CA2856460C

CA2856460C - Methods and apparatuses for obtaining a heavy oil product from a mixture

Info

Publication number: CA2856460C
Application number: CA2856460A
Authority: CA
Inventors: Rahman Khaledi; Thomas J. Boone; Larry M. Dittaro; Wenqiang Han
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2014-07-10
Filing date: 2014-07-10
Publication date: 2017-05-16
Anticipated expiration: 2034-07-10
Also published as: CA2962274C; CA2962274A1; CA2856460A1

Abstract

Methods and apparatus for obtaining a heavy oil product from a mixture of a first solvent and heavy oil. If the heavy oil product is to contain asphaltenes, the method includes forming a treated mixture by treating the mixture to prevent substantial precipitation of heavy end components; and producing a recovered solvent and the heavy oil product by separating a portion of the solvent from the treated mixture. If the heavy oil product is to have a lower quantity of asphaltenes than the asphaltenes in the mixture, the method includes forming a treated mixture containing asphaltenes by treating the mixture to cause precipitation of asphaltenes; providing separated asphaltenes and a separated treated mixture by separating the asphaltenes from the treated mixture; and producing a recovered solvent and the heavy oil product by separating a portion of the solvent from the separated treated mixture.

Description

METHODS AND APPARATUSES FOR OBTAINING A HEAVY OIL
PRODUCT FROM A MIXTURE
FIELD
[0001] The present disclosure relates to methods and apparatus for obtaining a heavy oil product from a mixture recovered from a subterranean reservoir.
BACKGROUND

[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.

[0005] Several methods have been developed to recover heavy oil from, for example, oil sands. Strip or surface mining may be performed to access oil sands. Once accessed, the oil sands may be treated with hot water to extract the heavy oil. For subterranean reservoirs where heavy oil is not close to the Earth's surface, heat may be added and/or dilution may be used to reduce the viscosity of the heavy oil and recover the heavy oil within the subterranean reservoir. Heat may be supplied through a heating agent like steam. The heat may be injected into the subterranean reservoir via an injection well or wellbore. If the heating agent is steam, the steam may be condensed to water at the steam/cooler-oil-sands interface in the subterranean reservoir and supply latent heat of condensation to heat the heavy oil in the oil sands, thereby reducing viscosity of the heavy oil and causing the heavy oil to flow more easily.
The heavy oil recovered from the subterranean reservoir may or may not be produced via a production well or wellbore. The production well or wellbore may be the same well or wellbore as the injection well or wellbore.

[0006] Cold and/or heated solvents (e.g., propane or higher alkanes) may be injected into the subterranean reservoir either alone or in combination with steam to decrease the viscosity of heavy oil. The solvent injected may dilute the heavy oil, and/or transfer thermal energy to the heavy oil, thereby reducing the viscosity of the heavy oil. As with a recovery process employing steam, when solvents are used for the recovery of heavy oil, heavy oil having a reduced viscosity may flow downwards to a well for recovery of the heavy oil through the well. The heavy oil whose viscosity has been reduced by a solvent or a steam and solvent combination may have a greater reduction in viscosity than a heavy oil whose viscosity has been reduced by steam alone under substantially similar conditions within the subterranean reservoir. Processes using solvent to at least assist in reducing the viscosity of the heavy oil may be referred to as solvent-based recovery processes.

[0007] Canadian Patent Nos. 2,633,061 and 2,299,790 disclose variations of a method of recovering heavy oil that involve heating a solvent to vapor under pressure until a condensation temperature of the solvent vapor is above a naturally-occurring temperature in a subterranean reservoir. The solvent vapor is then injected, under pressure, into the subterranean reservoir where the solvent vapor may condense. The latent heat of condensation, together with warm solvent, reduces the viscosity of the heavy oil in the subterranean reservoir while precipitating out asphaltenes from the heavy oil. This reduced-viscosity blend of heavy oil and solvent is then recovered from the subterranean reservoir.

[0008] Canadian Patent No. 2,769,356 discloses a method using a pentane and/or hexane solvent. When the solvent is produced as part of a blend of heavy oil and solvent, the solvent is allowed to remain within the blend of heavy oil and solvent to enhance subsequent blend treating and transportation steps.

[0009] Canadian Patent No. 2,349,234 discloses a process in which a solvent is injected into a subterranean reservoir at a pressure. The pressure is above that which allows the solvent to vaporize. The pressure is also sufficient to cause geomechanical formation dilation or pore fluid compression in the subterranean reservoir. After allowing the solvent to mix with the heavy oil in the subterranean reservoir, the pressure in the subterranean reservoir is reduced to produce solvent vapor and drive the diluted heavy oil from the subterranean reservoir.

[0010] Heavy oil may include heavy end components and light end components. The heavy end components may comprise a heavy viscous liquid or solid made up of heavy hydrocarbon molecules, such as C30+ molecules. The heavy viscous liquid may be composed of C30+ 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. The presence of heavy end components within mixtures of heavy oil and solvent produced by a solvent-based recovery process can cause handling problems at surface facilities above the subterranean reservoir.

[0011] The heavy end components can separate or precipitate from a mixture of the solvent and heavy oil at certain temperatures and at certain heavy oil to solvent ratios. The precipitation or separation of the heavy end components from the mixture may result in blockage of equipment at the surface region.

(0012) Asphaltenes contain heavy metal compounds that may be harmful to catalysts (e.g., catalyst poisoning) used in heavy oil upgrading processes. A heavy oil product having some or all asphaltenes removed may not require severe and costly heavy oil upgrading (e.g., cocking, heavy oil fluid catalytic cracking, etc.). A heavy oil product having some or all asphaltenes removed may be refined using less costly processes (e.g., hydro cracking, catalytic cracking, etc.). Consequently, it may be desirable to remove some or all of the heavy end components, like asphaltenes, from the heavy oil to produce a heavy oil product.

[0013] It may be desirable to remove some or all of the solvents from the mixture of solvent and heavy oil to produce the heavy oil product. The solvents can cause separation, precipitation or viscosity effects of the heavy end components in the heavy oil, thereby making handling and treatment of the heavy oil product at a surface facility difficult. It may be desirable to remove solvent when producing the heavy oil product at, for example, a refining facility.

[0014] It may be desirable to transport the heavy oil product by pipeline to, for example but not limited to, a refinery. The heavy oil product having some or all of the asphaltenes removed may have a reduced viscosity making it suitable for transportation by pipeline. Heavy oil products containing no or only small amounts of asphaltenes may be easier to transport by pipeline because of their lower viscosities and reduced tendencies to precipitate asphaltenes in pipeline equipment.

[0015] It may be desirable to provide a heavy oil product that contains at least some of the heavy end components while still making the heavy oil product suitable for transportation by pipeline. The heavy oil product containing at least some of the heavy end components may be made suitable for transportation by pipeline by, for example, adding solvent or retaining some or all of the solvent from the mixture of heavy oil and solvent in the heavy oil product to reduce a viscosity of the heavy oil product. If, for example, there is no facility or procedure that can process asphaltenes, which are precipitates, at a production site, it may be desirable to transport the asphaltenes with other heavy end components to a site with facilities that perform such processes.

[0016] In view of the above, there is a need to provide methods and apparatuses for obtaining a heavy oil product from a mixture recovered from the subterranean reservoir using a solvent-based recovery process where, for example, the handling and treatment of the mixture to produce the heavy oil product is improved.
SUMMARY

[0017] The present disclosure provides apparatuses and methods for treatment of heavy oil and solvent mixtures, among other things.

[0018] A method of obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered from a subterranean reservoir may comprise forming a treated mixture by treating the mixture to prevent substantial precipitation of heavy end components of the heavy oil from the mixture, and producing a recovered solvent and the heavy oil product by separating a portion of the first solvent from the treated mixture.

[0019] A method of obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered from a subterranean reservoir may comprise forming a treated mixture containing asphaltene precipitates by treating the mixture, wherein treating the mixture comprises precipitating asphaltenes in the heavy oil from the mixture;
providing separated asphaltenes and a separated treated mixture by separating the asphaltene precipitates from the treated mixture; and producing a recovered solvent and the heavy oil product by separating a portion of the first solvent from the separated treated mixture. The heavy oil product may have a lower content of asphaltenes than the asphaltenes in the mixture.

[0020] An apparatus for obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered from a subterranean reservoir may comprise a treating apparatus configured to receive and treat the mixture to prevent substantial precipitation of heavy end components of the heavy oil from the mixture; and a solvent separation apparatus in fluid communication with the treating apparatus that is configured to separate out a portion of the first solvent to produce a separated first solvent, the heavy oil product, and a water product.

[0021] An apparatus for obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered from a subterranean reservoir may comprise a treating apparatus configured to receive and treat the mixture to cause precipitation of asphaltenes of the heavy oil from the mixture to form a treated mixture containing asphaltene precipitates; an asphaltene separation apparatus in fluid communication with the treating apparatus that is configured to receive the treated mixture and separate the asphaltenes precipitates from the treated mixture to provide separated asphaltenes and a separated treated mixture; and a solvent separation apparatus in fluid communication with the asphaltene separation apparatus that is configured to receive the separated treated mixture and separate a portion of the first solvent from the separated treated mixture to produce a separated first solvent, the heavy oil product, and a water product. The heavy oil product may have a lower content of asphaltenes than the asphaltenes in the mixture.
In one particular embodiment the invention provides a method of obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered from a subterranean reservoir, the method comprising: drilling an injection well and a production well through a subterranean reservoir; vaporizing a first solvent; injecting the first solvent into the subterranean reservoir via the injection well; recovering a mixture of the first solvent and heavy oil recovered from the subterranean reservoir; forming a treated mixture by treating the mixture to prevent substantial precipitation of heavy end components of the heavy oil from the mixture; and producing a recovered solvent and the heavy oil product by separating a portion of the first solvent from the treated mixture; wherein the heavy oil product is obtained from a solvent-based in-situ recovery process.
In another particular embodiment the invention provides an apparatus for obtaining a mixture of a first solvent and heavy oil from a subterranean reservoir and obtaining a heavy oil product from the mixture, the apparatus comprising: an injection well; a production well in fluid connection with the injection well through a subterranean reservoir; a first solvent vaporizer for vaporizing the first solvent; an injectant supply system for injecting the first solvent into the injection well; a production well in fluid connection with the injection well through a subterranean reservoir for recovering the mixture of the first solvent and heavy oil recovered from a subterranean reservoir; a treating apparatus configured to receive and treat the mixture to prevent substantial precipitation of heavy end components of the heavy oil from the mixture; and a solvent separation apparatus in fluid communication with the treating apparatus that is configured to separate out a portion of the first solvent to produce a separated first solvent, the heavy oil product, and a water product.

[0022] 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

[0023] 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.

[0024] FIG. 1 is a drawing of a system that may be used for implementing a solvent-based recovery process used for recovering heavy oil from a subterranean reservoir;

[0025] FIG. 2 is an illustration of deposited asphaltene fraction versus temperature for a plurality of mixtures of heavy oil and solvent having various specified concentrations of the solvent n-heptane;

[0026] FIG. 3 is an illustration of deposited asphaltene fraction for mixtures of heavy oil and different solvents, each mixture having a concentration of solvent of 70 weight (wt.) % at different temperatures;

[0027] FIG. 4 is a drawing of an apparatus for treating a mixture of heavy oil and solvent;

[0028] FIG. 5 is an illustration of an asphaltene precipitation phase diagram for a mixture of Athabasca bitumen and a solvent;
6a

[0029] FIG. 6 is a drawing of an apparatus for treating a mixture of heavy oil and solvent;

[0030] FIG. 7 is a flow diagram illustrating a method according to the present disclosure;
and

[0031] FIG. 8 is a flow diagram illustrating a method according to the present disclosure.

[0032] It should be noted that the figures are merely examples and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for the purpose of convenience and clarity in illustrating various aspects of the disclosure.
DETAILED DESCRIPTION

[0033] 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.

[0034] 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.

[0035] 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.

[0036] "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);
30 wt.% aromatics (which can range from 15 wt.% - 50 wt.%, or higher);
32 wt.% resins (which can range from 15 wt.% - 50 wt.%, or higher); and some amount of sulfur (which can range in excess of 7 wt.%).
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. The term "heavy oil" includes bitumen, as well as lighter materials that may be found in a sand or carbonate reservoir.

[0037] "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.

[0038] "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.

[0039] "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.

[0040] 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, 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.

[0041] Two locations in a subterranean reservoir are in "fluid communication" when a path for fluid flow exists between the two locations. For example, fluid communication exists between an injection well and a production well when mobilized material can flow down to the production well from the injection well for collection and production.

[0042] "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.

[0043] "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.

[0044] A "subterranean reservoir" is a subsurface rock or sand reservoir from which a production fluid, or resource, can be harvested. The rock 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.

[0045] "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.

[0046] "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 extraction process (SEP), thermal solvent extraction processes (TSEP), and any other such recovery process employing solvents either alone or in s 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.

[0047] "Substantial" when used in reference to a quantity or amount of a material, or a specific characteristic of the material, refers 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.

[0048] 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.

[0049] An "injectant supply system" may be a surface facility used to supply an injectant to a well located in the subterranean reservoir. The injectant may include a vapor comprising steam, solvent or a combination of steam and solvent, of or a gas, such as, for example, a non-condensable gas. The injectant supply system may be provided with the injectant, which is then vaporized. The vapor may be provided to a well for injection into the subterranean reservoir.

[0050] "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).

[0051] "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.

[0052] A "vapor chamber" is a region of a subterranean reservoir containing heavy oil that forms around a well that is injecting vapor into the subterranean reservoir. The vapor chamber has a temperature and a pressure that is generally at or close to a temperature and pressure of the vapor injected into the subterranean reservoir. The vapor chamber may form when heavy oil has, due to heat from the vapor and 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 vapor, thus forming the vapor 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.

[0053] 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.

[0054] 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.

[0055] "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.

[0056] Any of the ranges disclosed may include any number within and/or bounded by the range given.

[0057] As an example of a solvent-based recovery process, reference is made to Figure 1.
FIG. 1 illustrates a system 10 that may be used for implementing the solvent-based recovery process for recovering heavy oil from a subterranean reservoir. The solvent-based recovery process illustrated in Fig. 1 is a solvent-extraction process (SEP). The system 10 may include an injection well 30 and a production well 70 that extend between a surface region 20 and a subterranean reservoir 24 that is present within a subsurface region 22.

[0058] The injection well 30 may be vertically and then horizontally drilled through the subterranean reservoir 24. The production well 70 may be drilled vertically and then horizontally through the subterranean reservoir 24. A horizontal section of the production well 70 may lie below a horizontal section of the injection well 30. The injection well 30 and the production well 70 may be drilled from the same pad at the surface region 20 or from a different pad at the surface region 20. The surface region 20 may be a surface of the subterranean reservoir 24. Drilling the injection well 30 and the production well 70 from the same pad may make it easier for the production well 70 to track (i.e., follow a similar path of) the injection well 30. The injection well 30 and the production well 70 may be vertically separated by a suitable distance, such as about 3 to 10 meters (m). The injection well 30 and the production well 70 may be vertically separated by the aforementioned amounts in the horizontal and/or vertical sections of the respective injection well 30 and production well 70.
Any of the aforementioned ranges may be within a range that includes or is bounded by any of the preceding examples.

[0059] The injection well 30 may be in fluid communication with an injectant supply system 40 for providing a solvent 44 to the injection well 30. The injectant supply system 40 may provide the solvent 44 from any suitable source (e.g., a storage structure 42). The solvent 44 may be supplied to a vaporization assembly 50 to generate a vapor 52. The vapor 52 may be provided to the injection well 30. The vapor 52 may be injected into the subterranean reservoir 24 at a predetermined temperature and pressure.

[0060] The vapor 52 may mobilize heavy oil in the subterranean reservoir 24. The heavy oil may drain down to the injection well 30 and/or the production well 70 and form a vapor chamber 60. The vapor 52 may have a temperature higher than an initial temperature in the subterranean reservoir 24. In the case of the Athabasca Oil Sands in Canada, the initial temperature in the subterranean reservoir is about 8 Celsius ( C), but the initial temperature in the subterranean reservoir may differ from one subterranean reservoir to another. For example, the vapor 52 may have a temperature of at least 30 C, but no more than about 250 C. The temperature may be any number within or bounded by the preceding range

[0061] The vapor 52 may condense upon injection into the subterranean reservoir 24, releasing latent heat of condensation and transferring heat to the subterranean reservoir 24 and/or generating a condensate 54. When the vapor 52 is injected into the subterranean reservoir 24 via the injection well 30, the vapor 52 may decrease in temperature (or lose thermal energy) while being conveyed through the injection well 30 to the subterranean reservoir 24. The vapor 52 may decrease in temperature while being conveyed through the subterranean reservoir 24 from the injection well 30 to an interface 62 between the vapor chamber 60 and heavy oil 26 that is not within the vapor chamber 60. If the vapor 52 is a single component vapor stream, the vapor 52 may be superheated prior to being injected into the subterranean reservoir 24. A portion of the vapor 52 may condense prior to reaching the interface 62.

[0062] Condensation of the vapor 52 may heat the heavy oil 26 within the subterranean reservoir 24. Heating the heavy oil may decrease a viscosity of the heavy oil 26 and increase flowability of the heavy oil under gravity. The vapor 52 and/or condensate 54 may combine with, mix with, be dissolved in, dissolve, and/or dilute the heavy oil 26, thereby further decreasing the viscosity of the heavy oil 26. An energy/heat transfer between the vapor 52 and the heavy oil 26 and/or the mixing of the vapor 52 with the heavy oil 26 may generate a mixture 74 of the heavy oil 26 having a reduced viscosity and a solvent. The mixture may flow to the production well 70 and/or the injection well 30.

[0063] The vapor 52 may be injected into the subterranean reservoir 24 at a pressure that is below a threshold maximum pressure of the subterranean reservoir 24.
Threshold maximum pressures may include, for example, a characteristic pressure of the subterranean reservoir. The characteristic pressure may be a fracture pressure of the subterranean reservoir, a hydrostatic pressure within the subterranean reservoir, a lithostatic pressure within the subterranean reservoir, a gas cap pressure for a gas cap that is present within the subterranean reservoir, and/or an aquifer pressure for an aquifer that is located above and/or under the subterranean reservoir. The threshold maximum pressure may be related to and/or based upon the characteristic pressure of the subterranean reservoir. Injection of the vapor 52 at a pressure that is below the threshold maximum pressure of the subterranean reservoir 24 may prevent (or at least reduce) damage to the subterranean reservoir 24 and a reservoir matrix of the subterranean reservoir 24. Injection of the vapor 52 at a pressure that is below the threshold maximum pressure may prevent or reduce escape of the vapor 52 from the subterranean reservoir 24.

[0064] A composition of the solvent 44 may be selected such that a dew point temperature of the vapor 52 and a bubble point temperature of the mixture 74 of the heavy oil and the solvent differ by at least a temperature difference. Illustrative, non-exclusive examples of the temperature difference include temperature differences between 10 C
and 100 C
inclusive. The temperature difference may be any number within or bounded by the preceding range.

[0065] The solvents used in the solvent-based recovery process may be, for example, hydrocarbons. The solvent may be a single hydrocarbon or a mixture of hydrocarbons of various molecular weights. Compounds with a larger number of carbon atoms (e.g., greater than or equal to 20 carbon atoms) may exhibit a lower vapor pressure at a given temperature when compared to compounds with less carbon atoms. Injecting the vapor stream 52 that is formed from a solvent 44, having a higher number of carbon atoms, may permit the vapor 52 to be injected at a lower pressure for a given temperature when compared to injection of solvent having a smaller number of carbon atoms.

[0066] The solvent 44 may be obtained from any suitable source. As illustrative, non-exclusive examples, the solvent 44 may be obtained from a gas plant condensate and/or a crude oil refinery naphtha cut.

[0067] The mixture 74 may be produced from the subterranean reservoir 24 by at least one of the injection well 30 and the production well 70. The mixture 74 of the heavy oil and solvent 44 may be pumped by at least one of the injection well 30 and the production well 70 so that the mixture 74 emerges at the surface region 20 as a product stream 72. The product stream 72 may include the mixture 74 of the heavy oil and the solvent as well as light hydrocarbon gases. Light hydrocarbon gases may include hydrocarbon and/or carbon compounds with four or fewer carbon atoms, such as methane, ethane, propane and/or butane. Light hydrocarbon gases may include any number of carbon atoms included or bounded within the preceding range. Light hydrocarbon gases may emerge from the production well 70 separately in the form of casing gases.

[0068] The injection well 30 may comprise injection wells. The production well 70 may comprise production wells. If the production well 70 comprises production wells, the product stream 72 from the production wells may be combined and then sent to a surface facility. If the production well 70 comprises a single well, the product stream 72 from the production well 70 may be sent to the surface facility.

[0069] The mixture 74 of the heavy oil and the solvent may encounter difficulties at the surface region 20 if the mixture 74 contains heavy end components, particularly asphaltenes, such as those previously discussed. Processing of the mixture of the heavy oil and the solvent into a heavy oil product may depend on an intended product of the recovery process. For example, it may be desirable to produce a heavy oil product from the mixture with the heavy oil product having the asphaltenes, and possibly other heavy end components, removed or substantially reduced in concentration. It may be desirable to transport a heavy oil product that contains the heavy end components, including asphaltenes. It may be desirable to include a solvent with the heavy oil product to reduce a viscosity of the heavy oil product to a level suitable for transport of the heavy oil product by pipeline.

[0070] The mixture of the solvent (i.e., first solvent) and heavy oil may be treated in two alternative ways, i.e. for partial or complete asphaltene removal or for heavy end component retention.

[0071] The present disclosure may include methods and apparatus for obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered/produced from a subterranean reservoir. Figs. 4 and 6 illustrate exemplary apparatuses 400 and 600. Figs. 7 and 8 illustrate exemplary flow diagrams of methods.

[0072] The mixture may comprise a first solvent and heavy oil. The mixture may be, for example, a mixture of a first solvent and heavy oil as produced as a result of a solvent-based recovery process, such as those previously discussed. The mixture may have a relatively high concentration of the first solvent to heavy oil, such as, for example, at least 30 weight (wt.)% of the first solvent or more. The weight percent may include any number bounded by or included within the aforementioned range. The first solvent may be a solvent injected into the subterranean reservoir to reduce a viscosity of the heavy oil to enable the heavy oil to be produced/recovered from the subterranean reservoir.

[0073] The first solvent may be a single hydrocarbon having greater than or equal to three carbon atoms (C3). For example, the first solvent may be a mixture of at least two, and more usually, at least three, hydrocarbons having a number of carbon atoms from the range of Cl to C30+. There may be at least hydrocarbons in the range of C3 to C12 or higher in various amounts in the first solvent. The first solvent may contain light hydrocarbons having a low number of carbon atoms, such as Cl to C3. The light hydrocarbons have low molecular weights and are generally the most volatile of the hydrocarbons in the mixture. The amount of carbon atoms within the first solvent may include any number bounded by or included within the preceding range.

[0074] Cl and C2 hydrocarbons may not always be present in the first solvent. Heavier hydrocarbons may be absent or present in only small amounts in the first solvent. Heaver hydrocarbons may include any amount of carbon atoms that are greater than or equal to 30.

Hydrocarbons having any number of carbon atoms greater than 2 or less than 30, such as but not limited to C3 to C15 compounds and C3 to C12 compounds, may often be present in the first solvent. This range of carbon atoms may include any number within or bounded by the preceding range. The first solvent may include but is not limited to normal alkanes, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, or olefin hydrocarbons. The normal alkanes have the highest tendency of causing heavy end component separation with a decreasing tendency in heavy end component separation from iso-alkanes to naphthenic hydrocarbons to aromatic hydrocarbons. Aromatic hydrocarbons (e.g., benzene, toluene and xylene) may be good solvents for mixture with heavy oil containing asphaltenes. The first solvent may be a first alkane having a carbon atom number in a range of C3 to C12.

[0075] Hydrocarbon mixtures used for producing solvents, such as first solvents, may be obtained, for example, from petroleum and natural gas products by distillation (e.g., as gas plant condensates), petroleum associate gases, or as crude refinery distillates (e.g., raw naphtha fraction) from an refinery crude distillation units, catalytic reforming units, catalytic cracking units, thermal cracking units, steam cracking units, hydrocracking units, cokers, or from petrochemical plants (e.g., from olefin units, aromatic solvent units, etc.)

[0076] The heavy oil product and the mixture may have different amounts of first solvent. The heavy oil product may have less of the first solvent than is present in the mixture.
The heavy oil product may contain the first solvent and a second solvent.
There may be some loss of the heavy end components from the mixture during the removal of some of the first solvent from the mixture. As such, the heavy oil product may contain a slightly reduced amount of heavy end components compared to the mixture. The heavy oil product may retain as much of the heavy end components as possible to achieve benefits, such as those previously described.

[0077] FIG. 2 is an illustration of asphaltene precipitation from mixtures of Athabasca heavy oil and solvent according to temperature and solvent concentration. The solvent used in Fig. 2 is n-heptane. From Fig. 2, it may be seen that the asphaltene precipitation increases with increased solvent concentration and decreased temperature. The asphaltene precipitation varies with solvent type, as shown in FIG. 3, which shows asphaltene and heavy end precipitation for the solvents, propane (C3), n-butane (C4), n-pentane (C5), n-hexane (C6) and n-heptane (C7) under the same conditions of temperature (for different temperatures) and at a certain solvent concentration.

[0078] The solubility of heavy end components, particularly asphaltenes, in mixtures of heavy oil and solvents may be affected in the following ways:
(I) temperature adjustment ¨ lower temperatures may result in precipitation/separation;
(II) solvent concentration ¨ higher concentrations may result in precipitation/separation;
(III) solvent type ¨ some solvents are more likely to result in precipitation/separation than others;
(IV) molecular weight of solvent ¨for solvents of a particular type, solvents of lower molecular weight may be more likely to result in precipitation/separation.

[0079] Regarding temperature adjustment, mixtures of heavy oil and solvents produced by solvent-based recovery processes may be delivered to a surface of a subterranean reservoir at temperatures higher (e.g., close to an operating temperature of the solvent-based recovery process) than both a naturally occurring temperature in the subterranean reservoir (e.g., 5 to 12 Celsius ( C)) and an ambient temperature at a surface of the subterranean reservoir. The higher temperatures may maintain the heavy end components in solution or suspension in the mixture so that the heavy end components do not remain in the subterranean reservoir.
Cooling of the mixture at the surface of the subterranean reservoir may result in precipitation of the heavy end components, such as asphaltenes.

[0080] Regarding solvent concentration, as shown in FIG. 2 for a solvent that is an alkane, the use of higher concentrations of solvent in the mixture of heavy oil and solvent may result in precipitation of asphaltenes at higher temperatures. It is a feature of many solvent-based recovery processes that the mixtures of heavy oil and solvent having high concentrations of solvent (e.g., greater than or equal to 30 wt.%) are produced, so that asphaltene precipitation is often likely on cooling of the mixture at the surface of the subterranean reservoir. The high concentration of solvent may include any number included within or bounded by the preceding range.

[0081] Regarding solvent type, solvents that may be employed for solvent-based recovery processes include, but are not limited to:
= normal (linear) alkanes;
= iso-alkanes (branched);
= cyclic alkanes (naphthenic, saturated) = aromatic (cyclic, unsaturated) hydrocarbons; and = alkenes or olefins (unsaturated).

[0082] The solvent used may depend on factors such as overall suitability for solvent-based recovery processes (which may depend, for example, on the boiling point of the solvent), relative cost and availability compared to other solvents, etc. Alkane based solvents, also referred to as paraffinic solvents, are often used in solvent-based recovery processes because of their relatively low cost, generally suitable boiling range, and their ready availability at production sites (e.g., in the form of gas plant condensates.) The solvents may be single compounds or mixtures of two or more compounds that may be of the same type or of different types. The above discussion of solvent type may apply to all solvents used, including the first solvent and the second solvent.

[0083] Regarding molecular weight of the solvent, lighter solvents (e.g., C3 and C4) can cause higher asphaltene precipitation of both asphaltenes and other heavy end components.
Heavier solvents (e.g., C5 and heavier) generally only cause precipitation of asphaltenes. For example, Fig. 3 illustrates the change in asphaltene and heavy end components separation for different solvents at different temperatures.

[0084] Substantial precipitation of heavy end components from the mixture may be, for example, removing no more than 5 wt.% asphaltenes (of the total weight of the heavy oil) where the heavy oil contains 15-20 wt.% asphaltenes and possibly 50 wt.% heavy end components. The weight percent of asphaltenes and heavy oil components in the heavy oil may include any number within or bounded by the respective preceding ranges.

[0085] The method of obtaining the heavy oil product may comprise forming a treated mixture. The treated mixture may be formed by treating the mixture to prevent substantial precipitation of heavy end components of the heavy oil from the mixture, 702 (Figure 7). The mixture of the first solvent and heavy oil may be treated by heating the mixture to above a precipitation temperature of the mixture, reducing a concentration of the solvent to below a precipitation concentration, or adding a second solvent to the mixture.

[0086] The method of obtaining the heavy oil product may comprise producing a recovered solvent and the heavy oil product by separating a portion of the first solvent from the treated mixture, 704 (Figure 7). The heavy oil product may be a heavy oil product that retains all or at least substantially most of the heavy end components of the heavy oil from the mixture. The separation of the portion of the first solvent from the treated mixture may be a partial separation in which an amount of the first solvent is left in the heavy oil product to enable transportation of the heavy oil product by pipeline. The separation of the portion of the first solvent from the treated mixture may be a complete separation of the first solvent from the treated mixture to produce the heavy oil product. If the treated mixture contains the second solvent, then a portion of the second solvent may or may not be separated when the portion of the first solvent is separated.

[0087] The treated mixture may be separated into the heavy oil product, the recovered solvent and an aqueous phase consisting mainly of water carried from the subterranean reservoir by the mixture of the first solvent and heavy oil.

[0088] Virtually all of the first solvent may be removed from the treated mixture as solvent vapor or only part of the first solvent may be removed. If only part of the first solvent is removed, the non-vaporized portion of the first solvent that remains in the heavy oil product may reduce the viscosity of the heavy oil product to a level suitable for pipelining. The removal of some or all of the first solvent makes the heavy end components of the heavy oil less likely to precipitate or separate out, especially when the first solvent is alkane based, so that the heavy oil product may be allowed to cool to ambient temperature with a reduced risk of the heavy end components precipitating/separating from the heavy oil product. The portion of the first solvent removed as solvent vapor may be cooled, and then separated into a light gas such as methane and/or carbon dioxide (which may have originated within the subterranean reservoir), a recovered solvent, and an aqueous phase. The recovered solvent may be supplemented with fresh solvent heated and re-injected into the subterranean reservoir (e.g., via an injection well,) for further operation of the solvent-based recovery process. Recycling of the first solvent may reduce an overall cost of the solvent-based recovery process. The heavy oil product may contain heavy end components. The heavy oil product may contain a lower amount of the first solvent than the mixture. The heavy oil product may be transported by pipeline to a refinery or other treatment plant.

[0089] The mixture may be treated by heating the mixture to a temperature above a precipitation temperature of the mixture at which the heavy end components will precipitate from the mixture. The mixture may be heated to a temperature above a heavy end component precipitation/separation temperature for a first solvent present in the mixture. The mixture may be heated to a temperature above a heavy end component precipitation/separation temperature for the first solvent employed for the solvent-based recovery process that produced the mixture. The temperature may vary according to the type of the first solvent in the mixture and a concentration of the first solvent in the mixture. Heating of the mixture of the first solvent and heavy oil may be used to avoid, or at least reduce, separation of the heavy end components, particularly asphaltenes.

[0090] The mixture may not be heated when treated if the temperature of the mixture is unlikely to fall below the temperature at which precipitation/separation begins before the first solvent is separated from the mixture. For example, the mixture may not be heated if the mixture is one having a fairly low temperature at which precipitation/separation begins upon cooling, or if a distance to be travelled by the mixture before separation of the first solvent is fairly short thereby allowing little time for cooling, especially if insulated piping is employed for the transfer from the production well to a fractionation facility.

[0091] The mixture may be treated by reducing a concentration of the first solvent to below a precipitation concentration at which the heavy end components precipitate from the mixture. Reducing the concentration of the first solvent may comprise one of:
(a) partially evaporating the first solvent from the mixture to form the treated mixture, (b) passing the mixture through a membrane that is configured to allow only flow through of the first solvent, wherein the treated mixture comprises a portion of the mixture that does not pass through the membrane, and (c) introducing an extracting agent into the mixture that dissolves a part of the first solvent in the mixture to form a solution including the first solvent and the extracting agent, and separating the solution from the mixture to form the treated mixture.

[0092] FIG. 5 shows a solvent/asphaltene precipitation phase boundary as an example for describing a solvent and asphaltene precipitation. The dashed line 500 shows the precipitation boundary. Above this line in region 502, asphaltenes are precipitated, but below the line in region 504 there is no asphaltene precipitation. The mixture could be heated from a temperature at point "A" to a temperature at point 131" shown in FIG. 5, thus moving the mixture from the precipitation region 502 across the precipitation boundary to the non-precipitation region 504. The concentration of the solvent could be reduced to point "Cl", i.e.
from about 68 wt.% to about 10 wt.%, which would drive the mixture into the non-precipitation region 504 which would reduce the risk of heavy end component precipitation/separation within the heavy oil product.

[0093] The first solvent may be partially evaporated from the mixture to form the treated mixture. The first solvent may be partially evaporated using one of a single-stage flash unit, a multi-stage flash unit and a distillation apparatus. If the first solvent is volatile (e.g., a C3 to C5 alkane), passing the treated mixture through a single-stage flash unit employing heat to vaporize and remove some of the first solvent may result in greater solvent reduction than if the first solvent is of lower volatility, or if the first solvent contains compounds of lower volatility (e.g., C6+). If a higher degree of reduction is desired, and the first solvent in the mixture is of lower volatility, a multi-stage flash unit or a distillation apparatus may be used to partially evaporate the first solvent.

[0094] The mixture may be passed through the membrane that is configured to allow only flow through of the first solvent. The membrane may be a permeable membrane or a semi-permeable membrane. Passing the first solvent through the membrane may reduce the concentration of the first solvent. The membrane may contain pores large enough to allow molecules of the first solvent to pass through. The pores may be too small to allow molecules of the heavy oil and heavy end components to pass through. The first solvent may pass through the membrane under gravity or through an application of pressure against the mixture to push the first solvent through the membrane. The first solvent is thus separated from the mixture.
The mixture may be passed through the membrane with portions of the mixture that are withheld from passage (i.e., the mixture that does not pass) through the membrane forming the treated mixture.

[0095] The extracting agent may be introduced into the mixture to dissolve a part of the first solvent. The introduction of the extracting agent may help reduce the concentration of the first solvent. The extracting agent may be introduced to mixture in an extraction apparatus.
The extracting agent may be introduced into the mixture to selectively dissolve either a part of the first solvent or the heavy oil within itself, leaving the other component of the mixture (heavy oil or solvent, respectively) unextracted. The extracting agent and either dissolved solvent or dissolved heavy oil may then be separated from each other in a further column or vessel and re-used. The extracting agent may be a liquid that is an extraction solvent for one of the heavy oil and the first solvent of the mixture but that is immiscible with other component(s). The extracting agent may dissolve part of the first solvent to form the solution of the first solvent and the extracting agent. The solution may be separated from the mixture to form the treated mixture. For example, the solution may be separated from the mixture using distillation.

[0096] The mixture may be treated by adding a second solvent to the mixture. The heavy end components may be more soluble in the second solvent than in the first solvent.
Adding the second solvent may help prevent precipitation/separation of heavy end components. The second solvent may be less likely to cause precipitation of heavy end components at temperatures that may be encountered at the surface of the subterranean reservoir than the first solvent.

[0097] The second solvent may be any suitable solvent. Alkane-based solvents, such as n-butane, n-pentane, n-hexane, or n-heptane, are often used for solvent-based recovery processes in which the first solvent is injected into the subterranean reservoir as a vapor.
Alkane-based solvents have a tendency to allow the heavy end components to precipitate/separate out at the surface of the subterranean reservoir. The second solvent may be a different type (e.g., benzene, toluene or xylene) or of a different molecular weight (e.g., n-decane) than the first solvent. The second solvent may be a single hydrocarbon or a mixture of different hydrocarbons. For example, the second solvent may be similar to the first solvent but with hydrocarbon components having a different molecular weight from the hydrocarbons components of the first solvent. For example, the second solvent may have a higher molecular weight than the molecular weight of the first solvent. The second solvent may comprise a second solvent compound that is a homologue of a first solvent compound of the first solvent.
The first solvent may comprise a first alkane and the second solvent may comprise a second alkane. The second alkane may have a higher carbon atom number than a carbon atom number of the first alkane. For example, the carbon atom number of the first alkane may be in a range of C3 to C12, for example. The carbon atom number of the second solvent may be greater than or equal to C6 or any number included or bounded by this range.
The second solvent may be any solvent that improves the solubility of asphaltene (e.g., gas oil, heavy gas oil, synthetic crude oil, deasphalted bitumen, etc.). The second solvent may comprise a second solvent compound that is non-homologous to a first solvent compound of the first solvent. The first solvent may comprise a normal alkane. The second solvent may comprise at least one of normal alkanes, iso-alkanes, napthenic hydrocarbons, aromatic hydrocarbons and olefin hydrocarbons.

[0098] Once the second solvent has been added to the mixture, the likelihood of precipitation/separation of heavy end components may be reduced. The second solvent in the heavy oil product may reduce a viscosity of the heavy oil product so that the heavy oil product is more suitable for transport by pipeline despite containing heavy end components.

[0099] Separating the portion of the first solvent from the treated mixture may comprise one of: (i) evaporating the portion of the first solvent from the treated mixture to form the heavy oil product, (ii) passing the mixture through a membrane that is configured to allow only flow through of the first solvent, where the heavy oil product comprises a portion of the treated mixture that does not pass through the membrane; and (iii) introducing an extracting agent into the treated mixture that dissolves a part of the first solvent in the treated mixture to form a solution including the first solvent and the extracting agent, and separating the solution from the treated mixture to form the heavy oil product. The solvent that is separated from the treated mixture may be only the first solvent or, if a second solvent was used in treating the mixture, then either the first solvent or the second solvent or both may be separated from the treated mixture. Separating the portion of the first solvent from the treated mixture is separate from treating the mixture by reducing a concentration of the first solvent. Separating the portion of the first solvent and reducing the concentration of the first solvent may include many of the same processes. Separating the portion of the first solvent may attempt to remove a larger portion of the first solvent than reducing the concentration of the first solvent. If a second solvent is added, then separating the portion of the first solvent may or may not remove a portion of the second solvent with the removal of the first solvent.
The second solvent may not be in the mixture during reducing the concentration of the first solvent.

[00100] The portion of the first solvent may be separated from the treated mixture by evaporation in one of a single-stage flash unit, a multi-stage flash unit and a distillation apparatus. A larger amount of solvent will be separated from the treated mixture using a single-stage flash unit when the first solvent is volatile (e.g., a C3 to C5 alkane) than when the first solvent is of lower volatility. Removal of only a portion of the first solvent may be suitable if a sufficient amount of solvent is to remain in the heavy oil product to reduce a viscosity of the heavy oil product and enable transportation of the heavy oil product by pipeline. The sufficient amount of solvent in the heavy oil product to enable transportation of the heavy oil product by pipeline may be generally, for example, no more than 30 wt. % of the heavy oil product being solvent. If a higher degree of separation of the portion of the first solvent is desired, and the first solvent in the mixture is of lower volatility, a multi-stage flash unit or a distillation apparatus may be used. Evaporation to separate the portion of the first solvent may use a similar process to evaporation to reduce the concentration of the first solvent but may use different parameters, for example, time, etc.

[00101] When separating the portion of the first solvent, passing the treated mixture through the membrane may be a membrane as discussed above in connection with reducing a concentration of the first solvent in the mixture. Separating using the membrane may allow passage of more of the first solvent than when the mixture was treated. For example, separating using the membrane may differ from reducing the concentration of the first solvent by, for example, using a different membrane or different parameters such as a time of the separating process or a pressure that may be applied against the treated mixture

[00102] The extracting agent may be introduced to the treated mixture to separate the portion of the first solvent. The extracting agent may dissolve either the first solvent or the heavy oil leaving the other components (heavy oil or first solvent, respectively) unextracted.
The extracting agent and either the dissolved heavy oil or the dissolved first solvent may be separated from each other. The extracting agent may be the same as and/or different from the extracting agent discussed above in connection with reducing the concentration of the first solvent.

[00103] The portion of the solvent separated from the treated mixture may be treated and recycled to form recovered solvent. Treatment of separated solvent, may include, for example, treatment by a single stage flashing unit, a multi stage flashing unit or a distillation apparatus. The treatment of the separated solvent may, for example, involve separation of by-products such as light and heavy unwanted compounds, adjusting the composition of the solvent mixture, and possibly an aqueous phase from the separated solvent to provide the recovered solvent.

[00104] The method described above may be employed when it is desired to retain all or most of the heavy end components of the heavy oil in the heavy oil product.

[00105] The present disclosure may include an apparatus 400 for obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered from a subterranean reservoir.
The apparatus 400 may be employed in conjunction with the above method in which the heavy oil product retains most or all of the heavy end components of the heavy oil in the heavy oil product.

[00106] The apparatus 400 may comprise a treating apparatus configured to receive and treat the mixture 472 to prevent substantial precipitation of heavy end compounds of the heavy oil from the mixture 472. The treating apparatus in Figure 4 may comprise a heater 476.
The treating apparatus may or may not comprise a solvent separation apparatus, such as but not limited to the solvent separation apparatus 478 in Figure 4. The treating apparatus 476 may be a separate and distinct apparatus from the solvent separation apparatus 478. A
production well 470 in a subterranean reservoir produces the mixture 472 of the first solvent and heavy oil as a product stream that is passed through the treating apparatus. The treating apparatus may comprise the heater 476. The heater 476 may heat the mixture to prevent substantial precipitation of heavy end components of the heavy oil from the mixture 472. The heater 476 may raise the temperature of the mixture 472 above a precipitation/separation temperature of the mixture 472 by heat exchange with a heating fluid to form the treated mixture 420. The treating apparatus may comprise a reduction apparatus to reduce a concentration of the first solvent in the mixture. The treating apparatus may comprise, a single-stage flashing unit, a multi-stage flashing unit, and a distillation apparatus, each of which may be the reduction apparatus. The treating apparatus may comprise a membrane as previously discussed for the reduction apparatus. The treating apparatus may comprise an extracting agent apparatus (not shown) in which an extracting agent, as discussed above, may be introduced to the mixture to reduce a concentration of the first solvent in the mixture. The treating apparatus may comprise an apparatus to add a second solvent to the mixture 472. The treating apparatus may output a treated mixture.

[00107] The apparatus 400 may comprise a solvent separation apparatus 478 in fluid communication with the treating apparatus. The solvent separation apparatus 478 may be configured to separate out a portion of the first solvent to produce a separated first solvent 480, a heavy oil product 482, and a water product 484. When the solvent separation apparatus is not part of the treating apparatus, the solvent separation apparatus may receive the treated mixture from the treating apparatus.

[00108] The solvent separation apparatus 478 may separate a mixture (i.e., the mixture or the treated mixture) into the separated first solvent 480, the heavy oil product 482 and a water product 484. The water product 484 may consist entirely or mainly of water.
The solvent separation apparatus 478 may comprise at least one of a single-stage flashing unit, a multi-stage flashing unit, and a distillation apparatus. The solvent separation apparatus 478 may comprise a membrane as previously discussed for separating out the portion of the first solvent. The solvent separation apparatus 478 may comprise an extracting agent apparatus in which an extracting agent, as discussed above, may be introduced to the treated mixture 420.
The extracting agent apparatus (not shown) may be a single stage extraction vessel, multistage extraction vessels, or an extractive column into which the extracting agent can be introduced to the treated mixture 420.

[00109] A solvent treating apparatus 422 may be in fluid communication with the solvent separation apparatus 478. The solvent treating apparatus 422 may be configured to receive the separated first solvent and separate the separated first solvent into a recovered solvent 492 and by-products 494, 496. The solvent treating apparatus 422 is shown in Fig.
4 as a cooler 486 and a gas separator 490. The cooler 486 and the gas separator 490 may be replaced by a single-stage flashing unit, a multi-stage flashing unit or a distillation apparatus. The solvent treating apparatus 422 cleans up separated solvent for re-use while the solvent separation apparatus 478 separates solvent from the treated mixture.

[00110] The separated first solvent 480 may be combined with casing gas 488 issuing from a well casing of the production well 470. The combined flows of the separated first solvent 480 and the casing gas 488 are passed through a cooler 486 that, through heat exchange with a cool fluid, cool the separated first solvent 480 and the casing gas 488. The casing gas and separated first solvent may then be fed to a gas separator 490 that separates the casing gas and separated first solvent into the recovered solvent 496 and by-products. The by-products may include, for example, a light gas 492 (mainly methane and carbon dioxide from the subterranean reservoir) which may be removed from the apparatus 400 as a valuable by-product, and a water product 494. The water product 484 from the solvent separation apparatus 478 and the water product 494 from the gas separator 490 may be combined and removed for possible recycling or disposal.

[00111] The heavy oil product 482 from the solvent separation apparatus 478 may be removed for possible transportation via a pipeline (not shown). The recovered solvent 496 from the gas separator 490 may be mixed with fresh solvent 443 from a fresh-solvent storage structure 442 to make up for inevitable losses within the subterranean reservoir and/or amounts remaining in the heavy oil product 482. The mixed fresh solvent and recovered solvent may be fed to a vaporization assembly 450 for vaporization and injection into an injection well 430 via line 444.

[00112] The heavy oil product 482 may contain all of the heavy end components from the mixture of the heavy oil and the solvent with little or no solvent.
Alternatively, the heavy oil product 482 may contain sufficient solvent to reduce a viscosity of the heavy oil product 482 for transportation by pipeline. The amount of solvent remaining in the heavy oil product 482 may be determined by the characteristics and conditions of operation of the solvent separation apparatus 478.

[00113] The heater 476 may keep the heavy end components in the mixture 472 in solution or suspension at least until some or all of the first solvent can be removed by the solvent separation apparatus 478. The removal of some or all of the first solvent may reduce heavy end component precipitation, especially when the first solvent is one that increases the tendency of precipitation with increased concentration, e.g. lower alkanes such as C3 to C7.

[00114] The apparatus 400 may remove most or all of the solvent from the mixture 472 while producing a transportable heavy oil product containing the heavy end components, with a reduced risk of premature heavy end component precipitation.

[00115] Corresponding points "A", "E31" and "Cl from Fig. 5 are shown on the apparatus 400 of FIG. 4.

[00116] Another method of the present disclosure may be a method of obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered from a subterranean reservoir. The heavy oil product obtained in this method may have a reduced content of asphaltenes. Details of the mixture of the first solvent and heavy oil may be the same as those previously described and may be produced by the previously described solvent-based recovered processes. The method may be employed when it is desired to remove a portion of the asphaltenes from the heavy oil in the heavy oil product. The first solvent may be a solvent as previously described that is injected into the subterranean reservoir to reduce a viscosity of the heavy oil to enable the heavy oil to be produced from the subterranean reservoir during a solvent-based recovery process as previously described. The heavy oil product and the mixture of the first solvent and heavy oil may differ in concentrations of the solvent, the solvents contained in the mixture versus the heavy oil product and/or the amount of asphaltenes contained in the mixture versus in the heavy oil product.

[00117] A treated mixture containing asphaltene precipitates may be formed by treating the mixture of the first solvent and heavy oil, 802 (Figure 8). Treating the mixture may comprise precipitating at least some asphaltenes in the heavy oil from the mixture. The mixture may be treated, for example, by cooling the mixture to below a precipitation temperature, such as is illustrated in Fig. 5 by points "A" to "B2", or adding a second solvent to the mixture so that a concentration of the first solvent and the second solvent in the mixture is above a precipitation concentration. The extent of precipitation may depend, for example, on a concentration of the first solvent and the second solvent.

[00118] Separated asphaltenes and a separated treated mixture may be provided by separating the asphaltene precipitates from the treated mixture, 804 (Figure 8).

[00119] A recovered solvent and the heavy oil product may be produced by separating a portion of the first solvent from the separated treated mixture, 806 (Figure 8). The separation of the portion of the first solvent from the separated treated mixture may be a partial separation in which a sufficient amount of the first solvent is left in the heavy oil product to enable transportation of the heavy oil product by pipeline. The separation of the portion of the first solvent from the separated treated mixture may be a complete separation of the first solvent from the separated treated mixture to produce the heavy oil product.

[00120] The removal of some or all of the asphaltenes from the mixture and then the removal of some or all of the first solvent may reduce further precipitation of the asphaltenes within the heavy oil product. The removal of some or all of the asphaltenes provides a heavy oil product that may be more desirable to heavy oil refiners and/or may be a lower viscosity than a heavy oil containing all of the light end components and the heavy end components. The heavy oil product having the reduced content of asphaltenes may be suitable for transport by pipeline with little or no solvent remaining in the heavy oil product

[00121] An illustration of this method is also provided by the graph of FIG. 5. The mixture shown at point "A" is moved to point "B2" by the initial precipitation/separation of the asphaltenes, i.e. the mixture is moved further into the asphaltene precipitation region 502. The removal of the precipitated/separated asphaltenes and subsequent removal of some or all of the solvent by heating moves the heavy oil product to point "C2", i.e., into the non-asphaltene precipitation region 504 so that further asphaltene precipitation may no longer be a concern.

[00122] The mixture may be treated by one of: (i) cooling the mixture to a temperature below a precipitation temperature at which asphaltenes begin to precipitate from the mixture;
and (ii) adding a second solvent to the mixture so that a concentration of the first solvent and the second solvent together in the mixture is above a precipitation concentration at which asphaltenes precipitate from the mixture.

[00123] Higher concentrations of solvent may increase the tendency of the asphaltenes to precipitate/separate, especially when an alkane is used as the first solvent.
The second solvent may be the same as the first solvent used for the solvent-based recovery process and therefore already present in the mixture. The second solvent may be a different solvent from the first solvent. If the second solvent is a different solvent, the second solvent may be a solvent of the same type or of a different type from the first solvent. If the first solvent and the second solvent are of the same type (e.g., different members of the group alkanes), the second solvent may be a solvent of lower molecular weight since solvents of lower molecular weight have an increased tendency to cause asphaltene precipitation. Thus, for example, if the first solvent in the mixture is n-heptane, the second solvent added at the surface of the subterranean reservoir may be n-hexane or n-pentane. If the second solvent is of a different type, the second solvent may be one having an increased tendency to cause asphaltene precipitation/separation versus the first solvent in the mixture. For example, if the first solvent in the mixture is an iso-alkane (branched alkane), the second solvent may be an n-alkane (linear alkane) of the same number of carbon atoms or fewer.

[00124] The second solvent may comprise a second solvent compound that is a homologue of a first solvent compound of the first solvent. The second solvent and the first solvent may comprise at least one compound selected from the group consisting of a normal alkane, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and olefin hydrocarbons. The first solvent may comprise a first alkane and the second solvent may comprise a second alkane. The second alkane may have a lower carbon atom number than a carbon atom number of the first alkane. For example, the carbon atom number of the first alkane and the second alkane may be in a range of C2 to C12 inclusive. This range of carbon atoms may include any number within or bounded by the preceding range.
Alternatively, the second solvent may comprise a second solvent compound that is non-homologous to a first solvent compound of the first solvent. The first solvent may comprise at least one of iso-alkanes, napthenic hydrocarbons, aromatic hydrocarbons and olefin hydrocarbons. The second solvent may comprise a normal alkane.

[00125] The asphaltene precipitates may be separated from the treated mixture by settling the asphaltene precipitates from the mixture by an action of gravity and removing the treated mixture from the settled precipitates. For example, the treated mixture may be placed in a vessel where the precipitates can settle under the action of the gravity to the bottom of the vessel. Water may be present in the mixture. The water may form a layer below the treated mixture that is removed from the treated mixture together with the asphaltene precipitates.

[00126] The portion of the first solvent that is separated from the separated treated mixture may be separated by one of: (i) evaporating the portion of the first solvent from the separated treated mixture to form the heavy oil product, (ii) passing the mixture through a membrane that is configured to allow only flow through of the first solvent, wherein the heavy oil product comprises a portion of the separated treated mixture that does not pass through the membrane; and (iii) introducing an extracting agent into the separated treated mixture that dissolves a part of the first solvent in the separated treated mixture to form a solution including the first solvent and the extracting agent, and separating the solution from the separated treated mixture to form the heavy oil product. Separation of the portion of the first solvent from the separated treated mixture may be performed by the same process as separating of the portion of the first solvent from the treated mixture as previously described.

[00127] The first solvent that has been separated from the separated treated mixture, 806 (Figure 8) may be treated and recycled to form recovered solvent.
Treatment of separated first solvent, which is the first solvent that has been separated from the separated treated mixture while separating the portion of the first solvent, may include, for example, treating by a single stage flashing unit, a multi stage flashing unit or a distillation apparatus. The treatment - of the separated solvent may, for example, involve separation of by-products such as light gas and heavy unwanted compounds, adjusting the composition of the solvent mixture, and possibly an aqueous phase from the separated solvent to provide the recovered solvent.

[00128] The present disclosure may include an apparatus for obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered from a subterranean reservoir. The heavy oil product obtained by this apparatus may have a lower content of asphaltenes. This apparatus may be employed in conjunction with the method in which the heavy oil product having a lower content of asphaltenes is employed.

[00129] An apparatus 600 (Figure 6) for obtaining the heavy oil product may comprise a treating apparatus 624 configured to receive and treat the mixture 672 to cause precipitation of at least some asphaltenes of the heavy oil from the mixture to form a treated mixture containing asphaltene precipitates. The treating apparatus may comprise a combiner 620 for combining the mixture 672 with a second solvent 674 and/or a cooler 675. One or both of the combiner 620 and the cooler 675 may be present in the treating apparatus 624.

[00130] A production well 670 produces a mixture 672 of the first solvent and heavy oil as a product stream that may be mixed with a second solvent 674. The second solvent 674 may be in excess of solvent required to cause precipitation of asphaltenes from the mixture. The mixture 672 with the added second solvent 674 is passed through a cooler 675 where cooling is effected by heat exchange with a cooler fluid. The cooler 675 producing the treated mixture 622. As shown in Fig. 5, cooling the mixture moves the mixture from "A" to 132", which is beyond the precipitation boundary. As can be seen in Fig. 5, an increase in concentration of the solvent (not shown) would also move the mixture to well above the precipitation boundary where precipitation of the asphaltenes would occur above the precipitation boundary.

[00131] The apparatus 600 may comprise an asphaltene separation apparatus 677 in fluid communication with the treating apparatus 624 to receive the treated mixture 622. The asphaltene separation apparatus 677 may be configured to separate the asphaltene precipitates from the treated mixture 622 to provide separated asphaltenes 679 and a separated treated mixture 681.

. [00132] The treated mixture 622 may be transferred to the asphaltene separation apparatus 677. Asphaltene precipitates may settle from the treated mixture 622 while in the asphaltene separation apparatus 677. The settled asphaltene precipitates may be removed in an asphaltene mixture 679 together with a water product containing mainly water produced from the subterranean reservoir. The treated mixture from which the asphaltene mixture 679 may have been separated may form a separated treated mixture (or a lower asphaltene content heavy oil and solvent mixture) 681.
[00133] The asphaltene mixture 679 may be delivered to an asphalt separation unit 683.
The asphalt separation unit 683 may separate the asphaltene mixture 679 into a water product 684 and asphalt 685. The asphalt 685 may be removed from the apparatus 600.
The asphalt 685 may be used as a saleable product, e.g. for road construction.
[00134] The apparatus 600 may comprise a solvent separation apparatus 628 in fluid communication with the asphaltene separation apparatus 677 to receive the separated treated mixture. The solvent separation apparatus 628 may be configured to separate a portion of the first solvent from the separated treated mixture 681 to produce a separated first solvent 680 and the heavy oil product 682 having the lower content of asphaltenes. The solvent separation apparatus 628 may include a solvent separator 678 possibly with a heater 676.
The solvent separator 678 may comprise at least one of a single-stage flashing unit, a multi-stage flashing unit, a distillation apparatus, the membrane as previously described, and an extracting agent apparatus in which an extracting agent may be introduced to the treated mixture, the extracting agent dissolving a part of the solvent in the treated mixture.
[00135] The separated treated mixture 681 remaining after the asphaltene separation is passed from the asphaltene separator 677 to a heater 676, where the separated treated mixture 681 may be heated by heat exchange with a heated fluid. The heated separated treated mixture may be passed to a solvent separator 678 that separates the heated separated treated mixture into a separated first solvent 680 and a heavy oil product 682 which may consequently contain little or no solvent. The heavy oil product 682 may have a lower amount of solvent according to the type of apparatus used for the solvent separator 678 and the conditions employed for the separation. The heavy oil product 682 may be transported via = pipeline with a reduced risk of further precipitation of asphaltenes or other heavy end components of the heavy oil from the heavy oil product.
[00136] The apparatus 600 for obtaining the heavy oil product may comprise a solvent treating apparatus 630 in fluid communication with the solvent separation apparatus 628 to receive the separated first solvent for separating the separated first solvent 680 into a recovered solvent 696 and by-products 692, 694. The solvent treating apparatus 630, shown as a cooler 686 and a gas/solvent separator 690 may be replaced by at least one of a single-stage flashing unit, a multi-stage flashing unit, and a distillation apparatus.
[00137] The separated first solvent 680 from the solvent separator 678 may be mixed with casing gas 688 (e.g., mainly methane and carbon dioxide) from a casing of the production well 670. The mixed solvent vapor and casing gas may be passed through a cooler 686 before being delivered to a gas/solvent separator 690. The gas/solvent separator 690 separates the mixed solvent vapor and casing gas from the cooler 686 into a recovered solvent 696 and by-products such as a light gas component 692, and a water product 694. The light gas component 692 is a potentially valuable product that may be removed from the apparatus 600 and used as a fuel or sold. The aqueous component 694 may be mixed with the water product 684 from the asphalt separation unit 683 and removed from the apparatus 600 for recycling or disposal. The recovered solvent 696 from the gas separator 690 may be mixed with fresh solvent 643 added from a storage structure 642 to make up for inevitable losses within the reservoir and/or amounts remaining in the heavy oil product 682. The recovered and fresh solvent mixture is delivered to a vaporization assembly 650 to convert it to a vapor for injection into an injection well 631 for further operation of the solvent-based recovery process within the subterranean reservoir.
[00138] FIG. 6 shows points "A", "B2" and "C2" corresponding to those shown on FIG. 5.
[00139] While detailed information has been provided above, it will be understood that numerous changes, modifications, and alternatives to the preceding description can be made and the scope of the claims should not be limited to the preferred and exemplified embodiments set forth. The scope of the claims should be given the broadest interpretation consistent with the description as a whole. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other in any effective manner.

Claims

What is claimed is:

1. A method of obtaining a heavy oil product from a mixture of a first solvent and heavy oil recovered from a subterranean reservoir, the method comprising:
drilling an injection well and a production well through a subterranean reservoir;
vaporizing a first solvent;
injecting the first solvent into the subterranean reservoir via the injection well;
recovering a mixture of the first solvent and heavy oil recovered from the subterranean reservoir;
forming a treated mixture by treating the mixture to prevent substantial precipitation of heavy end components of the heavy oil from the mixture; and producing a recovered solvent and the heavy oil product by separating a portion of the first solvent from the treated mixture;
wherein the heavy oil product is obtained from a solvent-based in-situ recovery process.

2. The method of claim 1, wherein treating the mixture comprises one of: (i) heating the mixture to a temperature above a precipitation temperature of the mixture at which the heavy end components precipitate from the mixture, (ii) reducing a concentration of the first solvent to below a precipitation concentration at which the heavy end components precipitate from the mixture, and (iii) adding a second solvent to the mixture, and wherein the heavy end components are more soluble in the second solvent than the first solvent.

3. The method of claim 2, wherein reducing the concentration comprises one of: (a) partially evaporating the first solvent from the mixture to form the treated mixture, (b) passing the mixture through a membrane that is configured to allow only flow through of the first solvent, wherein the treated mixture comprises a portion of the mixture that does not pass through the membrane, and (c) introducing an extracting agent into the mixture that dissolves a part of the first solvent in the mixture to form a solution including the first solvent and the extracting agent, and separating the solution from the mixture to form the treated mixture.

4. The method of claim 2, wherein the second solvent has a higher molecular weight than the first solvent.

5. The method of claim 4, wherein a second solvent compound of the second solvent is a homologue of a first solvent compound of the first solvent.

6. The method of claim 5, wherein the first solvent comprises a first alkane and the second solvent comprises a second alkane, and wherein the second alkane has a higher carbon atom number than a carbon atom number of the first alkane.

7. The method of claim 6, wherein the carbon atom number of the first alkane is in a range of C3 to C12.

8. The method of any one of claims 6 to 7, wherein the carbon atom number of the second solvent is in a range of C6 to C30+.

9. The method of any one of claims 2 to 4, wherein the second solvent comprises a second solvent compound that is non-homologous to a first solvent compound of the first solvent.

10. The method of claim 9, where the first solvent comprises a normal alkane, and the second solvent comprises at least one compound selected from the group consisting of a normal alkane, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and olefin hydrocarbons.

11. The method of any one of claims 1 to 10, wherein separating the portion of the first solvent from the treated mixture comprises one of: (i) evaporating the portion of the first solvent from the treated mixture to form the heavy oil product, (ii) passing the mixture through a membrane that is configured to allow only flow through of the first solvent, wherein the heavy oil product comprises a portion of the treated mixture that does not pass through the membrane; and (iii) introducing an extracting agent into the treated mixture that dissolves a part of the first solvent in the treated mixture to form a solution including the first solvent and the extracting agent, and separating the solution from the treated mixture to form the heavy oil product.

12. An apparatus for obtaining a mixture of a first solvent and heavy oil from a subterranean reservoir and obtaining a heavy oil product from the mixture, the apparatus comprising:
an injection well;
a production well in fluid connection with the injection well through a subterranean reservoir;
a first solvent vaporizer for vaporizing the first solvent;
an injectant supply system for injecting the first solvent into the injection well;
a production well in fluid connection with the injection well through a subterranean reservoir for recovering the mixture of the first solvent and heavy oil recovered from a subterranean reservoir;
a treating apparatus configured to receive and treat the mixture to prevent substantial precipitation of heavy end components of the heavy oil from the mixture; and a solvent separation apparatus in fluid communication with the treating apparatus that is configured to separate out a portion of the first solvent to produce a separated first solvent, the heavy oil product, and a water product.

13. The apparatus of claim 12, wherein the treating apparatus comprises the solvent separation apparatus.