CA2981619C - Optimization of solvent selection in a solvent-based oil recovery process - Google Patents

Abstract

The present disclosure comprises methods to model the a solvent-based oil recovery process on an economic return basis as a function of the normal. boiling point (NBP) ranges of available solvents in order to provide the user a simple and encompassing method for selecting the appropriate solvent NBP from which to obtain a preferred solvent (i.e., solvent NBP range) or tailor the recovered solvent to within a specific NBP range for reinjection in solvent-based oil recovery process. The primary variables for building the economic function are Oil Production Rate (OPR), the Solvent + Steam to Oil Ratio (Sol+StOR), the Solvent to Oil Ratio (SolOR), the Steam to Oil Ratio (StOR), and the Energy to Oil Ratio (EnOR). This method can be utilized on any type of solvent-based oil recovery process or system.

Description

J.
OPTIMIZATION OF SOLVENT SELECTION IN A SOLVENT-BASED OIL
RECOVERY PROCESS
BACKGROUND
Field of Disclosure [0001] The present disclosure relates to production of oil from a subterranean reservoir in a solvent-based oil recovery process through the optimization of solvent selection based on based on economic optimization as a function of solvent selection, variable reservoir production parameters and associated costs.
Description of Related Art

[0002] This section is intended to introduce various aspects of the art. This discussion is believed to facilitate a better understanding of particular aspects of the present techniques.
Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0003] Modern society is greatly dependent on the use of hydrocarbon resources for fuels and chemical feedstocks. Subterranean rock formations that can be termed "reservoirs" may contain resources such as hydrocarbons that can be recovered. Removing hydrocarbons from the subterranean reservoirs depends on numerous physical properties of the subterranean rock formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the subterranean rock formations, and the proportion of hydrocarbons present, among other things.

[0004] Easily produced sources of hydrocarbons are dwindling, leaving less conventional sources to satisfy future needs. As the costs of hydrocarbons increase, less conventional sources become more economical. One example of less conventional sources becoming more economical is that of oil sand production. The hydrocarbons produced from less conventional sources may have relatively high viscosities, for example, ranging from 1000 centipoise (cP) to 20 million cP with American Petroleum Institute (API) densities ranging from 8 degree ( ) API, or lower, up to 200 API, or higher. The hydrocarbons recovered from less conventional sources may include heavy oil. However, the hydrocarbons produced from 7.
the less conventional sources may be difficult to recover using conventional techniques. For example, the heavy oil may be sufficiently viscous that economical production of the heavy oil from a subterranean formation (also referred to as a "subterranean reservoir" herein) is precluded.

[0005] Several conventional recovery processes, such as but not limited to thermal recovery processes, have been utilized to decrease the viscosity of the heavy oil. Decreasing the viscosity of the heavy oil may decrease a resistance of the heavy oil to flow and/or permit production of the heavy oil from the subterranean reservoir by piping, flowing, and/or pumping the heavy oil from the subterranean reservoir. While each of these recovery processes may be effective under certain conditions, each possess inherent limitations.

[0006] One of the conventional recovery processes utilizes steam injection. The steam injection may be utilized to heat the heavy oil to decrease the viscosity of the heavy oil.
Water and/or steam may represent an effective heat transfer medium, but the pressure required to produce saturated steam at a desired temperature may limit the applicability of steam injection to high pressure operation and/or require a large amount of energy to heat the steam.

[0007] Another of the conventional recovery processes utilizes cold and/or heated solvents. Cold and/or heated solvents may be injected into a subterranean reservoir as liquids and/or vapors to decrease the viscosity of heavy oil present within the subterranean reservoir.
Traditionally, pure (i.e., single-component), or at least substantially pure, propane is injected into the subterranean reservoir as the cold and/or heated solvent. The injected propane may dissolve the heavy oil, dilute the heavy oil, and/or transfer thermal energy to the heavy oil.
Utilizing the cold and/or heated solvents may suffer from limited injection temperature and/or pressure operating ranges, and/or an inability to effectively decrease the viscosity of the heavy oil. In other recovery processes, the injected fluid may be substantially comprised of a hydrocarbon-based solvent and injected in a vaporized form.

[0008] However, in these processes, a single solvent composition is usually selected and maintained throughout the process. This is generally due to the lack of knowledge of changes that may be made in the selection in the composition the solvent being utilized and its overall economic that such changes may have on the process. Additionally, these solvent - -composition/economic relationships may change over time, due to either internal factors, such as changes in the reservoir or well properties or operating conditions, or to external factors, such as the cost to supply new/makeups solvents from sources separate to the reservoir operation or the value of the oil product produced from the reservoir. As such, without a comprehensive economic analysis of at least some of these reservoir variables and key performance indicators of the process, preferably performed over multiple periods of time, especially associated with changes in these internal and/or external factors, significant economic return can be lost to the use of non-optimal solvent composition selections.

[0009] A need therefore exists in the industry for improved technology, including to technology for methods enabling the optimization of solvent composition based on the significant economic effects for the overall solvent-based oil recovery system. A need exists for a system of economic analysis and modification and tailoring of solvents, and/or alternatively operating based on economic analyses for maximizing overall economic productivity of the overall recovery system.
SUMMARY

[0010] It is an object of the present disclosure to provide systems and methods for the optimization of solvent selection based on based on economic optimization as a function of solvent selection, variable reservoir production parameters and associated costs.

[0011] In a preferred embodiment herein is a method for optimizing a solvent-based oil recovery process for a subterranean reservoir, comprising:
a) selecting an operating pressure for the subterranean reservoir;
b) selecting an available range of proposed hydrocarbon solvents;
c) determining a first normal boiling point range for the proposed hydrocarbon solvents;
d) determining an economic return as a function of the first normal boiling point range for the proposed hydrocarbon solvents;
e) determining a second normal boiling point range for the proposed hydrocarbon solvents, corresponding to an optimum range of the economic return;

f) injecting a solvent mixture comprising a portion of the proposed hydrocarbon solvents which fall within the second normal boiling point range into the subterranean reservoir using a solvent-based oil recovery process; and g) recovering a product stream comprising oil from the subterranean reservoir.

[0012] In preferred embodiments, the economic return a function of at least one of the Oil Production Rate (OPR), the Solvent + Steam to Oil Ratio (Sol+StOR), the Solvent to Oil Ratio (SolOR), the Steam to Oil Ratio (StOR), and the Energy to Oil Ratio (EnOR).

[0013] In other preferred embodiments, the solvent mixture is in its vapor phase when injected into the subterranean reservoir. In other preferred embodiments, the steam is injected with the solvent mixture into the subterranean reservoir.

[0014] 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

[0015] 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.

[0016] Figure 1 is a simplified schematic representation of an example of a solvent-based oil recovery system.

[0017] Figure 2 illustrates the collective dew point curves of vapor mixtures of n-alkanes solvents with water at 1.5 MPa pressure.

[0018] Figure 3 illustrates the dew point temperature and water content of azeotropic vapor mixtures of n-alkanes solvents with water at 1.5 MPa pressure.

[0019] Figure 4 is a generic representation of the water-oil relative permeability curves for a heavy oil reservoir.

[0020] Figure 5 illustrates a generic example of the oil production rate (OPR) and the energy loss to reservoir per unit volume of oil produced (EnOR) as a function of the injected solvent normal boiling point (NBP).
100211 Figure 6 is a graph showing the latent heat of vaporization content of azeotropic vapor mixtures of n-alkanes solvents with water at 1.5 MPa pressure.
[0022] Figure 7 illustrates a generic example of the Solvent to Oil Ratio (SolOR), the Steam to Oil Ratio (StOR), and the Solvent + Steam to Oil Ratio (Sol+StOR) process key performance indicators as a function of the solvent normal boiling point (NBP).
[0023] Figure 8 illustrates a generic example of Oil Production Rate (OPR), the Solvent +
Steam to Oil Ratio (Sol+StOR), the Energy to Oil Ratio (EnOR), the Solvent to Oil Ratio (SolOR), and the Steam to Oil Ratio (StOR) as a function of the injected solvent normal boiling point (NBP) and identifies individual preferred ranges for these process key performance indicators based on economic criteria.
[0024] Figure 9 illustrates a combined, single economic return relationship per unit volume of oil produced as a function of solvent NBP based on several process key performance indicators as illustrated in Figure 8.
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DETAILED DESCRIPTION
[0025] 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.
[0026] 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.
[0027] 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.
[0028] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.)% aliphatics (which can range from 5 wt.% - 30 wt.%, or higher);
19 wt.% asphaltenes (which can range from 5 wt.% - 30 wt.%, or higher);
30 wt.% aromatics (which can range from 15 wt.% - 50 wt.%, or higher);
32 wt.% resins (which can range from 15 wt.% - 50 wt.%, or higher); and some amount of sulfur (which can range in excess of 7 wt.%).
[0029] The percentage of the hydrocarbon types found in bitumen can vary.
In addition bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt.% to in excess of 0.7 wt.%. The metals content, while small, may be removed to avoid contamination of synthetic crude oil. Nickel can vary from less than 75 ppm (parts per million) to more than 200 ppm. Vanadium can range from less than 200 ppm to more than 500 ppm.
[0030] The term "heavy oil" includes bitumen, as well as lighter materials that may be found in a sand or carbonate reservoir. "Heavy oil" includes oils that are classified by the American Petroleum Institute (API), as heavy oils, extra heavy oils, or bitumens. Thus the term "heavy oil" includes bitumen. Heavy oil may have a viscOsity of about 1000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more or 1,000,000 cP or more.
In general, a heavy oil has an API gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.00 API (density of 1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than 10.0 API
(density greater than 1,000 kg/m3 or greater than 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water, and bitumen. The recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluids by steam, hot water flooding, or gravity is possible.
The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.
A heavy oil may include heavy end components and light end components.
[0031] 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.
[0032] "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.
100331 "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.
[0034] 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.
[0035] "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.
[0036] "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.
[0037] A "subterranean reservoir" is a subsurface rock or sand reservoir from which a production fluid, or resource, can be harvested. A
subterranean reservoir may interchangeably be referred to as a subterranean formation. The subterranean formation may include sand, granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy oil (e.g., bitumen), oil, gas, or coal, among others. Subterranean reservoirs can vary in thickness from less than one foot (0.3048 meters (m)) to hundreds of feet (hundreds of meters). The resource is generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.
[0038] "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.
[0039] "Solvent-based recovery processes" include any type of hydrocarbon recovery process that uses a solvent, at least in part, to enhance the recovery, for example, by diluting or lowering a viscosity of the hydrocarbon. Solvent-based recovery processes may be used in combination with other recovery processes, such as, for example, thermal recovery processes.
In solvent-based recovery processes, a solvent is injected into a subterranean reservoir. The solvent may be heated or unheated prior to injection, may be a vapor or liquid and may be injected with or without steam. Solvent-based recovery processes may include, but are not limited to, solvent assisted cyclic steam stimulation (SA-CSS), solvent assisted steam assisted gravity drainage (SA-SAGD), solvent assisted steam flood (SA-SF), vapor extraction process (VAPEX), heated vapor extraction process (H-VAPEX), cyclic solvent process (CSP), heated cyclic solvent process (H-CSP), solvent flooding, heated solvent flooding, liquid extraction process, heated liquid extraction process, solvent-based extraction recovery process (SEP), thermal solvent-based extraction recovery processes (TSEP), and any other such recovery process employing solvents either alone or in combination with steam. A
solvent-based recovery process may be a thermal recovery process if the solvent is heated prior to injection into the subterranean reservoir. The solvent-based recovery process may employ gravity drainage.

[0040] "Steam to Oil Ratio" (or "StOR") is the ratio of a volume of steam (in cold water equivalents) required to produce a unit volume of oil. Cumulative StOR
("CStOin is the cumulative average volume of steam (in cold water equivalents) over the life of the operation required to produce a unit volume of oil. Instantaneous ("IStOR") is the instantaneous rate of steam (in cold water equivalents) required to produce a unit volume of oil.
StOR, CStOR, and IStOR are calculated at standard temperature and pressure ("STP", 15 C and 100kPa or 60 F and 14.696 psi).
[0041] Likewise, "Solvent to Oil Ratio" (or "SolOR") is the ratio of a volume of solvent (in cold liquid equivalents) required to produce a unit volume of oil.
"Cumulative SolOR" (or "CSolOW) is the cumulative average volume of solvent (in cold liquid equivalents) over the life of the operation required to produce a unit volume of oil. "Instantaneous SolOR" (or "ISolOR") is the instantaneous rate of solvent required to produce a unit volume of oil.
SolOR, CSolOR, and ISolOR are calculated at STP.
[0042] The "Solvent + Steam to Oil Ratio" (or "(Sol+St)OR") is the volume of steam +
solvent (both in cold liquid equivalents, calculated at STP) required to produce a unit volume of oil.
[0043] "Energy to Oil Ratio" (or "EnOR") is the ratio of the cumulative required energy magnitudes (including losses to reservoir, overburden and underburden) to produce a unit volume of oil.
[0044] "Oil Production Rate" (or "OPR") is the amount of oil produced from the reservoir per unit time. Herein the amount of oil produced includes all hydrocarbons produced from the reservoir, less the amount of recovered solvent from the reservoir.
[0045] "Azeotrope" means the thermodynamic azeotrope as described further herein.
[0046] A "wellbore" is a hole in the subsurface made by drilling or inserting a conduit .. into the subsurface. A wellbore may have a substantially circular cross section or any other cross-sectional shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. The term "well," when referring to an opening in the formation or reservoir, may be used interchangeably with the term "wellbore." Further, multiple pipes may be inserted into a single wellbore, for example, as a liner configured to allow flow from an outer chamber to an inner chamber.
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[0047] "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).
[0048] "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.
to [0049] 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 (%) 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 volA water with any remainder possibly being heavy oil.
[0050] 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.

[0051] 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.
[0052] 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.
[0053] 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.
[0054] 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.
[0055] 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.
[0056] 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.
100571 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.
100581 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.
100591 Figures 1-9 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 1-9, and these elements may not be discussed in detail herein with reference to each of Figures 1-9. Similarly, all elements may not be labeled in each of Figures 1-9, 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 1-9 may be included in and/or utilized with any of Figures 1-9 without departing from the scope of the present disclosure.
[0060] Figure 1 is a non-limiting schematic representation of a hydrocarbon production system 10 that may be utilized with, may be included in, and/or may include the systems and methods according to the present disclosure. Figure 1 is utilized only to assist in explaining the details of 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. For purposes of illustration, the hydrocarbon production system 10 may include an injection well 30 and a production well 70 that extend within a subterranean reservoir 24 that is present within a subsurface region 22 and/or that extend between a surface region 20 and the subterranean reservoir 24.
Hydrocarbon production system 10 may include a surface facility 40. Surface facility 40 may be configured to receive a reservoir heavy oil product stream 72 from production well 70. A
reservoir heavy oil product stream 72 may be produced from the subterranean reservoir 24.
Surface facility 40 may be configured to provide a reservoir injection mixture 32 to injection well 30.
[0061] The reservoir injection mixture 32 may be in liquid form, vapor form, or both.
The reservoir injection mixture preferably is comprised of a steam and a solvent mixture.
The solvent mixture is comprised of hydrocarbons. In preferred embodiments, the solvent mixture is substantially comprised of hydrocarbons, or even essentially comprised of hydrocarbons. In the preferred processes herein, the normal boiling point of the solvent mixture is selected such as to maximize the overall economic return of the oil recovery process based on one or more process key performance indicators.
[0062] When the reservoir injection mixture 32 comprises a vaporous hydrocarbon solvent mixture, the solvent-based recovery process may be referred to as, or may be, a vapor extraction process (VAPEX). Preferably, the reservoir injection mixture 32 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 another preferred embodiment, the reservoir injection mixture is comprised of at least 80% by weight of the steam and the solvent mixture. In other preferred embodiments, the reservoir injection mixture is comprised of at least 90% or.95% by weight of the steam and the solvent mixture, more preferably, is comprised essentially of the steam and the solvent mixture.
[0063] 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% , 95 wt% or 99 wt% of the reservoir injection mixture is hydrocarbon compounds.
[0064] When the solvent-based recovery process is performed using heated solvent, the solvent-based recovery process may be referred to as a high temperature solvent (and/or vapor) solvent-based recovery process. The heated solvent may be injected into the subterranean reservoir at an injection temperature and an injection pressure.
The injection temperature may be at, or near, a saturation temperature for the heated solvent at the injection pressure. When more than one solvent is utilized, the extraction process may be referred to as a multi-solvent-based recovery process and/or a multi-component solvent-based recovery process, which, at elevated temperatures, may be referred to as a high temperature multi-component solvent-based recovery process, which may be a high temperature multi-component vapor extraction process.
[0065] Once provided to subterranean reservoir 24, the reservoir injection mixture 32 may combine with the bituminous hydrocarbon deposit 25 within a solvent extraction chamber 60, may dilute the bituminous hydrocarbon deposit 25, may dissolve in the bituminous hydrocarbon deposit 25, and/or may dissolve the bituminous hydrocarbon deposit 25, thereby decreasing the viscosity of the bituminous hydrocarbon deposit.
When reservoir injection mixture 32 is a vaporous hydrocarbon solvent mixture, solvent extraction chamber .. 60 may be referred to as a vapor chamber 60. The vaporous hydrocarbon solvent mixture may condense within vapor chamber 60. When reservoir injection mixture 32 condenses, the µ, hydrocarbon solvent mixture may release latent heat (or latent heat of condensation), transfer thermal energy to the subterranean reservoir, and/or generate a condensate 34.
Condensation of the reservoir injection mixture 32 may heat a bituminous hydrocarbon deposit 25 that may be present within the subterranean reservoir, thereby decreasing a viscosity of the bituminous hydrocarbon deposit. 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.
[0066] The bituminous hydrocarbon deposit 25 may include bitumen, gaseous hydrocarbons, asphaltenes, and/or water. The reservoir injection mixture 32 and/or condensate 34 also may combine with, mix with, be dissolved in, dissolve, and/or dilute bituminous hydrocarbon deposit 25, further decreasing the viscosity of the bituminous hydrocarbon deposit.
[0067] The energy transfer between the reservoir injection mixture 32 and bituminous hydrocarbon deposit 25 and/or the mixing of reservoir injection mixture 32 and/or condensate 34 with bituminous hydrocarbon deposit 25 may generate reduced-viscosity hydrocarbons 74, which may flow to production well 70. The reduced-viscosity hydrocarbons 74 may flow to production well 70 due to gravity. After flowing to production well 70, a reservoir product stream 72 containing heavy oil is produced from the subterranean reservoir.
The reduced-viscosity hydrocarbons 74 may have a lower viscosity than the hydrocarbons within the subterranean reservoir 24 had before the reservoir injection mixture 32 was injected into the subterranean reservoir 24. The reservoir product stream 72 may comprise reduced-viscosity hydrocarbons 74, asphaltenes, gaseous hydrocarbons, water, reservoir injection mixture 32, and/or condensate 34 in any suitable ratio and/or relative proportion.
[00681 Surface facility 40 may process the reservoir product stream 72 and/or may separate the reservoir product stream 72 into one or more component streams prior to the product hydrocarbon stream being conveyed from the surface facility 40.
Surface facility 40 may separate reservoir product stream 72 into a bitumen product stream 42, a gaseous hydrocarbon product stream 44, an asphaltene product stream 48, a solvent mixture 35, a separated surplus solvent stream 49, and/or a water product sti-eam 46, which may include water 29. The bitumen product stream 42 may include bitumen and/or asphaltenes. The gaseous hydrocarbon product stream 44 may include gaseous hydrocarbons. The asphaltene product stream 48 may include asphaltenes. The separated surplus solvent stream 49 may include a portion of hydrocarbon solvent mixture 32 that was produced with the reservoir heavy oil product stream 72. The surplus solvent stream 49 may be referred to as an undesired solvent stream, an unwanted solvent stream, and/or an excess solvent stream.
Surplus solvent stream 49 may be generated as a result of adjustments to the solvent mixture composition. Surplus solvent stream 49 may be generated as a result of removing some of the solvents in the reservoir product stream 72 that are not wanted or desired to be in the solvent mixture 35 or the reservoir injection mixture 32. The surplus solvent stream 49 may be mixed as a diluting agent, blending agent, and/or viscosity-reducing agent with the bitumen product stream 42 to facilitate shipment by pipelines.
[0069] Surface facility 40 may generate a solvent mixture 35 from any suitable source.
The solvent mixture may comprise hydrocarbons that have been produced by a source separate from the subterranean reservoir. For example, the solvent mixture may comprise a natural gas liquid, a natural gas condensate, a liquefied petroleum gas, or a crude oil refinery naphtha. Surface facility 40 may receive a supplemental solvent stream 31 and/or may supply at least a portion of the solvent mixture 35 recovered from the reservoir product stream 72 as a part of the reservoir injection stream 32 to injection well 30.
Surface facility 40 may separate at least a portion of gaseous hydrocarbon product stream 44, solvent mixture 35, and/or condensate 34 from the reservoir product stream 72. Surface facility 40 may recycle and/or re-inject a portion of the gaseous hydrocarbon product stream 44, separated solvent mixture 35, and/or separated condensate 34 into injection well 30 as components of the reservoir injection mixture 32. Additional steam 50 may be added to the surface facility 40 and/or injected directly as part of the reservoir injection stream 32. The solvent mixture 35 may additionally include a supplemental solvent stream 31. The composition of the supplemental solvent stream 31 may be similar in composition to the solvent mixture 35 wherein its main purpose is to add additional solvent to the solvent mixture 35 for the reservoir injection mixture 32. Alternatively, the supplemental solvent stream 31 may be tailored to adjust the composition of the overall solvent mixture 35 for the reservoir injection mixture 32, as well as additionally supply additional solvent to the overall process to make up for losses in the subterranean reservoir and/or losses due to the surface facility processing and solvent recovery. In an embodiment, at least a portion of the reservoir product stream 72 is shown sent to a flash unit which separates the product stream into the bitumen (or heavy oil) product stream 42 and the solvent mixture 35, the latter of which may recycled for injection into the solvent-based oil recovery process. In other embodiments, at least a portion of the reservoir product stream 72 may be sent to a single stage flash unit or a multistage flash unit which separates the product stream into the heavy oil product stream 42, the recovered solvent mixture 35, and the separated surplus solvent stream 49. The flash unit may be a two-stage flash unit. In other embodiments, at least a portion of the reservoir product stream 72 may be sent to a separation unit comprising a multistage distillation unit which separates the product stream into the heavy oil product stream 42, the solvent mixture 35, and the separated surplus solvent stream 49. In any of these embodiments, the operational variables of the single stage flash unit, the multistate flash unit, or the multistage distillation unit may be regulated to tailor the composition of the solvent mixture 35 to the recommend range of the solvent normal boiling point by the this disclosed method. The operational variables may include the flash temperature and pressure in each flash units. In preferred embodiments, the operational variables of the single stage flash unit, the multistate flash unit, or the multistage distillation unit are regulated to match the composition of the solvent mixture to the an optimized normal boiling point range for the process.
[0070] Conventional recovery processes that utilize an injected vapor stream to decrease the viscosity of hydrocarbons may utilize a pure (i.e., single-component), or at least substantially pure, injected vapor stream that comprises a light hydrocarbon, such as propane.
In contrast, the systems and methods according to the present disclosure may utilize a solvent mixture 35. The solvent mixture 35 may include a hydrocarbon fraction that comprises, consists of, or consists essentially of C4 to C11 hydrocarbons, or C5 to C9 hydrocarbons. The solvent mixture 35 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.
[0071] Theoretically, available solvents to use in present solvent-based oil recovery processes can range from light hydrocarbon mixtures such as NGLs, and LPGs to heavy fractions such as different refinery streams. The concept disclosed herein proposes a new methodology for selecting a solvent-based oil recovery process and determining an optimum range of the normal boiling point of the potential injection solvent compounds. This concept relies on: 1) identification of key physical phenomena (phase behavior and flow dynamics) affecting the performance of a solvent-based oil recovery process based on different solvents as characterized by their boiling point, and in the case of solvent mixtures, the solvent mixture average, or normal boiling point ("NBP"), 2) test and analysis of the outcome of the intermingling mechanisms on process performance using available performance prediction tools; and 3) development of the selection methodology and recommendation of an optimum compositional range of the solvent mixture. The key performance indicators of the recovery process utilized herein are considered as: the oil production rate ("OPR"), the solvent to oil ratio per unit volume of oil produced ("SolOR"), the steam to oil ratio ("StOR") per unit volume of oil produced, the combined solvent and steam ratio per unit volume of oil produced ("(Sol+St)OR"), and the energy per unit volume of oil produced ("EnOR").
100721 To further describe the currently disclosed embodiments, non-limiting descriptions using near-azeotropic heated VAPEX (AH-VAPEX) recovery process configurations will be referred to herein. Figure 2 demonstrates the collective dew point curves of vapor mixtures of n-alkanes solvents with water at 1.5 MPa pressure as an example to describe the azeotropic behaviors of solvent-water vapor mixtures. A
hydrocarbon solvent mixture of similar boiling range behaves similarly as what is seen for the pure n-alkanes example of Figure 2. Light hydrocarbon solvents (including C3) do not form azeotropic mixtures with water; hence, the minimum dew point temperature of their mixtures with water is equal to the saturation temperature of the solvent. As a consequence, any co-injected steam with these solvents will condense first, and the effective operating temperature of the recovery process with these solvents is the saturation temperature of the solvent at the operating pressure. Medium and heavy molecular weight hydrocarbons form minimum boiling-temperature azeotropic mixtures with water in vapor phase as shown for n-alkanes solvents (nC4-nCi2) in Figure 2. Hence, the near-azeotropic mixture of any of these solvent compositions with water will travel through the depleted chamber within reservoir to the recovery interface and will condense at the azeotropic temperature and concentrations.

=
Figure 3 summarizes the key properties of the azeotropic mixtures of these compounds with water at pressure of 1.5 MPa. The heavier the solvent is in the solvent-water vapor mixture, the higher is the azeotropic temperature of the vapor mixture. The azeotropic temperature of the solvent-water mixtures increases monotonically toward an asymptote which is equal to the steam saturation pressure at given pressure. Hence, the heavier the injected solvent is for AH-VAPEX process, the greater is the temperature at oil recovery interface.
One can expect higher oil recovery rates with use of heavier solvents in AH-VAPEX process (tending to an asymptote) if only process temperature is considered. However, the azeotropic vapor injection mixture of heavier solvents holds more water in the form of steam as depicted in Figure 3 in liquid-equivalent volume fractions. Consequently, the volume of condensed water per unit volume of condensed solvent on the oil recovery interface will be higher for an azeotropic vapor injection solvent mixture of heavier carbon content solvents.
Increased volume of condensed water in drainage interface will potentially result in considerable decrease in liquid hydrocarbon phase drainage rate due to decrease in oil phase effective permeability. Figure 4 illustrates a generic relative permeability curves of the oil and water phases, wherein Ko is the relative permeability for the oil phase, lc, is the relative permeability for the water phase, and S, is the water saturation. As can be seen in the relative permeability curves of Figure 4, relative permeability to oil phase drops 50% when water saturation increases from irreducible value to 40%. Hence, if only isolated effects are considered, the oil recovery rate will increase with use of heavier solvent due to higher process temperature but will decrease due to higher condensed volumes on the drainage interface. These opposing trends show that the selection. along a range of solvent compositions (i.e., characterized by NBP) will have differing effects on the efficiency of oil recovery from the reservoir, solvent recovery from the reservoir, as well as optimum steam use per unit volume of oil recovered and the required energy per unit volume of oil recovered.
[0073] The analytical modeling analysis and numerical simulation results illustrate this concept for a single set of reservoir conditions in Figure 5 illustrating the oil production rate (OPR) and the energy per unit volume of oil produced (EnOR) as a function of the solvent NBP. The increasing trend of azeotropic temperature with solvent boiling point (Figure 3) implies that more heat will be lost to the reservoir to produce unit volume of oil (EnOR) with

- 21 -heavier solvents in an AH-VAPEX process as confirmed by numerical simulation results of Figure 5. However, the near azeotropic injection mixture of heavier solvents are more efficient for delivering heat due to higher water vapor content. According to Figure 6, the available latent heat upon condensation of the injection mixtures of heavier compounds are greater per volume of injected/recycled solvent. In general, the heavier the solvent is for an AH-VAPEX process, the lower is the SolOR, the higher is the StOR and lower is the total working/injection fluid in circulation. Figure 7 illustrates these opposing trends based on numerical simulation results.
100741 Figure 8 illustrates a generic example of Oil Production Rate (OPR), the Solvent +
Steam to Oil Ratio (Sol+StOR), the Energy to Oil Ratio (EnOR), the Solvent to Oil Ratio (SolOR), and the Steam to Oil Ratio (StOR) as a function of the solvent normal boiling point (NBP) and identifies individual preferred ranges for these variables based on economic criteria. As is illustrated in Figure 8, the optimum economic operating range of each of these process key performance indicators alone may lie in different spectrums of the overall NBP
distribution which do not coincide, or in cases, do not overlap with the NBP
corresponding to the optimum values of the other process key performance indicators. In illustrative Figure 8, "range A" shows a range of economically available solvents for use in the solvent-based oil recovery process. In Figure 8, "range B" illustrates the optimum range of solvents for maximizing the Oil Production Rate (OPR) as a function of the solvent normal boiling point (NBP). In similar fashion, "range C" illustrates the optimum range of solvents for minimizing the Solvent + Steam to Oil Ratio (Sol+StOR) as a function of the solvent normal boiling point (NBP); "range D" illustrates the optimum range of solvents for minimizing the Energy to Oil Ratio (EnOR) as a function of the solvent normal boiling point (NBP); "range E" illustrates the optimum range of solvents for minimizing the Solvent to Oil Ratio (SolOR) as a function of the solvent normal boiling point (NBP); and "range F"
illustrates the optimum range of solvents for minimizing the Steam to Oil Ratio (StOR) as a function of the solvent normal boiling point (NBP).
100751 The OPR, (Sol+St)OR, ENOR, SolOR, and STOR as shown on Figure 8, can all be characterized through economic relationships and corresponding algorithms to convert each of these process key performance indicators into an economic return (which may contain negative values where the relationship results in an overall economic cost) per unit _22 _ volume of oil produced as a function of solvent NBP. This concept is illustrated in Figure 9.
As can be seen in Figure 9, the economic return per unit volume of oil produced shows a maxima associated with an NBP value. Figure 9 illustrates a range of optimum solvent range for maximizing the overall economic return that may be selected to bound the maxima of the overall economic return. The upper and lower bounds of this range may be selected by the user by any criteria that may be meaningful in this analysis. . In embodiments herein, the normal boiling point range for the optimum solvent mixture may fall within 100 C +/-, 75 C
+/-, 50 +/- , 25 +/-, or 5 +/- of the normal boiling point corresponding to the maxima of the economic return. In other embodiments, the normal boiling point range for the optimum solvent mixture may fall within hydrocarbons with 3 +/-, 2 +/-, or 1 +/- carbon atoms of the carbon atom number of the solvent normal boiling point ranges corresponding to the maxima of the economic return. Preferably, at least 75 wt%, at least 85 wt%, or at least 95 wt% of the solvent mixture as selected is comprised of hydrocarbon solvents which fall within the normal boiling point range for the optimized solvent mixture.
[00761 The analyses required to characterize the relationship of the NBP of the injected solvent mixture to these process key performance indicators can be done by any economic and technical analysis available to the user. It should be noted that the functionalities of these process key performance indictors to NBP and economic return will be dependent upon many factors and thus will be different in just about any case performed. The functionalities of these process key performance indictors to NBP may depend on selected solvent-based recovery process, the reservoir properties, and/ or the operation pressure.
Additionally, the time interval over which this solvent NBP/economic return analysis is analyzed can be any interval selected by the user, such as less than one week, less than one month, less than one year, less than five years, less than ten years, less than twenty years, less then forty years, over the entire life cycle of the project, over the remaining production life of the project, reservoir or well, or even over the entire life of the project, reservoir or well. The analysis of determining an economic return as a function of the overall solvent normal boiling point range for the proposed hydrocarbon solvents and then determining a normal boiling point range for the solvent mixture, corresponding to an optimum range of the economic return, may be repeated and the composition of the selected solvent mixture in the step may be modified prior to injecting the solvent mixture into the subterranean reservoir. This option is particularly useful when a portion of the solvent mixture is being separated on-site from the reservoir product stream and recycled into the reservoir injection mixture.
This option is also particularly useful when a portion of the solvent mixture is being separated on-site from a precursor commercially available solvent mixture and injected into the reservoir injection mixture. This may allow real time or near-real time tailoring of the composition of the injected solvent mixture to maintain a composition within a range of economically preferred solvent NBP even as the reservoir properties and/or the process key performance indicators or even the economic relationships to the process key performance indicators are changing during the ongoing operation of the solvent-based oil recovery process.
[0077] It is also noted that each analysis is dependent upon the physical characteristics and properties of the particular reservoir, the operating parameters including pressure of the particular reservoir, the reservoir available oil volume, the reservoir production rate, the characteristics of the oil produced, the well type, and/or the well configuration. The modeled relationship can include capital expenditures (CAPEX), operating expenditures (OPEX), or both as required by the particular operating profile selected by the user. The assigned or calculated values of the individual process key performance indicators in analyses may also be dependent upon the type of recovery process utilized (e.g., SA-SAGD vs. H-VAPEX).
However those of skill in the art of solvent-based recovery processes and associated economic and cost modeling will be able to formulate these necessary relationships and build an economic return model as a function of NBP as described herein.
[0078] In the present disclosure, several examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently.
Industrial Applicability [0079] The systems and methods disclosed in the present disclosure are applicable to the oil and gas industry.
[0080] 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.

Claims (43)

1. A method for optimizing a solvent-based oil recovery process for a subterranean reservoir, comprising:
a) selecting an operating pressure for the subterranean reservoir;
b) selecting an available range of proposed hydrocarbon solvents;
c) determining a first normal boiling point range for the proposed hydrocarbon solvents;
d) determining an economic return as a function of the first normal boiling point range for the proposed hydrocarbon solvents;
e) determining a second normal boiling point range for the proposed hydrocarbon solvents, corresponding to an optimum range of the economic return;
0 injecting a solvent mixture comprising a portion of the proposed hydrocarbon solvents which fall within the second normal boiling point range, into the subterranean reservoir using a solvent-based oil recovery process; and g) recovering a product stream comprising oil from the subterranean reservoir.

2. The method of claim 1, wherein the solvent-based oil recovery process is a gravity drainage process.

3. The method of claim 1 or 2, wherein the solvent mixture is injected in its vapor phase.

4. The method of any one of claims 1-3, wherein steam is injected with the solvent mixture into the subterranean reservoir.

5. The method of any one of claims 1-4, wherein the economic return is further a function of at least one of the Oil Production Rate (OPR), the Solvent + Steam to Oil Ratio (Sol+StOR), the Solvent to Oil Ratio (SolOR), the Steam to Oil Ratio (StOR), and the Energy to Oil Ratio (EnOR).

6. The method of any one of claims 1-4, wherein the economic return is further a function of the Oil Production Rate (OPR).

7. The method of claim 6, wherein the economic return is further a function of at least one of the Solvent + Steam to Oil Ratio (Sol+StOR), the Solvent to Oil Ratio (SolOR), the Steam to Oil Ratio (StOR), and the Energy to Oil Ratio (EnOR).

8. The method of any one of claims 1-4, wherein the economic return is further a function of the Oil Production Rate (OPR), the Solvent + Steam to Oil Ratio (Sol+StOR), the Solvent to Oil Ratio (SolOR), the Steam to Oil Ratio (StOR), and the Energy to Oil Ratio (EnOR).

9. The method of any one of claims 1-8, wherein the second normal boiling point range for the proposed hydrocarbon solvents falls within 50 +/- of the maxima of the economic return corresponding to the solvent mixture within the first normal boiling point range.

10. The method of any one of claims 1-8, wherein the second normal boiling point range for the proposed hydrocarbon solvents falls within 25 °C +/- of the maxima of the economic return corresponding to the solvent mixture within the first normal boiling point range.

11. The method of any one of claims 1-8, wherein the second normal boiling point range for the proposed hydrocarbon solvents falls within 5 °C +/- of the maxima of the economic return corresponding to the solvent mixture within the first normal boiling point range.

12. The method of any one of claims 1-8, wherein the second normal boiling point range for the proposed hydrocarbon solvents falls within hydrocarbons with 3 +/-carbon atoms of the carbon atom number of the solvent normal boiling point corresponding to the maxima of the economic return corresponding to the solvent mixture within the first normal boiling point range.

13. The method of any one of claims 1-8, wherein the second normal boiling point range for the proposed hydrocarbon solvents falls within hydrocarbons with 2 +/-carbon atoms of the carbon atom number of the solvent normal boiling point corresponding to the maxima of the economic return corresponding to the solvent mixture within the first normal boiling point range.

14. The method of any one of claims 1-8, wherein the second normal boiling point range for the proposed hydrocarbon solvents falls within hydrocarbons with 1 +/-carbon atoms of the carbon atom number of the solvent normal boiling point corresponding to the maxima of the economic return corresponding to the solvent mixture within the first normal boiling point range.

15. The method of any one of claims 1-14, wherein the solvent mixture comprises hydrocarbons that have been produced by a source separate from the subterranean reservoir.

16. The method of 15, wherein the solvent mixture comprises a natural gas liquid, a natural gas condensate, a liquefied petroleum gas, or a crude oil refinery naphtha.

17. The method of any one of claims 1-16, further comprising:
- separating at least a portion of the product stream into a heavy oil product and a recovered solvent mixture; and - mixing at least a portion of the recovered solvent mixture into the solvent mixture prior to step f).

18. The method of claim 17 wherein, wherein the at least a portion of the product stream is sent to a single stage flash unit or a multistage flash unit which separates the product stream into the heavy oil product and a recovered solvent mixture.

19. The method of claim 18 wherein the multistage flash unit is a two-stage flash unit.

20. The method of claim 17, wherein the at least a portion of the product stream is sent to a separation unit comprising a distillation unit which separates the product stream into the heavy oil product and a recovered solvent mixture.

21. The method of any one of claims 18-19, wherein the operational variables of the single flash unit or the multistage flash unit are regulated to match the composition of the recovered solvent mixture to the second normal boiling point range as determined in step e).

22. The method of claim 20, wherein the operational variables of the distillation unit are regulated to match the composition of the recovered solvent mixture to the second normal boiling point range as determined in step e).

23. The method of any one of claims 1-22, wherein at least 75 wt% of the solvent mixture is comprised of the proposed hydrocarbon solvents which fall within the second normal boiling point range.

24. The method of any one of claims 4-23, wherein the compositions of the solvent mixture and the steam in the injection mixture are 30%+/- of the.azeotropic solvent molar fraction of the steam and the solvent mixture as measured at the operating pressure of the subterranean reservoir.

25. The method of any one of claims 4-23, wherein the molar fraction of the solvent mixture in the solvent and the steam injection mixture is 70-110% of the azeotropic solvent molar fraction of the steam and the solvent mixture as measured ,at the operating pressure of the subterranean reservoir.

26. The method of any one of claims 4-23, wherein the molar fraction of the solvent mixture in the solvent and the steam injection mixture is 70-100% of the azeotropic solvent molar fraction of the steam and the solvent mixture as measured at the operating pressure of the subterranean reservoir.

27. The method of any one of claims 4-23, wherein the molar fraction of the solvent mixture in the solvent and the steam injection mixture is 80-100% of the azeotropic solvent molar fraction of the steam and the solvent mixture as measured at the operating pressure of the subterranean reservoir.

28. The method of any one of claims 1-27, wherein the solvent mixture comprises C4 to C12 hydrocarbons.

29. The method of any one of claims 1-27, wherein the solvent mixture comprises C5 to C9 hydrocarbons.

30. The method of any one of claims 1-27, wherein the solvent mixture comprises C4 to C6 hydrocarbons.

31. The method of any one of claims 1-30, wherein at least steps d) and e) are repeated, and the composition of the solvent mixture in step 0 is modified as a result steps d) and e), before continuing to steps and g).

32. The method of any one of claims 1-31, wherein the solvent mixture comprises at least one of alkanes, iso-alkanes, naphthenic hydrocarbons, aromatic hydrocarbons, and olefin hydrocarbons.

33. The method of any one of claims 1-32, wherein the subterranean reservoir operating temperature is 30-250 °C.

34. The method of any one of claims 1-33, wherein the subterranean reservoir operating pressure is 5% to 95% of a fracture pressure of the subterranean reservoir.

35. The method of any one of claims 1-33, wherein the subterranean reservoir operating pressure is the pressure of a gas cap in the subterranean reservoir.

36. The method of any one of claims 1-33, wherein the subterranean reservoir operating pressure is the pressure of a gas zone within the subterranean reservoir.

37. The method of any one of claims 1-33, wherein the subterranean reservoir operating pressure is the pressure of a bottom water zone in the subterranean reservoir.

38. The method of any one of claims 1-33, wherein the subterranean reservoir operating pressure is the pressure of a mobile water zone within the subterranean reservoir.

39. The method of any one of claims 1-38, wherein the subterranean reservoir operating pressure is 0.2 MPa to 4 MPa.

40. The method of any one of claims 1-39, wherein economic return as a function of the first normal boiling point range contains capital expenditures (CAPEX), operating expenditures (OPEX), or both.

41. The method of any one of claims 1-40, wherein the time interval over which the economic return as a function of the first normal boiling point range is determined is less than 40 years.

42. The method of any one of claims 1-40, wherein the time interval over which the economic return as a function of the first normal boiling point range is determined is less than 20 years.

43. The method of any one of claims 1-40, wherein the time interval over which the economic return as a function of the first normal boiling point range is determined is less than years.