CA2857329C

CA2857329C - Regulation of asphaltene production in a solvent-based recovery process and selection of a composition of a hydrocarbon solvent mixture

Info

Publication number: CA2857329C
Application number: CA2857329A
Authority: CA
Inventors: Rahman Khaledi; B. Karl Pustanyk; Ernesto C. Dela Rosa; Thomas J. Boone; Wenqiang Ernest Han
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2014-07-21
Filing date: 2014-07-21
Publication date: 2017-02-28
Anticipated expiration: 2034-07-21
Also published as: CA2857329A1

Abstract

Regulating asphaltene production in a solvent-based recovery process may include determining a bituminous hydrocarbon deposit composition of a bituminous hydrocarbon deposit that includes asphaltenes, selecting a hydrocarbon solvent mixture composition of a hydrocarbon solvent mixture, injecting the hydrocarbon solvent mixture into a solvent extraction chamber, producing a product hydrocarbon stream from the subterranean formation, determining a product hydrocarbon stream asphaltene content of the product hydrocarbon stream, and comparing the product hydrocarbon stream asphaltene content to a target asphaltene content for the product hydrocarbon stream.

Description

REGULATION OF ASPHALTENE PRODUCTION IN A SOLVENT-BASED
RECOVERY PROCESS AND SELECTION OF A COMPOSITION OF A
HYDROCARBON SOLVENT MIXTURE
BACKGROUND
Field of Disclosure [0001] The present disclosure relates to regulating asphaltene production in a solvent-based recovery process and selecting a composition of a hydrocarbon solvent mixture.
Description of Related Art

[0002] 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 20 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 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 formation by piping, flowing, and/or pumping the heavy oil from the subterranean formation. 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 formation as liquids and/or vapors to decrease the viscosity of heavy oil present within the subterranean formation. Traditionally, pure (i.e., single-component), or at least substantially pure, propane is injected into the subterranean formation 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 formation. 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 formation may comprise asphaltenes.
Asphaltenes may not be soluble in the solvent used and thus the asphaltenes may not be produced from the subterranean formation. Under certain conditions, it may be desirable to produce at least a fraction of the asphaltenes from the subterranean formation; it may be desirable to regulate an asphaltene content of the heavy oil produced from the subterranean formation.

[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.

[0011] A method of regulating asphaltene product in a solvent-based recovery process solvent-based recovery process may include determining a bituminous hydrocarbon deposit composition of a bituminous hydrocarbon deposit that includes asphaltenes and is present within a subterranean formation; selecting a hydrocarbon solvent mixture composition of a hydrocarbon solvent mixture based on the bituminous hydrocarbon deposit composition, wherein selecting comprises selecting such that a product hydrocarbon stream that is produced by combining the hydrocarbon solvent mixture and the bituminous hydrocarbon deposit within a solvent extraction chamber extending within the subterranean formation, is expected to have at least a threshold asphaltene content at a temperature and pressure within the solvent extraction chamber, and wherein the hydrocarbon solvent mixture includes hydrocarbon molecules that define an average molecular carbon content;
injecting the hydrocarbon solvent mixture into the solvent extraction chamber; producing the product hydrocarbon stream from the subterranean formation; determining a product hydrocarbon stream asphaltene content of the product hydrocarbon stream; and comparing the product hydrocarbon stream asphaltene content to a target asphaltene content for the product hydrocarbon stream.

[0012] A method of selecting a hydrocarbon solvent mixture composition of a hydrocarbon solvent mixture for injection into a subterranean formation at an injection pressure to produce a product hydrocarbon stream from the subterranean formation via a solvent-based recovery process, wherein the subterranean formation includes a bituminous hydrocarbon deposit that includes asphaltenes, and wherein the product hydrocarbon stream is generated via combination of the hydrocarbon solvent mixture and the bituminous hydrocarbon deposit within a solvent extraction chamber that extends within the subterranean formation, may comprise determining a threshold maximum pressure of the subterranean formation; determining a stream temperature at which the hydrocarbon solvent mixture is to be injected into the subterranean formation; determining a target asphaltene content for the product hydrocarbon stream; and selecting the hydrocarbon solvent mixture composition based on the stream temperature, the threshold maximum pressure, and the target asphaltene content, wherein the hydrocarbon solvent mixture includes hydrocarbon molecules that define an average molecular carbon content.

[0013] 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

[0014] 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.

[0015] Fig. 1 is a schematic representation of examples of a hydrocarbon production system.

[0016] Fig. 2 is a schematic representation of a surface facility.

[0017] Fig. 3 is a bar graph illustrating heavy end component deposition within a subterranean formation for various single-component hydrocarbon solvents.

[0018] Fig. 4 is a table illustrating an average saturation temperature for three different hydrocarbon solvent mixtures.

[0019] Fig. 5 is a bar graph illustrating heavy end component deposition within the subterranean formation for the three different hydrocarbon solvent mixtures of Fig. 4.

[0020] Fig. 6 is a flowchart depicting a method of regulating asphaltene production in a multicomponent solvent-based recovery process.

[0021] Fig. 7 is a flowchart depicting a method of selecting a composition of a hydrocarbon solvent mixture to be utilized in a multicomponent solvent-based recovery process.
DETAILED DESCRIPTION

[0022] 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.

[0023] 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.

[0024] A "hydrocarbon" is an organic compound that primarily includes the elements 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.

[0025] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.)% aliphatics (which can range from 5 wt.% - 30 wt.%, or higher);
19 wt.% asphaltenes (which can range from 5 wt.% - 30 wt.%, or higher);
wt.% aromatics (which can range from 15 wt.% - 50 wt.%, or higher);
30 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 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.

[0027]
"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.

[0028] "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 oil.

[0029] 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.

[0030] "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.

[0031] "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.

[0032] A
"subterranean reservoir" is a subsurface rock or sand reservoir from which a production fluid, or resource, can be harvested. A
subterranean reservoir may interchangeably be referred to as a subterranean formation. The subterranean formation may include sand, granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy oil (e.g., bitumen), oil, gas, or coal, among others. Subterranean reservoirs can vary in thickness from less than one foot (0.3048 meters (m)) to hundreds of feet (hundreds of meters). The resource is generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.

[0033]
"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.

[0034]
"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-CSS), 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.

[0035] 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, 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.

[0036] "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).

[0037] "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.

[0038] 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.

[0039] A "vapor chamber" is a solvent extraction chamber that includes a vapor, or vaporous solvent. Thus, when the solvent is injected into the subterranean formation as a vapor, a vapor chamber may be formed around the well.

[0040] A "compound that has five or more carbon atoms" may include any 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 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.

[0041] 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.
100421 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.

[0043] As used herein, the phrase "at least one," in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one" refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at least one of A and/or B") may refer, 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.
[0044] 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.
[0045] As used herein the terms "adapted" and "configured" mean that the element, component, or other subject matter is designed and/or intended to perform a given function.
Thus, the use of the terms "adapted" and "configured" should not be construed to mean that a , given element, component, or other subject matter is simply "capable of"
performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.
[0046] 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.
[0047] Any of the ranges disclosed may include any number within and/or bounded by the range given.
[0048] Figs. 1-7 provide illustrative, non-exclusive examples of systems 10 according to the present disclosure, components of systems 10, data that may be utilized to select a composition of a hydrocarbon solvent mixture 32 that may be utilized with systems 10, and/or methods, according to the present disclosure, of operating and/or utilizing systems 10.
The systems 10 may be referred to as hydrocarbon production systems 10.
Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of Figs. 1-7, and these elements may not be discussed in detail herein with reference to each of Figs. 1-7. Similarly, all elements may not be labeled in each of Figs. 1-7, but associated reference numerals may be utilized for consistency. Elements, components, and/or features that are discussed herein with reference to one or more of Figs. 1-7 may be included in and/or utilized with any of Figs. 1-7 without departing from the scope of the present disclosure.

[0049] 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.
[0050] Fig. 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 formation 24 that is present within a subsurface region 22 and/or that extend between a surface region 20 and the subterranean formation 24. Hydrocarbon production system 10 may include a surface facility 40. Surface facility 40 may be configured to receive a product hydrocarbon stream 72 from production well 70. Product hydrocarbon stream 72 may be hydrocarbon produced from the subterranean formation 24. Surface facility 40 may be configured to provide a hydrocarbon solvent mixture 32 to injection well 30.
[0051] Hydrocarbon solvent mixture 32 may be, or may be referred to as, a liquid hydrocarbon solvent mixture 32.
When the hydrocarbon solvent mixture is liquid hydrocarbon solvent mixture 32, the solvent-based recovery process may be referred to as, or may be, a liquid extraction process. An example of a liquid extraction process is a cyclic solvent process (CSP). Hydrocarbon solvent mixture 32 also may be, or may be referred to as, a vaporous hydrocarbon solvent mixture 32. When the hydrocarbon solvent mixture is 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.
[0052] 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 formation 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.
[0053] Once provided to subterranean formation 24, hydrocarbon solvent 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 hydrocarbon solvent 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 hydrocarbon solvent mixture 32 condenses, the hydrocarbon solvent mixture may release latent heat (or latent heat of condensation), transfer thermal energy to the subterranean formation, and/or generate a condensate 34. Condensation of the hydrocarbon solvent mixture 32 may heat a bituminous hydrocarbon deposit 25 that may be present within the subterranean formation, thereby decreasing a viscosity of the bituminous hydrocarbon deposit.
[0054] The bituminous hydrocarbon deposit 25 may include bitumen 26, gaseous hydrocarbons 27, asphaltenes 28, and/or water 29. Hydrocarbon solvent 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.
[0055] The energy transfer between hydrocarbon solvent mixture 32 and bituminous hydrocarbon deposit 25 and/or the mixing of hydrocarbon solvent 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, reduced-viscosity hydrocarbons 74 may be produced from the subterranean formation as product hydrocarbon stream 72. The reduced-viscosity hydrocarbons 74 may have a lower viscosity than the hydrocarbons within the subsurface formation 24 had before the hydrocarbon solvent mixture 32 was injected into the subterranean formation 24. The product hydrocarbon stream 72 may comprise reduced-viscosity hydrocarbons 74, asphaltenes 28, gaseous hydrocarbons 27, water 29, hydrocarbon solvent mixture 32, and/or condensate 34 in any suitable ratio and/or relative proportion.
[0056] The systems and methods according to the present disclosure may be utilized to control and/or regulate a product hydrocarbon stream composition of the product hydrocarbon 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 formation 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 product hydrocarbon 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 formation, does not become reduced-viscosity hydrocarbons 74, and/or is not produced with product hydrocarbon 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.
[0057] 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 formation and/or that are not produced with the product hydrocarbon stream.
[0058] Surface facility 40 may process product hydrocarbon stream 72 and/or may separate product hydrocarbon 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 product hydrocarbon stream 72 into a bitumen product stream 42, a gaseous hydrocarbon product stream 44, an asphaltene product stream 48, a separated solvent stream 49, and/or a water product stream 46, which may include water 29. The bitumen product stream 42 may include bitumen 26 and/or asphaltenes 28. The gaseous hydrocarbon product stream 44 may include gaseous hydrocarbons 27. The asphaltene product stream 48 may include asphaltenes 28. The separated solvent stream 49 may include a portion of hydrocarbon solvent mixture 32 that was produced with product hydrocarbon stream 72.

:
Separated solvent stream 49 may be referred to as a surplus solvent stream 49, an undesired solvent stream 49, an unwanted solvent stream 49, and/or an excess solvent stream 49.
Separated solvent stream 49 may be generated as a result of adjustments to the hydrocarbon solvent mixture composition. Separated solved stream 49 may be generated as a result of removing some of the solvents in product hydrocarbon stream 72 that are not wanted or desired to be in the hydrocarbon solvent mixture 32.
[0059] Surface facility 40 may generate hydrocarbon solvent mixture 32 from any suitable source. Surface facility 40 may receive a supplemental solvent stream 31 and/or may supply at least a portion of the solvent stream to injection well 30 as hydrocarbon solvent mixture 32. Surface facility 40 may separate at least a portion of gaseous hydrocarbons 27, hydrocarbon solvent mixture 32, and/or condensate 34 from product hydrocarbon stream 72.
Surface facility 40 may recycle and/or re-inject the separated gaseous hydrocarbons 27, separated hydrocarbon solvent mixture 32, and/or separated condensate 34 into injection well 30 as hydrocarbon solvent mixture 32.
[0060] 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 32. The hydrocarbon solvent mixture 32 may include a heavy hydrocarbon fraction that comprises, consists of, or consists essentially of hydrocarbons with five or more carbon atoms. 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 32. 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 32.
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.
[0061] 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 32. 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 32. 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.
[0062] 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.
[0063] The hydrocarbon solvent mixture 32 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.
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.
[0064] The hydrocarbon solvent mixture 32 may comprise any suitable number of compounds and/or chemical species. For example, the hydrocarbon 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 32 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.
[0065] Hydrocarbon solvent mixture 32 may be injected into subterranean formation 24 at a stream temperature. A hydrocarbon solvent mixture composition of hydrocarbon solvent mixture 32 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 formation. This may prevent damage to the subterranean formation and/or escape of hydrocarbon solvent mixture 32 from the subterranean formation. The threshold maximum pressure may include, for example, a characteristic pressure of the subterranean formation, such as a fracture pressure of the subterranean formation, a hydrostatic pressure within the subterranean formation, a lithostatic pressure within the subterranean formation, a gas cap pressure for a gas cap that is present within the subterranean formation, and/or an aquifer pressure for an aquifer that is located above and/or under the subterranean formation.
[0066] 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 formation, and/or estimated, such as via modeling the subterranean formation.
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.
[0067] The threshold maximum pressure also may be related to and/or based upon the characteristic pressure of the subterranean formation. 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 for the subterranean formation. 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 formation. 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.
[0068] 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.
[0069] 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 C, 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 C, at least 125 C, at least 130 C, at least 135 C, at least 140 C, at least 145 C, at least 150 C, 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 C, 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 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.
[0070] Injection well 30 may include any suitable structure that may form a fluid conduit to convey hydrocarbon solvent mixture 32 to, or into, subterranean formation 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 product hydrocarbon stream 72 from subterranean formation 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.
[0071] Bituminous hydrocarbon deposit 25 may include and/or be any suitable subterranean hydrocarbon deposit that may include bitumen 26 and/or asphaltenes 28.
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.
[0072] 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 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., C11-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 product hydrocarbon streams 72 that are formed from bituminous hydrocarbon deposits 25.
Asphaltenes 28 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.
[0073] 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 product hydrocarbon stream 72 may depend upon the hydrocarbon solvent mixture composition. The hydrocarbon solvent 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 product hydrocarbon stream.
[0074] 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 28. Prior to being produced from the subterranean formation, 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 hydrocarbon solvent 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 formation and/or within the product hydrocarbon stream.
[0075] 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 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.
[0076] 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.
[0077] 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. 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.
[0078] The disclosed systems and methods may utilize the variable solubility of asphaltenes 28 in different hydrocarbon solvent mixtures 32 to control, regulate, and/or vary the asphaltene content of product hydrocarbon stream 72 and/or to control, regulate, and/or vary a proportion of the asphaltenes that are present within bituminous hydrocarbon deposit that is produced with product hydrocarbon stream 72.
[0079] Fig. 2 is a schematic representation of a surface facility 40 that may include and/or 25 be utilized with the systems and methods according to the present disclosure. Fig. 2 may be a more detailed view of surface facility 40 of Fig. 1 and any of the structures, features, and/or functions that are described with reference to surface facility 40 of Fig. 2 may be included in and/or utilized with surface facility 40 of Fig. 1. Any of the structures, features, and/or functions that are described with reference to surface facility 40 of Fig. 1 also may be included in and/or utilized with surface facility 40 of Fig. 2.

[0080] Surface facility 40 may receive product hydrocarbon stream 72 from production well 70. Product hydrocarbon stream 72 may include hydrocarbon solvent mixture 32, condensate 34, and/or reduced-viscosity hydrocarbons 74, including bitumen, gaseous hydrocarbons 27, and/or asphaltenes. Product hydrocarbon stream 72 also may include water 29.
[0081] Product hydrocarbon stream 72 may be provided to a separation unit 52.
Separation unit 52 may separate product hydrocarbon stream 72 into one or more constituent streams. The constituent streams ¨ interchangeably referred to as component streams ¨ may include a bitumen product stream 42, a gaseous hydrocarbon product stream 44, a water product stream 46, an asphaltene product stream 48, a separated solvent stream 49, and/or a recovered solvent stream 55. Bitumen product stream 42, gaseous hydrocarbon product stream 44, water product stream 46, asphaltene product stream 48, and/or separated solvent stream 49 may be discharged from surface facility 40 and/or utilized in any suitable process that may be downstream from surface facility 40. Separated solvent stream 49 may be combined, or mixed, with bitumen product stream 42 to reduce a viscosity of the bitumen product stream. Such a viscosity reduction may decrease a resistance to flow of the bitumen product stream within a pipeline. Gaseous hydrocarbon product stream 44 may be utilized as a fuel, such as to provide heat for vaporization of hydrocarbon solvent mixture 32.
Asphaltene product stream 48 may be utilized as a feedstock for a gasification process to generate a synthetic gas.
[0082] Recovered solvent stream 55 may be provided to a solvent treatment unit 53, which may be utilized to regulate, adjust, and/or control the composition of an adjusted solvent stream 56 that may be produced by the solvent treatment unit. Solvent treatment unit 53 may combine recovered solvent stream 55 with a supplemental solvent stream 31. Solvent treatment unit 53 may separate a separated solvent stream 49 from recovered solvent stream 55 (or from a combined stream that includes recovered solvent stream 55 and supplemental solvent stream 31) to generate adjusted solvent stream 56. Separated solvent stream 49 may include a portion of hydrocarbon solvent mixture 32 and/or condensate 34 that was produced with product hydrocarbon stream 72.
[0083] Adjusted solvent stream 56 may be provided to a solvent injection unit 58. The solvent injection unit may generate hydrocarbon solvent mixture 32 from adjusted solvent stream 56. The solvent injection unit 58 may provide the hydrocarbon solvent mixture to an injection well 30 for injection into a subterranean formation.
[0084] Separation unit 52 may include any suitable structure that may be utilized to separate product hydrocarbon stream 72 into one or more of the illustrated component streams. Separation unit 52 may include a separating unit, a phase separator, a liquid-gas separator, a liquid-liquid separator, a liquid-liquid-gas separator, an extraction unit, a distillation column, an extractive distillation column, an adsorption column, an absorption column, and/or any other separating unit or any combination of the above-listed structures that may be combined in a complex separation unit that includes more than one suitable separation structure.
[0085] Solvent treatment unit 53 may include any suitable structure that may be configured to receive recovered solvent stream 55 and/or supplemental solvent stream 31 and to generate adjusted solvent stream 56 and/or separated solvent stream 49 from the solvent treatment unit 53. Solvent treatment unit 53 may include a mixing unit, a separation unit, a phase separator, a liquid-gas separator, a liquid-liquid separator, a liquid-liquid-gas separator, an extraction unit, a distillation column, an extractive distillation column, an adsorption column, an absorption column, and/or any other separating unit or any combination of the above-listed structures that may be combined in a complex separation unit that includes more than one suitable separation structure.
[0086] Solvent injection unit 58 may include any suitable structure that may be configured to generate hydrocarbon solvent mixture 32 from adjusted solvent stream 56.
Solvent injection unit 58 may include a vaporization assembly that may be configured to vaporize adjusted solvent stream 56 to generate hydrocarbon solvent mixture 32. Solvent injection unit 58 may include a pressurization assembly that may be configured to pressurize adjusted solvent stream 56 to generate hydrocarbon solvent mixture 32.
[0087] Referring more generally to Figs. 1-2, the systems and methods according to the present disclosure may include controlling, regulating, and/or varying a hydrocarbon solvent mixture composition that is injected into injection well 30. This control, regulation, and/or variation in the hydrocarbon solvent mixture composition is discussed in more detail with reference to methods 100 and 200 of Figs. 6-7, respectively, and may be utilized to control, regulate, and/or vary a composition of product hydrocarbon stream 72.

;-=
[0088] For example, the hydrocarbon solvent mixture composition may be varied (i.e., increased or decreased) to maintain at least a threshold asphaltene content within product hydrocarbon stream 72. The hydrocarbon solvent mixture composition may be varied to maintain the asphaltene content within product hydrocarbon stream 72 at, or near, a target asphaltene content. The target asphaltene content may be different from (or greater than) the threshold asphaltene content.
[0089] The hydrocarbon solvent mixture composition may be varied based upon a desired stream temperature at which the hydrocarbon solvent 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 hydrocarbon solvent mixture 32.
[0090] The hydrocarbon solvent mixture composition may be varied based upon a desired pressure at which the hydrocarbon solvent 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 hydrocarbon solvent mixture 32, and/or a production rate of product hydrocarbon stream 72. The hydrocarbon solvent mixture composition of may be varied in any suitable manner. The hydrocarbon solvent mixture 32 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 that may be present in hydrocarbon molecules that comprise hydrocarbon solvent mixture 32.
[0091] The hydrocarbon solvent mixture 32 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 32, 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 32 might comprise 50 mole percent propane and 50 mole percent pentane. For such a hydrocarbon solvent mixture 32, the average molecular carbon content would be (0.5*3+0.5*5), which yields an average molecular carbon content of 4Ø
[0092] The systems and methods according to the present disclosure are described in the context of the average molecular carbon content of hydrocarbon solvent mixture 32.
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 32. 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.
[0093] Changes in the chemical structure of hydrocarbon solvent mixture 32 may change the asphaltene content of product hydrocarbon 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 32 to change, or vary, the asphaltene content of product hydrocarbon stream 72.
[0094] The systems and methods according to the present disclosure may include increasing a proportion of hydrocarbon solvent mixture 32 that comprises chemical structures that provide a (relatively) higher asphaltene content in product hydrocarbon stream 72, such as naphthenic hydrocarbons and/or aromatic hydrocarbons, to increase the asphaltene content of the product hydrocarbon stream. The systems and methods according to the present disclosure also may include increasing a proportion of hydrocarbon solvent mixture 32 that comprises chemical structures that provide a (relatively) lower asphaltene content in product hydrocarbon stream 72, such as normal alkanes and/or iso-alkanes, to decrease the asphaltene content of the product hydrocarbon stream.
[0095] 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.

[0096] With reference to Fig. 2, the operation of separation unit 52 may be varied to vary the composition, or average molecular carbon content, of recovered solvent stream 55. The operation of solvent treatment unit 53 may be varied to vary the composition, or average molecular carbon content, of adjusted solvent stream 56. The variation in the operation of separation unit 52 and/or of solvent treatment unit 53 may include varying respective operating temperatures, varying respective operating pressures, and/or varying a composition of streams 42, 44, 46, 48, and/or 49.
[0097] Fig. 3 is a bar graph illustrating heavy end component deposition within a subterranean formation for various single-component hydrocarbon solvents at two different temperatures. Stated another way, Fig. 3 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 formation that may include the bituminous hydrocarbon deposit subsequent to solvent extraction of bituminous hydrocarbon deposit at the given temperatures by the given solvents.
[0098] As may be seen in Fig. 3, increasing the carbon content of the single-component hydrocarbon solvents decreases the fraction of the heavy end components that may remain within the subterranean formation 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 formation via the solvent-based recovery process.
[0099] Fig. 3 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 formation. Thus, Fig. 3 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 formation that may include a bituminous hydrocarbon deposit. However, single-component hydrocarbon solvents generally exhibit specific and/or well-defined vapor pressures at a given temperature, which may significantly limit the temperature and/or pressure of solvent-based recovery processes that may be performed utilizing the single-component hydrocarbon solvents.
[0100] The systems and methods according to the present disclosure may utilize a multicomponent hydrocarbon solvent, such as hydrocarbon solvent mixture 32 of Figs. 1-2.
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.
[0101] 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 Figs.
4-5. Fig. 4 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 Mix 1, Mix2, and Mix3, and have average molecular carbon contents of 5.65, 5.05, and 4.25, respectively. Fig. 5 is a bar graph illustrating heavy end component deposition, which may include asphaltene deposition, within a subterranean formation for the three different hydrocarbon solvent mixtures of Fig. 4.
[0102] As may be seen in Figs. 4-5, 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 formation after performing the solvent-based recovery process.
[0103] The data in Figs. 4-5 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.
[0104] Figs. 3-5 illustrate the properties of various hydrocarbon solvent mixtures that may be formed 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.
[0105] Fig. 6 is a flowchart depicting methods 100, according to the present disclosure, of regulating asphaltene production in a multicomponent solvent-based recovery process.
Methods 100 include determining a composition of a bituminous hydrocarbon deposit at 110, selecting a hydrocarbon solvent mixture composition at 120, injecting the hydrocarbon solvent mixture at 130, and producing a product hydrocarbon stream at 140.
Methods 100 may include separating a hydrocarbon solvent fraction of the product hydrocarbon stream from a bituminous hydrocarbon fraction of the product hydrocarbon stream at 150. Methods 100 may include determining an asphaltene content of the product hydrocarbon stream at 160 and comparing the asphaltene content to a target asphaltene content at 170.
Methods 100 may include adjusting the composition of the hydrocarbon solvent mixture at 180, and/or repeating the methods at 190.
[0106] Determining the bituminous hydrocarbon deposit composition of the bituminous hydrocarbon deposit at 110 may include determining the bituminous hydrocarbon deposit composition of any suitable bituminous hydrocarbon deposit that may include asphaltenes and that may be present within a subterranean formation. The bituminous hydrocarbon deposit composition may be determined in any suitable manner.
[0107] The determining at 110 may include measuring the bituminous hydrocarbon deposit composition and/or measuring the composition of a sample of the bituminous hydrocarbon deposit. The determining at 110 may include performing a crude assay on the sample, obtaining a gas chromatograph of the sample, and/or performing a standard ASTM
asphaltene test. Examples of standard ASTM asphaltene tests include ASTM test numbers D6560, D3279, and D7061.
[0108] The determining at 110 may include obtaining the bituminous hydrocarbon deposit composition. The determining at 110 may include utilizing a tabulated composition of the bituminous hydrocarbon deposit. The tabulated composition may be obtained from any suitable source, such as a suitable book, publication, and/or database of bituminous hydrocarbon deposit compositions.

[0109] Selecting the hydrocarbon solvent mixture composition at 120 may include selecting based, at least in part, on the determined bituminous hydrocarbon deposit composition. The selecting at may include selecting the hydrocarbon solvent mixture composition such that the product hydrocarbon stream is expected to have at least a threshold asphaltene content at a temperature and pressure of, or within, the solvent extraction chamber. Thus, when the hydrocarbon solvent mixture is combined with the bituminous hydrocarbon deposit within the solvent extraction chamber, the product hydrocarbon stream with at least the threshold asphaltene content may be produced. The selecting at 120 may include performing methods 200 of Fig. 7.
[0110] The hydrocarbon solvent mixture may include a plurality of hydrocarbon molecules that defines an average molecular carbon content. The selecting at 120 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.
[0111] The selecting at 120 also 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.

_ [0112] As discussed with reference to Figs. 4-5, the hydrocarbon solvent mixture composition may directly impact the average saturation temperature and/or the vapor pressure of the hydrocarbon solvent mixture. The selecting at 120 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.
[0113] The production rate of the product hydrocarbon stream that is produced during the producing at 140 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 formation. The desired pressure within the solvent extraction chamber may be based, at least in part, on the threshold maximum pressure of the subterranean formation. The threshold maximum pressure is discussed with respect to Fig. 1.
[0114] As illustrated in Fig. 6 at 122, the selecting at 120 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 formation. The average molecular carbon content may be increased to decrease the pressure (or based upon a decrease in the desired pressure) within the subterranean formation.
[0115] As illustrated in Fig. 6 at 124, the selecting at 120 also 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 formation. The average molecular carbon content may be decreased to increase the pressure (or based upon an increase in the desired pressure) within the subterranean formation.
[0116] As illustrated in Fig. 6 at 126, the selecting at 120 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 at 126 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 at 126 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 at 126 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 at 126 may include decreasing the normal alkane content of the hydrocarbon solvent mixture to increase the asphaltene content of the product hydrocarbon stream.
[0117] Injecting the hydrocarbon solvent mixture at 130 may include injecting the hydrocarbon solvent mixture into the solvent extraction chamber. The injecting at 130 may include injecting the hydrocarbon solvent mixture into an injection well. The injection well may extend within the subterranean formation, may extend within the solvent extraction chamber, may extend proximal the solvent extraction chamber, may extend between a surface region and the subterranean formation, and/or may extend between the surface region and the solvent extraction chamber.
[0118] Injecting the hydrocarbon solvent mixture at 130 may include injecting at an injection temperature and/or at an injection pressure. Injecting the hydrocarbon solvent mixture at 130 may include injecting such that the hydrocarbon solvent mixture is a liquid hydrocarbon solvent mixture at the injection temperature and the injection pressure. Injecting the hydrocarbon solvent mixture at 130 may include injecting such that the hydrocarbon solvent mixture is a vaporous hydrocarbon solvent mixture at the injection temperature and the injection pressure. Injecting the hydrocarbon solvent mixture at 130 may include injecting such that the hydrocarbon solvent mixture is a liquid-vapor hydrocarbon solvent mixture that includes both a liquid and a vapor at the injection temperature and the injection 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.
[0119] Producing the product hydrocarbon stream at 140 may include producing the product hydrocarbon stream from the subterranean formation, producing the product hydrocarbon stream from the solvent extraction chamber, and/or producing the product hydrocarbon stream to the surface region. The producing at 140 may include producing the product hydrocarbon stream from a production well. The production well may extend within =
the subterranean formation, may extend within the solvent extraction chamber, may extend proximal the solvent extraction chamber, may extend between a surface region and the subterranean formation, 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 formation than the injection well.
[0120] Separating the hydrocarbon solvent fraction of the product hydrocarbon stream from the bituminous hydrocarbon fraction of the product hydrocarbon stream at 150 may include separating in any suitable manner. The separating at 150 may include separating in, or utilizing, a surface facility, such as surface facility 40 of Figs. 1-2.
[0121] When methods 100 include the separating at 150, the injecting at 130 may include injecting at least a portion of the hydrocarbon solvent fraction as the hydrocarbon solvent mixture. When methods 100 include the separating at 150, methods 100 may include regulating the separating at 150 to regulate the composition of the hydrocarbon solvent fraction. Regulation of the composition of the hydrocarbon solvent fraction may be utilized during, or to accomplish, the adjusting at 180.
[0122] Determining the asphaltene content of the product hydrocarbon stream at 160 may include determining the asphaltene content in any suitable manner. For example, the determining at 160 may include indirectly determining the asphaltene content of the product hydrocarbon stream. The indirectly determining may include measuring a density of the product hydrocarbon stream and/or measuring a viscosity of the product hydrocarbon stream.
[0123] The determining at 160 may include performing a crude assay on a sample from the product hydrocarbon stream. The determining at 160 may include obtaining a gas chromatograph of the sample from the product hydrocarbon stream. The determining at 160 may include performing a standard ASTM asphaltene test. Examples of standard ASTM
asphaltene tests include ASTM test numbers D6560, D3279, and D7061.
[0124] The determining at 160 may include determining the asphaltene content of any suitable portion of the product hydrocarbon stream. When methods 100 include the separating at 150, the determining at 160 may include determining an asphaltene content of the bituminous hydrocarbon fraction.
[0125] Comparing the asphaltene content to the target asphaltene content at 170 may include comparing the asphaltene content of the product hydrocarbon stream to any suitable target, desired, and/or predetermined asphaltene content for the product hydrocarbon stream.
For example, and prior to the producing at 140, the bituminous hydrocarbon deposit may define an initial hydrocarbon mass. The target asphaltene content may be based, at least in part, on a desired fraction of the initial hydrocarbon mass to be produced from the subterranean formation. The desired fraction of the initial hydrocarbon mass may be based, at least in part, on a market value of the product hydrocarbon stream as a function of the asphaltene content of the product hydrocarbon stream.
[0126] Adjusting the composition of the hydrocarbon solvent mixture at 180 may include adjusting based, at least in part, on the comparing at 170. The target asphaltene content may be a target asphaltene content range, and the adjusting at 180 may include adjusting to maintain the asphaltene content of the product hydrocarbon stream within the target asphaltene content range. The product hydrocarbon 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 during the injecting at 130. 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.
[0127] The adjusting at 180 also may include adjusting to maintain the asphaltene content of the product hydrocarbon 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 weight percent, at least 6 weight percent, at least 8 weight percent, at least 10 weight 5 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 ranges listed above.
[0128] The subterranean formation may have a fluid permeability, and deposition of asphaltenes within the subterranean formation may impact, or decrease the fluid permeability.
The adjusting at 180 may include adjusting to maintain at least a threshold fluid permeability within the subterranean formation. The threshold fluid permeability may be determined based upon one or more characteristics of the subterranean formation and/or based upon a desired production rate of the product hydrocarbon stream from the subterranean formation.
[0129] The product hydrocarbon 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 at 180 may include adjusting to maintain a concentration of the one or more contaminants below a threshold contaminant level. 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 product hydrocarbon stream include heavy metals, vanadium, nickel, nitrogen, and/or sulfur heteroatoms and others.
[0130] The adjusting at 180 may include adjusting to maintain one or more material properties of the product hydrocarbon stream and/or of the bituminous hydrocarbon fraction of the product hydrocarbon stream within a desired range. The adjusting at 180 may include adjusting to maintain the pipelineability of the product hydrocarbon stream.
As another example, the product hydrocarbon stream may have a density at a given temperature (such as 5 degrees Celsius). The adjusting at 180 may include adjusting the viscosity to maintain the density within a target density range. The product hydrocarbon stream may have a viscosity at the given temperature. The adjusting at 180 may include adjusting to maintain the viscosity within a target viscosity range. The adjusting at 180 may include adjusting to produce a target weight percent of the asphaltenes from the bituminous hydrocarbon deposit.
The adjusting at 180 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 at 180 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.
[0131] The adjusting at 180 may include adjusting to deposit a target weight percent of the asphaltenes within the subterranean formation during the producing at 140.
The adjusting at 180 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 formation.
The adjusting at 180 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 formation. 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.
[0132] As illustrated in Fig. 6 at 182, the adjusting at 180 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 product hydrocarbon stream. The average molecular carbon content may be increased to decrease deposition of asphaltenes within the subterranean formation, which may increase the fluid permeability of the subterranean formation. 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 product hydrocarbon stream. The average molecular carbon content may be increased to increase the viscosity of the product hydrocarbon stream. The average molecular carbon content may be increased to increase the density of the product hydrocarbon stream.
[0133] As illustrated in Fig. 6 at 184, the adjusting at 180 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 product hydrocarbon stream. The average molecular carbon content may be decreased to increase deposition of asphaltenes within the subterranean formation, which may decrease the fluid permeability of the subterranean formation. 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 product hydrocarbon stream. The average molecular carbon content may be decreased to decrease the viscosity of the product hydrocarbon stream. The average molecular carbon content may be decreased to decrease the density of the product hydrocarbon stream.
[0134] As illustrated in Fig. 6 at 186, the adjusting at 186 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 at 186 may include adjusting the chemical structures and/or a relative proportion of the chemical structures such that the product hydrocarbon stream has the target asphaltene content. The adjusting at 186 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 adjusting at 186 also 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 adjusting at 186 may include decreasing the normal alkane content of the hydrocarbon solvent mixture to increase the asphaltene content of the product hydrocarbon stream.
[0135] Repeating the methods at 190 may include repeating any suitable portion of methods 100. For example, the repeating at 190 may include repeating at least the injecting at 130, the producing at 140, the determining at 150, the comparing at 160, and the adjusting at 170. The producing at 140 may include at least substantially continuously producing the product hydrocarbon stream during a production interval, or time. The repeating at 190 may include periodically repeating during the production interval to maintain the asphaltene content of the product hydrocarbon stream at, or near, the target asphaltene content or at, or within, the target asphaltene content range.
[0136] Fig. 7 is a flowchart depicting methods 200, according to the present disclosure, of selecting a composition of a hydrocarbon solvent mixture to be utilized in a multicomponent solvent-based recovery process. The hydrocarbon solvent mixture may be injected into a subterranean formation at an injection pressure to produce a hydrocarbon product stream from the subterranean formation via a solvent-based recovery process. The subterranean formation may include a bituminous hydrocarbon deposit that may include asphaltenes. The product hydrocarbon stream may be generated via combination of the hydrocarbon solvent mixture with the bituminous hydrocarbon deposit within a solvent extraction chamber that extends within the subterranean formation.
[0137] Methods 200 include determining a threshold maximum pressure of the subterranean formation at 210, determining a stream temperature for the hydrocarbon solvent mixture at 220, determining a target asphaltene content for the product hydrocarbon stream at 230, and selecting a composition of the hydrocarbon solvent mixture at 240.
Methods 200 further may include injecting the hydrocarbon solvent mixture at 245, producing the product hydrocarbon stream at 250, separating a hydrocarbon solvent fraction of the product hydrocarbon stream from a bituminous hydrocarbon fraction of the product hydrocarbon stream at 255, determining the asphaltene content of the product hydrocarbon stream at 260, comparing the asphaltene content to the target asphaltene content at 265, adjusting the composition of the hydrocarbon solvent mixture at 270, and/or repeating the methods at 275.
[0138] Determining the threshold maximum pressure of the subterranean formation at 210 may include determining any suitable threshold maximum pressure of the subterranean formation. Examples of the threshold maximum pressure of the subterranean formation are discussed with reference to Fig. 1. The determining at 210 may include determining in any suitable manner. The threshold maximum pressure of the subterranean formation may be measured. The threshold maximum pressure of the subterranean formation may be calculated. The threshold maximum pressure of the subterranean formation may be obtained from a tabulation and/or from a database of threshold maximum pressures for subterranean formations.
[0139] Determining the stream temperature for the hydrocarbon solvent mixture at 220 may include determining and/or establishing any suitable stream temperature at which the hydrocarbon solvent mixture is to be injected into the subterranean formation.
The determining at 220 may include determining in any suitable manner. The determining at 220 may include determining based upon a desired temperature within the solvent extraction chamber. The determining at 220 may include determining based upon a desired production rate of the product hydrocarbon stream from the subterranean formation. The determining at 220 may include determining based upon a desired heat loss to the subterranean formation and/or to maintain less than a threshold heat loss to the subterranean formation.
[0140] Determining the target asphaltene content for the product hydrocarbon stream at 230 may include determining any suitable target asphaltene content for the product hydrocarbon stream. The determining at 230 may include determining based upon an asphaltene content of the bituminous hydrocarbon deposit. The determining at 230 may include determining based upon a target, or desired, fluid permeability for the subterranean formation. The determining at 230 may include determining based upon a target, or desired, contaminant concentration within the product hydrocarbon stream. The determining at 230 may include determining based upon a desired density of the product hydrocarbon stream and/or of a bituminous hydrocarbon fraction of the product hydrocarbon stream.
The determining at 230 may include determining based upon a desired viscosity of the product hydrocarbon stream and/or of the bituminous hydrocarbon fraction.
[0141] Selecting the composition of the hydrocarbon solvent mixture at 240 may include selecting based, at least in part, on the threshold maximum pressure.
Selecting the composition of the hydrocarbon solvent mixture at 240 may include selecting based, at least in part, on the stream temperature. Selecting the composition of the hydrocarbon solvent mixture at 240 may include selecting based, at least in part on the target asphaltene content for the product hydrocarbon stream.
[0142] The hydrocarbon solvent mixture may include a plurality of hydrocarbon molecules that defines an average molecular carbon content. The selecting at 240 may include selecting such that the average molecular carbon content has a threshold value and/or is within a threshold range. Examples of threshold values and/or threshold ranges of the average molecular carbon content are discussed with reference to the selecting at 120 of methods 100.
[0143] As illustrated in Fig. 7 at 241, the selecting at 240 may include increasing the average molecular carbon content of the hydrocarbon solvent mixture. The increasing at 241 may include increasing to increase the stream temperature and/or based upon an increase in a desired stream temperature. The increasing at 241 may include increasing to decrease the injection pressure and/or based upon a decrease in a desired injection pressure. The increasing at 241 may include increasing to increase the asphaltene content for the product hydrocarbon stream and/or based upon an increase in the target asphaltene content for the product hydrocarbon stream.
[0144] As illustrated in Fig. 7 at 242, the selecting at 240 also may include decreasing the average molecular carbon content of the hydrocarbon solvent mixture. The decreasing at 242 may include decreasing to decrease the stream temperature and/or based upon a decrease in the desired stream temperature. The decreasing at 242 may include decreasing to increase the injection pressure and/or based upon an increase in the desired injection pressure. The decreasing at 242 may include decreasing to decrease the asphaltene content for the product hydrocarbon stream and/or based upon a decrease in the target asphaltene content for the product hydrocarbon stream.
[0145] As illustrated in Fig. 7 at 243, the selecting at 240 also may include selecting 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 selecting at 243 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 at 243 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 at 243 also 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 at 243 may include decreasing the normal alkane content of the hydrocarbon solvent mixture to increase the asphaltene content of the product hydrocarbon stream.
[0146] Injecting the hydrocarbon solvent mixture at 245 may be at least substantially similar to the injecting at 130 of methods 100 of Fig. 6. Producing the product hydrocarbon stream at 250 may be at least substantially similar to the producing at 140 of methods 100 of Fig. 6. Separating the hydrocarbon solvent fraction of the product hydrocarbon stream from the bituminous hydrocarbon fraction of the product hydrocarbon stream at 255 may be at least substantially similar to the separating at 150 of methods 100 of Fig. 6.
Determining the asphaltene content of the product hydrocarbon stream at 260 may be at least substantially similar to the determining at 160 of methods 100 of Fig. 6. Comparing the asphaltene content to the target asphaltene content at 265 may be at least substantially similar to the comparing at 170 of methods 100 of Fig. 6. Adjusting the hydrocarbon solvent mixture composition at 270 may be at least substantially similar to the adjusting at 180 of methods 100 of Fig. 6.
The adjusting the hydrocarbon solvent mixture composition at 270 may include increasing or decreasing the average molecular carbon content of the hydrocarbon solvent mixture.
Repeating the methods at 275 may be at least substantially similar to the repeating at 190 of methods 100 of Fig. 6.
[0147] 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 formation that may include the bituminous hydrocarbon deposit.
[0148] 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 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.
[0149] 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.
Industrial Applicability [0151]
The systems and methods disclosed in the present disclosure are applicable to the oil and gas industry.
[0152]
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.

42

Claims

1. A method of regulating asphaltene production in a solvent-based recovery process, the method comprising:
determining a bituminous hydrocarbon deposit composition of a bituminous hydrocarbon deposit that includes asphaltenes and is present within a subterranean formation;
selecting a hydrocarbon solvent mixture composition of a hydrocarbon solvent mixture based on the bituminous hydrocarbon deposit composition, wherein selecting comprises selecting such that a product hydrocarbon stream that is produced by combining the hydrocarbon solvent mixture and the bituminous hydrocarbon deposit within a solvent extraction chamber extending within the subterranean formation, is expected to have at least a threshold asphaltene content at a temperature and pressure within the solvent extraction chamber, and wherein the hydrocarbon solvent mixture includes hydrocarbon molecules that define an average molecular carbon content;
injecting the hydrocarbon solvent mixture into the solvent extraction chamber;

producing the product hydrocarbon stream from the subterranean formation;
determining a product hydrocarbon stream asphaltene content of the product hydrocarbon stream; and comparing the product hydrocarbon stream asphaltene content to a target asphaltene content for the product hydrocarbon stream.

2. The method of claim 1, further comprising adjusting the hydrocarbon solvent mixture composition based on comparing the product hydrocarbon stream asphaltene content to the target asphaltene content.

3. The method of claim 2, wherein adjusting comprises increasing the product hydrocarbon stream asphaltene content when the product hydrocarbon stream asphaltene content is less than the target asphaltene content by increasing the average molecular carbon content of the hydrocarbon solvent mixture.

4. The method of any one of claims 2-3, wherein adjusting comprises decreasing the product hydrocarbon stream asphaltene content when the product hydrocarbon stream asphaltene content is greater than the target asphaltene content by decreasing the average molecular carbon content of the hydrocarbon solvent mixture.

5. The method of any one of claims 2-4, wherein adjusting comprises decreasing the product hydrocarbon stream asphaltene content when the product hydrocarbon stream asphaltene content is greater than the target asphaltene content by increasing a normal alkane content of the hydrocarbon solvent mixture.

6. The method of any one of claims 2-4, wherein adjusting comprises increasing the product hydrocarbon stream asphaltene content when the product hydrocarbon stream asphaltene content is less than the target asphaltene content by decreasing a normal alkane content of the hydrocarbon solvent mixture.

7. The method of any one of claims 2-6, wherein the target asphaltene content comprises a target asphaltene content range, and wherein adjusting comprises maintaining the product hydrocarbon stream asphaltene content within the target asphaltene content range.

8. The method of claim 7, wherein the product hydrocarbon stream includes a hydrocarbon solvent fraction, formed from the hydrocarbon solvent mixture, and a bituminous hydrocarbon fraction, formed from the bituminous hydrocarbon deposit, and wherein the target asphaltene content range is 1-30 weight percent of the bituminous hydrocarbon fraction.

9. The method of claim 8, wherein the threshold asphaltene content is at least 2 weight percent of the bituminous hydrocarbon fraction.

10. The method of any one of claims 8-9, wherein adjusting comprises maintaining a bituminous hydrocarbon fraction asphaltene content of the bituminous hydrocarbon fraction above the threshold asphaltene content.

11. The method of any one of claims 2-6, wherein the product hydrocarbon stream includes a hydrocarbon solvent fraction, formed from the hydrocarbon solvent mixture, and a bituminous hydrocarbon fraction, formed from the bituminous hydrocarbon deposit, and wherein, subsequent to producing the product hydrocarbon stream, the method further comprises separating the hydrocarbon solvent fraction from the bituminous hydrocarbon fraction.

12. The method of claim 11, wherein injecting the hydrocarbon solvent mixture includes injecting the hydrocarbon solvent fraction as a portion of the hydrocarbon solvent mixture.

13. The method of any one of claims 11-12, wherein adjusting comprises regulating a hydrocarbon solvent fraction composition of the hydrocarbon solvent fraction by regulating separating the hydrocarbon solvent fraction from the bituminous hydrocarbon fraction.

14. The method of any one of claims 2-13, wherein adjusting comprises adjusting to produce 2-98 weight percent of the asphaltenes while producing the product hydrocarbon stream.

15. The method of any one of claims 2-14, wherein adjusting comprises adjusting to deposit 2-98 weight percent of the asphaltenes within the subterranean formation while producing the product hydrocarbon stream.

16. The method of any one of claims 2-15, wherein adjusting comprises maintaining a threshold fluid permeability within the subterranean formation.

17. The method of any one of claims 2-16, wherein the product hydrocarbon stream includes a contaminant, and wherein adjusting comprises maintaining a concentration of the contaminant below a threshold level.

18. The method of claim 17, wherein the contaminant includes at least one of a heavy metal, vanadium, nickel, a nitrogen heteroatom, and a sulfur heteroatom.

19. The method of any one of claims 2-18, wherein the product hydrocarbon stream has a density, and wherein adjusting comprises maintaining the density within a target density range.

20. The method of any one of claims 2-19, wherein the product hydrocarbon stream has a viscosity, and wherein adjusting comprises maintaining the viscosity within a target viscosity range.

21. The method of any one of claims 2-20, further comprising repeatedly injecting the hydrocarbon solvent mixture, producing the product hydrocarbon stream, determining the product hydrocarbon stream asphaltene content, comparing the product hydrocarbon stream asphaltene content, and adjusting the hydrocarbon solvent mixture composition.

22. The method of claim 21, wherein producing the product hydrocarbon stream comprises substantially continuously producing the product hydrocarbon stream during a production interval, and wherein the method further comprises maintaining the product hydrocarbon stream asphaltene content near the target asphaltene content by periodically repeating the repeating during the production interval.

23. The method of any one of claims 1-22, wherein, prior to producing the product hydrocarbon stream, the bituminous hydrocarbon deposit defines an initial hydrocarbon mass, and wherein the target asphaltene content for the product hydrocarbon stream is based on a desired fraction of the initial hydrocarbon mass to be produced from the subterranean formation.

24. The method of claim 23, wherein the desired fraction is based on a market value of the product hydrocarbon stream as a function of the asphaltene content of the product hydrocarbon stream.

25. The method of any one of claims 1-24, wherein determining the bituminous hydrocarbon deposit composition comprises measuring the bituminous hydrocarbon deposit composition.

26. The method of claim 25, wherein measuring comprises performing a measurement on a sample of the bituminous hydrocarbon deposit.

27. The method of claim 26, wherein the measuring further comprises performing a crude assay on the sample.

28. The method of any one of claims 26-27, wherein the measuring further comprises obtaining a gas chromatograph of the sample.

29. The method of any one of claims 1-28, wherein determining the bituminous hydrocarbon deposit composition comprises obtaining the bituminous hydrocarbon deposit composition.

30. The method of claim 29, wherein obtaining the bituminous hydrocarbon deposit composition comprises utilizing a tabulated composition of the bituminous hydrocarbon deposit.

31. The method of any one of claims 1-30, wherein selecting the hydrocarbon solvent mixture composition comprises selecting such that the average molecular carbon content of the hydrocarbon solvent mixture is one of at least 3.5, at least 4.0, and between 3.5 and 9.

32. The method of any one of claims 1-31, wherein selecting the hydrocarbon solvent mixture composition comprises selecting the hydrocarbon solvent mixture composition such that the hydrocarbon solvent mixture includes:

a first fraction comprising a first compound with at least five carbon atoms, wherein the first fraction comprises at least 10 mole percent of the hydrocarbon solvent mixture; and (ii) a second fraction comprising a second compound with at least six carbon atoms, wherein the second fraction comprises at least 10 mole percent of the hydrocarbon solvent mixture.

33. The method of any one of claims 1-32, wherein selecting the hydrocarbon solvent mixture composition further comprises selecting based on a desired temperature within the solvent extraction chamber.

34. The method of claim 33, wherein the desired temperature is based on a desired production rate of the product hydrocarbon stream.

35. The method of any one of claims 33-34, wherein selecting the hydrocarbon solvent mixture composition comprises increasing the average molecular carbon content to increase the desired temperature.

36. The method of any one of claims 33-35, wherein selecting the hydrocarbon solvent mixture composition comprises decreasing the average molecular carbon content to decrease the desired temperature.

37. The method of any one of claims 1-36, wherein selecting the hydrocarbon solvent mixture composition comprises selecting based on a desired pressure within the solvent extraction chamber.

38. The method of claim 37, wherein selecting the hydrocarbon solvent mixture composition comprises increasing the average molecular carbon content responsive to a decrease in the desired pressure.

39. The method of any one of claims 37-38, wherein selecting the hydrocarbon solvent mixture composition comprises decreasing the average molecular carbon content responsive to an increase in the desired pressure.

40. The method of any one of claims 37-39, wherein the desired pressure is based on a threshold maximum pressure of the subterranean formation.

41. The method of claim 40, wherein the desired pressure is less than 90%
of the threshold maximum pressure.

42. The method of any one of claims 1-41, wherein injecting the hydrocarbon solvent mixture comprises injecting the hydrocarbon solvent mixture into an injection well extending within the solvent extraction chamber.

43. The method of claim 42, wherein producing the product hydrocarbon stream comprises producing the product hydrocarbon stream from a production well extending within the subterranean formation.

44. The method of claim 43, wherein the production well is spaced apart from the injection well.

45. The method of any one of claims 43-44, wherein the production well is vertically deeper than the injection well within the subterranean formation.

46. The method of any one of claims 1-45, wherein determining the product hydrocarbon stream asphaltene content includes indirectly determining the product hydrocarbon stream asphaltene content.

47. The method of claim 46, wherein indirectly determining the product hydrocarbon stream asphaltene content comprises measuring a density of the product hydrocarbon stream.

48. The method of any one of claims 46-47, wherein indirectly determining the product hydrocarbon stream asphaltene content comprises measuring a viscosity of the product hydrocarbon stream.

49. The method of any one of claims 1-48, wherein determining the product hydrocarbon stream asphaltene content includes performing a crude assay on a sample of the product hydrocarbon stream.

50. The method of any one of claims 1-49, wherein determining the product hydrocarbon stream asphaltene content includes obtaining a gas chromatograph of a sample of the product hydrocarbon stream.

51. The method of any one of claims 1-50, wherein determining the product hydrocarbon stream asphaltene content includes performing an ASTM standard asphaltene test.

52. The method of any one of claims 1-51, wherein injecting comprises injecting at an injection temperature and an injection pressure, wherein the injection temperature is a saturation temperature for the hydrocarbon solvent mixture at the injection pressure, and wherein the hydrocarbon solvent mixture is a vaporous hydrocarbon solvent mixture.

53. A method of selecting a hydrocarbon solvent mixture composition of a hydrocarbon solvent mixture for injection into a subterranean formation at an injection pressure to produce a product hydrocarbon stream from the subterranean formation via a solvent-based recovery process, wherein the subterranean formation includes a bituminous hydrocarbon deposit that includes asphaltenes, and wherein the product hydrocarbon stream is generated via combination of the hydrocarbon solvent mixture and the bituminous hydrocarbon deposit within a solvent extraction chamber that extends within the subterranean formation, the method comprising:
determining a threshold maximum pressure of the subterranean formation;
determining a stream temperature at which the hydrocarbon solvent mixture is to be injected into the subterranean formation;
determining a target asphaltene content for the product hydrocarbon stream;
and selecting the hydrocarbon solvent mixture composition based on the stream temperature, the threshold maximum pressure, and the target asphaltene content, wherein the hydrocarbon solvent mixture includes hydrocarbon molecules that define an average molecular carbon content.

54. The method of claim 53, further comprising increasing the average molecular carbon content to increase the stream temperature.

55. The method of any one of claims 53-54, further comprising decreasing the average molecular carbon content to decrease the stream temperature.

56. The method of any one of claims 53-55, further comprising increasing the average molecular carbon content to decrease the injection pressure.

57. The method of any one of claims 53-56, further comprising decreasing the average molecular carbon content to increase the injection pressure.

58. The method of any one of claims 53-57, further comprising increasing the average molecular carbon content to increase the target asphaltene content.

59. The method of any one of claims 53-58, further comprising decreasing the average molecular carbon content to decrease the target asphaltene content.

60. The method of any one of claims 53-59, wherein selecting the hydrocarbon solvent mixture composition comprises selecting such that the average molecular carbon content is at least 3.5.

61. The method of any one of claims 53-60, further comprising injecting the hydrocarbon solvent mixture into the solvent extraction chamber.