CA3026716C

CA3026716C - Processing of produced fluids from a subterannean formation in a near-azeotropic injection process

Info

Publication number: CA3026716C
Application number: CA3026716A
Authority: CA
Inventors: Hamed R. Motahhari; Rahman Khaledi
Original assignee: Imperial Oil Resources Ltd
Current assignee: Imperial Oil Resources Ltd
Priority date: 2017-12-18
Filing date: 2018-12-06
Publication date: 2020-05-26
Anticipated expiration: 2038-12-06
Also published as: CA3026716A1

Abstract

The present disclosure relates to production of oil from a subterranean reservoir in a near-azeotropic solvent-based oil recovery process and processing of related process fluids, wherein products from a production well associated with the subterranean reservoir are processed, a heavy oil product stream is produced, and a near-azeotropic solvent mixture is produced and utilized in the reservoir injection mixture for injection into the near-azeotropic solvent- based oil recovery process.

Description

PROCESSING OF PRODUCED FLUIDS FROM A SUBTERANNEAN FORMATION IN
A NEAR-AZEOTROPIC INJECTION PROCESS
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. Provisional Patent Application 62/607,073 filed 18 December 2017 entitled PROCESSING OF PRODUCED FLUIDS FROM A
SUBTERRANEAN FORMATION IN A NEAR-AZEOTROPIC INJECTION PROCESS, U.S.
Provisional Patent Application 62/607,077 filed 18 December 2017 entitled PROCESSING OF
PRODUCED FLUIDS FROM A SUBTERRANEAN FORMATION IN A NEAR-AZEOTROPIC
INJECTION PROCESS and U.S. Provisional Patent Application 62/607,081 filed 18 December 2017 entitled PROCESSING OF PRODUCED FLUIDS FROM A SUBTERRANEAN
FORMATION IN A NEAR-AZEOTROPIC INJECTION PROCESS.
BACKGROUND
Field of Disclosure

[0002] The present disclosure relates to production of oil from a subterranean reservoir in a near-azeotropic solvent-based oil recovery process and processing of related process fluids.
Description of Related Art

[0003] 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.

[0004] 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.

[0005] Easily produced sources of hydrocarbons are dwindling, leaving less conventional sources to satisfy future needs. As the costs of hydrocarbons increase, less conventional sources become more economical. One example of less conventional sources becoming more economical is that of oil sand production. The hydrocarbons produced from less conventional sources may have relatively high viscosities, for example, ranging from 1000 centipoise (cP) to 20 million cP
with American Petroleum Institute (API) densities ranging from 8 degree ( ) API, or lower, up to 20 API, or higher. The hydrocarbons recovered from less conventional sources may include heavy oil. However, the hydrocarbons produced from the less conventional sources may be difficult to recover using conventional techniques. For example, the heavy oil may be sufficiently viscous that economical production of the heavy oil from a subterranean formation (also referred to as a "subterranean reservoir" herein) is precluded.

[0006] Several conventional recovery processes, such as but not limited to thermal recovery processes, have been utilized to decrease the viscosity of the heavy oil.
Decreasing the viscosity of the heavy oil may decrease a resistance of the heavy oil to flow and/or permit production of the heavy oil from the subterranean reservoir by piping, flowing, and/or pumping the heavy oil from the subterranean reservoir. While each of these recovery processes may be effective under certain conditions, each possess inherent limitations.

[0007] One of the conventional recovery processes utilizes steam injection. The steam injection may be utilized to heat the heavy oil to decrease the viscosity of the heavy oil. Water and/or steam may represent an effective heat transfer medium, but the pressure required to produce saturated steam at a desired temperature may limit the applicability of steam injection to high pressure operation and/or require a large amount of energy to heat the steam.

[0008] Another of the conventional recovery processes utilizes cold and/or heated solvents.
Cold and/or heated solvents may be injected into a subterranean reservoir as liquids and/or vapors to decrease the viscosity of heavy oil present within the subterranean reservoir. Solvent-based recovery processes may include, but are not limited to, solvent assisted cyclic steam stimulation (SA-CSS), solvent assisted steam assisted gravity drainage (SA-SAGD), solvent assisted steam flood (SA-SF), vapor extraction process (VAPEX), heated vapor extraction process (H-VAPEX), cyclic solvent process (CSP), heated cyclic solvent process (H-CSP), solvent flooding, heated solvent flooding, liquid extraction process, heated liquid extraction process, solvent-based extraction recovery process (SEP), thermal solvent-based extraction recovery processes (TSEP), and any other such recovery process employing solvents either alone or in combination with steam.
In particular is also a near-azeotropic heated VAPEX (AH-VAPEX) as described in Patent No.
CA 2,915,571 C to Boone et al., wherein a process is described for injecting steam and a vaporized hydrocarbon solvent as near-azeotropic conditions to improve the overall recovery process cost, efficiencies, and/or hydrocarbon recovery.

[0009] However, the AH-VAPEX process described only includes the conditions under which the steam and the vaporized hydrocarbon solvent should be injected to improve the overall recovery processes in a subterranean reservoir. A need exists in the industry for improved technology, including technology for methods and other process required for further improvement of the AH-VAPEX process, including, but not limited to, recovery, processing and re-use of fluids recovered from produced heavy oil stream resulting from the AH-VAPEX process.
SUMMARY

[0010] It is an object of the present disclosure to provide improved systems and methods for the efficient and cost effective operation of near-azeotropic heated VAPEX (AH-VAPEX) processes.

[0011] In a preferred embodiment herein is a method for the processing of the produced fluids by AH-VAPEX process in a main processing facility to obtain a heavy oil product and to generate near-azeotropic vapor injection mixture. In this processing facilities embodiment, the azeotropic evaporation phenomena is utilized to separate the produced water and solvent compounds from the production mixture. Hence, the produced water and hydrocarbons are generally processed together in the main processing facility prior to preparation of the near-azeotropic vapor injection mixture.

[0012] In a preferred embodiment herein is a method for recovering viscous hydrocarbons from a subterranean reservoir, the method comprising:
a) drilling at least one well pair in a subterranean reservoir, wherein the well pair is comprised of an injection well and a production well, and the injection well is located at an elevation above the production well within the subterranean reservoir;

b) injecting a near-azeotropic reservoir injection mixture comprising steam and a solvent mixture into the subterranean reservoir via the injection well, wherein the first near-azeotropic reservoir injection mixture is injected in the vapor phase;
c) producing a reservoir product stream comprising a reduced-viscosity hydrocarbons, water, and a condensate; wherein the condensate comprises at least a portion of the solvent mixture;
d) sending at least a portion of the reservoir product stream to a primary separation unit, and producing a primary water stream, a primary gas vapor stream, and a primary hydrocarbon phase stream;
e) sending at least a portion of the primary hydrocarbon phase stream to a solvent separation unit; and producing a solvent vapor stream, and a heavy oil product stream;
0 sending at least a portion of the primary water stream to a water treatment unit and producing a treated water stream;
g) sending at least a portion of the solvent vapor stream to a gas separation unit, and producing an off gas stream and a recovered solvent stream; and h) vaporizing at least a portion of the recovered solvent stream and at least a portion of the treated water stream in at least one vapor generation unit;
wherein the near-azeotropic reservoir injection mixture comprises at least a portion of the recovered solvent stream and at least a portion of the treated water stream.

[0013] In another preferred embodiment herein is a method for recovering viscous hydrocarbons from a subterranean reservoir, the method comprising:
a) drilling at least one well pair in a subterranean reservoir, wherein the well pair is comprised of an injection well and a production well, and the injection well is located at an elevation above the production well within the subterranean reservoir;
b) injecting a near-azeotropic reservoir injection mixture comprising steam and a solvent mixture into the subterranean reservoir via the injection well, wherein the near-azeotropic reservoir injection mixture is injected in the vapor phase;

c) producing a reservoir product stream comprising a reduced-viscosity hydrocarbons, water, and a condensate; wherein the condensate comprises at least a portion of the solvent mixture;
d) optionally adding a primary make-up solvent stream, a primary make-up water stream or a combination thereof to the reservoir product stream to produce a primary separation unit feedstream;
e) sending at least a portion of the primary separation unit feedstream to a primary separation unit, and producing a primary water stream, a primary gas vapor stream, and a heavy oil product stream;
0 sending at least a portion of the primary gas vapor stream to a gas separation unit; and producing a recovered solvent/water stream and an off gas stream;
g) optionally adding a final make-up solvent stream, a final make-up water stream or a combination thereof to the recovered solvent/water stream to produce a final tailored reservoir solvent/water mixture, wherein a hydrocarbon solvent and water in the final tailored reservoir solvent/water mixture is compositionally at a near-azeotropic mixture at the subterranean reservoir operating conditions; and h) vaporizing at least a portion of the final tailored reservoir solvent/water mixture in at least one vapor generation unit;
wherein the near-azeotropic reservoir injection mixture comprises at least a portion of the vaporized final tailored reservoir solvent/water mixture.

[0014] In yet another preferred embodiment herein is a method for recovering viscous hydrocarbons from a subterranean reservoir, the method comprising:
a) drilling at least one well pair in a subterranean reservoir, wherein the well pair is comprised of an injection well and a production well, and the injection well is located at an elevation above the production well within the subterranean reservoir;
b) injecting a near-azeotropic reservoir injection mixture comprising steam and a solvent mixture into the subterranean reservoir via the injection well, wherein the near-azeotropic reservoir injection mixture is injected in the vapor phase;

c) producing a reservoir product stream comprising a reduced-viscosity hydrocarbons, water, and a condensate; wherein the condensate comprises at least a portion of the solvent mixture;
d) sending at least a portion of the reservoir product stream to a primary separation unit, and producing a primary water stream, a primary vapor stream, and a primary hydrocarbon phase stream;
e) sending at least a portion of the primary hydrocarbon phase stream to a solvent separation unit; and producing a solvent vapor stream, and a heavy oil product stream;
0 sending at least a portion of the primary vapor stream and at least a portion of the solvent vapor stream to a primary gas separation unit;
g) sending at least a portion of the primary water stream to the primary gas separation unit;
h) producing a primary gas separation vapor stream and a primary gas separation liquid stream from the primary gas separation unit;
i) sending at least a portion of the primary gas separation liquid stream to a secondary gas separation unit;
j) sending at least a portion of the primary gas separation gas stream to a tertiary gas separation unit;
k) producing an off gas stream and a recovered solvent/water stream from the tertiary gas separation unit;
1) optionally adding a final make-up solvent stream, a final make-up water stream, or a combination thereof to the recovered solvent/water stream to form a final tailored reservoir solvent/water mixture; wherein the solvent and water in the final tailored reservoir solvent/water mixture are at a near-azeotropic mixture; and m) vaporizing the final tailored reservoir solvent/water mixture in at least one vapor generation unit;
wherein the near-azeotropic reservoir injection mixture comprises at least a portion of the vaporized final tailored reservoir solvent/water mixture.

[0015] 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

[0016] 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.

[0017] Figure 1 is a simplified schematic representation of an example of a well system that may be utilized in an AH-VAPEX process for in-situ heavy oil recovery.

[0018] Figure 2 illustrates the collective dew point curves of vapor mixtures of n-alkanes solvents with water at 1.5 MPa pressure.

[0019] Figure 3 is a simplified illustration of an AH-VAPEX main processing facility according to an embodiment of the systems and processes disclosed herein.

[0020] Figure 4 is a simplified illustration of an AH-VAPEX main processing facility according to an embodiment of the systems and processes disclosed herein.

[0021] Figure 5 is a simplified illustration of an AH-VAPEX main processing facility according to an embodiment of the systems and processes disclosed herein.
DETAILED DESCRIPTION

[0022] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein, are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.

[0023] At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication of issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.

[0024] A "hydrocarbon" is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. However, the techniques described herein are not limited to heavy oils, but may also be used with any number of other subterranean reservoirs. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.

[0025] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.)% aliphatics (which can range from 5 wt.% - 30 wt.%, or higher);
19 wt.% asphaltenes (which can range from 5 wt.% - 30 wt.%, or higher);
wt.% aromatics (which can range from 15 wt.% - 50 wt.%, or higher);
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.%).
100261 The percentage of the hydrocarbon types found in bitumen can vary.
In addition 25 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.

[0027] The term "heavy oil" includes bitumen, as well as lighter materials that may be found in a sand or carbonate reservoir. "Heavy oil" includes oils that are classified by the American Petroleum Institute (API), as heavy oils, extra heavy oils, or bitumens. Thus the term "heavy oil"
includes bitumen. Heavy oil may have a viscosity of about 1000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more or 1,000,000 cP or more. In general, a heavy oil has an API
gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 gams 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 10.00 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.
[0028] The term "asphaltenes" or "asphaltene content" refers to pentane insolubles (or the amount of pentane insoluble in a sample) according to ASTM D3279. Other examples of standard ASTM asphaltene tests include ASTM test numbers D4055, D6560, and D7061.
[0029] "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.
[0030] "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.
[0031] A "fluid" includes a gas or a liquid and may include, for example, a produced or native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold water, or a mixture of these among other materials. "Vapor" refers to steam, wet steam, and mixtures of steam and wet steam, any of which could possibly be used with a solvent and other substances, and any material in the vapor phase.
[00321 "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.
[0033] "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.

[0034] A "subterranean reservoir" or "subterranean formation" is a subsurface rock or sand reservoir from which a production fluid, or resource, can be harvested. A
subterranean reservoir may interchangeably be referred to as a subterranean formation. The subterranean formation may include sand, granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy oil (e.g., bitumen), oil, gas, or coal, among others. Subterranean reservoirs can vary in thickness from less than one foot (0.3048 meters (m)) to hundreds of feet (hundreds of meters).
The resource is generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.
[0035] "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.
100361 "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), near-azeotropic heated vapor extraction process (AH-VAPEX), cyclic solvent process (CSP), heated cyclic solvent process (H-CSP), solvent flooding, heated solvent flooding, liquid extraction process, heated liquid extraction process, solvent-based extraction recovery process (SEP), thermal solvent-based extraction recovery processes (TSEP), and any other such recovery process employing solvents either alone or in combination with steam.
A solvent-based recovery process may be a thermal recovery process if the solvent is heated prior to injection into the subterranean reservoir. The solvent-based recovery process may employ gravity drainage.

[0037] "Azeotrope" or "Azeotropic" (or similar), as used herein, means the thermodynamic azeotrope of a mixture when the mixture is a two (2) component mixture of water (steam) and a single component solvent at a specified pressure. When the solvent is a multi-component solvent mixture, the terms "Azeotrope" or "Azeotropic" (or similar), as used herein, means the minimum boiling point (at a specified pressure) of water (steam) and the multi-component solvent mixture.
The term "Near-Azeotropic" (or similar), as used herein, means within a certain range (as specified in its individual context where utilized) of the azeotrope point as defined herein.
[0038] 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 to shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. The term "well," when referring to an opening in the formation or reservoir, may be used interchangeably with the term "wellbore." Further, multiple pipes may be inserted into a single wellbore, for example, as a liner configured to allow flow from an outer chamber to an inner chamber.
[0039] "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).
[0040] "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.
[0041] A "solvent extraction chamber" is a region of a subterranean reservoir containing heavy oil that forms around a well that is injecting solvent into the subterranean reservoir. The solvent extraction chamber has a temperature and a pressure that is generally at or close to a temperature and pressure of the solvent injected into the subterranean reservoir. The solvent extraction chamber may form when heavy oil has, due to heat from the solvent, dissolution within the solvent, combination with the solvent, and/or the action of gravity, at least partially mobilized through the pore spaces of the reservoir matrix. The mobilized heavy oil may be at least partially replaced in the pore spaces by solvent, thus forming the solvent chamber. The solvent chamber may contain liquid solvent, vapor solvent, condensed solvent, residual heavy oil, water, gas, non-condensable gas and/or a combination and/or mixture of them. In practice, layers in the subterranean reservoir containing heavy oil may not necessarily have pore spaces that contain 100 percent (/0) 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.
[0042] A "vapor chamber" is a solvent extraction chamber that includes a vapor, or vaporous solvent. The vapor chamber may contain other gases including vapor water, and/or non-condensable gases. The vapor chamber may also contain vapor mixtures of water and solvent. The vapor chamber may also contain near-azeotropic or azeotropic vapor mixtures of water and solvent. Thus, when the solvent is injected into the subterranean reservoir as a vapor, a vapor chamber may be formed around the well.
[0043] A "compound that has five or more carbon atoms" or "C5+"may include any suitable single chemical species that may include five or more carbon atoms. A
"compound that has five or more carbon atoms" also may include any suitable mixture of chemical species. Each of the chemical species in the mixture of chemical species may include five or more carbon atoms and each of the chemical species in the mixture of chemical species also may include the same number of carbon atoms as the other chemical species in the mixture of chemical species. For example, a compound that has five carbon atoms may include a pentane, n-pentane, a branched pentane, cyclopentane, a pentene, n-pentene, a branched pentene, cyclopentene, a pentyne, n-pentyne, a branched pentyne, cyclopentyne, methylbutane, dimethylpropane, ethylpropane, and/or any other hydrocarbon with five carbon atoms. A compound with six carbon atoms, seven carbon atoms, or eight carbon atoms may include a single chemical species with six carbon atoms, seven carbon atoms, or eight carbon atoms, respectively, and/or may include a mixture of chemical species that each include six carbon atoms, seven carbon atoms, or eight carbon atoms, respectively.
[0044] The terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure. These terms when used in reference to a quantity or amount of a material, or a specific characteristic of the material, refer to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.
[0045] 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.
[0046] As used herein, the phrase "at least one," in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one"
refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at least one of A and/or B") may refer, to at least one, optionally including more than one, A, with no B
present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A
present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases "at least one," "one or more," and "and/or" are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C," "at least one of A, B, or C," "one or more of A, B, and C," "one or more of A, B, or C" and "A, B, and/or C" may mean A alone, B
alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.
[0047] As used herein, the term "and/or" placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity.
Multiple entities listed with "and/or" should be construed in the same manner, i.e., "one or more"

of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the "and/or" clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to "A
and/or B," when used in conjunction with open-ended language such as "comprising" may refer to A
only (optionally including entities other than B); to B only (optionally including entities other than A); to both A
and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.
[0048] As used herein the terms "adapted" and "configured" mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms "adapted" and "configured" should not be construed to mean that a given element, component, or other subject matter is simply "capable of" performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function.
It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.
[0049] As used herein, the phrase, "for example," the phrase, "as an example," and/or simply the term "example," when used with reference to one or more components, features, details, structures, embodiments, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, embodiment, and/or method is an illustrative, non-exclusive example of components, features, details, structures, embodiments, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, embodiment, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, embodiments, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, embodiments, and/or methods, are also within the scope of the present disclosure. Any of the ranges disclosed may include any number within and/or bounded by the range given.
[0050] In the illustrative figures herein, in general, elements that are likely to be included are illustrated in solid lines, while elements that are optional may be illustrated in dashed lines.

=
However, elements that are shown in solid lines may not be essential. Thus, an element shown in solid lines may be omitted without departing from the scope of the present disclosure.
[0051] Figures 1-5 provide illustrative, non-exclusive examples of systems according to the present disclosure, components of systems, data that may be utilized to select a composition of a hydrocarbon solvent mixture and or a reservoir injection mixture that may be utilized with systems, and/or methods, according to the present disclosure, of operating and/or utilizing systems.
Elements that serve a similar, or at least substantially similar, purpose are labeled with like numbers in each of Figures 1-5, and these elements may not be discussed in detail herein with reference to each of Figures 1-5. Similarly, all elements may not be labeled in each of Figures 1-5, but associated reference numerals may be utilized for consistency. Elements, components, and/or features that are discussed herein with reference to one or more of Figures 1-5 may be included in and/or utilized with any of Figures 1-5 without departing from the scope of the present disclosure.
[0052] The inventions disclosed herein are related to process improvements to a Near-Azeotropic Heated VAPEX process for in-situ recovery of heavy oil products from a subterranean reservoir. The Near-Azeotropic Heated VAPEX may also be referred to herein by such terms as "Near-Azeotropic H-VAPEX", "Azeotropic H-VAPEX", "Azeo. H-VAPEX", or "AH-VAPEX", all of which should be construed to have the same meaning in the context of this disclosure.
100531 AH-VAPEX is a variation of a heated VAPEX (H-VAPEX) process in which an optimum volume of steam is co-injected with hydrocarbon solvent in vapor phase. The optimum volume of steam for given solvent is determined according to the phase behavior of solvent and water mixture at the operation pressure, and is the exact or near azeotropic/minimum boiling point concentration of water in vapor phase. In both AH-VAPEX and H-VAPEX processes, the well configuration is typically similar to a steam-assisted gravity drainage (or "SAGD") process in which two substantially horizontal wells (or "well pair") are installed substantially one above the other in the hydrocarbon-containing subterranean reservoir, wherein the upper well is utilized as an injection well and the lower well is utilized as a production well. The AH-VAPEX process injects a specific solvent and steam ratio in the vapor phase through the injection well and utilizes a gravity drainage oil recovery mechanism of the mobilized heavy oil due to reduced in-situ viscosity by increased temperature and dilution/mixing with the condensed solvent compounds.
[0054] Figure 1 is a non-limiting schematic representation of a well configuration that may utilize the AH-VAPEX process which is supplied for the purpose of illustrating an embodiment of an AH-VAPEX process that may be utilized with, or may be included in the systems and methods according to the present disclosure. Figure 1 is utilized only to assist in explaining details related to the present disclosure, and is not meant to be limiting in any manner, including any limitations on reservoir or well configurations, solvent or steam usage or requirements, or overall recovery system and/or oil processing requirements.
[0055] Figure 1 illustrates a simplified, and non-limiting description of well system 10 that may be utilized in an AH-VAPEX process which includes an injection well 20 and a production well 30 that extend within a subterranean reservoir 40 that is present within a subsurface region 45 and/or that extend between a surface region 50 and the subterranean reservoir 40.
[0056] In the AH-VAPEX process, a reservoir injection mixture 22 comprising steam and a hydrocarbon-containing solvent mixture (or "solvent mixture" herein) wherein the reservoir injection mixture 22 is injected substantially in the vapor phase into the subterranean reservoir 40 via an injection well 20. As noted, the solvent mixture is comprised of hydrocarbons, and in preferred embodiments, the solvent mixture is substantially comprised of hydrocarbons, or even essentially comprised of hydrocarbons. The term hydrocarbon-containing solvent mixture herein is preferably a mixture or range of boiling point hydrocarbon compounds, but as utilized herein, may additional additionally consist essentially of a single hydrocarbon compound. It has been discovered that, in a VAPEX type heavy oil recovery process, the optimum volume of steam for given solvent is determined according to the phase behavior of solvent and water mixture at the operation pressure, and is the exact or near azeotropic/minimum boiling point concentration of water in vapor phase.
[0057] Continuing with Figure 1, the AH-VAPEX comprises of injecting the vapor stream into the subterranean reservoir 40 via the injection well 20 and producing a reservoir product stream 32 from the subterranean reservoir 40 via the production well 30. The reservoir injection mixture 22 utilized in the process includes steam and a solvent mixture. Preferably the solvent mixture is comprised essentially of hydrocarbons. In a preferred embodiment, the steam and solvent mixture is within 30%+/-, 20%+/-, or 10%+/- of the azeotropic solvent molar fraction of the steam and the solvent mixture as measured at the reservoir operating pressure.
Alternatively, molar fraction of solvent mixture in the solvent and steam injection mixture is 70-100%, 80-100%, or 90 to 100%

of the azeotropic solvent molar fraction of the steam and the solvent mixture as measured at the reservoir operating pressure. Alternatively, the molar fraction of solvent mixture in the solvent and steam injection mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the solvent mixture as measured at the reservoir operating pressure. In preferred embodiments, the reservoir injection mixture 22 is comprised of at least 75%, 90%, 95, or substantially 100% by weight of the steam and the solvent mixture.
[0058] In preferred embodiments, at least 90%, at least 95%, or essentially all (by weight) of the reservoir injection mixture is injected into the subterranean reservoir in vapor form. In other embodiments, at least 5 wt%, 10 wt%, 20 wt%, 40 wt%, 60 wt%, 75 wt%, 85 wt%, 90 wt%, or 95 wt% of the solvent mixture is hydrocarbon compounds. The solvent mixture may include a hydrocarbon fraction that comprises, consists of, or consists essentially of C4 to C12 hydrocarbons, or C5 to C9 hydrocarbons. The solvent mixture may include a hydrocarbon fraction that comprises, consists of, or consists essentially of at least one of alkanes, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and olefin hydrocarbons. In preferred embodiments, these compositions will also apply to the reservoir injection mixtures produced by the facilities and associated processes described herein.
[0059] The reservoir injection mixture 22 may be injected into the subterranean reservoir at an injection temperature and an injection pressure. The injection temperature may be at, or near, a saturation temperature for the heated solvent at the injection pressure. When more than one solvent .. is utilized, the extraction process may be referred to as a multi-solvent-based recovery process and/or a multi-component solvent-based recovery process, which, at elevated temperatures, may be referred to as a high temperature multi-component solvent-based recovery process, which may be a high temperature multi-component vapor extraction process.
[0060] Available solvents and solvent mixtures that may be utilized in the AH-VAPEX
.. processes described herein may range from light hydrocarbon mixtures such as NGLs, and LPG
to heavy fractions such as different refinery streams. Preferably, these mixtures are mainly composed of hydrocarbon compounds with 3 to 12 carbon atoms and beyond. In the processes herein, these compounds form vapor mixtures with steam wherein the vapor mixture exhibits azeotropic behavior as the collective dew point curves of Figure 2 demonstrates for a range of C3 to Ci2 alkanes at 1.5 MPa pressure. Hence, after injection, these compositions of hydrocarbon vapor and water vapor tend to co-condense at the azeotropic temperature in the reservoir at given reservoir pressure to form two immiscible liquid phases. Also, a mixture of liquid water and these liquid hydrocarbon compounds tends to evaporate to a single vapor phase at these azeotropic conditions at given reservoir pressure and temperature. In general, the azeotropic temperature for vapor mixtures of water and the hydrocarbon compounds at the given reservoir pressure is equal to or less than the saturation temperature of pure water vapor and pure hydrocarbon compounds.
For the purpose of the AH-VAPEX processes herein, depending on the solvent type, a near azeotropic/minimum boiling point mixture of solvent and steam contains 15-98 vol. % solvent and 2-85 vol. % steam, in cold liquid equivalents, calculated at standard temperature and pressure.
[0061] Returning to Figure 1, once provided to subterranean reservoir 40, the reservoir injection mixture 22 may combine with a bituminous hydrocarbon deposit 55 within a solvent extraction chamber 60, may dilute the bituminous hydrocarbon deposit 55, may dissolve in the bituminous hydrocarbon deposit 55, and/or may dissolve the bituminous hydrocarbon deposit 55, thereby decreasing the viscosity of the bituminous hydrocarbon deposit. In an AH-VAPEX
process, a solvent extraction chamber 60, which may also be referred as a vapor chamber, is created. The vaporous hydrocarbon solvent mixture may condense within the solvent extraction chamber 60. When reservoir injection mixture 22 condenses, the hydrocarbon solvent mixture may release latent heat (or latent heat of condensation), transfer thermal energy to the subterranean reservoir, and/or generate a condensate 65. Condensation of the reservoir injection mixture 22 may heat a bituminous hydrocarbon deposit 55 that may be present within the subterranean reservoir, thereby decreasing a viscosity of the bituminous hydrocarbon deposit. In embodiments, the subterranean reservoir operating temperature may be 30-250 C or 80-150 C.
In further embodiments, the subterranean reservoir operating pressure may be 5-95% of a fracture pressure of the reservoir, or 0.2 to 4 MPa, or 1 to 2.5 MPa. Conversely, the subterranean reservoir operating pressure may be equal to the pressure of a gas cap in the subterranean reservoir, the pressure of a gas zone within the subterranean reservoir, the pressure of a bottom water zone in the subterranean reservoir, or the pressure of a mobile water zone within the subterranean reservoir.
[0062] The bituminous hydrocarbon deposit 55 may include bitumen, gaseous hydrocarbons, asphaltenes, and/or water. The reservoir injection mixture 22 and/or condensate 65 also may combine with, mix with, be dissolved in, dissolve, and/or dilute bituminous hydrocarbon deposit 55, further decreasing the viscosity of the bituminous hydrocarbon deposit.
[0063] The energy transfer between the reservoir injection mixture 22 and bituminous hydrocarbon deposit 55 and/or the mixing of reservoir injection mixture 22 and/or condensate 65 with bituminous hydrocarbon deposit 55 may generate reduced-viscosity hydrocarbons 70, which .. may flow to production well 30. The reduced-viscosity hydrocarbons 70 may flow to production well 30 due to gravity and/or pressure drop. After flowing to production well 30, a reservoir product stream 32 containing heavy oil is produced from the subterranean reservoir. The reduced-viscosity hydrocarbons 70 may have a lower viscosity than the hydrocarbons within the subterranean reservoir 45 had before the reservoir injection mixture 22 was injected into the subterranean reservoir 40. The reservoir product stream 32 may comprise the reduced-viscosity hydrocarbons 70 and condensate 65 in any suitable ratio and/or relative proportion. The reservoir product stream 32 may also contain asphaltenes, gaseous hydrocarbons, water, water soluble minerals and salts, solids, and/or other materials or contaminants. The reservoir product stream 32 is generally comprised of a hydrocarbon liquid phase (including reduced-viscosity heavy oil .. and a condensed portion of injected solvent compounds, i.e., condensate), a gas phase mixture (including in-situ native solution gas compounds such as CH4, process gaseous by-products such as CO2 and H2S, water vapor and a portion of injected solvent compounds) and a water liquid phase (including a portion in-situ formation water with dissolved minerals and a condensed portion of injected steam or water vapor). The reservoir product stream 32 may also carry some suspended minerals and solid particles (including sand, silt and clay from the subterranean formation).
Detailed Embodiment 1 [0064] Figure 3 depicts a schematic flow diagram of the main processing facility 300 for an embodiment of a process herein for managing the reservoir product stream 32, producing product streams, and producing a tailored reservoir solvent mixture 345 for reuse for injection as and/or co-injection with another stream as a component of the reservoir injection mixture 22. In the currently disclosed embodiment of this process, the reservoir product stream 32, or a portion thereof, is sent to a primary separation unit 301. In this primary separation unit 301, a major portion of the produced liquid water is separated from the reservoir product stream 32 to produce a primary water stream 302. The primary water stream 302 may also contain some amount of hydrocarbons and solids. Preferably, the primary separation unit 301 utilizes a gravity settling phenomena, for instance, a device such as a gravity settler. The pressure and temperature of the primary separation unit 301 may be chosen in such a way to evolve and isolate a vapor phase, mainly composed of solution gas compounds, process gaseous by-products, water vapor and may contain a portion of compounds from the solvent mixture of reservoir injection mixture 22, to produce a primary gas vapor stream 304. The primary separation unit 301 also produces a third stream which is designated as a primary hydrocarbon phase stream 305 which contains the majority of the reduced-viscosity hydrocarbons 70, as well as the majority of the solvent mixture that is a component of the reservoir injection mixture 22, that are present in the reservoir product stream 32, and which has been produced and recovered from the AH-VAPEX
processes described herein. In preferred embodiments, the primary hydrocarbon phase stream 305 recovers at least 70%, at least 80%, at least 90%, at least 95%, or at least 99% by weight of the reduced-viscosity hydrocarbons 70 present in the portion of the reservoir product stream 32 that is sent to the primary separation unit 301. In preferred embodiments, the primary hydrocarbon phase stream 305 recovers at least 70%, at least 80%, at least 90%, at least 95%, or at least 99% by weight of the solvent mixture present in the portion of the reservoir product stream 32 that is sent to the primary separation unit 301. The primary hydrocarbon phase stream 305 may also contain some water and solids.
100651 In the currently disclosed processes, the primary hydrocarbon phase stream 305 is sent to a solvent separation unit 310. In the solvent separation unit 310, the majority of the solvent boiling range compounds are separated from the primary hydrocarbon phase stream 305. In embodiments, the solvent separation unit 310 can be comprised of a single stage flash unit, a multiple-stage flash unit, a distillation/stripping column and/or a combination thereof. Depending on the temperature and pressure of the primary hydrocarbon phase stream 305, a primary .. hydrocarbon phase heater 307 may be used to heat the stream to a certain process temperature and provide the required thermal energy to vaporize the solvent compounds. In embodiments, this temperature on the hydrocarbon outlet of the primary hydrocarbon phase heater 307 is maintained to vaporize at least 70%, at least 80%, at least 90%, at least 95%, or at least 99% by weight of the solvent boiling range compounds present in the primary hydrocarbon phase stream 305 at the operating pressure of the solvent separation unit 310. The operating pressure of the solvent separation unit 310 will be taken at the inlet to the flash unit or distillation column deployed within the solvent separation unit 310. The thermal energy for the primary hydrocarbon phase heater 307 may be provided by any direct or indirect heating method (for example: fired heater, hot oil loop, by heat exchange with other process streams, such as waste heat recovery, or by direct steam heating).
[0066] In embodiments, a solvent separation unit controller 309, may be used to control the flow and/or pressure drop in the primary hydrocarbon phase stream 305. In embodiments, the solvent separation unit controller 309 is adjusted to maintain the primary hydrocarbon phase stream 305 upstream of the controller substantially in the liquid phase. In embodiments, the solvent separation unit controller 309 is further adjusted such as to flash the solvent boiling range compounds of the primary hydrocarbon phase stream 305 substantially to the vapor phase entering the solvent separation unit 310. Chemicals may be added to the reservoir product stream 32 and/or the primary hydrocarbon phase stream 305 to prevent foaming, fouling, scaling, and/or other similar operation phenomena in the associated process equipment. In addition, special mechanical designs may be utilized in the equipment associated with the primary separation unit 301 and/or the solvent separation unit 310 to prevent the aforementioned phenomena.
[0067] A heavy oil product stream 312 is produced from the solvent separation unit 310 from which, in embodiments, most of the solvent boiling range compounds have been removed. The heavy oil product stream 312 may be of sufficient composition to meet necessary pipeline specifications in which case the heavy oil product stream 312 may be sent to a pipeline as a pipeline product stream 320. In embodiments herein, the solvent separation unit 310 may be operated such that a sufficient amount of solvent, for example C4 to C12 hydrocarbons, remains in the heavy oil product stream 312 to allow the heavy oil product stream to meet pipeline specifications or reduces the amount of a diluent 314 that needs to be added to meet pipeline specifications.
[0068] Alternatively, in embodiments herein, the heavy oil product stream 312 may be too viscous or have to low an API gravity to meet specifications for pipeline transportation. In these instances, a diluent 314 may be added to the heavy oil product stream 312 to produce the pipeline product stream 320. A diluent treating unit 315 may additionally be utilized to further control the amount of diluent added and provide proper mixing of the diluent 314 and heavy oil product stream 312 to meet the specifications of the produced pipeline product stream 320.
Additionally, or optionally, excess solids and water present in the heavy oil product stream 312 can be removed in the diluent treating unit 315 to meet the pipeline specifications. The diluent treating unit 315 may utilize electrostatic mechanisms to separate excess solids and water from the heavy oil product stream. When a diluent treating unit 315 is utilized, the diluent 314 may be added to the heavy oil product stream 312 and/or optionally directly into the diluent treating unit 315. In embodiments, the design and operation pressure and temperature of the solvent separation unit 310 produces the heavy oil product stream 312 such that it contains a portion of the solvent boiling range compounds in order to meet the pipeline specification requirements.
[0069] The solvent separation unit 310 also produces a solvent vapor stream 325. In preferred embodiments, this stream comprises solvent boiling range compounds recovered from the reservoir product stream 32 which are within the boiling point ranges of the solvent mixture utilized in the reservoir injection mixture 22. The solvent vapor stream 325 may also include other gaseous compounds that were part of the reservoir product stream 32 and not removed in the primary gas vapor stream 304 of the primary separation unit 301.
[0070] In embodiments, each the heavy oil product stream 312 and the solvent vapor stream 325 may be composed of a single stream each (as shown in simplified Figure 3) or they may be composed of a combination of multiple streams produced in the solvent separation unit 310 which are grouped and/or combined to form the heavy oil product stream 312 and the solvent vapor stream 325, respectively.
[0071] As noted prior, some of the solvent boiling range compounds may be recovered in the primary gas vapor stream 304 from the primary separation unit 301. In this case, in preferred embodiments, at least a portion of the primary gas vapor stream 304 and at least a portion of the solvent vapor stream 325 can be combined into stream 327 and sent to the gas separation unit 330 for further processing. Alternatively, only the solvent vapor stream 325, or a portion thereof, is sent via stream 327 to the gas separation unit 330. Prior to the gas separation unit 330, stream 327 is sent through a solvent cooler 328, where the stream is cooled so that at least portion of the solvent boiling range compounds are condensed to a liquid. The solvent cooler 328 may be designed and operated to provide thermal energy to other process streams main processing facility 300. Alternatively, at least a portion of the primary gas vapor stream 304 and at least a portion of the solvent vapor stream 325 may independently undergo similar gas separation processes and the final streams then may be combined with the corresponding streams.

100721 In preferred embodiments, the gas separation unit 330 produces an off gas stream 331, a recovered solvent stream 333, and a gas separator water stream 335 as illustrated in Figure 3.
The off gas stream 331 will generally be comprised of light hydrocarbon gases, such as methane and ethane, but generally will also include some non-hydrocarbon gases such as CO2 and H2S.
Optionally, special provisions and designs may be utilized in the gas separation units to separate some of the light hydrocarbon gases from the entrained CO2 and/or H2S for proper treatment and/or disposal prior to sending the off gas stream 331 to a fuel gas system or for direct use in fired heating equipment that may be part of the main processing facility 300. Optionally, the off gas stream 331 may be added directly to a make-up fuel gas stream 332 prior to use in the fired heating equipment.
[0073] The gas separation unit 330 is operated under conditions to produce a recovered solvent stream 333 that is generally be free of impurities and ready for near-azeotropic vapor generation.
The gas separator water stream 335 will recover the condensed water from the water gas separation unit 330. The gas separator water stream 335 should be substantially free of impurities and require little, if any, further treatment prior to uses such as boiler feedwater supplied to fired heating equipment that may be part of the main processing facility 300. In embodiments, the gas separation unit 330 can be comprised of a single stage flash unit, a multiple-stage flash unit, a distillation/stripping column and/or a combination thereof 100741 In the processes herein, the recovered solvent stream 333 is tailored in composition for use as a solvent mixture for use in the AH-VAPEX process, or if needed, a make-up solvent stream .. 340 can be added prior to final use to produce a tailored reservoir solvent mixture 345 for use in the reservoir injection mixture 22. Figure 3 shows an optional solvent storage system 342 which may be utilized as a surge buffer and/or mixing step in the process. The make-up solvent stream 340 can be alternatively introduced to the recovered solvent stream 333 upstream and/or downstream of the optional solvent storage system 342 if utilized. The make-up solvent stream 340 may be used to add additional solvent to the process to make up for solvent losses from the AH-VAPEX process to the subterranean reservoir as well as from the main processing facility 300 and/or may be used to tailor the recovered solvent stream 333 to compositional specifications for a tailored reservoir solvent mixture 345 required for the near-azeotropic formulation of the reservoir injection mixture 22.
[0075] Much of the water required to generate the steam for the AH-VAPEX
process can be recovered from the reservoir product stream 32 as illustrated in the disclosed processes herein. As shown in Figure 3, at least a portion of the primary water stream 302 may be sent to a water treatment unit 350. In the water treatment unit 350, the primary water stream 302 is treated to boiler feed-water specifications by means of conventional water treatment methods. The water treatment unit 350 may utilize any of physical-chemical water treatment methods such as hot lime water softening kits and/or mechanical methods such as reverse osmosis, water vapor compression evaporators, evaporative water treatment methods, or any other water treating method. Additional make-up water 352, if required, may be added before or after or during water treatment processes depending on its source and required treatment to meet boiler feed-water specifications. In general, a portion of the water utilized in the water treatment unit 350 will be disposed (not recovered and recycled) to carry-over all impurities such as solids, salts and minerals which can be sent to a water disposal facilities 354 where the disposed water will undergo the extra processing to remove hydrocarbons and other contaminants to meet environmental regulations.
[0076] The water treatment unit 350 will produce a treated water stream 354, which as noted, meets boiler feed-water specifications. The gas separator water stream 335 may be added as shown to the treated water stream 354 if of sufficient quality to meet boiler feed-water specifications.
Alternatively, all, or a portion, of the gas separator water stream 335 may be sent to the water treatment unit 350. Optionally, the treated water stream 354 may be sent to a water storage tank 355 prior to be utilized in the AH-VAPEX process.
[0077] The treated water stream from the water storage tank 355 (designated as stored treated water stream 358) and the tailored reservoir solvent mixture 345 (or a portion of each thereof) are supplied to a vapor generation unit 360 in required proportions to generate the near-azeotropic/minimum boiling point vapor mixture for use in the AH-VAPEX
process. The vapor generation unit 360 may be comprised of heat exchanger, a steam heat exchanger, a hot oil heat exchanger, a fired heater, or any other suitable vaporizer design. The water and solvent mixture may be combined together and evaporated simultaneously to the corresponding dew-point temperature at the unit operation pressure. Excess heat generated in the vapor generation unit 360 may be utilized to superheat the combined stream. Alternatively, stored treated water stream 358 and the tailored reservoir solvent mixture 345 may be vaporized separately at the corresponding saturation temperature at the unit operation pressure, and subsequently combined prior to use in the AH-VAPEX process. A reservoir injection mixture 22 is produced (see Figure 3) from the process which is subsequently injected into the injection well 20 under the near-azeotropic conditions herein (see Figure 1). The use of superheat will result in some degrees of superheat of the final vapor mixture which can assist in providing excess heat to the solvent extraction chamber 60 thereby improving the hydrocarbon recovery of the AH-VAPEX process. In an embodiment, wherein the near-azeotropic reservoir injection mixture is injected into the subterranean reservoir at 1 to 50 C of superheat, measured with respect to the saturation temperature of the near-azeotropic reservoir injection mixture at the subterranean reservoir operating pressure. In preferred embodiments, at least 75 wt%, at least 90 wt% at least 95 wt%, or at least 99 wt% of the near-azeotropic reservoir injection mixture consists of the recovered solvent stream and the treated water stream as obtained from the processes herein.
100781 The main processing facility 300 may additionally include a feed pump 362 and/or mixing unit 365 upstream of the vapor generation unit 360. Either the feed pump 362 and/or mixing unit 365 may be utilized to provide proper mixing of the stored treated water stream 358 and the tailored reservoir solvent mixture 345 prior to entering the vapor generation unit 360. In preferred embodiments, the feed pump 362 is utilized to raise the unit operation pressure to sufficient enough pressure to transport the near-azeotropic/minimum boiling point vapor mixture (i.e., the reservoir injection mixture 22) to the injection well 20 wellheads in order to facilitate injection of the reservoir injection mixture 22 into the subterranean reservoir 40. Although the processes disclosed herein have been illustrated with a single main processing facility and a single subterranean well pair, a main processing facility may be built and dedicated to each injection/production well-pair, or to a group of injection/production wells, or to all of the injection/production well-pairs associated with a particular reservoir.
Detailed Embodiment 2 100791 Figure 4 depicts a schematic flow diagram of the main processing facility 400 for an embodiment of a process herein for managing the reservoir product stream 32, producing product streams, and producing a tailored reservoir solvent mixture 445 for reuse for injection as and/or co-injection with another stream as a component of the reservoir injection mixture 22. In the currently disclosed embodiment of this process, the reservoir product stream 32, or a portion

- 26 -thereof, is sent to a primary separation unit 401. Here an optional production mixture make-up solvent stream 403a and/or an optional production mixture water stream 403b is added to the reservoir product stream 32 as will be further described as follows to form a primary separation unit feedstream 406. The primary separation unit feedstream 406 is optionally sent through a primary feedtream heater 407 and a primary feedtream controller 409. The primary functions of the primary feedtream heater 407 and a primary feedtream controller 409 will be further described as follows.
[0080] In this primary separation unit 401, a portion of the produced liquid water is separated from the reservoir product stream 32 to produce a primary water stream 402.
The primary water stream 402 may also contain some amount of hydrocarbons and solids. In an embodiment, the primary separation unit 401 utilizes a gravity settling phenomena, for instance, a device such as a gravity settler. However, in other embodiments, the primary separation unit 401 can be comprised of a single stage flash unit, a multiple-stage flash unit, a distillation/stripping column and/or a combination thereof. Here, the pressure and temperature of the primary separation unit 401, as well as the composition of the primary separation unit feedstream 406, is controlled in such a manner as to evolve a vapor phase and produce a primary gas vapor stream 404 wherein the primary gas vapor stream 404 comprises a hydrocarbon solvent/water mixture at near-azeotropic conditions. The primary gas vapor stream 404 may also comprise solution gas compounds, process gaseous by-products, and other compounds other that the hydrocarbon solvent/water compounds that are produced at near azeotropic conditions.
[0081] The separation of near-azeotropic hydrocarbon solvent/water mixture in the primary separation unit 401 from the primary separation unit feedstream 406 is achieved through a volatility-based separation process utilizing the properties that: 1) the water and solvent compounds of the tailored primary separation unit feedstream 406 are more volatile than the heavy oil compounds in the reservoir product stream 32, and 2) the water and solvent compounds tailored primary separation unit feedstream 406 will tend to evaporate simultaneously and to form an azeotropie vapor mixture. Since an important goal of this process is to compositionally tailor and control the process such that a hydrocarbon solvent/water mixture at near-azeotropic conditions can be produced in and recovered from the primary separation unit 401, certain equipment and controls, although some which will not be required in all installations or at all times during the

-27-=
process, will generally be employed as on the front end of, and in, the primary separation unit 401 as will be further described.
[0082] In most instances, the reservoir product stream 32 will not be produced from the subterranean reservoir 40 under process conditions, or with a physical composition, to optimize the processes as described herein. Here an optional primary make-up solvent stream 403a and/or an optional primary water stream 403b is added to the reservoir product stream 32 in order to modify the solvent and water composition of the primary separation unit feedstream 406 as necessary to improve or optimize the processing in the primary separation unit 401. Here, the primary make-up solvent stream 403a is added to bring the hydrocarbon solvent concentration of the primary separation unit feedstream 406 to proper levels for processing in the primary separation unit 401 to produce a primary gas vapor stream 404 comprising a hydrocarbon solvent/water mixture at near-azeotropic conditions. Likewise, the primary water stream 403b is added to bring the water concentration of primary separation unit feedstream 406 to proper levels for processing in the primary separation unit 401 to produce a primary gas vapor stream 404 comprising a hydrocarbon solvent/water mixture at near-azeotropic conditions.
It should be noted here that the concentration of the hydrocarbon solvent and water in the primary separation unit feedstream 406 may be, but is likely not to be, the same relative concentrations hydrocarbon solvent/water mixture produced as the primary gas vapor stream 404. This due to the fact that some water in the primary separation unit feedstream 406 will be withdrawn from the primary separation unit 401 as a primary water stream 402 for reasons, such as removal of entrained solids and contaminants, as will be discussed further herein. Additionally, in embodiments, some of the hydrocarbon solvent in the primary separation unit feedstream 406 may be withdrawn as part of a heavy oil product stream 412 for reasons as discussed later herein.
[0083] As noted, in most instances, the reservoir product stream 32 will not be produced under process conditions to optimize the processes as described herein. To address this, as shown in Figure 4, the primary separation unit feedstream 406 is optionally sent through a primary feedstream heater 407 and a primary feedtream controller 409. The optional primary feedtream heater 407 is operated under conditions to provide the thermal energy for vaporization and to heat the primary separation unit feedstream 406 to the temperature in the primary separation unit 401 necessary to produce the primary gas vapor stream 404 such that the hydrocarbon solvent/water

-28-mixture within the primary gas vapor stream 404 is produced at near-azeotropic conditions. In a similar manner, the optional primary feedtream controller 409 is operated under conditions to maintain the pressure in the primary separation unit 401 at a pressure necessary to produce the primary gas vapor stream 404 such that the hydrocarbon solvent/water mixture within the primary gas vapor stream 404 is produced at near-azeotropic conditions.
[0084] The thermal energy for the primary feedtream heater 407 may be provided by any direct or indirect heating method. These methods may include the use of fired heater, a hot oil loop, by heat exchange with other process streams (e.g., waste heat recovery streams), or by direct steam heating. Optionally, chemicals may be added to the tailored primary separation unit feedstream to 406 to prevent foaming, fouling, scaling, and/or other similar operational phenomena in the primary separation unit 401. In addition, special mechanical designs and provisions may be utilized in the primary separation unit 401 to prevent the aforementioned operational phenomena.
[0085] The primary separation unit 401 also produces a heavy oil product stream 412 which contains the majority of the reduced-viscosity hydrocarbons 70 recovered from the subterranean reservoir 40, and are present in the reservoir product stream 32, and which has been produced and recovered from the AH-VAPEX processes described herein. In preferred embodiments, the heavy oil product stream 412 recovers at least 70%, at least 80%, at least 90%, at least 95%, or at least 99% of the reduced-viscosity hydrocarbons 70 present in the portion of the reservoir product stream 32 that is sent to the primary separation unit 401. In preferred embodiments, the heavy oil product stream 412 recovers at least 70%, at least 80%, at least 90%, at least 95%, or at least 99%
of the solvent mixture present in the portion of the reservoir product stream 32 that is sent to the primary separation unit 401. The heavy oil product stream 412 may also contain some water and solids. In embodiments, each the heavy oil product stream 412 and the primary gas vapor stream 404 may be composed of a single stream each (as shown in simplified Figure 4) or they may be composed of a combination of multiple streams produced in the primary separation unit 401 which are grouped and/or combined to form the heavy oil product stream 412 and the primary gas vapor stream 404, respectively.
[0086] The heavy oil product stream 412 is produced from the solvent separation unit 410 from which, in embodiments, most of the solvent boiling range compounds have been removed.
The heavy oil product stream 412 may be of sufficient composition to meet necessary pipeline

- 29 -specifications in which case the heavy oil product stream 412 may be sent to a pipeline as a pipeline product stream 420. In embodiments herein, as noted, the primary separation unit 401 may be operated such that a sufficient amount of solvent, for example C4 to C12 hydrocarbons, remains in the heavy oil product stream 412 to allow the heavy oil product stream to meet pipeline specifications or reduces the amount of a diluent 414 that needs to be added to meet pipeline specifications.
[0087] Alternatively, in embodiments herein, the heavy oil product stream 412 may be too viscous or have to low an API gravity to meet specifications for pipeline transportation. In these instances, a diluent 414 may be added to the heavy oil product stream 412 to produce the pipeline to product stream 420. A diluent treating unit 415 may additionally be utilized to further control the amount of diluent added and provide proper mixing of the diluent 414 and heavy oil product stream 412 to meet the specifications of the produced pipeline product stream 420.
Additionally, or optionally, excess solids and water present in the heavy oil product stream 412 can be removed in the diluent treating unit 415 to meet the pipeline specifications. The diluent treating unit 415 may utilize electrostatic mechanisms to separate excess solids and water from the heavy oil product stream. When a diluent treating unit 415 is utilized, the diluent 414 may be added to the heavy oil product stream 412 and/or optionally directly into the diluent treating unit 415. In embodiments, the design and operation pressure and temperature of the primary separation unit 401 produces the heavy oil product stream 412 such that it contains a portion of the solvent boiling range compounds in order to meet the pipeline specification requirements.
[0088] Continuing with Figure 4, in the primary separation unit 401, the majority of the solvent boiling range compounds are separated from the heavy oil product stream 412.
In embodiments, this temperature and pressure of the primary separation unit 401 is maintained to vaporize at least 70%, at least 80%, at least 90%, at least 95%, or at least 99% of the solvent boiling range compounds present in the primary separation unit feedstream 406. The operating pressure of the primary separation unit 401 will be taken at the inlet to the flash unit or distillation column deployed within the primary separation unit 401.
[0089] As noted, the primary separation unit 401 also produces a primary gas vapor stream 404 which comprises a hydrocarbon solvent/water mixture at near-azeotropic conditions. The .. primary gas vapor stream 404 may also comprise solution gas compounds, process gaseous by-

- 30 -products, and other compounds other than the hydrocarbon solvent/water compounds. Here, at least a portion of the primary gas vapor stream 404 that is produced from the primary separation unit 401 is sent to a gas separation unit 430 for further processing. Prior to the gas separation unit 430, the primary gas vapor stream 404 is sent through a gas separation cooler 428, where the stream is cooled so that at least portion of the solvent boiling range compounds and the water in the primary gas vapor stream 404 are condensed to a liquid.
[0090] In preferred embodiments, at least 80%, 90%, 95% or substantially all of the solvent in the primary gas vapor stream 404 is condensed and removed as part of the recovered solvent/water stream 433. In preferred embodiments, at least 80%, 90%, 95% or substantially all of the water in the primary gas vapor stream 404 is condensed and removed as part of the recovered solvent/water stream 433. In preferred embodiments, the solvent/water mixture in the recovered solvent/water stream 433 is at a near-azeotropic composition. The gas separation cooler 428 may be designed and operated to provide thermal energy to other process streams of the main processing facility 400.
[0091] In preferred embodiments, the gas separation unit 430 produces an off gas stream 431 and the recovered solvent/water stream 433 as illustrated in Figure 4. The off gas stream 431 will generally be comprised of light hydrocarbon gases, such as methane and ethane, but generally will also include some non-hydrocarbon gases such as CO2 and H2S. Optionally, special provisions and designs may be utilized in the gas separation units to separate some of the light hydrocarbon gases from the entrained CO2 and/or H2S for proper treatment and/or disposal prior to sending the off gas stream 431 to a fuel gas system or for direct use in fired heating equipment that may be part of the main processing facility 400. Optionally, the off gas stream 431 may be added to a make-up fuel gas stream 432 prior to use in the fired heating equipment.
[0092] The gas separation unit 430 is operated under conditions to produce a recovered solvent/water stream 433 that is generally be free of impurities and ready for near-azeotropic vapor generation. In embodiments, the gas separation unit 430 can be comprised of a single stage flash unit, a multiple-stage flash unit, a distillation/stripping column and/or a combination thereof.
[0093] In the processes herein, an optional final make-up solvent stream 440a and/or an optional final water stream 440b may be added to the recovered solvent/water stream 433. The optional final make-up solvent stream 440a and/or an optional final water stream 440b, may be

-31 -used to make a final compositional modification to the recovered solvent/water stream 433 prior to use of the mixture in the AH-VAPEX processes herein. However, since the primary separation unit 401 and the gas separation unit 430 will normally be operated under conditions to produce the recovered solvent/water stream 433 at a near-azeotropic mixture of hydrocarbon solvent and water, the final make-up solvent stream 440a and/or the final water stream 440b may be added primarily for the purpose of making up for volume loses of the solvent and/or water utilized in the subterranean reservoir during the AH-VAPEX heavy oil recovery processes and/or volume losses in the processes described herein for recover and preparation of the reservoir injection mixture 22.
As such, the recovered solvent/water stream 433 may be furthered tailored in composition and/or volume for use in the AH-VAPEX process for use in the reservoir injection mixture 22. The final make-up solvent stream 440a and the final water stream 440b, may be provided from the same source as the primary make-up solvent stream 403a and/or the primary water stream 403b. In embodiments, the primary make-up solvent stream, the final make-up solvent stream, or both may be comprised of hydrocarbons that have been produced by a source separate from the subterranean IS reservoir. The primary make-up solvent stream, the final make-up solvent stream, or both may be comprised of a natural gas liquid, a natural gas condensate, a liquefied petroleum gas, or a crude oil refinery naphtha.
[0094] Figure 4 also shows an optional solvent/water storage system 442 which may be utilized as a surge buffer and/or mixing step in the process. The final make-up solvent stream 440a and/or the final water stream 440b can be alternatively introduced to the recovered solvent/water stream 433 upstream and/or downstream of the optional solvent/water storage system 442 if utilized.
[0095] As shown in Figure 4, at least a portion of the primary water stream 402 may be sent to a water disposal treatment unit 450. In the water disposal treatment unit 450, the primary water stream 402 is treated to allow for the proper disposal of the primary water stream 402. The primary water stream 402 will contain impurities from the primary separation unit feedstream 406 such as solids, salts and minerals. The dissolved minerals in the primary water stream 402 will not vaporize in the primary separation unit 401, and will tend to stay in the liquid portion of the water produced from the primary separation unit 401. Hence, a relatively concentrated liquid solution of minerals in water will form in the primary separation unit 401. The design of the primary

- 32 -separation unit 401 will not allow the full vaporization of all of the water in the primary separation unit feedstream 406 and this excess water will be utilized in the liquid phase as the carrier media for the disposal of the impurities. In addition, a gravity settling vessel may be used at the inlet of the primary separation unit 401 to remove some of the suspended particles which are heavy enough to settle. The primary water stream 402 will undergo the extra processing in a disposal water treatment unit 450 to remove hydrocarbons and other contaminants necessary to meet environmental regulations and be sent to final disposal to water disposal facilities 454.
[0096] A final tailored reservoir solvent/water mixture 445 is supplied to a vapor generation unit 460 to generate the near-azeotropic/minimum boiling point vapor mixture for use in the AH-VAPEX process. The vapor generation unit 460 may be comprised of heat exchanger, a steam heat exchanger, a hot oil heat exchanger, a fired heater, or any other suitable vaporizer design. The water and solvent of the final tailored reservoir solvent/water mixture 445 is evaporated to the corresponding dew-point temperature at the unit operation pressure. Excess heat generated in the vapor generation unit 460 may be utilized to superheat the stream. A reservoir injection mixture 22 is produced (see Figure 4) from the process which is subsequently injected into the injection well 20 under the near-azeotropic conditions herein (see Figure 1). A
reservoir injection mixture 22 is produced is in the vapor phase and preferably additionally contains some amount of superheat. The use of a superheater (which may be part of the vapor generation unit 460) will result in some degrees of superheat of the final vapor mixture which can assist in providing excess heat to the solvent extraction chamber 60 thereby improving the hydrocarbon recovery of the AH-VAPEX process. In an embodiment, wherein the near-azeotropic reservoir injection mixture is injected into the subterranean reservoir at 1 to 50 C of superheat, measured with respect to the saturation temperature of the near-azeotropic reservoir injection mixture at the subterranean reservoir operating pressure.
[0097] The main processing facility 400 may additionally include a feed pump 462 and/or mixing unit 465 upstream of the vapor generation unit 460. Either the feed pump 462 and/or mixing unit 465 may be utilized to provide proper mixing the final tailored reservoir solvent mixture 465 prior to entering the vapor generation unit 460. In preferred embodiments, the feed pump 462 is utilized to raise the unit operation pressure to sufficient enough pressure to transport the near-azeotropic/minimum boiling point vapor mixture (i.e., the reservoir injection mixture 22)

- 33 -to the injection well 20 wellheads in order to facilitate injection of the reservoir injection mixture 22 into the subterranean reservoir 40. Although the processes disclosed herein have been illustrated with a single main processing facility and a single subterranean well pair, a main processing facility may be built and dedicated to each injection/production well-pair, or to a group .. of injection/production wells, or to all of the injection/production well-pairs associated with a particular reservoir.
Detailed Embodiment 3 [0098] Figure 5 depicts a schematic flow diagram of the main processing facility 500 for an embodiment of a process herein for managing the reservoir product stream 32, producing product streams, and producing a tailored reservoir solvent mixture 545 for reuse for injection as and/or co-injection with another stream as a component of the reservoir injection mixture 22. In the currently disclosed embodiment of this process, the reservoir product stream 32, or a portion thereof, is sent to a primary separation unit 501. In this primary separation unit 501, a major portion of the produced liquid water is separated from the reservoir product stream 32 to produce a primary water stream 502. The primary water stream 502 may also contain some amount of hydrocarbons and solids. Preferably, the primary separation unit 501 utilizes a gravity settling phenomena, for instance, a device such as a gravity settler. The pressure and temperature of the primary separation unit 501 may be chosen in such a way to evolve and isolate a vapor phase, mainly composed of solution gas compounds, process gaseous by-products, water vapor and may contain a portion of compounds from the solvent mixture of reservoir injection mixture 22, to produce a primary vapor stream 504. The primary separation unit 501 also produces a third stream which is designated as a primary hydrocarbon phase stream 505 which contains the majority of the reduced-viscosity hydrocarbons 70, as well as the majority of the solvent mixture that is a component of the reservoir injection mixture 22, that are present in the reservoir product stream 32, and which has been produced and recovered from the AH-VAPEX processes described herein.
In preferred embodiments, the primary hydrocarbon phase stream 505 recovers at least 70%, at least 80%, at least 90%, at least 95%, or at least 99% of the reduced-viscosity hydrocarbons 70 present in the portion of the reservoir product stream 32 that is sent to the primary separation unit 501. In preferred embodiments, the primary hydrocarbon phase stream 505 recovers at least 70%,

- 34 -at least 80%, at least 90%, at least 95%, or at least 99% of the solvent mixture present in the portion of the reservoir product stream 32 that is sent to the primary separation unit 501. The primary hydrocarbon phase stream 505 may also contain some water and solids.
[0099] In the currently disclosed processes, the primary hydrocarbon phase stream 505 is sent to a solvent separation unit 510. In the solvent separation unit 510, the majority of the solvent boiling range compounds are separated from the primary hydrocarbon phase stream 505. In embodiments, the solvent separation unit 510 can be comprised of a single stage flash unit, a multiple-stage flash unit, a distillation/stripping column and/or a combination thereof. Depending on the temperature and pressure of the primary hydrocarbon phase stream 505, a primary hydrocarbon phase heater 507 may be used to heat the stream to a certain process temperature and provide the required thermal energy to vaporize the solvent compounds. . In embodiments, this temperature on the hydrocarbon outlet of the primary hydrocarbon phase heater 507 is maintained to vaporize at least 70%, at least 80%, at least 90%, at least 95%, or at least 99% of the solvent boiling range compounds present in the primary hydrocarbon phase stream 505 at the operating pressure of the solvent separation unit 510. The operating pressure of the solvent separation unit 510 will be taken at the inlet to the flash unit or distillation column deployed within the solvent separation unit 510. The thermal energy for the primary hydrocarbon phase heater 507 may be provided by any direct or indirect heating method (for example: fired heater, hot oil loop, by heat exchange with other process streams, such as waste heat recovery, or by direct steam heating).
[00100] In embodiments, a solvent separation unit controller 509, may be used to control the flow and/or pressure drop in the primary hydrocarbon phase stream 505. In embodiments, the solvent separation unit controller 509 is adjusted to maintain the primary hydrocarbon phase stream 505 upstream of the controller substantially in the liquid phase. In embodiments, the solvent separation unit controller 509 is further adjusted such as to flash the solvent boiling range compounds of the primary hydrocarbon phase stream 505 substantially to the vapor phase entering the solvent separation unit 510. Chemicals may be added to the reservoir product stream 32 and/or the primary hydrocarbon phase stream 505 to prevent foaming, fouling, scaling, and/or other similar operation phenomena in the associated process equipment. In addition, special mechanical designs may be utilized in the equipment associated with the primary separation unit 501 and/or the solvent separation unit 510 to prevent the aforementioned phenomena.

- 35 -[00101] A heavy oil product stream 512 is produced from the solvent separation unit 310 from which, in embodiments, most of the solvent boiling range compounds have been removed. The heavy oil product stream 512 may be of sufficient composition to meet necessary pipeline specifications in which case the heavy oil product stream 512 may be sent to a pipeline as a pipeline product stream 520. In embodiments herein, the solvent separation unit 510 may be operated such that a sufficient amount of solvent, for example C4 to C12 hydrocarbons, remains in the heavy oil product stream 512 to allow the heavy oil product stream to meet pipeline specifications or reduces the amount of a diluent 514 that needs to be added to meet pipeline specifications.
[00102] Alternatively, in embodiments herein, the heavy oil product stream 512 may be too .. viscous or have to low an API gravity to meet specifications for pipeline transportation. In these instances, a diluent 514 may be added to the heavy oil product stream 512 to produce the pipeline product stream 520. A diluent treating unit 515 may additionally be utilized to further control the amount of diluent added and provide proper mixing of the diluent 514 and heavy oil product stream 512 to meet the specifications of the produced pipeline product stream 520.
Additionally, or optionally, excess solids and water present in the heavy oil product stream 512 can be removed in the diluent treating unit 515 to meet the pipeline specifications. The diluent treating unit 515 may utilize electrostatic mechanisms to separate excess solids and water from the heavy oil product stream. When a diluent treating unit 515 is utilized, the diluent 514 may be added to the heavy oil product stream 512 and/or optionally directly into the diluent treating unit 515. In embodiments, the design and operation pressure and temperature of the solvent separation unit 510 produces the heavy oil product stream 512 such that it contains a portion of the solvent boiling range compounds in order to meet the pipeline specification requirements.
[00103] The solvent separation unit 510 also produces a solvent vapor stream 525. In preferred embodiments, this stream comprises solvent boiling range compounds recovered from the reservoir product stream 32 which are within the boiling point ranges of the solvent mixture utilized in the reservoir injection mixture 22. The solvent vapor stream 525 may also include other gaseous compounds that were part of the reservoir product stream 32 and not removed in the primary vapor stream 504 of the primary separation unit 501.
[00104] In embodiments, each of the heavy oil product stream 512 and the solvent vapor stream 525 may be composed of a single stream each (as shown in simplified Figure 5) or they may be

- 36 -=
composed of a combination of multiple streams produced in the solvent separation unit 510 which are grouped and/or combined to form the heavy oil product stream 512 and the solvent vapor stream 525, respectively.
[00105] As noted prior, some of the solvent boiling range compounds may be recovered in the primary vapor stream 504 from the primary separation unit 501. In this case, in preferred embodiments, at least a portion of the primary vapor stream 504 and at least a portion of the solvent vapor stream 525 can be combined into a primary gas separation feed stream 527 and sent to a primary gas separation unit 570 for further processing. The further processing may include use of the primary gas separation feed stream 527 to treat the primary produced water stream 502.
to Alternatively, only the solvent vapor stream 525, or a portion thereof, is sent via a primary gas separation feed stream 527 to the primary gas separation unit 570. In the primary gas separation unit 570, at least a portion of the thermal energy for water phase change from liquid to vapor may be provided by condensation of some of the solvent compounds in the vapor phase from the gas separation feed stream 527. Additional make-up water 552, if required, may be added before or after or during water treatment processes depending on its source. The amount of make-up water 552, added to the process may adjusted in order to produce a primary gas separation vapor stream 571 containing a solvent and water at near-azeotropic conditions. The primary gas separation vapor stream 571 may also be comprised of light hydrocarbon gases, such as methane and ethane, as well as some non-hydrocarbon gases such as CO2 and H2S.
[00106] Alternatively or additionally, the amount of make-up water 552, added to the process may adjusted in order to produce a primary gas separation vapor stream 571 wherein the quality of the water in the primary gas separation vapor stream 571 is of sufficient quality to meet boiler feed-water specifications. The primary gas separation unit 570 also produces a primary gas separation liquid stream 572 which comprises condensed solvents and water. A
gas treating make-up solvent stream 573 may be added to the primary gas separation liquid stream 572 to form a secondary gas separation feed stream 574. In preferred embodiments, the secondary gas separation feed stream 574 is passed through a gas separation stage heater 575 which vaporizes at least a portion of the solvent and water in the secondary gas separation feed stream 574 before being set to a secondary gas separation unit 580.
[00107] In the secondary gas separation unit 580, most of the solvent and some of the water is

-37-separated in a vapor phase to form a secondary gas separation vapor stream 581. In preferred embodiments, the secondary gas separation vapor stream 581 comprises a solvent and water mixture at near-azeotropic conditions. In preferred embodiments, essentially all of the secondary gas separation unit 580 is vaporized and leaves the secondary gas separation unit 580 as part of the secondary gas separation vapor stream 581. In preferred embodiments, the secondary gas separation liquid stream 535 leaving the secondary gas separation unit 580 is comprised of less than 10 wt%, 5 wt% or 2 wt% hydrocarbons.
[00108] Continuing with Figure 5, the primary gas separation vapor stream 571 and the secondary gas separation vapor stream 581 are combined to form a tertiary gas separation feed stream 582 and sent to a tertiary gas separation unit 585. Prior to the tertiary gas separation unit 585 the tertiary gas separation feed stream 582 is passed through a gas separation stage cooler 583.
While, for simplification purposes, the combined tertiary gas separation feed stream 582 is illustrated as passing through the gas separation stage cooler 583, in an alternative a portion of the tertiary gas separation feed stream 582 and/or a portion of any of the separate streams making up the tertiary gas separation feed stream 582 may be passed through a cooler.
Also, while one cooler is shown for exemplary purposes, multiple separate coolers may be utilized in the step and may be associated with different component streams to the tertiary gas separation unit 585.
[00109] In preferred embodiments, the tertiary gas separation feed stream 582 produces an off gas stream 531 and the recovered solvent/water stream 533 as illustrated in Figure 3. The off gas stream 531 will generally be comprised of light hydrocarbon gases, such as methane and ethane, but generally will also include some non-hydrocarbon gases such as CO2 and H2S. Optionally, special provisions and designs may be utilized in the gas separation units to separate some of the light hydrocarbon gases from the entrained CO2 and/or H2S for proper treatment and/or disposal prior to sending the off gas stream 531 to a fuel gas system or for direct use in fired heating equipment that may be part of the main processing facility 500. Optionally, the off gas stream 531 may be added directly to a make-up fuel gas stream 532 prior to use in the fired heating equipment.
[00110] The tertiary gas separation unit 585 is operated under conditions to produce a recovered solvent/water stream 533 that is generally be free of impurities and ready for near-azeotropic vapor generation. In embodiments, the primary gas separation unit 570, the secondary gas separation unit 580, and/or the tertiary gas separation unit 585 can be comprised of a single stage flash unit,

- 38 -a multiple-stage flash unit, a distillation/stripping column and/or a combination thereof [00111] In the processes herein, an optional final make-up solvent stream 540a and/or an optional final make-up water stream 540b may be added to the recovered solvent/water stream 533. The optional final make-up solvent stream 540a and/or an optional final make-up water stream 540b, may be used to make a final compositional modification to the recovered solvent/water stream 533 prior to use of the mixture in the AH-VAPEX processes herein.
However, since the primary separation unit 501 and the gas separation units 570, 580, and 585 will normally be operated under conditions to produce the recovered solvent/water stream 533 at a near-azeotropic mixture of hydrocarbon solvent and water, the final make-up solvent stream 540a and/or the final make-up water stream 540b may be added primarily for the purpose of making up for volume loses of the solvent and/or water utilized in the subterranean reservoir during the AH-VAPEX heavy oil recovery processes and/or volume losses in the processes described herein for recover and preparation of the reservoir injection mixture 22. As such, the recovered solvent/water stream 533 may be furthered tailored in composition and/or volume for use in the AH-VAPEX
process for use in the reservoir injection mixture 22. In embodiments, the final make-up solvent stream may be comprised of hydrocarbons that have been produced by a source separate from the subterranean reservoir. The final make-up solvent stream may be comprised of a natural gas liquid, a natural gas condensate, a liquefied petroleum gas, or a crude oil refinery naphtha.
[00112] Figure 5 also shows an optional solvent/water storage system 542 which may be utilized as a surge buffer and/or mixing step in the process. The final make-up solvent stream 540a and/or the final make-up water stream 540b can be alternatively introduced to the recovered solvent/water stream 533 upstream and/or downstream of the optional solvent/water storage system 542 if utilized.
[00113] As shown in Figure 5, at least a portion of the secondary gas separation liquid stream 535 leaving may be sent to a water disposal treatment unit 550. In the water disposal treatment unit 550, the secondary gas separation liquid stream 535 is treated to allow for the proper disposal of the primary water stream 502. The secondary gas separation liquid stream 535 will contain impurities from the reservoir product stream 32 such as solids, salts and minerals. The dissolved minerals in the secondary gas separation liquid stream 535 will not vaporize in the secondary gas separation unit 580, and will tend to stay in the liquid portion of the water produced secondary gas

-39-separation unit 580. Hence, a relatively concentrated liquid solution of minerals in water will form in secondary gas separation unit 580. The design of the secondary gas separation unit 580 will not allow the full vaporization of all of the water in the secondary gas separation feed stream 574 and this excess water will be utilized in the liquid phase as the carrier media for the disposal of the impurities. The secondary gas separation liquid stream 535 will undergo the extra processing in a disposal water treatment unit 550 to remove hydrocarbons and other contaminants necessary to meet environmental regulations and be sent to final disposal to water disposal facilities 554.
[00114] A final tailored reservoir solvent/water mixture 545 is supplied to a vapor generation unit 560 to generate the near-azeotropic/minimum boiling point vapor mixture for use in the AH-process. The vapor generation unit 560 may be comprised of heat exchanger, a steam heat exchanger, a hot oil heat exchanger, a fired heater, or any other suitable vaporizer design. The water and solvent of the final tailored reservoir solvent/water mixture 545 is evaporated to the corresponding dew-point temperature at the unit operation pressure. Excess heat generated in the vapor generation unit 560 may be utilized to superheat the stream. A reservoir injection mixture 22 is produced (see Figure 5) from the process which is subsequently injected into the injection well 20 under the near-azeotropic conditions herein (see Figure 1). A
reservoir injection mixture 22 is produced is in the vapor phase and preferably additionally contains some amount of superheat. The use of a superheater (which may be part of the vapor generation unit 560) will result in some degrees of superheat of the final vapor mixture which can assist in providing excess heat to the solvent extraction chamber 60 thereby improving the hydrocarbon recovery of the AH-VAPEX process. In an embodiment, wherein the near-azeotropic reservoir injection mixture is injected into the subterranean reservoir at 1 to 50 C of superheat, measured with respect to the saturation temperature of the near-azeotropic reservoir injection mixture at the subterranean reservoir operating pressure.
[00115] The main processing facility 500 may additionally include a feed pump 562 and/or mixing unit 565 upstream of the vapor generation unit 560. Either the feed pump 562 and/or mixing unit 565 may be utilized to provide proper mixing the final tailored reservoir solvent mixture 545 prior to entering the vapor generation unit 560. In preferred embodiments, the feed pump 562 is utilized to raise the unit operation pressure to sufficient enough pressure to transport the near-azeotropic/minimum boiling point vapor mixture (i.e., the reservoir injection mixture 22)

- 40 -to the injection well 20 wellheads in order to facilitate injection of the reservoir injection mixture 22 into the subterranean reservoir 40. Although the processes disclosed herein have been illustrated with a single main processing facility and a single subterranean well pair, a main processing facility may be built and dedicated to each injection/production well-pair, or to a group of injection/production wells, or to all of the injection/production well-pairs associated with a particular reservoir.
[00116] In the present disclosure, several examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently.
[00117] In the event that any patents, patent applications, or other references are referenced herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either a portion of the present disclosure or any of the other references referenced herein, the portion of the present disclosure shall control.
Industrial Applicability [00118] The systems and methods disclosed in the present disclosure are applicable to the oil and gas industry.
[00119] It is believed that the following claims particularly point out certain combinations and subcombinations that are novel and non-obvious. Other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the present disclosure.

- 41 -

Claims

1. A method for recovering viscous hydrocarbons from a subterranean reservoir, the method comprising:
a) drilling at least one well pair in a subterranean reservoir, wherein the well pair is comprised of an injection well and a production well, and the injection well is located at an elevation above the production well within the subterranean reservoir;
b) injecting a near-azeotropic reservoir injection mixture comprising steam and a solvent mixture into the subterranean reservoir via the injection well, wherein the near-azeotropic reservoir injection mixture is injected in the vapor phase;
c) producing a reservoir product stream comprising reduced-viscosity hydrocarbons, water, and a condensate; wherein the condensate comprises at least a portion of the solvent mixture;
d) sending at least a portion of the reservoir product stream to a primary separation unit, and producing a primary water stream, a primary gas vapor stream, and a primary hydrocarbon phase stream;
e) sending at least a portion of the primary hydrocarbon phase stream to a solvent separation unit; and producing a solvent vapor stream, and a heavy oil product stream;
f) sending at least a portion of the primary water stream to a water treatment unit and producing a treated water stream;
g) sending at least a portion of the solvent vapor stream to a gas separation unit, and producing an off gas stream and a recovered solvent stream; and h) vaporizing at least a portion of the recovered solvent stream and at least a portion of the treated water stream in at least one vapor generation unit;
wherein the near-azeotropic reservoir injection mixture comprises at least a portion of the recovered solvent stream and at least a portion of the treated water stream.

2. The method of claim 1, wherein each of the recovered solvent stream and the treated water stream are vaporized by separate vapor generation units prior to injecting them as part of the near-azeotropic reservoir injection mixture.

3. The method of claim 1, wherein the recovered solvent stream and the treated water stream are combined in near-azeotropic proportions to form the reservoir injection mixture prior to be vaporized in a common vapor generation unit.

4. The method of any one of claim 3, wherein the composition of the near-azeotropic reservoir injection mixture is substantially the same as the combined recovered solvent stream and the treated water stream.

5. The method of claim 1, wherein the near-azeotropic reservoir injection mixture is injected into the subterranean reservoir via more than one injection well.

6. The method of claim 1, wherein the near-azeotropic reservoir injection mixture is injected into the subterranean reservoir at 1 to 50 °C of superheat, measured with respect to the saturation temperature of the injected near-azeotropic reservoir injection mixture at an operating pressure of the subterranean reservoir.

7. The method of any one of claims 1-6, wherein the recovered solvent stream further comprises hydrocarbons that have been produced by a source separate from the subterranean reservoir.

8. The method of claim 7, wherein the recovered solvent stream comprises a natural gas liquid, a natural gas condensate, a liquefied petroleum gas, or a crude oil refinery naphtha.

9. The method of any one of claims 1-8, wherein the near-azeotropic reservoir injection mixture is comprised of C4 to C12 hydrocarbons.

10. The method of any one of claims 1-9, wherein the recovered solvent stream is comprised of C4 to C12 hydrocarbons.

11. The method of any one of claims 1-10, wherein at least a portion of the primary gas vapor stream is combined with the solvent vapor stream prior to the solvent separation unit.

12. The method of any one of claims 1-11, wherein a makeup water stream is combined with the primary water stream.

13. The method of any one of claims 1-12, wherein solids, salts and minerals are removed from the primary water stream in the water treatment unit and the solids, salts and minerals are sent to a water disposal facility.

14. The method of any one of claims 1-13, wherein the at least one vapor generation unit comprises a heat exchanger, a steam heat exchanger, a hot oil heat exchanger, or a fired heater.

15. The method of claim 14, wherein the at least one vapor generation unit comprises a fired heater and at least a portion of the off gas stream is utilized as a fuel to the fired heater.

16. The method of claim 15, wherein the off gas stream is comprised of CO2 and H2S
and at least a portion of the CO2 and the H2S in the off gas stream is removed in the gas separation unit.

17. The method of any one of claims 15 and 16, wherein at least a portion of the off gas stream is added to a fuel gas stream prior to being utilized as fuel to the fired heater.

18. The method of any one of claims 1-17, wherein the gas separation unit further produces a gas separator water stream.

19. The method of claim 18, wherein the gas separator water stream is combined with the treated water stream prior to the at least one vapor generation unit.

20. The method of claim 19, wherein the gas separator water stream and the treated water stream are sent to a water storage tank prior to the at least one vapor generation unit.

21. The method of any one of claims 1-20, wherein a make-up solvent stream is added to the recovered solvent stream.

22. The method of any one of claims 1-21, wherein a diluent is added to at least a portion of the heavy oil product stream.

23. The method of any one of claims 1-21, wherein the solvent separation unit is operated such that a sufficient amount of C4 to C12 hydrocarbons remain in the heavy oil product stream for the heavy oil product stream to meet pipeline specifications.

24. The method of any one of claims 1-23, wherein the gas separation unit is comprised of a single stage flash unit, a multiple-stage flash unit, a distillation/stripping column, or a combination thereof.

25. The method of any one of claims 1-24, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 30%+/- of the azeotropic solvent molar fraction of the combined recovered solvent stream and the treated water stream at an operating pressure of the subterranean reservoir.

26. The method of any one of claims 1-24, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 70-110% of the azeotropic solvent molar fraction of the combined recovered solvent stream and the treated water stream at an operating pressure of the subterranean reservoir.

27. The method of any one of claims 1-24, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 70-100% of the azeotropic solvent molar fraction of the combined recovered solvent stream and the treated water stream at an operating pressure of the subterranean reservoir.

28. The method of any one of claims 1-24, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 80-100% of the azeotropic solvent molar fraction of the combined recovered solvent stream and the treated water stream at an operating pressure of the subterranean reservoir.

29. The method of any one of claims 1-28, wherein at least 75 wt% of the near-azeotropic reservoir injection mixture consists of the recovered solvent stream and the treated water stream.

30. The method of any one of claims 1-28, wherein at least 90 wt% of the near-azeotropic reservoir injection mixture consists of the recovered solvent stream and the treated water stream.

31. The method of any one of claims 1-28, wherein at least 95 wt% of the near-azeotropic reservoir injection mixture consists of the recovered solvent stream and the treated water stream.

32. The method of any one of claims 1-28, wherein at least 99 wt% of the near-azeotropic reservoir injection mixture consists of the recovered solvent stream and the treated water stream.

33. The method of any one of claims 1-28, wherein the near-azeotropic reservoir injection mixture substantially consists of the recovered solvent stream and the treated water stream.

34.
A method for recovering viscous hydrocarbons from a subterranean reservoir, the method comprising:
a) drilling at least one well pair in a subterranean reservoir, wherein the well pair is comprised of an injection well and a production well, and the injection well is located at an elevation above the production well within the subterranean reservoir;
b) injecting a near-azeotropic reservoir injection mixture comprising steam and a solvent mixture into the subterranean reservoir via the injection well, wherein the near-azeotropic reservoir injection mixture is injected in the vapor phase;
c) producing a reservoir product stream comprising reduced-viscosity hydrocarbons, water, and a condensate; wherein the condensate comprises at least a portion of the solvent mixture;
d) adding a primary make-up solvent stream, a primary make-up water stream or a combination thereof to the reservoir product stream to produce a primary separation unit feedstream;
e) sending at least a portion of the primary separation unit feedstream to a primary separation unit, and producing a primary water stream, a primary gas vapor stream, and a heavy oil product stream;
f) sending at least a portion of the primary gas vapor stream to a gas separation unit; and producing a recovered solvent/water stream and an off gas stream;
g) adding a final make-up solvent stream, a final make-up water stream or a combination thereof to the recovered solvent/water stream to produce a final tailored reservoir solvent/water mixture, wherein a hydrocarbon solvent and water in the final tailored reservoir solvent/water mixture is compositionally at a near-azeotropic mixture at the subterranean reservoir operating conditions; and h) vaporizing at least a portion of the final tailored reservoir solvent/water mixture in at least one vapor generation unit;
wherein the near-azeotropic reservoir injection mixture comprises at least a portion of the vaporized final tailored reservoir solvent/water mixture.

35. The method of claim 34, wherein the hydrocarbon solvent and water in the primary gas vapor stream is compositionally at a near-azeotropic vapor mixture at the operating conditions of the primary separation unit.

36. The method of any one of claims 34 and 35, wherein the primary make-up solvent stream, the primary make-up water stream, or a combination thereof is added to the reservoir product stream to produce the primary separation unit feedstream wherein the hydrocarbon solvent and water in the primary separation unit feedstream is compositionally at a near-azeotropic mixture at the subterranean reservoir conditions.

37. The method of any one of claims 34-36, wherein the final make-up solvent stream, the final make-up water stream, or a combination thereof is added to the recovered solvent/water stream to produce the final tailored reservoir solvent/water mixture wherein the hydrocarbon solvent and water in the final tailored reservoir solvent/water mixture is compositionally at a near-azeotropic mixture at the subterranean reservoir conditions.

38. The method of any one of claims 34-37, wherein the composition of the near-azeotropic reservoir injection mixture is substantially the same as the final tailored reservoir solvent/water mixture.

39. The method of any one of claims 34-38, wherein the near-azeotropic reservoir injection mixture is injected into the subterranean reservoir via more than one injection well.

40. The method of any one of claims 34-39, wherein the near-azeotropic reservoir injection mixture is injected into the subterranean reservoir at 1 to 50 °C of superheat, measured with respect to the saturation temperature of the injected near-azeotropic reservoir injection mixture at an operating pressure of the subterranean reservoir.

41. The method of any one of claims 34-40, wherein the primary make-up solvent stream, the final make-up solvent stream, or both is comprised of hydrocarbons that have been produced by a source separate from the subterranean reservoir.

42. The method of claim 41, wherein the primary make-up solvent stream, the final make-up solvent stream, or both are comprised of a natural gas liquid, a natural gas condensate, a liquefied petroleum gas, or a crude oil refinery naphtha.

43. The method of any one of claims 34-42, wherein the near-azeotropic reservoir injection mixture is comprised of C4 to C12 hydrocarbons.

44. The method of any one of claims 34-43, wherein the primary gas vapor stream is comprised of C4 to C12 hydrocarbons.

45. The method of any one of claims 34-44, wherein hydrocarbons and solids are removed from the primary water stream in a water disposal treatment unit.

46. The method of any one of claims 34-45, wherein at least a portion of the primary separation unit feedstream is passed through a primary feedstream heater which is operated under conditions to heat the primary separation unit feedstream to the temperature in the primary separation unit necessary to produce the primary gas vapor stream such that the hydrocarbon solvent/water mixture within the primary gas vapor stream is produced at near-azeotropic conditions.

47. The method of any one of claims 34-46, wherein at least a portion of the primary separation unit feedstream is passed through a primary feedtream controller which is operate under conditions to maintain the pressure in the primary separation unit at a pressure necessary to produce the primary gas vapor stream such that the hydrocarbon solvent/water mixture within the primary gas vapor stream is produced at near-azeotropic conditions.

48. The method of any one of claims 34-47, wherein the solvent mixture is comprised of C4 to C12 hydrocarbons.

49. The method of any one of claims 34-48, wherein the solvent mixture consists of C4 to C12 hydrocarbons.

50. The method of any one of claims 34-49, wherein the at least one vapor generation unit comprises a heat exchanger, a steam heat exchanger, a hot oil heat exchanger, or a fired heater.

51. The method of claim 50, wherein at least a portion of the off gas stream is utilized as fuel to the fired heater.

52. The method of claim 51, wherein the off gas stream is comprised of CO2 and H2S
and at least a portion of the CO2 and the H2S in the off gas stream is removed in the gas separation unit.

53. The method of any one of claims 51 and 52, wherein a make-up fuel gas stream is added to the fuel gas stream prior to being utilized as fuel to the fired heater.

54. The method of any one of claims 34-53, wherein a diluent is added to at least a portion of the heavy oil product stream.

55. The method of any one of claims 34-54, wherein the primary separation unit is comprised of a single stage flash unit, a multiple-stage flash unit, a distillation/stripping column, or a combination thereof.

56. The method of any one of claims 34-55, wherein the gas separation unit is comprised of a single stage flash unit, a multiple-stage flash unit, a distillation/stripping column, or a combination thereof.

57. The method of any one of claims 34-56, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 30%+/- of the azeotropic solvent molar fraction of the final tailored reservoir solvent/water mixture at an operating pressure of the subterranean reservoir.

58. The method of any one of claims 34-56, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 70-110% of the azeotropic solvent molar fraction of the final tailored reservoir solvent/water mixture at an operating pressure of the subterranean reservoir.

59. The method of any one of claims 34-56, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 70-100% of the azeotropic solvent molar fraction of the final tailored reservoir solvent/water mixture at an operating pressure of the subterranean reservoir.

60. The method of any one of claims 34-56, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 80-100% of the azeotropic solvent molar fraction of the final tailored reservoir solvent/water mixture at an operating pressure of the subterranean reservoir.

61. The method of any one of claims 34-60, wherein at least 75 wt% of the near-azeotropic reservoir injection mixture consists of the final tailored reservoir solvent/water mixture.

62. The method of any one of claims 34-60, wherein at least 90 wt% of the near-azeotropic reservoir injection mixture consists of the final tailored reservoir solvent/water mixture.

63. The method of any one of claims 34-60, wherein at least 95 wt% of the near-azeotropic reservoir injection mixture consists of the final tailored reservoir solvent/water mixture.

64. The method of any one of claims 34-60, wherein the near-azeotropic reservoir injection mixture substantially consists of the final tailored reservoir solvent/water mixture.

65. A method for recovering viscous hydrocarbons from a subterranean reservoir, the method comprising:
a) drilling at least one well pair in a subterranean reservoir, wherein the well pair is comprised of an injection well and a production well, and the injection well is located at an elevation above the production well within the subterranean reservoir;
b) injecting a near-azeotropic reservoir injection mixture comprising steam and a solvent mixture into the subterranean reservoir via the injection well, wherein the near-azeotropic reservoir injection mixture is injected in the vapor phase;
c) producing a reservoir product stream comprising reduced-viscosity hydrocarbons, water, and a condensate; wherein the condensate comprises at least a portion of the solvent mixture;
d) sending at least a portion of the reservoir product stream to a primary separation unit, and producing a primary water stream, a primary vapor stream, and a primary hydrocarbon phase stream;
e) sending at least a portion of the primary hydrocarbon phase stream to a solvent separation unit; and producing a solvent vapor stream, and a heavy oil product stream;
f) sending at least a portion of the primary vapor stream and at least a portion of the solvent vapor stream to a primary gas separation unit;
g) sending at least a portion of the primary water stream to the primary gas separation unit;
h) producing a primary gas separation vapor stream and a primary gas separation liquid stream from the primary gas separation unit;
i) sending at least a portion of the primary gas separation liquid stream to a secondary gas separation unit;

j) sending at least a portion of the primary gas separation gas stream to a tertiary gas separation unit;
k) producing an off gas stream and a recovered solvent/water stream from the tertiary gas separation unit;
l) adding a final make-up solvent stream, a final make-up water stream, or a combination thereof to the recovered solvent/water stream to form a final tailored reservoir solvent/water mixture; wherein the solvent and water in the final tailored reservoir solvent/water mixture are at a near-azeotropic mixture; and m) vaporizing the final tailored reservoir solvent/water mixture in at least one vapor generation unit;
wherein the near-azeotropic reservoir injection mixture comprises at least a portion of the vaporized final tailored reservoir solvent/water mixture.

66. The method of claim 65, further comprising:
producing a secondary gas separation vapor stream and a secondary gas separation liquid stream from the secondary gas separation unit.

67. The method of claim 66, further comprising:
combining a portion of the secondary gas separation vapor stream with at least a portion of the secondary gas separation vapor stream prior to the tertiary gas separation unit.

68. The method of any one of claims 66 and 67, wherein secondary gas separation liquid stream comprises water and less than 10 wt%, 5 wt% or 2 wt%
hydrocarbons.

69. The method of any one of claims 66-68, wherein at least a portion of the secondary gas separation liquid stream is sent to a water disposal treatment unit, wherein hydrocarbons and solids are removed from the secondary gas separation liquid stream.

70. The method of any one of claims 65-69, wherein at least a portion of the primary gas separation liquid stream is vaporized prior to the secondary gas separation unit.

71. The method of any one of claims 65-70, wherein a gas treating make-up solvent stream is added to the primary gas separation liquid stream.

72. The method of any one of claims 65-71, wherein at least a portion of the secondary gas separation vapor stream is condensed prior to the tertiary gas separation unit.

73. The method of any one of claims 65-72, wherein the solvent and water in the primary vapor stream is compositionally at a near-azeotropic mixture at the primary separation unit operating conditions.

74. The method of any one of claims 65-73, wherein the solvent and water in the solvent vapor stream is compositionally at a near-azeotropic mixture at the solvent separation unit operating conditions.

75. The method of any one of claims 65-74, wherein the solvent and water in the primary gas separation vapor stream is compositionally at a near-azeotropic mixture at the primary gas separation unit operating conditions.

76. The method of any one of claims 66-75, wherein the solvent and water in the secondary gas vapor stream is compositionally at a near-azeotropic mixture at the secondary gas separation unit operating conditions.

77. The method of any one of claims 65-76, wherein the composition of the first near-azeotropic reservoir injection mixture is substantially the same as the final tailored reservoir solvent/water mixture.

78. The method of any one of claims 65-77, wherein the near-azeotropic reservoir injection mixture is injected into the subterranean reservoir via more than one injection well.

79. The method of any one of claims 65-78, wherein the near-azeotropic reservoir injection mixture is injected into the subterranean reservoir at 1 to 50 °C of superheat, measured with respect to the saturation temperature of the injected near-azeotropic reservoir injection mixture at an operating pressure of the subterranean reservoir.

80. The method of claim 71, wherein the gas treating make-up solvent stream is comprised of hydrocarbons that have been produced by a source separate from the subterranean reservoir.

81. The method of claim 80, wherein the gas treating make-up solvent stream is comprised of a natural gas liquid, a natural gas condensate, a liquefied petroleum gas, or a crude oil refinery naphtha.

82. The method of any one of claims 65-81, wherein the final make-up solvent stream is added to the recovered solvent/water stream and the final make-up solvent stream is comprised of hydrocarbons that have been produced by a source separate from the subterranean reservoir.

83. The method of claim 82, wherein the final make-up solvent stream is comprised of a natural gas liquid, a natural gas condensate, a liquefied petroleum gas, or a crude oil refinery naphtha.

84. The method of any one of claims 65-83, wherein the near-azeotropic reservoir injection mixture is comprised of C4 to C12 hydrocarbons.

85. The method of any one of claims 65-84, wherein the primary vapor stream is comprised of C4 to C12 hydrocarbons.

86. The method of any one of claims 65-85, wherein at least a portion of the primary separation unit feedstream is passed through a primary feedtream heater which is operated under conditions to heat the primary separation unit feedstream to the temperature in the primary separation unit necessary to produce the primary gas vapor stream such that the solvent/water mixture within the primary vapor stream is produced at near-azeotropic conditions.

87. The method of any one of claims 65-86, wherein at least a portion of the primary separation unit feedstream is passed through a primary feedtream controller which is operate under conditions to maintain the pressure in the primary separation unit at a pressure necessary to produce the primary vapor stream such that the solvent/water mixture within the primary gas vapor stream is produced at near-azeotropic conditions.

88. The method of any one of claims 65-87, wherein the solvent mixture is comprised of C4 to C12 hydrocarbons.

89. The method of any one of claims 65-88, wherein the solvent mixture consists of C4 to C12 hydrocarbons.

90. The method of any one of claims 65-89, wherein the at least one vapor generation unit comprises a heat exchanger, a steam heat exchanger, a hot oil heat exchanger, or a fired heater.

91. The method of claim 90, wherein at least a portion of the off gas stream is utilized as fuel to the fired heater.

92. The method of any one of claims 65-91, wherein the off gas stream is comprised of CO2 and H2S and at least a portion of the CO2 and the H2S in the off gas stream is removed from the off gas stream.

93. The method of any one of claims 65-92, wherein a make-up fuel gas stream is added to the off gas stream prior to being utilized as fuel to the fired heater.

94. The method of any one of claims 65-93, wherein a diluent is added to at least a portion of the heavy oil product stream.

95. The method of any one of claims 65-94, wherein the primary separation unit, the primary gas separation unit, the secondary gas separation unit, or the tertiary gas separation unit is comprised of a single stage flash unit, a multiple-stage flash unit, a distillation/stripping column, or a combination thereof.

96. The method of any one of claims 65-95, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 30%+/- of the azeotropic solvent molar fraction of the final tailored reservoir solvent/water mixture at an operating pressure of the subterranean reservoir.

97. The method of any one of claims 65-95, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 70-110% of the azeotropic solvent molar fraction of the final tailored reservoir solvent/water mixture at an operating pressure of the subterranean reservoir.

98. The method of any one of claims 65-95, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 70-100% of the azeotropic solvent molar fraction of the final tailored reservoir solvent/water mixture at an operating pressure of the subterranean reservoir.

99. The method of any one of claims 65-95, wherein the solvent mole fraction of the near-azeotropic reservoir injection mixture is 80-100% of the azeotropic solvent molar fraction of the final tailored reservoir solvent/water mixture at an operating pressure of the subterranean reservoir.

100. The method of any one of claims 65-99, wherein at least 75 wt% of the near-azeotropic reservoir injection mixture consists of the final tailored reservoir solvent/water mixture.

101. The method of any one of claims 65-99, wherein at least 90 wt% of the near-azeotropic reservoir injection mixture consists of the final tailored reservoir solvent/water mixture.

102. The method of any one of claims 65-99, wherein at least 95 wt% of the near-azeotropic reservoir injection mixture consists of the final tailored reservoir solvent/water mixture.

103. The method of any one of claims 65-99, wherein the near-azeotropic reservoir injection mixture substantially consists of the final tailored reservoir solvent/water mixture.