituminous hydrocarbon deposit 25 may be referred to as a viscous hydrocarbon deposit 25, a bitumen deposit 25, an oil sands deposit 25, and/or an asphaltene-containing deposit 25. An example of a bituminous hydrocarbon deposit 25 that may be included in and/or utilized with the systems and methods according to the present disclosure may include the Athabasca bitumen deposit in Alberta, Canada.
[00129] Bituminous hydrocarbon deposit 25 may include a wide range of hydrocarbon molecules that may possess a correspondingly wide range of molecular carbon contents, molecular weights, viscosities, densities, chemical functionalities, and/or solvent solubilities.
Bituminous hydrocarbon deposit 25 may include hydrocarbon molecules with eleven (i.e., C11) or more carbon atoms. The composition of the bituminous hydrocarbon deposit may be characterized into two different fractions. The first fraction, which may be referred to as the

- 35 -=
light fraction, the light end, the light end fraction, and/or the light end components, may include hydrocarbon molecules with eleven to thirty carbon atoms (i.e., Cil-C30). The second fraction, which may be referred to as the heavy fraction, the heavy end, the heavy end fraction, and/or the heavy end components, may include hydrocarbon molecules with greater than thirty carbon atoms (i.e., C30+). The first fraction and the second fraction often may separate into two different liquid phases (i.e., a light liquid phase and a heavy liquid phase) in the reservoir heavy oil product stream 72 that is formed from bituminous hydrocarbon deposits 25. Asphaltenes are heavy end components and may be present in the heavy liquid phase; however, under certain conditions, a portion of the asphaltenes may precipitate from the heavy liquid phase, forming a separate solid, or semi-solid, phase.
[00130] The portion of the asphaltenes that precipitate from the heavy liquid phase and/or a fraction of the heavy liquid phase that may be produced with the reservoir heavy oil product stream 72 may depend upon the reservoir injection mixture composition. The reservoir injection mixture composition may be regulated to regulate the precipitation of the asphaltenes and/or the fraction of the heavy liquid phase that is produced with the reservoir heavy oil product stream.
[00131] Bituminous hydrocarbon deposits 25 that may be included in and/or utilized with the systems and methods according to the present disclosure may include any suitable portion, proportion, or fraction of the light end components, the heavy end components, and/or asphaltenes. Prior to being produced from the subterranean reservoir, such as by utilizing the systems and methods that are disclosed in the present disclosure, the light end components, the heavy end components, and the asphaltenes may form a (heterogeneous and/or homogeneous) multicomponent mixture that defines bituminous hydrocarbon deposit 25. The light end components, the heavy end components, and the asphaltenes may be (at least substantially) indistinguishable within bituminous hydrocarbon deposit 25. During and/or subsequent to being combined with reservoir injection mixture 32, the light end components, the heavy end components, and/or the asphaltenes may separate from one another and/or may become separate, or distinct, phases within the subterranean reservoir and/or within the product hydrocarbon stream.
[00132] The light end components may comprise at least 10 weight percent, at least 15 weight percent, at least 20 weight percent, at least 25 weight percent, or at least 30 weight

- 36 -percent of the bituminous hydrocarbon deposit. The light end components also may comprise less than 50 weight percent, less than 45 weight percent, less than 40 weight percent, less than 35 weight percent, or less than 30 weight percent of the bituminous hydrocarbon deposit.
Suitable ranges may include combinations of any upper and lower amount of weight percent ranges listed above or any number within or bounded by the weight percent ranges listed above.
[00133] The heavy end components may comprise at least 50 weight percent, at least 55 weight percent, at least 60 weight percent, at least 65 weight percent, or at least 70 weight percent of the bituminous hydrocarbon deposit. The heavy end components also may comprise less than 90 weight percent, less than 85 weight percent, less than 80 weight percent, less than 75 weight percent, or less than 70 weight percent of the bituminous hydrocarbon deposit. Suitable ranges may include combinations of any upper and lower amount of weight percent ranges listed above or any number within or bounded by the weight percent ranges listed above.
[00134] The asphaltenes may comprise at least 1 weight percent, at least 2.5 weight percent, at least 5 weight percent, at least 7.5 weight percent, at least 10 weight percent, at least 12 weight percent, at least 14 weight percent, at least 16 weight percent, or at least 18 weight percent of the bituminous hydrocarbon deposit. The asphaltenes also may comprise less than 24 weight percent, less than 22 weight percent, less than 20 weight percent, or less than 18 weight percent of the bituminous hydrocarbon deposit. In preferred embodiments, the target asphaltene content or actual asphaltene content of the produced reservoir heavy oil product stream is from 1 to 30 weight percent. Suitable ranges may include combinations of any upper and lower amount of weight percent ranges listed above or any number within or bounded by the weight percent ranges listed above.
[00135] The disclosed systems and methods may utilize the variable solubility of asphaltenes n different reservoir injection mixtures 32 to control, regulate, and/or vary the asphaltene content of reservoir heavy oil product stream 72 and/or to control, regulate, and/or vary a proportion of the asphaltenes that are present within bituminous hydrocarbon deposit 25 that is produced with the reservoir heavy oil product stream 72.
[00136]
Surface facility 40 may receive the reservoir heavy oil product stream 72 from

- 37 -production well 70. The reservoir heavy oil product stream 72 may include hydrocarbon solvent mixture, condensate, and/or reduced-viscosity hydrocarbons, including bitumen, gaseous hydrocarbons, and/or asphaltenes. The reservoir heavy oil product stream 72 also may include water.
=
[00137] Referring more generally to Fig. 1, the systems and methods according to the present disclosure may include controlling, regulating, and/or varying a reservoir injection mixture 32 composition that is injected into injection well 30.
[00138] For example, the reservoir injection mixture composition may be varied to maintain at least a threshold asphaltene content within the reservoir heavy oil product stream 72. The hydrocarbon solvent mixture composition may be varied to maintain the asphaltene content within the reservoir heavy oil product stream 72 at, or near, a target asphaltene content. The target asphaltene content may be different from (or greater than) the threshold asphaltene content.
[00139] The composition of the reservoir injection mixture 32 may be varied based upon a desired stream temperature at which the reservoir injection mixture is injected into injection well 30 and/or based upon a desired temperature within solvent extraction chamber 60. The desired temperature may impact the viscosity of bituminous hydrocarbon deposit 25 and/or the solubility of bituminous hydrocarbon deposit 25 within the reservoir injection mixture 32.
[00140] The reservoir injection mixture composition may be varied based upon a desired pressure at which the reservoir injection mixture is injected into injection well 30 and/or based upon a desired pressure within solvent extraction chamber 60. The desired pressure may impact the average saturation temperature of injected solvent and consequently the viscosity of bituminous hydrocarbon deposit 25, the solubility of bituminous hydrocarbon deposit 25 within the reservoir injection mixture 32, and/or a production rate of the reservoir heavy oil product stream 72. The composition of the reservoir injection mixture composition, including the composition of the hydrocarbon solvent mixture 35 may be varied in any suitable manner. The hydrocarbon solvent mixture 35 may include a plurality of hydrocarbon molecules that defines, or has, an average molecular carbon content; the hydrocarbon solvent mixture composition may be varied by varying the average molecular carbon content. The phrase "average molecular carbon content" may refer to an average number of carbon atoms =

- 38 -that may be present in hydrocarbon molecules that comprise hydrocarbon solvent mixture 35.
[00141] The hydrocarbon solvent mixture 35 might comprise 25 mole percent propane (which includes three carbon atoms), 25 mole percent butane (which includes four carbon atoms), 25 mole percent pentane (which includes five carbon atoms), and 25 mole percent hexane (which includes six carbon atoms). For such a hydrocarbon solvent mixture 35, the average molecular carbon content would be (0.25*3+0.25*4+0.25*5+0.25*6), which yields an average molecular carbon content of 4.5. The hydrocarbon solvent mixture 35 might comprise 50 mole percent propane and 50 mole percent pentane. For such a hydrocarbon solvent mixture 35, the average molecular carbon content would be (0.5*3+0.5*5), which yields an average molecular carbon content of 4Ø
[00142] The systems and methods according to the present disclosure are described in the context of the average molecular carbon content of hydrocarbon solvent mixture 35.
However, it is to be understood that changes in the average molecular carbon content may produce a proportionate change in an average molecular weight of hydrocarbon solvent mixture 35. Changing the average molecular carbon content may be referred to as changing the average molecular weight. Increasing the average molecular carbon content also may be referred to as increasing the average molecular weight. Decreasing the average molecular carbon content may be referred to as decreasing the average molecular weight.
[00143] Changes in the chemical structure of hydrocarbon solvent mixture 35 may change the asphaltene content of reservoir heavy oil product stream 72. For a molecule with a given number of carbon atoms, normal alkanes generally will produce a lower asphaltene content than iso-alkanes. Iso-alkanes generally will produce a lower asphaltene content than naphthenic hydrocarbons. Naphthenic hydrocarbons generally will produce a lower asphaltene content than aromatic hydrocarbons. The systems and methods according to the present disclosure may utilize this variation in asphaltene content with chemical structure of hydrocarbon solvent mixture 35 to change, or vary, the asphaltene content of reservoir heavy oil product stream 72.
[00144] The systems and methods according to the present disclosure may include increasing a proportion of hydrocarbon solvent mixture 35 that comprises chemical structures that provide a (relatively) higher asphaltene content in reservoir heavy oil product stream 72,

- 39 -such as naphthenic hydrocarbons and/or aromatic hydrocarbons, to increase the asphaltene content of the reservoir heavy oil product stream. The systems and methods according to the present disclosure also may include increasing a proportion of hydrocarbon solvent mixture 35 that comprises chemical structures that provide a (relatively) lower asphaltene content in reservoir heavy oil product stream 72, such as normal alkanes and/or iso-alkanes, to decrease the asphaltene content of the reservoir heavy oil product stream.
1001451 The control, regulation, and/or variation in the hydrocarbon solvent mixture composition may be accomplished in any suitable manner. For example, a supplemental solvent stream composition of supplemental solvent stream 31 may be varied to control, regulate, and/or vary the hydrocarbon solvent mixture composition. The operation of surface facility 40 may be varied to vary the hydrocarbon solvent mixture composition.
[00146] Figure 11 is a bar graph illustrating heavy end component deposition within a subterranean reservoir for various single-component hydrocarbon solvents at two different temperatures. Stated another way, Figure 11 illustrates a fraction, proportion, or percentage of heavy end components that initially may be present within a bituminous hydrocarbon deposit and that remain in a subterranean reservoir that may include the bituminous hydrocarbon deposit subsequent to solvent extraction of bituminous hydrocarbon deposit at the given temperatures by the given solvents.
[00147] As may be seen in Figure 11, increasing the carbon content of the single-component hydrocarbon solvents decreases the fraction of the heavy end components that may remain within the subterranean reservoir subsequent to the solvent-based recovery process. Stated another way, increasing the carbon content of the single-component hydrocarbon solvents increases the fraction of the heavy end components that may be produced from the subterranean reservoir via the solvent-based recovery process.
[00148] Figure 11 illustrates that increasing the temperature of the solvent-based recovery process decreases the fraction of the heavy end components that may remain within the subterranean reservoir. Thus, Figure 11 illustrates that both the carbon content and the temperature of the single-component hydrocarbon solvents may have a significant impact on the production of heavy end components from a subterranean reservoir that may include a bituminous hydrocarbon deposit.

- 40 -[00149] The systems and methods according to the present disclosure may utilize a multicomponent hydrocarbon solvent as the hydrocarbon solvent mixture 35.
Performing solvent-based recovery processes with multicomponent hydrocarbon solvent mixtures may permit independent (or at least quasi-independent) selection of the temperature of the solvent-based recovery process, the pressure of the solvent-based recovery process, and the proportion of the heavy end components that may be produced during the solvent-based recovery process.
[00150] The ability of the systems and methods according to the present disclosure to independently select the temperature of the solvent-based recovery process, the pressure of the solvent-based recovery process, and the proportion of the heavy end components that may be produced during the solvent-based recovery process is illustrated in Figures 12-13. Figure 12 is a table illustrating an average saturation temperature for three different hydrocarbon solvent mixtures at a pressure of 0.5 megapascals. The three different hydrocarbon solvent mixtures are designated Mixl, Mix2, and Mix3, and have average molecular carbon contents of 5.65, 5.05, and 4.25, respectively. Figure 13 is a bar graph illustrating heavy end component deposition, which may include asphaltene deposition, within a subterranean reservoir for the three different hydrocarbon solvent mixtures of Figure 12.
[00151] As may be seen in Figures 12-13, decreasing the average molecular carbon content of the hydrocarbon solvent mixture decreases the average saturation temperature of the hydrocarbon solvent mixture at 0.5 megapascals. Decreasing the average molecular carbon content also increases the fraction of the heavy end components that remains in the subterranean reservoir after performing the solvent-based recovery process.
[00152] The data in Figures 12-13 are presented as examples to illustrate how the systems and methods according to the present disclosure may vary the Composition of a hydrocarbon solvent mixture to vary the temperature, pressure, heavy end component, and/or asphaltene production of a solvent-based recovery process that utilizes the hydrocarbon solvent mixture.
The specific hydrocarbon solvent mixtures and the pressure of 0.5 megapascals are provide for illustration purposes only. It is within the scope of the present disclosure that other hydrocarbon solvent mixtures that produce different average saturation temperatures at 0.5 megapascals may be utilized in the disclosed systems and methods. The disclosed systems and methods also may operate at pressures greater than and/or less than 0.5 megapascals.

- 41 -=

[00153] Figures 11-13 illustrate the properties of various hydrocarbon solvent mixtures that may be foimed from normal alkanes and/or heavy end deposition for these mixtures.
However, it is to be understood that hydrocarbon solvent mixtures according to the present disclosure may include other components in addition to normal alkanes. These other components may include iso-alkanes, naphthenic hydrocarbons, olefin hydrocarbons, and/or aromatic hydrocarbons. In addition, the hydrocarbon solvent mixture initially may be obtained from any suitable source. As examples, the hydrocarbon solvent mixtures may include, or be, a gas plant condensate and/or crude oil refinery naphtha products.
[00154] The hydrocarbon solvent mixture may include a plurality of hydrocarbon molecules that defines an average molecular carbon content. Selecting the hydrocarbon solvent mixture may include selecting such that the average molecular carbon content has a threshold value. Examples of the threshold value of the average molecular carbon content include average molecular carbon contents of at least 2, at least 2.25, at least 2.5, at least 2.75, at least 3, at least 3.25, at least 3.5, at least 3.75, at least 4, at least 4.25, at least 4.5, at least 4.75 at least 5, at least 5.25, at least 5.5, at least 5.75, at least 6, at least 6.25, at least 6.5, at least 6.75, or at least 7. Additional examples of the threshold value of the average molecular carbon content include average molecular carbon contents of less than 12, less than 11.5, less than 11, less than 10.5, less than 10, less than 9.5, less than 9, less than 8.5, less than 8, less than 7.5, less than 7, less than 6.5, less than 6, less than 5.5, or less than 5.
Suitable ranges may include combinations of any upper and lower amount of average molecular carbon content ranges listed above or any number within or bounded by the average molecular carbon content ranges listed above.
[00155] Selecting of the hydrocarbon solvent mixture may include selecting such that the hydrocarbon solvent mixture may include a first fraction that comprises a first compound with at least five carbon atoms and a second fraction that comprises a second compound with at least six carbon atoms. The first compound and the second compound each may comprise at least 10 mole percent, at least 20 mole percent, at least 30 mole percent, at least 40 mole percent, at least 50 mole percent, at least 60 mole percent, at least 70 mole percent, or at least 80 mole percent of the hydrocarbon solvent mixture. Suitable ranges may include combinations of any upper and lower amount of mole percent ranges listed above or any number within or bounded by the mole percent ranges listed above.

- 42 -[00156] As discussed with reference to Figures 12-13, the hydrocarbon solvent mixture composition may directly impact the average saturation temperature and/or the vapor pressure of the hydrocarbon solvent mixture. The selecting of the hydrocarbon solvent mixture may include selecting the hydrocarbon solvent mixture composition based, at least in part, on a desired temperature within the solvent extraction chamber and/or based upon a desired pressure within the solvent extraction chamber. As used herein, the temperature within the solvent extraction chamber (or "reservoir temperature") is the temperature of the reservoir as measured (or is as calculated if no in-situ sensors are available) near the injection well. As used herein, the pressure within the solvent extraction chamber (or "reservoir pressure") is the pressure of the reservoir as measured (or is as calculated if no in-situ sensors are available) near the injection well.
[00157] The production rate of the reservoir heavy oil product stream that is produced may be impacted by the temperature within the solvent extraction chamber, with higher temperatures yielding higher production rates. The desired temperature within the solvent extraction chamber may be based, at least in part, on a desired production rate of the product hydrocarbon stream. The pressure within the solvent extraction chamber may be limited to a threshold maximum pressure of the subterranean reservoir. The desired pressure within the solvent extraction chamber may be based, at least in part, on the threshold maximum pressure of the subterranean reservoir.
[00158] The selecting of the hydrocarbon solvent mixture may include increasing the average molecular carbon content of the hydrocarbon solvent mixture. The average molecular carbon content may be increased to increase the temperature (or based upon an increase in the desired temperature) within the subterranean reservoir. The average molecular carbon content may be increased to decrease the pressure (or based upon a decrease in the desired pressure) within the subterranean reservoir.
[00159] The selecting of the hydrocarbon solvent mixture may include decreasing the average molecular carbon content of the hydrocarbon solvent mixture. The average molecular carbon content may be decreased to decrease the temperature (or based upon a decrease in the desired temperature) within the subterranean reservoir. The average molecular carbon content may be decreased to increase the 'pressure (or based upon an increase in the desired pressure) within the subterranean reservoir.

- 43 -[00160] The selecting of the hydrocarbon solvent mixture may include selecting a chemical structure of the hydrocarbon solvent mixture. The hydrocarbon solvent mixture may include hydrocarbon molecules that have different chemical structures. The selecting of the hydrocarbon solvent mixture may include selecting the chemical structures and/or a relative proportion of the chemical structures such that the product hydrocarbon stream has at least the threshold asphaltene content. The selecting may include increasing a proportion of the hydrocarbon solvent mixture that comprises chemical structures that provide a (relatively) higher asphaltene content in the product hydrocarbon stream, such as naphthenic hydrocarbons and/or aromatic hydrocarbons, to increase the asphaltene content of the product hydrocarbon stream. The selecting of the hydrocarbon solvent mixture may include increasing a proportion of the hydrocarbon solvent mixture that comprises chemical structures that provide a (relatively) lower asphaltene content in the product hydrocarbon stream, such as normal alkanes and/or iso-alkanes, to decrease the asphaltene content of the product hydrocarbon stream. The selecting may include decreasing the normal alkane content of the hydrocarbon solvent mixture to increase the asphaltene content of the product hydrocarbon stream.
[00161] Injecting the reservoir injection mixture may include injecting the reservoir injection mixture into the solvent extraction chamber. The injecting may include injecting the reservoir injection mixture into an injection well. The injection well may extend within the subterranean reservoir, may extend within the solvent extraction chamber, may extend proximal the solvent extraction chamber, may extend between a surface region and the subterranean reservoir, and/or may extend between the surface region and the solvent extraction chamber.
[00162] Injecting the reservoir injection mixture may include injecting at an injection temperature and/or at an injection pressure. Injecting the reservoir injection mixture may include injecting such that the reservoir injection mixture is a liquid mixture at the injection temperature and the injection pressure. However, it is preferred that the injecting of the reservoir injection mixture include where the reservoir injection mixture include both the hydrocarbon solvent mixture and steam and injecting such that the reservoir injection mixture is a vaporous mixture at the injection temperature and the injection pressure.
Injecting the reservoir injection mixture may include injecting such that the reservoir injection mixture is a

- 44 -=
liquid-vapor mixture that includes both a liquid and a vapor at the injection temperature and the injection pressure. However, it is most preferred that the reservoir injection mixture 32 comprise both the hydrocarbon solvent mixture 35 and steam 50 and be injected at near azeotropic conditions and wherein the reservoir injection mixture is at least 90%, at least 95%
or essentially 100% vapor by weight at injection into the injection well 30.
Here the term near-azeotropic conditions are preferably wherein the steam and hydrocarbon solvent mixture is within 30%+/-, 20%+/-, or 10%+/- of the azeotropic solvent molar fraction of the steam and the solvent as measured at the reservoir operating pressure.
Alternatively, the steam and hydrocarbon solvent mixture is 70-110%, 70-100%, 80-100%, or 90 to 100% of the azeotropic solvent molar fraction of the steam and the solvent as measured at the reservoir operating pressure. When the hydrocarbon solvent mixture is the vaporous hydrocarbon solvent mixture, the injection temperature may be at, or near, a saturation temperature for the vaporous hydrocarbon solvent mixture at the injection pressure.
[00163] Producing the reservoir heavy oil product stream may include producing the reservoir heavy oil product stream from the subterranean reservoir, producing the reservoir heavy oil product stream from the solvent extraction chamber, and/or producing the reservoir heavy oil product stream to the surface region. This may include producing the reservoir heavy oil product stream from a production well. The production well may extend within the subterranean reservoir, may extend within the solvent extraction chamber, may extend proximal the solvent extraction chamber, may extend between a surface region and the subterranean reservoir, and/or may extend between the surface region and the solvent extraction chamber. The production well may be spaced apart from the injection well. The production well may be located below the injection well and/or may be located vertically deeper within the subterranean reservoir than the injection well.
[00164] Determining the asphaltene content of the reservoir heavy oil product stream may include determining the asphaltene content in any suitable manner. For example, the determining the asphaltene content may include indirectly determining the asphaltene content of the reservoir heavy oil product stream. The indirectly determining may include measuring a density of the product hydrocarbon stream and/or measuring a viscosity of the product hydrocarbon stream.
[00165] The determining of the asphaltene content of the reservoir heavy oil product

- 45 -stream may include performing a crude assay on a sample from the reservoir heavy oil product stream. The determining of the asphaltene content of the reservoir heavy oil product stream may include obtaining a gas chromatograph of the sample from the product hydrocarbon stream. The asphaltene content may include performing a standard ASTM
asphaltene test such as ASTM test number D3279. Other suitable alternative ASTM
asphaltene test methods include ASTM test numbers D4055, D6560, and D7061.
This may alternatively include determining the asphaltene content of any suitable portion of the reservoir heavy oil product stream.
[00166] In embodiments, the process may comprise measuring a density of the product hydrocarbon stream comprising: determining a target density for the reservoir heavy oil stream; measuring an existing density of the reservoir heavy oil stream; and adjusting the amount of the hydrocarbon solvent mixture in the reservoir injection mixture to obtain an actual density of the reservoir heavy oil stream equal to the target density.
In other embodiments, the process may comprise: determining a target density for the reservoir heavy oil stream; measuring an existing density of the reservoir heavy oil stream;
and adjusting the composition of the hydrocarbon solvent mixture in the reservoir injection mixture to obtain an actual density of the reservoir heavy oil stream equal to the target density.
[00167] In embodiments, the process may comprise: determining a target viscosity for the reservoir heavy oil stream; measuring an existing viscosity of the reservoir heavy oil stream;
and adjusting the amount of the hydrocarbon solvent mixture in the reservoir injection mixture to obtain an actual viscosity of the reservoir heavy oil stream equal to the target viscosity. In other embodiments, the process may comprise: determining a target viscosity for the reservoir heavy oil stream; measuring an existing viscosity of the reservoir heavy oil stream; and adjusting the composition of the hydrocarbon solvent mixture in the reservoir injection mixture to obtain an actual viscosity of the reservoir heavy oil stream equal to the target viscosity.
[00168] Comparing the asphaltene content of the reservoir heavy oil product stream to the target asphaltene content may include comparing the asphaltene content of the product hydrocarbon stream to any suitable target, desired, and/or predetermined asphaltene content for the reservoir heavy oil product stream.

- 46 -[00169] Adjusting the composition of the reservoir injection mixture 32 may include adjusting based, at least in part, on comparing the asphaltene content of the reservoir heavy oil product stream to the target asphaltene content. The target asphaltene content may be a target asphaltene content range, and the adjusting may include adjusting to maintain the asphaltene content of the product hydrocarbon stream within the target asphaltene content range. The reservoir heavy oil product stream may include a hydrocarbon solvent fraction and a bituminous hydrocarbon fraction. The hydrocarbon solvent fraction may include, comprise, or be formed from the hydrocarbon solvent mixture that was injected.
The bituminous hydrocarbon fraction may include, comprise, or be formed from the bituminous hydrocarbon deposit. Examples of lower limits for the target asphaltene content range include lower limits of at least 1 weight percent, at least 2 weight percent, at least 3 weight percent, at least 4 weight percent, at least 5 weight percent, at least 6 weight percent, at least 8 weight percent, at least 10 weight percent, at least 12 weight percent, at least 14 weight percent, or at least 16 weight percent of the bituminous hydrocarbon fraction.
Examples of upper limits for the target asphaltene content range include upper limits of less than 30 weight percent, less than 28 weight percent, less than 26 weight percent, less than 24 weight percent, less than 22 weight percent, less than 20 weight percent, less than 18 weight percent, less than 16 weight percent, less than 14 weight percent, less than 12 weight percent, less than 10 weight percent, or less than 5 weight percent of the bituminous hydrocarbon fraction.
Suitable ranges may include combinations of any upper and lower amount of weight percentage ranges listed above or any number within or bounded by the weight percentage ranges listed above.
[00170] The adjusting the composition of the reservoir injection mixture 32 also may include adjusting to maintain the asphaltene content of the reservoir heavy oil product stream above the threshold asphaltene content. Examples of the threshold asphaltene content include threshold asphaltene contents of at least 1 weight percent, at least 2 weight percent, at least 3 weight percent, at least 4 weight percent, at least 5 weight percent, at least 6 weight percent, at least 8 weight percent, at least 10 weight percent, at least 12 weight percent, at least 14 weight percent, or at least 16 weight percent of the bituminous hydrocarbon fraction.
Suitable ranges may include combinations of any upper and lower amount of weight percentage ranges listed above or any number within or bounded by the weight percentage

- 47 -ranges listed above.
[00171] The subterranean reservoir may have a fluid permeability, and deposition of asphaltenes within the subterranean reservoir may impact, or decrease the fluid permeability.
The adjusting the composition of the reservoir injection mixture 32 may include adjusting to maintain at least a threshold fluid permeability within the subterranean reservoir. The threshold fluid permeability may be determined based upon one or more characteristics of the subterranean reservoir and/or based upon a desired production iate of the reservoir heavy oil product stream from the subterranean reservoir.
[00172] The reservoir heavy oil product stream may include one or more contaminants that may be present within and/or be generated from the bituminous hydrocarbon deposit. These contaminants may negatively impact the operation of equipment that may receive and/or process the product hydrocarbon stream. The adjusting the composition of the reservoir injection mixture 32 may include adjusting to maintain a concentration of the one or more contaminants below a threshold contaminant level in the reservoir heavy oil product stream.
The threshold contaminant level may be selected such that the one or more contaminants do not have a negative impact on the operation of the equipment that may receive and/or process the product hydrocarbon stream. Examples of contaminants that may be present within the reservoir heavy oil product stream include heavy metals, vanadium, nickel, nitrogen, and/or sulfur heteroatoms and others.
[00173] The adjusting the composition of the reservoir injection mixture 32 may include adjusting to maintain one or more material properties of the reservoir heavy oil product stream and/or of the bituminous hydrocarbon fraction of the reservoir heavy oil product stream within a desired range. The adjusting the composition of the reservoir injection mixture 32 may include adjusting to maintain the pipelineability of the reservoir heavy oil product stream 72 or, more importantly, of the bitumen product stream 42. As another example, the reservoir heavy oil product stream may have a density at a given temperature (such as 5 degrees Celsius). The adjusting the composition of the reservoir injection mixture 32 may include adjusting the viscosity to maintain the density within a target density range.
The reservoir heavy oil product stream may have a viscosity at the given temperature. The adjusting the composition of the reservoir injection mixture 32 may include adjusting to maintain the viscosity of the reservoir heavy oil product stream within a target viscosity

- 48 -range. The adjusting the composition of the reservoir injection mixture 32 may include adjusting to produce a target weight percent of the asphaltenes from the bituminous hydrocarbon deposit. The adjusting the composition of the reservoir injection mixture 32 may include adjusting to produce at least 1, at least 2, at least 5, at least 10, at least 15, at least 20, or at least 25 weight percent of the asphaltenes from the bituminous hydrocarbon deposit. The adjusting the composition of the reservoir injection mixture 32 also may include adjusting to produce less than 99, less than 98, less than 95, less than 90, less than 85, less than 80, or less than 75 weight percent of the asphaltenes from the bituminous hydrocarbon deposit. Suitable ranges may include combinations of any upper and lower amount of weight percentage ranges listed above or any number within or bounded by the weight percentage ranges listed above.
[00174] The adjusting the composition of the reservoir injection mixture 32 may include adjusting to deposit a target weight percent of the asphaltenes within the subterranean reservoir during production. The adjusting the composition of the reservoir injection mixture 32 may include adjusting to deposit at least 1, at least 2, at least 5, at least 10, at least 15, at least 20, or at least 25 weight percent of the asphaltenes within the subterranean reservoir.
The adjusting the composition of the reservoir injection mixture 32 may include adjusting to deposit less than 99, less than 98, less than 95, less than 90, less than 85, less than 80, or less than 75 weight percent of the asphaltenes within the subterranean reservoir.
Suitable ranges may include combinations of any upper and lower amount of weight percentage ranges listed above or any number within or bounded by the weight percentage ranges listed above.
[00175] The adjusting the composition of the reservoir injection mixture 32 may include increasing the average molecular carbon content of the hydrocarbon solvent mixture. The average molecular carbon content may be increased to increase the asphaltene content of the reservoir heavy oil product stream. The average molecular carbon content may be increased to decrease deposition of asphaltenes within the subterranean reservoir, which may increase the fluid permeability of the subterranean reservoir. Contaminants may be bound to and/or produced with asphaltenes, and the average molecular carbon content may be increased to increase the concentration of contaminants within the reservoir heavy oil product stream.
The average molecular carbon content may be increased to increase the viscosity of the reservoir heavy oil product stream. The average molecular carbon content may be increased

- 49 -to increase the density of the reservoir heavy oil product stream.
[00176] The adjusting the composition of the reservoir inje6tion mixture 32 may include decreasing the average molecular carbon content of the hydrocarbon solvent mixture. The average molecular carbon content may be decreased to decrease the asphaltene content of the reservoir heavy oil product stream. The average molecular carbon content may be decreased to increase deposition of asphaltenes within the subterranean reservoir, which may decrease the fluid permeability of the subterranean reservoir. Contaminants may be bound to and/or produced with asphaltenes, and the average molecular carbon content may be decreased to decrease the concentration of contaminants within the reservoir heavy oil product stream.
The average molecular carbon content may be decreased to decrease the viscosity of the reservoir heavy oil product stream. The average molecular carbon content may be decreased to decrease the density of the reservoir heavy oil product n stream.
[00177] The adjusting the composition of the reservoir injection mixture 32 also may include adjusting a chemical structure of the hydrocarbon solvent mixture. The hydrocarbon solvent mixture may include a plurality of hydrocarbon molecules that have different chemical structures. The adjusting the composition of the reservoir injection mixture 32 may include adjusting the chemical structures and/or a relative proportion of the chemical structures such that the reservoir heavy oil product stream has the target asphaltene content.
The adjusting the composition of the reservoir injection mixture 32 may include increasing a proportion of the hydrocarbon solvent mixture that comprises chemical structures that provide a (relatively) higher asphaltene content in the reservoir heavy oil product stream, such as naphthenic hydrocarbons and/or aromatic hydrocarbons, to increase the asphaltene content of the reservoir heavy oil product stream. The adjusting the composition of the reservoir injection mixture 32 also may include increasing a proportion of the hydrocarbon solvent mixture that comprises chemical structures that provide a (relatively) lower asphaltene content in the reservoir heavy oil product stream, such as normal alkanes and/or iso-alkanes, to decrease the asphaltene content of the reservoir heavy oil product stream. The adjusting the composition of the reservoir injection mixture 32 may include decreasing the normal alkane content of the hydrocarbon solvent mixture to increase the asphaltene content of the reservoir heavy oil product stream.
[00178] Based on the disclosure and teachings herein, the following are specific

- 50 -embodiments of the processes disclosed.
Embodiments:
[00179] Embodiment 1. A process for recovery of heavy oil from a subterranean reservoir, the process comprising:
a) determining a target subterranean reservoir operating pressure;
b) determining a target subterranean reservoir operating temperature;
c) determining a target asphaltene content for a produced reservoir heavy oil product stream from the subterranean reservoir;
d) adjusting the composition of a hydrocarbon solvent mixture to achieve the asphaltene content in step c) under the conditions of steps a) and b);
e) determining the azeotropic/minimum dew point steam content of the hydrocarbon solvent mixture in the vapor phase under the conditions of steps a) and b);
0 at an actual subterranean reservoir operating pressure and an actual subterranean reservoir operating temperature, co-injecting a reservoir injection mixture in the vapor phase into the subterranean reservoir comprising steam and the hydrocarbon solvent mixture, wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture as determined in step e);
recovering a reservoir heavy oil stream from the subterranean reservoir; and h) producing a bitumen product stream from the reservoir heavy oil product stream.
1001801 Embodiment 2. The process of Embodiment 1, wherein the target subterranean reservoir operating temperature is the existing subterranean reservoir operating temperature.
[00181] Embodiment 3. The process of Embodiment 1, further comprising:
- determining an increased target subterranean reservoir operating temperature which is greater than the existing subterranean reservoir operating temperature;
-increasing the content of the higher boiling point hydrocarbon compounds of

-51 -the hydrocarbon solvent mixture to produce a revised reservoir injection mixture wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture at the increased target subterranean reservoir operating temperature;
- increasing the actual subterranean reservoir operating temperature to the increased target subterranean reservoir operating temperature; and - co-injecting the revised reservoir injection mixture in the vapor phase into the subterranean reservoir.
[00182] Embodiment 4. The process of Embodiment 1, further comprising:
- determining a decreased target subterranean reservoir operating temperature which is lower than the existing subterranean reservoir operating temperature, - increasing the content of the lower boiling point hydrocarbon compounds of the hydrocarbon solvent mixture to produce a revised reservoir injection mixture wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture at the decreased target subterranean reservoir operating temperature;
- decreasing the actual subterranean reservoir operating temperature to the decreased target subterranean reservoir operating temperature; and - co-injecting the revised reservoir injection mixture in the vapor phase into the subterranean reservoir.
[00183] Embodiment 5. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content of the reservoir heavy oil product stream;
- increasing the content of the higher boiling point hydrocarbon compounds of the hydrocarbon solvent mixture to produce a revised reservoir injection mixture wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture

- 52 -is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture at the actual subterranean reservoir operating temperature;
- co-injecting the revised reservoir injection mixture into the subterranean reservoir; and - recovering the reservoir heavy oil product stream from the subterranean reservoir.
[00184] Embodiment 6. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content for the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the. reservoir heavy oil product stream to the target asphaltene content of the reservoir heavy oil product stream;
-increasing the content of the lower boiling point hydrocarbon compounds of the hydrocarbon solvent mixture to produce a revised reservoir injection mixture wherein the wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture at the actual subterranean reservoir operating temperature;
- co-injecting the revised reservoir injection mixture into the subterranean reservoir; and - recovering the reservoir heavy oil product stream from the subterranean reservoir.
[00185] Embodiment 7. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content for the reservoir heavy oil product stream; and - when the actual asphaltene content of the reservoir heavy oil product stream is higher than the target asphaltene content for the reservoir heavy oil product stream, increasing the content of the lower boiling point hydrocarbon compounds of the hydrocarbon

- 53 -solvent mixture.
[00186] Embodiment 8. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content for the reservoir heavy oil product stream; and - when the actual asphaltene content of the reservoir heavy oil product stream is lower than the target asphaltene content for the reservoir heavy oil product stream, increasing the content of the higher boiling point hydrocarbon compounds of the hydrocarbon solvent mixture.
[00187] Embodiment 9. The process of any one of Embodiments 3, 5 and 8, wherein the higher boiling point hydrocarbon compounds are the C5+ compounds of the hydrocarbon solvent mixture.
[00188] Embodiment 10. The process of any one of Embodiments 4, 6 and 7, wherein the lower boiling point hydrocarbon compounds are the C1 ¨ C4 compounds of the hydrocarbon solvent mixture.
[00189] Embodiment 11. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content for the reservoir heavy oil product stream; and - when the actual asphaltene content of the reservoir heavy oil product stream is higher than the target asphaltene content for the reservoir heavy oil product stream, decreasing the content of the aromatic compounds of the hydrocarbon solvent mixture.
[00190] Embodiment 12. The process of Embodiment 11, further comprising:
- decreasing the olefinic or naphthenic content of the hydrocarbon solvent mixture.
[00191] Embodiment 13. The process of Embodiment 11 or 12, further comprising:

- 54 -- increasing the paraffinic content of the hydrocarbon solvent mixture.
[00192] Embodiment 14. The process of Embodiment 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the. reservoir heavy oil product stream to the target asphaltene content for the reservoir heavy oil product stream; and - when the actual asphaltene content of the reservoir heavy oil product stream is lower than the target asphaltene content for the reservoir heavy oil product stream, increasing the content of the aromatic compounds of the hydrocarbon solvent mixture.
lo [00193] Embodiment 15. The process of Embodiment 14, further comprising:
- increasing the olefinic or naphthenic content of the hydrocarbon solvent mixture.
[00194] Embodiment 16. The process of Embodiment 14 or 15, further comprising:
- decreasing the paraffinic content of the hydrocarbon solvent mixture.
[00195] The disclosed systems and methods may refer to producing certain proportions, fractions, and/or percentages of heavy end components, such as asphaltenes, that may be present within a bituminous hydrocarbon deposit. The systems and methods also may refer to depositing, or retaining, certain proportions, fractions, and/or percentages of the heavy end components in a subterranean reservoir that may include the bituminous hydrocarbon deposit.
[00196] The disclosed systems and methods may not be utilized over, or to produce, an entire bituminous hydrocarbon deposit. It may be uneconomical, or even impossible, to perform the disclosed systems and methods within certain regions of the bituminous hydrocarbon deposit. The disclosed systems and methods may be performed over a period of several years. Other recovery processes may be utilized within certain portions of a given bituminous hydrocarbon deposit. Thus, the described proportions, fractions, and/or percentages may refer to proportions, fractions, and/or percentages of a produced portion (or fraction) of the bituminous hydrocarbon deposit and not to proportions, fractions, and/or percentages of the entire bituminous hydrocarbon deposit. The produced portion may include a portion of the bituminous hydrocarbon deposit that is produced utilizing the disclosed

- 55 -systems and methods and/or a portion of the bituminous hydrocarbon deposit that is produced at a given point in time (or over a given period of time) utilizing the disclosed systems and methods.
[00197] In the present disclosure, several 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, 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.
[00198] 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.
Industrial Applicability [00199] The systems and methods disclosed in the present disclosure are applicable to the oil and gas industry.
[00200] It is believed that the following claims particularly point out certain combinations and subcombinations that are novel and non-obvious.
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 different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the present disclosure.

- 56 -

Claims

1. A process for recovery of heavy oil from a subterranean reservoir, the process comprising:
a) determining a target subterranean reservoir operating pressure;
b) determining a target subterranean reservoir operating temperature;
c) determining a target asphaltene content for a produced reservoir heavy oil product stream from the subterranean reservoir;
d) adjusting the composition of a hydrocarbon solvent mixture to achieve the asphaltene content in step c) under the conditions of steps a) and b);
e) determining the azeotropic/minimum dew point steam content of the hydrocarbon solvent mixture in the vapor phase under the conditions of steps a) and b);
f) at an actual subterranean reservoir operating pressure and an actual subterranean reservoir operating temperature, co-injecting a reservoir injection mixture in the vapor phase into the subterranean reservoir comprising steam and the hydrocarbon solvent mixture, wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture as determined in step e);
g) recovering a reservoir heavy oil stream from the subterranean reservoir;
and h) producing a bitumen product stream from the reservoir heavy oil product stream.

2. The process of claim 1, wherein the target subterranean reservoir operating temperature is the existing subterranean reservoir operating temperature.

3. The process of claim 1, further comprising:
- determining an increased target subterranean reservoir operating temperature which is greater than the existing subterranean reservoir operating temperature;
- increasing the content of the higher boiling point hydrocarbon compounds of the hydrocarbon solvent mixture to produce a revised reservoir injection mixture wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture at the increased target subterranean reservoir operating temperature;
- increasing the actual subterranean reservoir operating temperature to the increased target subterranean reservoir operating temperature; and - co-injecting the revised reservoir injection mixture in the vapor phase into the subterranean reservoir.

4. The process of claim 1, further comprising:
- determining a decreased target subterranean reservoir operating temperature which is lower than the existing subterranean reservoir operating temperature, - increasing the content of the lower boiling point hydrocarbon compounds of the hydrocarbon solvent mixture to produce a revised reservoir injection mixture wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture at the decreased target subterranean reservoir operating temperature, - decreasing the actual subterranean reservoir operating temperature to the decreased target subterranean reservoir operating temperature; and - co-injecting the revised reservoir injection mixture in the vapor phase into the subterranean reservoir.

5. The process of claim 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content of the reservoir heavy oil product stream, - increasing the content of the higher boiling point hydrocarbon compounds of the hydrocarbon solvent mixture to produce a revised reservoir injection mixture wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture at the actual subterranean reservoir operating temperature;
- co-injecting the revised reservoir injection mixture into the subterranean reservoir; and - recovering the reservoir heavy oil product stream from the subterranean reservoir.

6. The process of claim 1, further comprising:
- determining the actual asphaltene content for the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content of the reservoir heavy oil product stream;
- increasing the content of the lower boiling point hydrocarbon compounds of the hydrocarbon solvent mixture to produce a revised reservoir injection mixture wherein the wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the hydrocarbon solvent mixture at the actual subterranean reservoir operating temperature;
- co-injecting the revised reservoir injection mixture into the subterranean reservoir; and - recovering the reservoir heavy oil product stream from the subterranean reservoir.

7. The process of claim 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content for the reservoir heavy oil product stream; and - when the actual asphaltene content of the reservoir heavy oil product stream is higher than the target asphaltene content for the reservoir heavy oil product stream, increasing the content of the lower boiling point hydrocarbon compounds of the hydrocarbon solvent mixture.

8. The process of claim 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content for the reservoir heavy oil product stream; and - when the actual asphaltene content of the reservoir heavy oil product stream is lower than the target asphaltene content for the reservoir heavy oil product stream, increasing the content of the higher boiling point hydrocarbon compounds of the hydrocarbon solvent mixture.

9. The process of any one of claims 3, 5 and 8, wherein the higher boiling point hydrocarbon compounds are the C5+ compounds of the hydrocarbon solvent mixture

10. The process of any one of claims 4, 6 and 7, wherein the lower boiling point hydrocarbon compounds are the C1 - C4 compounds of the hydrocarbon solvent mixture.

11 The process of claim 1, further comprising:
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content for the reservoir heavy oil product stream; and - when the actual asphaltene content of the reservoir heavy oil product stream is higher than the target asphaltene content for the reservoir heavy oil product stream, decreasing the content of the aromatic compounds of the hydrocarbon solvent mixture.

12. The process of claim 11, further comprising:
- decreasing the olefinic or naphthenic content of the hydrocarbon solvent mixture.

13. The process of claim 11 or 12, further comprising:
- increasing the paraffinic content of the hydrocarbon solvent mixture

14. The process of claim 1, further comprising.
- determining the actual asphaltene content of the reservoir heavy oil product stream;
- comparing the actual asphaltene content of the reservoir heavy oil product stream to the target asphaltene content for the reservoir heavy oil product stream; and when the actual asphaltene content of the reservoir heavy oil product stream is lower than the target asphaltene content for the reservoir heavy oil product stream, increasing the content of the aromatic compounds of the hydrocarbon solvent mixture.

15. The process of claim 14, further comprising:
- increasing the olefinic or naphthenic content of the hydrocarbon solvent mixture.

16. The process of claim 14 or 15, further comprising:
- decreasing the paraffinic content of the hydrocarbon solvent mixture.

17. The process of any one of claims 1-16, wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 80-100% of the azeotropic solvent molar fraction

18. The process of any one of claims 1-17, wherein the hydrocarbon solvent molar fraction of the combined steam and hydrocarbon solvent mixture is 90-100% of the azeotropic solvent molar fraction.

19. The process of any one of claims 1-18, wherein the hydrocarbon solvent mixture comprises at least one of alkanes, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and olefin hydrocarbons.

20. The process of any one of claims 1-19, wherein the hydrocarbon solvent mixture comprises at least 50 wt. % of one or more C3-C12 hydrocarbons.

21. The process of any one of claims 1-19, wherein the hydrocarbon solvent mixture comprises at least 50 wt. % of one or more C4-C10 hydrocarbons.

22. The process of any one of claims 1-19, wherein the hydrocarbon solvent mixture comprises at least 50 wt % of one or more C5-C7 hydrocarbons.

23. The process of any one of claims 1-22, wherein the hydrocarbon solvent mixture comprises a natural gas condensate or a crude oil refinery naphtha.

24 The process of any one of claims 1-23, wherein the actual subterranean reservoir operating temperature is 80-150°C.

25. The process of any one of claims 1-24, wherein the actual subterranean reservoir operating pressure is 5% to 95% of a fracture pressure of the subterranean reservoir.

26. The process of any one of claims 1-24, wherein the actual subterranean reservoir operating pressure is 0.2 MPa to 4 MPa.

27. The process of any one of claims 1-26, wherein the target asphaltene content is from 1 to 30 weight percent of the produced reservoir heavy oil product stream.

28. The process of any one of claims 1-27, wherein the process further comprises separating at least a portion of the hydrocarbon solvent mixture from the reservoir heavy oil reservoir stream.

29. The process of any one of claims 1-28, further comprising:
- determining a target density for the reservoir heavy oil stream, - measuring an existing density of the reservoir heavy oil stream; and adjusting the amount of the hydrocarbon solvent mixture in the reservoir injection mixture to obtain an actual density of the reservoir heavy oil stream equal to the target density.

30. The process of any one of claims 1-28, further comprising:
- determining a target density for the reservoir heavy oil stream;
- measuring an existing density of the reservoir heavy oil stream; and - adjusting the composition of the hydrocarbon solvent mixture in the reservoir injection mixture to obtain an actual density of the reservoir heavy oil stream equal to the target density.

31. The process of any one of claims 1-28, further comprising:
- determining a target viscosity for the reservoir heavy oil stream;
- measuring an existing viscosity of the reservoir heavy oil stream, and - adjusting the amount of the hydrocarbon solvent mixture in the reservoir injection mixture to obtain an actual viscosity of the reservoir heavy oil stream equal to the target viscosity.

32. The process of any one of claims 1-28, further comprising:
- determining a target viscosity for the reservoir heavy oil stream;
- measuring an existing viscosity of the reservoir heavy oil stream; and - adjusting the composition of the hydrocarbon solvent mixture in the reservoir injection mixture to obtain an actual viscosity of the reservoir heavy oil stream equal to the target viscosity.