US20100243248A1

US20100243248A1 - Particle Stabilized Emulsions for Enhanced Hydrocarbon Recovery

Info

Publication number: US20100243248A1
Application number: US12/516,901
Authority: US
Inventors: Dan S. Golomb; David Ryan; Gene Barry; Peter Swett; Michael Woods
Original assignee: University of Massachusetts UMass
Current assignee: University of Massachusetts UMass
Priority date: 2006-12-01
Filing date: 2007-12-03
Publication date: 2010-09-30
Also published as: WO2008070035A2; WO2008070035A8; WO2008070035A3; CA2670986A1

Abstract

Hydrophobic and hydrophilic particles as can be used to stabilize emulsions for hydrocarbon extraction and/or recovery.

Description

BACKGROUND OF THE INVENTION

Hydrocarbon (e.g., crude oil, or simply oil) recovery may be classified as primary, secondary and tertiary recovery. In primary recovery, the crude oil is simply drawn out of a subterranean formation by a pumping action. The hydrostatic pressure resulting from the overlying strata drives the oil toward the pumped well. Primary recovery methods usually recover only 20-30% of the original oil in place (OIP) estimated to be in the formation. Secondary recovery refers to the injection of pressurized liquid water or water vapor (steam) into the formation via a bore pipe. The additional pressure of the injected water, and/or the heating action of the steam drives more of the crude oil toward the pumped well. In such a manner, an additional 10-20% of the original OIP estimated to be in the formation may be recovered. Tertiary recovery involves methods to reduce the viscosity and dissolve the oil and/or increase its mobility in some fashion. Injecting liquid or supercritical carbon dioxide into the formation (e.g., CO₂flooding) is another popular tertiary recovery method. In such a process, liquid or supercritical CO₂is injected via a bore pipe. Carbon dioxide is readily miscible with crude oil and reduces its viscosity, thereby allowing the oil/CO₂mixture to more easily flow toward the pumped well. Optionally, CO₂injection is followed by pressurized water injection or alternating floods of liquid CO₂. Pressurized water drives the less viscous oil/CO₂mixture toward the pumped well. This method is called water-alternate-gas injection (WAG).
Carbon dioxide flooding alone, or WAG injection, may not always result in more oil being recovered. Upon injection, the low density and low viscosity liquid CO₂or supercritical CO₂has a tendency to buoy upward from the injection point toward the top of the formation, or sideways, bypassing the oil-saturated granules without dissolving the oil, a process called fingering.
These and related issues are also encountered in the context of coal beds. Underground coal deposits typically contain hydrocarbon gases, primarily methane (CH₄). It is estimated that US coal deposits contain 700 trillion cubic feet of methane, equivalent to about 700 quadrillion BTU (Q). (The US total primary energy consumption approaches 100 Q/y.) Presently, about 8% of US natural gas consumption comes from coal bed methane. Coal bed methane production could be enhanced if methods were found that more efficiently dislocate methane occluded in the coal bed. Even so, waste-related concerns often arise. Coal bed methane extraction almost always brings to the surface vast quantities of “produced water;” that is, water also contained in the coal bed. The produced water is invariably contaminated with toxic metals, salts and other contaminants that render it unsuitable for drinking, irrigation or cost-effective purification. Some of this water is re-injected into the coal bed or other subterranean formations, or left standing in open ponds or lagoons until it evaporates, with the solid residue disposed in secure landfills. The lack of safe and permanent disposal methods for produced water further impedes coal bed methane production—not only in the US but world-wide.
As with tertiary methods for oil recovery, methane/gas extraction has used liquid/supercritical carbon dioxide flooding, but is adversely affected by much the same issues and concerns. Accordingly, there remains an on-going search in the art for a method to enhance recovery/extraction of residual oil or gas, to better utilize the benefits and advantages associated with carbon dioxide flooding.

SUMMARY OF THE INVENTION

In light of the foregoing, it is an object of the present invention to provide one or more methods and/or systems for hydrocarbon recovery, thereby overcoming various deficiencies and shortcomings of the prior art, including those outlined above. It will be understood by those skilled in the art that one or more aspects of this invention can meet certain objectives, while one or more other aspects can meet certain other objectives. Each objective may not apply equally, in all its respects, to every aspect of this invention. As such, the following objects can be viewed in the alternative with respect to any one aspect of this invention.
It can be an object of the present invention to provide a method of enhancing recovery of gas or oil from a subterranean formation.
It can also be an object of the present invention to stabilize liquid/supercritical carbon dioxide emulsions, with control of viscosity and various other physical or performance-related parameters, as may be needed for a particular recovery application.
It can be another object of the present invention, alone or in conjunction with one or more of the preceding objectives, to provide a suitable approach for the handling and/or disposal of waste materials associated with such recoveries.
Other objects, features, benefits and advantages of the present invention will be apparent from this summary and the following descriptions of certain embodiments, and will be readily apparent to those skilled in the art having knowledge of various oil and gas recovery processes and production techniques. Such objects, features, benefits and advantages will be apparent from the above as taken into conjunction with the accompanying examples, data, figures and all reasonable inferences to be drawn therefrom.
In part, the present invention can be directed to a tertiary method of subterranean hydrocarbon recovery. Such a method can comprise providing a subterranean formation comprising a residual hydrocarbon component, such a component as can be selected from a gas and an oil; contacting the subterranean formation with a fluid medium comprising an emulsion comprising a liquid carbon dioxide and/or supercritical carbon dioxide component, an aqueous component and a particulate component selected from hydrophilic components and/or combinations thereof and hydrophobic components and/or combinations thereof, such particulate component(s) in an amount sufficient for at least partial emulsification, such contact for a time and/or at a pressure at least partially sufficient to displace the hydrocarbon component from the subterranean formation; and recovering some or all of the hydrocarbon component and, optionally, at least a portion of the fluid medium and/or emulsion.
In certain embodiments, the subterranean formation can be but is not limited to a geologic formation accessed by an oil well or drilling field; regardless, such a residual hydrocarbon can comprise an oil. In certain such non-limiting embodiments, the fluid medium can comprise an emulsion comprising a dispersed phase comprising one or more such carbon dioxide components, a continuous phase comprising an aqueous component and a hydrophilic particulate component. Useful particulate components can include but are not limited to limestone particles, sand particles, gypsum particles, fly ash particles, clay particles, cellulosic particles, biomass particles (e.g., without limitation, chitin) and combinations of such components.
In certain other embodiments, the subterranean formation can comprise but is not limited to a coal bed; regardless, a residual hydrocarbon can be a gas, such as but not limited to methane. In certain such embodiments, the fluid medium can comprise an emulsion comprising a dispersed phase comprising an aqueous component, a continuous phase comprising one or more such carbon dioxide components and a hydrophobic particulate component. Such particulate components can be selected from but are not limited to coal particles, carbon black particles, activated carbon particles, asphaltene particles, petrocoke particles, resin particles (e.g., without limitation, latex, polystyrene), fluorocarbon particles (e.g., without limitation, Teflon), protenaceous particles (e.g., without limitation, proteins, enzymes) and combinations of such components.
With regard to coal bed and related formations, recovery of a hydrocarbon gas can also produce, as discussed elsewhere herein, a water component from such a formation. In certain such embodiments of the inventive methodology, the carbon dioxide component of a recovered fluid medium can be emulsified with such a produced water component. Such an emulsion can be prepared as described elsewhere herein. In certain non-limiting embodiments, such an emulsion can comprise hydrophobic particles and combinations thereof or hydrophilic particles and combinations thereof. The carbon dioxide-produced water emulsion can then be returned to such a coal bed or introduced to another subterranean formation, with benefits and advantages of the sort described elsewhere herein.
Without regard to any particular hydrocarbon or subterranean formation, in certain non-limiting embodiments, a carbon dioxide component of an emulsion used in conjunction with this invention, whether part of a continuous phase or dispersed phase, can be present in an amount greater than about 1 wt. % of the emulsion. Regardless, particles utilized in conjunction with such an emulsion can be dimensioned from about 5 nanometers or less to about 100 microns or more. With correlation to a dispersed phase of such an emulsion, particle dimension can be about 5× to about 50× smaller than a dimensional aspect of any such dispersed phase. These and various other non-limiting emulsion parameters are discussed elsewhere herein or as would be understood by those skilled in the art made aware of this invention. Such parameters can be varied, limited only by the physical properties and/or functional effect desired of a particular emulsion, in the context of a particular subterranean formation and/or hydrocarbon recovery.
In part, the present invention can also be directed to a method of using a particle-stabilized emulsion for tertiary oil recovery. Such a method can comprise providing a subterranean formation comprising a residual oil component; contacting the formation with an emulsion comprising a liquid carbon dioxide and/or a supercritical carbon dioxide component, an aqueous component and a particulate component selected from hydrophilic particles and/or combinations thereof and hydrophobic particles and/or combinations thereof, such a particulate in an amount sufficient for at least partial emulsification, such contact for a time and/or at a pressure at least partially sufficient to displace the residual oil from the formation; and recovering the residual oil. In certain embodiments, such an emulsion can be as described above or elsewhere herein. In certain such embodiments, an emulsion can comprise a dispersed phase comprising one or more such carbon dioxide components, a continuous phase comprising an aqueous component and a hydrophilic particulate component. A particulate component can be selected from one or more of the particles described above or elsewhere herein. In certain such embodiments, a particulate component can be selected from limestone particles and/or compositional components (e.g., without limitation CaCO₃) thereof. Regardless of emulsion composition, such a method can comprise recovery of a carbon dioxide component thereof, as can be reused for oil recovery or sequestered as otherwise described herein.
In part, the present invention can also be directed to a method of using a particle-stabilized carbon dioxide emulsion for recovery of hydrocarbon gas from a coal bed. Such a method can comprise providing a coal bed or related formation comprising a residual hydrocarbon gas including but not limited to methane; contacting such a formation with an emulsion comprising a liquid carbon dioxide component and/or a supercritical carbon dioxide component, an aqueous component, and a particulate component selected from hydrophilic particles and/or combinations thereof and hydrophobic particles and/or combinations thereof, such a particulate component in an amount sufficient for at least partial emulsification, such contact for a time and/or at a pressure at least partially sufficient to displace residual gas from the formation; and recovering the hydrocarbon gas component and at least a portion of the emulsion and/or a carbon dioxide component thereof.
Emulsions useful in conjunction with such a methodology can be as described elsewhere herein. Without limitation, such an emulsion can comprise a dispersed phase comprising an aqueous component, a continuous phase comprising one or more carbon dioxide components, and a hydrophobic particle component. Whether part of a continuous phase or a dispersed phase, such carbon dioxide component(s) can comprise greater than about 1 wt. % of the emulsion to about 99 wt. %. Regardless, a particle component can be selected from one or more of the particles described above or elsewhere herein. In certain such embodiments, a particle component can be selected from coal particles and/or compositional components thereof. Without regard to emulsion composition, such a method can comprise recovery of the carbon dioxide component(s) of such an emulsion for re-emulsification with produced-water from the coal bed/formation. In certain such embodiments, such a carbon dioxide-produced water emulsion can then be returned to such a coal bed or introduced to another subterranean formation, for sequestration of the carbon dioxide and/or produced water components.
With respect to either the methods and emulsions of the present invention, the steps and components thereof can suitably comprise, consist of, or consist essentially of any of the steps or components disclosed herein. Each such method or step and emulsion or component thereof is distinguishable, characteristically or functionally contrasted and can be practiced in conjunction with the present invention separate and apart from another. Accordingly, it should also be understood that inventive methods and/or emulsions, as illustratively disclosed herein, can be practiced or utilized in the absence of any one component or step which may or may not be disclosed, referenced or inferred herein, the absence of which may or may not be specifically disclosed, referenced or inferred herein.

BRIEF DESCRIPTION OF THE DRAWINGS

Non-limiting embodiments of the present invention can be described by way of example with reference to the accompanying figures, which are schematic and are not intended to be drawn to scale. In the figures, each identical or nearly identical component illustrated is typically represented by a single numeral. For purposes of clarity, not every component is labeled in every figure, nor is every component of each embodiment of the invention shown where illustration is not necessary to allow those of ordinary skill in the art to understand the invention. In the figures:

FIG. 1 shows a schematic diagram of a particle stabilized emulsion (i.e., Pickering emulsion) according to one embodiment of the invention;

FIG. 2 shows droplets of liquid carbon dioxide in a seawater continuous phase stabilized by calcium carbonate particles according to another embodiment of the invention;

FIG. 3 shows droplets of water in a dodecane continuous phase stabilized by carbon black particles according to another embodiment of the invention;

FIG. 4 shows a schematic diagram of a high-pressure batch reactor for forming an emulsion according to another embodiment of the invention;

FIG. 5 shows a static mixer that can be used to form an emulsion according to another embodiment of the invention;

FIG. 6 shows a static mixer emulsion apparatus according to another embodiment of the invention;

FIG. 7 shows a system for recovering oil from a subterranean formation according to another embodiment of the invention; and

FIG. 8 shows one particular system for recovering oil from a subterranean formation according to another embodiment of the invention.

FIGS. 9A-B show photographs illustrating use of (A) an A/O (or A/C)-type emulsion employing a representative hydrophobic particle to recover oil from a material of a subterranean formation, as compared to (B) no recovery without use of a method of this invention.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Particle stabilized emulsions, and more specifically, particle stabilized emulsions for enhanced oil recovery (EOR) and enhanced coal bed methane (ECBM) recovery processes are provided. While certain embodiments are discussed in the context of either an EOR or ECBM process, it will be understood by those skilled in the art made aware of this invention that any such embodiment can independently pertain to the other or another such recovery process with corresponding revision or adaptation to a particular recovery, subterranean formation and/or particular end-use application, and can be applied thereto with comparable effect. One aspect of the invention relates to a process for recovering hydrocarbons from a subterranean formation by injecting an emulsion of liquid or supercritical carbon dioxide in an aqueous liquid (CO₂-in-aqueous (C/A) emulsion) stabilized by fine hydrophilic particles, or by injecting an emulsion of aqueous liquid in liquid or supercritical carbon dioxide (aqueous-in-CO₂(A/C) emulsion) stabilized by fine hydrophobic particles, into the formation. Because the particle stabilized C/A or A/C emulsions have a higher viscosity than liquid or supercritical CO₂alone, they may have a better sweep efficiency for driving out the crude oil, and less of the injected CO₂may be lost to upward buoying and sideways fingering in the formation. Thus, the particle stabilized emulsions can better displace hydrocarbons from the formations compared to water injection alone (e.g., water flooding) or carbon dioxide injection alone (e.g., CO₂flooding).
Without limitation to any one theory or mode of operation, an “emulsion” can be considered a stable mixture of at least two immiscible liquids, and stability can imply kinetic stability or stability in some time frame and not thermodynamic stability. In general, mixing or dispersing immiscible liquids (one phase into the other) creates an unstable dispersion, which tends to separate back into two distinct phases. An emulsion is thus stabilized by the addition of an “emulsifying agent” which functions to reduce surface tension between at least two immiscible liquids. As used herein, an “emulsifying agent” defines a substance that, when combined with a first component defining a first phase, and a second component defining a second phase immiscible with the first phase, will facilitate assembly of a stable emulsion of the first and second phases.
Emulsions described herein may be stabilized by particulate materials such as, for example, hydrophilic particles including, but not limited to, pulverized limestone, pulverized sandstone, pulverized gypsum, flyash, clay, cellulosic particles, biomass particles (e.g. chitin) and other particles natural or synthetic, or by hydrophobic particles, such as pulverized coal, pulverized asphaltene, petrocoke, carbon black, or other particles natural or synthetic. The particles may orient themselves around the droplets according to their hydrophilicity or hydrophobicity. In C/A emulsions, a larger part of the hydrophilic particles may be wetted by the continuous aqueous phase; in A/C emulsions, a larger part of the hydrophobic particles may be wetted by the continuous carbon dioxide phase. The sheath of particles surrounding the droplets can prevent the coalescence of either the carbon dioxide or water droplets into a bulk phase. As discussed below, the invention comprises many types of aqueous systems including water that is distilled, deionized, artesian, sea, waste, brine, oil- and gas-well associated or formation water. Similarly, the invention comprises all sorts of carbon dioxide, pure liquid and supercritical carbon dioxide, as well as complex mixtures and complex liquids, such as liquid hydrogen sulfide or other gases, organic and inorganic solvents freely miscible with carbon dioxide.
As described in more detail below, emulsions described herein can be used to extract oil from subterranean formations containing oil (e.g., petroleum) that is poorly mobile (e.g., highly viscous) and difficult to remove. The subterranean formation may represent, for example, a spent or abandoned oil well. Without wishing to be bound by theory, it is postulated that upon injection of an emulsion into a subterranean formation, the emulsion disperses and disintegrates. If, for example, an A/C emulsion was injected, the liquid or supercritical CO₂released from the emulsion can partition into the oil of the formation, dissolve at least a portion of the oil and thus reduce the viscosity of the oil (which may cause the oil to swell), and leave behind a slurry of fine particles in water. Furthermore, as the sand granules of the formation may be hydrophilic, they may prefer to be coated with water than with hydrophobic oil, thus allowing release of the oil from the granules. In other words, water can displace oil from the surface of the granules, thereby mobilizing the oil for extraction and recovery. In one embodiment, such a procedure can replace water alternate gas technology (WAG) typically used in enhanced oil recovery with a one-step procedure for extracting oil from subterranean formations. In another embodiment, the procedure can be performed in multiple numbers of steps. In yet other embodiments, such procedures for oil extraction can be used in conjunction with WAG technology. Advantageously, methods for extracting oil using emulsions described herein may enable significantly more oil to be recovered than by pumping action alone, by injecting water alone, by carbon dioxide alone, or by successive injections of carbon dioxide and water (water alternate gas) injections.
As mentioned, the invention can also be directed to hydrocarbon gas recovery and the emulsification of liquid and/or supercritical carbon dioxide using very fine particles as emulsifying agents. Liquid carbon dioxide is very sparingly soluble in water; for instance, only a few percent by weight at a pressure of 4.5 MPa and temperature of 15° C. However, up to about 50 wt. % or more of a carbon dioxide component can be dispersed in water using fine particles, as described herein, as emulsifying agents. When hydrophilic particles are used (e.g. pulverized limestone or sand), a CO₂-in-aqueous emulsion (C/A) is produced; when hydrophobic particles are used (e.g. pulverized coal, petrocoke, carbon black), an aqueous-in-CO₂emulsion (A/C) ensues.
Such embodiments can entail producing either type of emulsion at or proximate to a coal bed methane extraction site, and injecting the emulsion into the coal bed. Alternatively the emulsion can be prepared elsewhere and transported to the site. Such emulsions are produced in high-pressure autoclaves to keep the CO₂component liquefied. Injection of such an emulsion into a coal bed can serve three purposes: (a) The emulsion will dislocate methane and other hydrocarbon gases from the pores and cleats of the coal bed, as CO₂has a propensity to dislocate CH₄from the surface of coal granules; (b) The re-injection of a CO₂-produced water emulsion into the coal bed disposes the produced water without endangering human or animal health and the environment; and (c) The re-injection or geologic sequestration of a CO₂-produced water emulsion into the coal bed or another subterranean formation (e.g. saline aquifers) disposes of CO₂that otherwise would be emitted into the atmosphere, to reduce a factor contributing to global warming.
In certain instances, after extraction, the carbon dioxide from the emulsion can remain in the subterranean formation, providing the added benefit of carbon dioxide sequestration (i.e., storage of the carbon dioxide from the emitting sources on a permanent basis). Additionally and/or alternatively, the carbon dioxide may be recovered and recycled to regenerate the emulsion.
Moreover, emulsions described herein may be low in cost, easy to recover, and can be tailored for each specific application, for example, by adjusting the chemical properties (e.g., pH, ionic strength, solubility, and ratio of CO₂to water) and physical properties (e.g., density, viscosity, and rheology) of the phases of emulsion, as described in more detail below.
Although much of the description herein involves an exemplary application of the present invention related to extracting oil from a subterranean formation, the invention and its uses are not so limited, and it should be understood that embodiments of the invention can also be used in other settings, such settings, including but not limited to extraction of a hydrocarbon gas (e.g., methane) from a coal bed.
Accordingly, in one embodiment, a method of recovering or extracting oil or a hydrocarbon gas from a subterranean formation is provided. The method comprises introducing an emulsion comprising supercritical CO₂, an aqueous liquid, and an emulsifying agent comprising a particulate material, into a subterranean formation, and extracting oil/gas from the subterranean formation. In some cases, the emulsion comprises supercritical CO₂and an aqueous liquid. For example, the emulsion may comprise a continuous phase comprising supercritical CO₂and a dispersed phase comprising an aqueous liquid, or the emulsion may comprise a dispersed phase comprising supercritical CO₂and a continuous phase comprising an aqueous liquid.
In another embodiment, such a method comprises introducing an emulsion comprising a continuous or dispersed phase including greater than about 1% by weight of liquid CO₂, a continuous or dispersed phase comprising an aqueous liquid, and an emulsifying agent comprising a particulate material, into a subterranean formation, and extracting oil/gas from the subterranean formation. In one embodiment, the emulsion comprises a continuous phase comprising greater than about 1% by weight of liquid CO₂and a dispersed phase comprising an aqueous liquid. In another embodiment, the emulsion comprises a dispersed phase comprising greater than about 1% by weight of liquid CO₂and a continuous phase comprising an aqueous liquid.
In another embodiment, a related system is provided. The system comprises supercritical CO₂, an aqueous liquid, and a particulate material in fluid communication with an emulsion-forming apparatus for forming an emulsion comprising the supercritical CO₂, aqueous liquid, and particulate material. The system also includes an apparatus for introducing the emulsion into a subterranean formation and an apparatus for recovering oil/gas from the subterranean formation. In one embodiment, the emulsion formed by such a system comprises a continuous phase comprising supercritical CO₂and a dispersed phase comprising an aqueous liquid. In another embodiment, the emulsion comprises a dispersed phase comprising supercritical CO₂and a continuous phase comprising an aqueous liquid.
In another embodiment, a related system comprises liquid CO₂, an aqueous liquid, and a particulate material in amounts sufficient to form an emulsion comprising a continuous or dispersed phase including greater than about 1% by weight of liquid CO₂, a continuous or dispersed phase comprising an aqueous liquid, and an emulsifying agent comprising a particulate material. The liquid CO₂, aqueous liquid, and particulate material may be in fluid communication with an emulsion-forming apparatus. The system also includes an apparatus for introducing the emulsion into a subterranean formation and an apparatus for recovering oil/gas from the subterranean formation. In one embodiment, the emulsion formed by such a system comprises a continuous phase comprising greater than about 1% by weight of liquid CO₂and a dispersed phase comprising an aqueous liquid. In another embodiment, the emulsion comprises a dispersed phase comprising greater than about 1% by weight of liquid CO₂and a continuous phase comprising an aqueous liquid.
In another aspect, whether method or system-related, a series of emulsions are provided. In one embodiment, the emulsion comprises a plurality of droplets of an aqueous liquid dispersed in a continuous phase comprising supercritical CO₂, and an emulsifying agent comprising a particulate material. In another embodiment, an emulsion comprises a plurality of droplets of an aqueous liquid dispersed in a continuous phase comprising greater than about 1% by weight of liquid CO₂, and an emulsifying agent comprising a particulate material.
In another embodiment, an emulsion comprises a dispersed phase comprising a first liquid suspended in a continuous phase comprising a second liquid, wherein the first or second liquid comprises supercritical CO₂, and an emulsifying agent comprising a particulate material. In some cases, the first liquid is supercritical CO₂. For example, the first liquid may be supercritical CO₂and the second liquid may be an aqueous liquid. In other cases, the second liquid is supercritical CO₂and the first liquid is an aqueous liquid.
In another embodiment, a method of this invention comprises extracting a hydrocarbon component from a mixture of hydrocarbons. The method comprises introducing an emulsion comprising supercritical CO₂, an aqueous liquid, and an emulsifying agent comprising a particulate material, into a mixture comprising a hydrocarbon or component hydrocarbons, and extracting the first component or components from the mixture. In some cases, the emulsion comprises supercritical CO₂and an aqueous liquid. For example, the emulsion may comprise a continuous phase comprising supercritical CO₂and a dispersed phase comprising an aqueous liquid, or the emulsion may comprise a dispersed phase comprising supercritical CO₂and a continuous phase comprising an aqueous liquid.
In another embodiment, such a method of extracting a component from a mixture comprises introducing an emulsion comprising a continuous or dispersed phase including greater than about 1% by weight of liquid CO₂, a continuous or dispersed phase comprising an aqueous liquid, and an emulsifying agent comprising a particulate material, into a mixture comprising a hydrocarbon or component hydrocarbons, and extracting the first component hydrocarbon or component hydrocarbons from the mixture. In one embodiment, the emulsion comprises a continuous phase comprising greater than about 1% by weight of liquid CO₂and a dispersed phase comprising an aqueous liquid. In another embodiment, the emulsion comprises a dispersed phase comprising greater than about 1% by weight of liquid CO₂and a continuous phase comprising an aqueous liquid.
In another aspect, a related system for recovering a component from a mixture is provided. In one embodiment, the system comprises supercritical CO₂, an aqueous liquid, and a particulate material in fluid communication with an emulsion-forming apparatus for forming an emulsion comprising the supercritical CO₂, aqueous liquid, and particulate material. The system also includes an apparatus for introducing the emulsion into a mixture comprising first and second components, and an apparatus for recovering the first component from the mixture. In some cases, the emulsion of such system comprises supercritical CO₂and an aqueous liquid. For example, the emulsion may comprise a continuous phase comprising supercritical CO₂and a dispersed phase comprising an aqueous liquid, or the emulsion may comprise a dispersed phase comprising supercritical CO₂and a continuous phase comprising an aqueous liquid.
In one embodiment, a related system for recovering a component from a mixture comprises liquid CO₂, an aqueous liquid, and a particulate material in amounts sufficient to form an emulsion comprising a continuous or dispersed phase including greater than about 1% by weight of liquid CO₂. The system also includes a continuous or dispersed phase comprising an aqueous liquid, and an emulsifying agent comprising a particulate material. The liquid CO₂, aqueous liquid, and particulate material are in fluid communication with an emulsion-forming apparatus, an apparatus for introducing the emulsion into a mixture comprising first and second components, and an apparatus for recovering the first component from the mixture. In some cases, the emulsion comprises a continuous phase comprising greater than about 1% by weight of liquid CO₂and a dispersed phase comprising an aqueous liquid. Or, the emulsion may comprise a dispersed phase comprising greater than about 1% by weight of liquid CO₂and a continuous phase comprising an aqueous liquid.
As shown in the embodiment illustrated in FIG. 1, emulsion 8 includes droplets 10 (also known as “globules”) of a dispersed phase 14 (i.e., the isolated phase stabilized by an emulsifying agent). In some embodiments, the dispersed phase can comprise an aqueous liquid (e.g., water or aqueous solutions), an oil (e.g., a hydrocarbon or mixture of hydrocarbons), or carbon dioxide (e.g., liquid or supercritical CO₂or other gases). In certain embodiments in which the dispersed phase comprises an aqueous liquid, continuous phase 18 can comprise supercritical or liquid carbon dioxide (i.e., an A/C-type emulsion). In some embodiments in which the dispersed phase comprises supercritical or liquid carbon dioxide, the continuous phase can comprise an aqueous liquid (e.g., water) (i.e., an C/A-type emulsion). Some emulsions may also include an oil forming all, or portions, of a continuous or dispersed phase (e.g., A/O or O/A-type emulsions). Examples of such emulsions are provided below. The droplets of the emulsion are stabilized by particulate material 22, which may include, for example, solid particles such as pulverized rock and coal. The particulate material forms a particle sheath at the interface of the two phases, preventing their coalescence into a bulk phase. Without limitation, such particle stabilized emulsions can be referred to or are commonly known as “Pickering emulsions”.
While in some embodiments, liquid or supercritical CO₂may form substantially all of the continuous or dispersed phase of A/C or C/A emulsions, respectively, the invention is not so limited, and it should be understood that A/C and C/A emulsions described herein can have other compositions. For example, as described in more detail below, A/C or C/A emulsions can also include other fluids in the continuous or dispersed phases in addition to liquid or supercritical CO₂(e.g., to form a ternary mixture). In certain embodiments including A/C-type and C/A-type emulsions, the continuous or dispersed phase, respectively, can include greater than about 1% by weight of liquid or supercritical CO₂. For example, in some cases, the continuous or dispersed phase can include between about 1% and about 100%, about 50 and about 100%, or about 70 and about 100% by weight of liquid or supercritical CO₂.
As used herein “droplet” means an isolated phase having any shape, for example cylindrical, spherical, ellipsoidal, tubular, irregular shapes, etc. Generally, in emulsions described herein, aqueous droplets and/or droplets comprising carbon dioxide are spherical, although emulsions described herein are not limited in this respect. Droplets may have an average cross-sectional dimension of greater than or equal to 25 nm, greater than or equal to 50 nm, greater than or equal to 100 nm, greater than or equal to 250 nm, greater than or equal to 500 nm, greater than or equal to 1 micron, greater than or equal to 5 microns, greater than or equal to 10 microns, greater than or equal to 50 microns, greater than or equal to 100 microns, greater than or equal to 200 microns, greater than or equal to 350 microns, greater than or equal to 500 microns, greater than or equal to 700 microns, greater than or equal to 800 microns, or greater than or equal to 900 microns. The droplet size of a particular emulsion may depend, at least in part, on the size and type of the particulate materials, interparticle interactions (e.g., steric interactions), concentration and compositions of the continuous and dispersed phases, as well as the rate of shearing/mixing when forming the emulsion, as described in more detail below.
In some embodiments, emulsions described herein have a CO₂continuous phase and an aqueous dispersed phase. For example, in one embodiment, an emulsion comprises a plurality of droplets 10 of an aqueous liquid (e.g., water and seawater) dispersed in continuous phase 18 comprising greater than about 1% by weight of liquid CO₂, and an emulsifying agent comprising a particulate material. The continuous phase may comprise greater than about 1% by weight of liquid CO₂. For example, in some cases, the continuous phase can include between about 1%-about 100%, about 50%-about 100%, or about 70%-about 100% by weight of liquid CO₂. In some cases, the continuous phase consists essentially of liquid CO₂. Emulsions comprising an aqueous continuous phase and a CO₂dispersed phase are also provided.
In some embodiments, emulsions described herein include supercritical CO₂as the continuous or dispersed phase. For example, an emulsion may comprise a dispersed phase comprising a first liquid suspended in a continuous phase comprising a second liquid, wherein the first or second liquid comprises supercritical CO₂. The emulsion can further include an emulsifying agent comprising a particulate material.
In some cases, the first liquid of the dispersed phase is supercritical CO₂. The second liquid of the continuous phase may be an aqueous liquid. In another embodiment, the second liquid is supercritical CO₂, and the first liquid may be an aqueous liquid.
An example of an emulsion including a dispersed phase comprising liquid carbon dioxide and a continuous phase comprising an aqueous liquid is shown in FIG. 2. As shown in this illustrative embodiment, emulsion 30 includes a plurality of liquid CO₂droplets 34 in seawater continuous phase 36. Calcium carbonate (CaCO₃) particles 38 are used as an emulsifying agent to stabilize the droplets. As shown, the average diameter of droplets 34 is about 200 microns; however, in other embodiments, the size of the droplets can be tailored by varying the size and type of the particulate materials, the concentration and compositions of the continuous and dispersed phases, as well as the shear force of dispersing one fluid into another, as described in more detail below.
In certain embodiments, particle stabilized oil-in-aqueous (O/A) and aqueous-in-oil (A/O) emulsions are contemplated. (Such emulsions are also known as oil-in-water (O/W) and water-in-oil (W/O) emulsions, respectively). As described below, an “oil” can include any liquid that is immiscible with an aqueous liquid such as water; that is, any liquid that, when admixed with an aqueous liquid, can form a two-phase mixture. In one embodiment, an emulsion may include a continuous phase comprising an oil (e.g., a hydrocarbon or fluorocarbon) and a dispersed phase comprising an aqueous liquid (e.g., water). In other embodiments, an emulsion may comprise a continuous phase comprising an aqueous liquid and a dispersed phase comprising an oil. Such emulsions may optionally comprise liquid or supercritical carbon dioxide with respect to a dispersed or continuous phase thereof. An example of a particle stabilized oil-in-aqueous emulsion is shown in FIG. 3. In the illustrative embodiment of FIG. 3, emulsion 40 including droplets 42 of water in a dodecane continuous phase 44. The droplets are stabilized by carbon black particles 48. In this particular embodiment, the droplets have an average size of 10-20 microns.
The aqueous liquid of an emulsion can be any liquid miscible with water; that is, any liquid that, when admixed with water, can form a single-phase solution. In some cases, the aqueous liquid can comprise one or more additives, such as salts (e.g., salts of alkali and/or alkaline earth metals). Non-limiting examples of aqueous phase materials include, for example, water (e.g., purified water, unpurified water, distilled water, deionized water, artesian water, seawater, ground water, well water, waste water, brackish water, brine, oil- and gas-well associated water, formation water, natural sources of water that may or may not contain dissolved salts or contaminants, etc.), methanol, ethanol, DMF (dimethylformamide), or DMSO (dimethyl sulfoxide). Those of ordinary skill in the art can choose appropriate aqueous liquid(s) for forming particle stabilized emulsions based on general knowledge of the art in combination with description provided herein.
The oil portion of an emulsion can be any liquid that is immiscible with an aqueous liquid such as water. In some cases, the oil may include one or more additives such as a surfactant. Two classes of oils that may be used in emulsions described herein include hydrocarbons and halocarbons (e.g., fluorocarbons). The emulsion can be stable at any suitable temperature depending on the particular application.
A hydrocarbon may include a linear, branched, cyclic, saturated, or unsaturated hydrocarbon. The hydrocarbon can optionally include at least one heteroatom (e.g., in the backbone of the compound). Non-limiting examples of hydrocarbons include methane, ethane, propane, butane, pentane, hexane, heptane, octane, nonane, decane, undodecane, dodecane, and the like. Higher-order hydrocarbons such as C₁₀-C₂₀hydrocarbons can also be used. In some cases, a continuous or dispersed phase of an emulsion can include mixtures of hydrocarbons of various chain lengths. The hydrocarbon may be, for example, a petroleum hydrocarbon. In some cases, hydrocarbons recovered from a subterranean formation can be used in continuous or dispersed phases of emulsions described herein.
A fluorocarbon may include any fluorinated compound such as a linear, branched, cyclic, saturated, or unsaturated fluorinated hydrocarbon. The fluorocarbon can optionally include at least one heteroatom (e.g., in the backbone of the component). In some cases, the fluorocarbon compound may be highly fluorinated, i.e., greater than 50% of the hydrogen atoms of the component are replaced by fluorine atoms. In other cases, the fluorocarbon is perfluorinated. Halocarbons including, for example, bromine or chlorine atoms, are also contemplated.
In certain embodiments, emulsions described here include liquid or supercritical carbon dioxide in either of the continuous or dispersed phases. Gaseous carbon dioxide can become liquid carbon dioxide when compressed or pressurized (e.g., above 5.1 atm). Supercritical carbon dioxide can form when the carbon dioxide is brought above its critical temperature (31.1° C.) and pressure (78.3 atm). Supercritical carbon dioxide behaves like a gas with respect to viscosity, and can expand to fill its container like a gas, but behave like a liquid with respect to density. Additionally, liquid and supercritical carbon dioxide can diffuse through solids like a gas, and dissolve materials like a liquid, because of their properties such as low viscosity, high diffusion rate, and little or no surface tension. For example, the viscosity of supercritical carbon dioxide is typically in the range of 20 to 100 μPa·s, whereas typical liquids have viscosities of approximately 500 to 1000 μPa·s. Such properties make supercritical and liquid carbon dioxide useful for extraction processes.
The invention comprises all sorts of carbon dioxide, pure liquid and supercritical carbon dioxide, complex mixtures, complex liquids, as well as binary liquids, such as liquid hydrogen sulfide, organic and inorganic solvents freely miscible with carbon dioxide.
In embodiments comprising liquid or supercritical carbon dioxide as part of a continuous and/or dispersed phase of an emulsion, it should be understood that other materials can form at least a portion of that phase. For example, continuous or dispersed phases described herein may include one or more of the following non-limiting examples of supercritical fluids: water, methane, ethane, propane, ethylene, propylene, methanol, ethanol and acetone. Additionally and/or alternatively, the continuous or dispersed phase can also include liquids such as liquid nitrogen, liquid oxygen, liquid hydrogen, liquid argon, liquid helium, or other cryogenic liquids (i.e., liquefied gases at very low temperatures). Particle stabilized emulsions comprising a cryogenic liquid or a supercritical fluid as a continuous or dispersed phase, and an aqueous liquid as a continuous or dispersed phase are also provided.
Liquids forming continuous and dispersed phases may have a range of viscosities suitable for forming emulsions described herein. In some cases in which the continuous and/or dispersed phase comprises a supercritical or cryogenic liquid, for example, the viscosity of the liquid may be in the range of, e.g., between 10-200 μPa·s. For instance, in one embodiment, a continuous and/or dispersed phase consisting essentially of a supercritical or cryogenic liquid may have a viscosity in the above range. In another embodiment, a continuous and/or dispersed phase comprising a supercritical or cryogenic liquid (e.g., which may be dissolved in a liquid) may have a viscosity in the range of between 200-1,500 μPa·s. In yet another exemplary embodiment, a continuous and/or dispersed phase comprising a liquid, but which does not comprise a supercritical or cryogenic liquid therein, may have a viscosity in the range of between 200-1,500 μPa·s. It should be understood, however, that any suitable viscosity of a continuous and/or dispersed phase can be used to form emulsions described herein and that the invention is not limited in this respect.
In certain embodiments, the dispersed and/or continuous phase of an emulsion may include one or more additives such as organic substances, microbial components (e.g., bacteria), minerals, undissolved particles, various dissolved species, gases, solvents, salts, and the like. Accordingly, in some embodiments, emulsions described herein include ternary or higher mixtures.
In certain embodiments, emulsions described herein are stabilized at least in part by a particulate material. Suitable particulate materials include solid particles that are at least partially undissolved in the emulsion. The particulate materials may be, for example, naturally-occurring, synthetic, or modified. Particulate materials can be held at the interface between the two phases of the emulsion by, e.g., van der Waals forces, hydrophobic/hydrophilic interactions, hydrogen bonding, ionic interactions, and the like.
The surface properties of the particulate material (e.g., wettability) determines, at least in part, whether a CO₂-in-aqueous (C/A) or aqueous-in-CO₂(A/C) emulsion is formed in the case of a mixture of carbon dioxide (e.g., supercritical or liquid carbon dioxide) and an aqueous liquid. For example, particles having some hydrophilic character (e.g., CaCO₃, SiO₂, flyash, shale, and magnesium silicate) are preferentially wetted by the water phase; hence, they promote C/A-type emulsions. Particles having some hydrophobic character (e.g., ground Teflon, activated carbon, carbon black, and pulverized coal) are preferentially wetted by the carbon dioxide phase; hence, they promote A/C-type emulsions. In some cases, the hydrophobic or hydrophilic character of the particulate materials is naturally occurring or inherent in the material. In other embodiments, however, particulate materials can be treated by a process such as heating or coating, which can change the surface characteristics of the materials. For instance, particulate materials can be partially, completely, or uniformly coated with a substance (e.g., a surfactant or polymer). Applicable surface properties of the particles can be measured by those of ordinary skill in the art by techniques such as contact angle measurements between, for example, particle, aqueous and carbon dioxide three-component systems.
Particulate materials described herein may have a variety of shapes and sizes. For example, particulate materials may be cylindrical, spherical, rectangular, triangular, ellipsoidal, tubular, rod-like, or irregularly shaped. Suitable sizes of the particulate material may depend on factors such as the particulate type of emulsion (e.g., a carbon dioxide-in-water or water-in-carbon dioxide emulsion), the components of the continuous and dispersed phases, and the size of the dispersed droplets in the medium. The size of the particulate material refers to the length of the shortest line (e.g., cross-sectional dimension) connecting two end points of the material and passing through the geometric center of the material. In some embodiments, the average size of the particulate materials used to form an emulsion is less than 100 microns, less than 50 microns, less than 25 microns, less than 10 microns, less than 5 microns, less than 1 micron, less than 500 nm, less than 250 nm, less than 100 nm, less than 50 nm, less than 10 nm, or less than 5 nm. Particles may comprise the class of particles referred to as nanoparticles.
In some instances, the average size of the particulate materials used to form an emulsion is chosen, at least in part, by the desired size of the dispersed droplets of the emulsion. For instance, in some embodiments, very small particles may not be suitable for large droplets, as the particles may be dislodged from the surface of large droplets by Brownian motion. In other embodiments, large particles may not be suitable for small droplets, as the particles may not be able to pack onto small droplets. Accordingly, in some cases, the particle size is adjusted to the dispersed droplet diameter. In certain embodiments, the average size of the particulate materials may be about 5-about 50 times smaller than the average size of the dispersed droplets of the emulsion. For example, the average size of the particulate materials may be at least 5, 15, 25, or 50 times smaller than the average size of the dispersed droplets of the emulsion. Without limitation, the ratio of particle size to droplet size may be, for example, between 1:10 and 1:30 (e.g., between 1:10 and 1:20 or between 1:20 and 1:30). Of course, other ratios of particle size to droplet size may also be used.
Particulate materials may include elemental metals (e.g., gold, silver, copper), semi-metals and non-metals (e.g., antimony, bismuth, graphite, sulfur), and/or ceramics. In some instances, particulate materials can include metal oxides, metal sulfides, and/or metal sulfates.
In some embodiments, a particulate material is formed of a rock or a mineral. Non-limiting examples of rocks or minerals that can be used as particulate materials include silica, alumina, bentonite, magnesium aluminum silicate, magnesium oxide, magnesium trisilicate, titanium dioxide, silicon dioxide, tin oxide, limestone, magnetite, chlorite (e.g., clinochlore chamosite, nimite, and pennantite), pyroxenes, amphibole, and biotite. Classes of minerals that may be used as particulate materials include, but are not limited to, silicates (e.g., feldspars, quartz, olivines, pyroxenes, amphiboles, garnets, and micas), carbonates (e.g., calcite, aragonite, dolomite, siderite, and nitrate and borate minerals), sulfates (e.g., anhydrite, celestite, barite, gypsum, and chromate, molydate, selenate, sulfite, tellurate, and tungstate minerals), hyalites (e.g., fluorite, halite, sylvite, sal ammoniac, and fluoride, chloride and iodide minerals), oxides (e.g., hematite, magnetite, chromite, spinel, rutile, and other oxide and hydroxide minerals), sulfides (e.g., pyrite, chalcopyrite, pentlandite, galena, and selenides, tellurides, arsenides, antimonides, bismuthinides, and sulfusotes), and phosphates (e.g., apatite, and phosphate, arsonates, vanadate, and antimonate minerals).
In some embodiments, particulate materials that can be used as an emulsifying agent include pulverized stones, such as one or more of the following: limestone, marble, granite, sandstone, slate, dolomite, chalk, and flint.
Particulate materials can also include polymer particles (e.g., plastics) such as polycarbonates, polyethers, polyethylenes, polypropylenes, polyvinyl chloride, polystyrene, polyamides, polyacrylates, polymethacrylates, polytetrafluoroethylene (Teflon) and the like. Particles may also be derived from biomass or natural sources such as cellulose, chitin, chitosan, proteins, carbohydrates, etc.
In one particular embodiment, particulate materials from the following group of materials can be used: pulverized sand, carbon black, petrocoke, treated clays, Teflon, flyash, shale, magnesium silicate rock, pulverized coal, quartz, feldspar, lizardite, clays, serpentine, and gypsum. It should be understood that the invention is not limited to the above-mentioned particulate materials, but any particle or group of particles that facilitates the generation of a C/A or A/C emulsion as desired can be used in accordance with the invention.
In certain embodiments of the invention, an emulsion can be stabilized by both a particulate material and a surfactant, which act as emulsifying agents to stabilize at least two immiscible phases. A variety of surfactants are known in the art and may include, for example, anionic, cationic, zwitterionic, and non-ionic species.
Those of ordinary skill in the art can also choose an appropriate emulsifying agent by, for example, choosing the components used to form the continuous and dispersed phases of the emulsion and knowing the surface properties (e.g., wettability) and/or likelihood of reactivity between the emulsifying agent and the two phases, and/or by a simple screening test. For example, if a carbon dioxide-in-water emulsion is desired, a suitable emulsifying agent (e.g., a particulate material) may include one that is hydrophilic such that it can be wetted by the continuous water phase. One simple screening test may include mixing one set of components in a vial or pressure vessel to form the emulsion and determining the stability of the emulsion. Either the material composition, quantities, and/or concentration of one component can then be varied while keeping the others constant, and the stability of this emulsion can then be measured. Other simple tests can be conducted by those of ordinary skill in the art.
The criteria in accordance with certain embodiments of the invention that can be used to select suitable dispersed phases, continuous phases, and emulsifying agents suitable for use in the invention may also include a simple screening test to determine which type of emulsion (e.g., an A/C or C/A emulsion) has been created. For example, for an emulsion comprising an aqueous liquid and carbon dioxide, if a water-soluble, carbon dioxide-insoluble dye is added without mixing to an emulsion, if the emulsion is an aqueous-in-carbon dioxide emulsion the dye may form a separate phase, since it is not miscible with the continuous, carbon dioxide phase. But in the case of a carbon dioxide-in-aqueous emulsion, the dye may dissolve in the continuous, aqueous phase giving the appearance of dissolution of the dye in the entire mixture. In a second screening test, the aqueous phase can be made slightly electrically conductive and, if the emulsion is slightly electrically conductive, then the continuous phase is aqueous, i.e., a carbon dioxide-in-aqueous phase results. If the mixture is not electrically conductive, then an aqueous-in-carbon dioxide emulsion results. In the description herein concerning the use of appropriate materials and compositions to form emulsions, those of ordinary skill in the art can select suitable dispersed phases, continuous phases, emulsifying agents, and techniques, etc. based upon general knowledge of the art, in combination with the description herein.
Emulsions described herein are, according to some embodiments, stable for at least about 1 minute. Emulsions that are stable over time are useful because they allow for the time necessary to transport, place, and/or use the emulsion before coalescence or disintegration. For example, emulsions may be stable for more than 1 minute, 1 hour, 1 day, 1 week, 1 month, or 1 year. As used herein, a “stable emulsion” means that droplets of the emulsion do not coalesce, e.g., to form larger droplets, at a particular temperature and pressure resulting in two bulk phases with a meniscus between. In one particular embodiment, an emulsion that can be used in EOR is stable from the time of formation to the time of injection of the emulsion into a subterranean formation.
Emulsions described herein can have any suitable ratio of continuous and dispersed phases. Typically, however, the volume of the continuous phase is greater than that of the dispersed phase. Without limitation as to exact ratio, for example, the ratio of the volumes of the continuous phase to dispersed phase may be greater than or equal to 1:1 up to 20:1 (e.g., between 1:1 and 5:1, between 5:1 and 10:1, or between 10:1 and 20:1). It should be understood, however, that any suitable ratio of volumes of continuous phase to dispersed phase can be used to form emulsions described herein and that the invention is not limited in this respect.
The amount of particulate material necessary for forming an emulsion may depend on one or more of the following parameters: the particle size, the droplet size, the type of emulsion formed, the shape of the particles (which, in turn, may effect interparticulate or steric interactions), concentrations and compositions of the continuous and dispersed phases, and physical parameters associated with forming the emulsion (e.g., shear force, temperature, and pressure). Accordingly, various amounts of particulate materials relative to the amount of dispersed and/or continuous phase may be used to form emulsions described herein. Without limitation as to numeric value, in certain embodiments, the mass ratio of particulate material to carbon dioxide may be, for example, greater than or equal to 0.005:1 up to 1.0:1 (e.g., between 0.005:1 and 0.2:1, between 0.2:1 and 0.6:1, or between 0.6:1 and 1.0:1).
In some embodiments, the amount of particulate material added to two immiscible phases of an emulsion can be greater than that which is necessary to form the emulsion, and a portion of the particulate material can accumulate, for example, at the bottom of a reactor. In addition, because not all particles are of uniform size and may, in fact, include a distribution of sizes (e.g., some may be too small to adhere to the interface of the continuous and dispersed phases, and some may be too big), higher ratios of particulate material to dispersed phase material may be used.
In some embodiments, the amount of particulate material necessary for emulsion formation can be estimated from a particle sheath model (e.g., a monolayer or multi-layer sheath model). An example is given for liquid CO₂droplets in an aqueous continuous phase and a particulate material comprising CaCO₃. Taking a droplet diameter of 100 microns, a sheath thickness of 2 microns (corresponding to a monolayer of Hubercarb CaCO₃Q6 particles with mean size 2 microns), a liquid CO₂density at 15° C. and 17 MPa of 0.93 g/cm³, and a CaCO₃bulk density of the mass ratio of CaCO₃/CO₂is estimated at 0.2:1. Because not all particles have a uniform size, different ratios of CaCO₃/CO₂may be used; for example, 0.4:1, that is, for every 1 kg of CO₂, 0.4 kg of pulverized limestone may be used.
Emulsions described herein may be formed using any suitable emulsification procedure known to those of ordinary skill in the art. In this regard, it will be appreciated that the emulsions can be formed using methods/systems such as microfluidic systems (e.g., a microfluidizer), ultrasound, high pressure homogenization, using a static mixer, shaking, stirring, spray processes, and membrane techniques. In certain embodiments, emulsions described herein are formed by shear forces. In the description herein concerning the use of appropriate methods of fabricating emulsions, those of ordinary skill in the art can select suitable materials, techniques, conditions (e.g., temperature and pressure) etc. based upon the particular application, general knowledge of the art and available reference materials concerning certain techniques for forming emulsions, in combination with the description herein.
In one particular embodiment, emulsions described herein are formed using a high-pressure batch reactor, as shown in FIG. 4. As shown in the embodiment illustrated in FIG. 4, high-pressure batch reactor 50 can be used to form an emulsion comprising water and liquid or supercritical carbon dioxide as the continuous or dispersed phases. The reactor includes source of water 54 in fluid communication with vertical batch reactor 58. Electrical pump 60 can transport water from the source to the reactor via pipe 62, and this process which can be controlled at least in part by check valve 64 and/or release valve 66. As illustrated, source of carbon dioxide 70 is also in fluid communication with the reactor via pipe 72. Introduction of carbon dioxide into the reactor can be controlled by manual piston screw pump 74, shut off valves 76 and 78, and relief valve 80. The pressures in the pipes can be measured by gauges 82 and 86. Once water and carbon dioxide are introduced into reactor 58, magnetic mixer assembly 88 can mix the components and form an emulsion. The temperature inside the reactor can be measured by thermal couple and panel meter 90.
Particulate matter can be introduced into the reactor via an opening (not shown) in the form of a slurry or particulate material alone. System 100, or a similar system, can be used to form a variety of emulsions including, but not limited to, CO₂-in-aqueous, aqueous-in-CO₂, aqueous-in-oil, and oil-in-aqueous emulsions.
In another embodiment, a microfluidizer is used to form an emulsion. The size and stability of the droplets produced by this method may vary depending on, for example, capillary tip diameter, fluid velocity, viscosity ratio of the continuous and dispersed phases, and interfacial tension of the two phases.
In another embodiment, a static mixer is used to form an emulsion. An example of a static mixer is illustrated in FIG. 5. As shown in the embodiment illustrated in FIG. 5, static mixer 92 is tubular and includes alternating helical mixing blades 96 with no moving parts. In some cases, the static mixer is a Kenics-type static mixer. The components of an emulsion (e.g., liquid or supercritical CO₂, particles, and an aqueous liquid) can be introduced at an up-stream portion 94 of the mixer, and an emulsion formed of the components can exit at a down-stream portion 98. A static mixer can be incorporated into a static mixer emulsion apparatus, e.g., as shown in FIG. 6. The size and stability of the droplets produced by a static mixer may vary depending on, for example, the pressure differential between the up- and down-stream portions of the static mixer, the length of the mixer, the number of baffles per unit length of the mixer, and other variables (e.g., temperature).
In some embodiments of the invention, emulsions described herein are used for extracting a component from a mixture of hydrocarbons. The component to be extracted may be in the form of a solid (e.g., kerogen), a liquid (e.g., crude oil), or a gas (e.g., methane). In some cases, the component may include impurities and/or can include more than one phase (e.g., solid contaminants in a liquid). The at least two components of the mixture may be of the same phase (e.g., both solid, both liquid, or both gaseous) or may include different phases (e.g., a solid and a liquid, a solid and a gas, or a liquid and a gas).
FIG. 7 schematically illustrates a system and one or more associated methods that can be used to recover an oil or a hydrocarbon gas from a subterranean formation. As shown in this illustrative embodiment, system and related method(s) 100 include particulate material 102, supercritical or liquid CO ₂ 104 and aqueous liquid 108 (e.g., water), which can be in fluid communication with emulsion forming apparatus 112 for forming, for example, CO₂-in-aqueous, aqueous-in-CO₂, oil-in-aqueous, or aqueous-in-oil emulsions. Once an appropriate emulsion is formed, the emulsion may flow to injection apparatus 118 (e.g., an injection well or pump), which may introduce the emulsion into well 123 in the direction of arrows 122.
Well 123 may be drilled from top layer 124 to bottom layer 125 of a subterranean formation, and the intermediate layer may include reservoir or coal bed 126 containing mixtures of oil and earth or gas and produced water, respectively. With regard to the former, the oil in the reservoir is typically immobile or very viscous. Without limitation as to any one theory or mode of operation, when the emulsion is introduced into well 123, this produces areas of high pressure 127 and low pressure 129; as a result, the emulsion flows in the direction of arrows 128 from well 123 to well 130. In this process, supercritical or liquid carbon dioxide from the emulsion can reduce the viscosity of the oil by acting as a solvent to dissolve at least a portion of the oil and/or by causing the oil to swell and reducing oil density, thereby mobilizing the oil in the direction of arrows 128. In some cases, the aqueous liquid portions of the emulsion can replace or exchange with the oil coated on the porous earth of the formation. The oil extracted from reservoir 126, along with portions of the continuous and/or dispersed phases of the emulsion, can flow in the directions of arrows 132 to receiver 142 (e.g., a producing well).
With regard to embodiments relating to coal bed 126, introduction of such an emulsion and subsequent contact thereof with cleats, fissures, fractures, pores or surfaces of the coal bed (124/125) can cause at least a partial emulsion disruption. Released carbon dioxide component, whether from a continuous or a dispersed phase, can interact with coal bed surfaces via cleats, fissures, fractures and pores 124/125 to induce release of methane and/or other associated hydrocarbon gases therefrom. As discussed above, such an emulsion can also serve to facilitate release and transport of produced water.
Regardless, as the resulting extracted mixture may include carbon dioxide, an oil or gas, water (e.g., in the case of a water-in-CO₂or a CO₂-in-water emulsion being injected), and/or produced water, separation of the components may be necessary or desired. A first separation process can include the use of separator 146, which may separate carbon dioxide from the oil/gas and water (and/or produced water). The carbon dioxide, which may now be in the form of a gas, can be recovered in container 154. If desired, this carbon dioxide can be recycled by transporting it to compressor/condenser 158, which can compress and/or condense the carbon dioxide to form supercritical or liquid CO₂. This compressed carbon dioxide can act as, or be added to, source of carbon dioxide 104. Alternatively, the well can be capped off and at least a portion of the carbon dioxide can be left inside the well and/or formation for sequestration. In other coal bed embodiments, as discussed above, all or a portion of the carbon dioxide component can be emulsified with produced water, for sequestration.
Once separator 146 removes CO₂from the extracted mixture, oil/gas and water can be transported to separator 164, which can separate water from the hydrocarbon component. Water, including produced water from a coal bed, separated from the mixture can be transported to container 168, and can act as, or be added to, source of water 108 used in forming the emulsion. Additionally and/or alternatively, at least a portion of the water can be transported to a water disposal well, lagoon, etc. The oil or gas separated from separator 164 can be transported to storage facility 174 for future use or consumption. Oil can be refined on site (not shown), or transported to another facility. In some embodiments, at least a portion of the oil can act as, or be added to, source of oil 109 used to form the emulsion.
Carbon dioxide 104 may be obtained commercially from sources such as natural CO₂deposits, gas wells, CO₂separated from natural gas wells, from coal gasification processes, from separating CO₂in the flue gas of fossil fuel combustion, from cement manufacturing, from fermentation, from combustion of carbonaceous fuels, and as a by-product of chemical processing where CO₂is a major by-product. For example, CO₂may be obtained as a by-product from steam-hydrocarbon reformers used in the production of ammonia, gasoline, and other chemicals. In some cases, carbon dioxide produced as waste from an oil upgrading process or a power generating plant is used as a carbon dioxide source for forming emulsions. For example, upgrading processes for converting crude oil into lighter oils typically includes carbon removal and/or hydrogen addition processes. Carbon removal, or “coking”, involves catalytically “cracking” crude oil using heat to form lighter oils and a solid carbonaceous by-product. Hydrogen addition, “hydrocracking”, typically involves cracking crude oil into lighter oils by the addition of hydrogen (i.e., hydrogenation) to increase in the hydrogen to carbon ratio. Both processes typically involve the production of large amounts of CO₂. As gases produced from these process may include, in addition to CO₂, contaminants such as water, SO_x, and NO_x, the CO₂may be removed from the gases, compressed, and transported for later use.
As described above, at least a portion of carbon dioxide 104 may be recycled or recovered from the extraction process. Carbon dioxide may be treated by processes such as, for example, amine (MEA) treatment, adsorption processes, extractive distillation techniques, and membrane systems. Crude CO₂(e.g., containing at least 90% CO₂) can be compressed in either two or three stages, cooled, purified, and condensed to the liquid phase by a compressor/condensor. The carbon dioxide can then be placed in an insulated storage vessel.
If the carbon dioxide is imported to the site, the carbon dioxide can be transported, for example, in high-pressure uninsulated steel cylinders, as a low-pressure liquid in insulated truck trailers or rail tank cars, or as dry ice in insulated boxes, trucks, or boxcars.
As described above, a variety of aqueous liquids can be used in emulsions described herein. In one embodiment, water from a well on site of the subterranean formation can be used. In other embodiments, well water, sea water, or other sources of water can be imported. In yet another embodiment, waste water from an oil refinement process may be used in forming emulsions described herein. Optionally, the water may be purified (e.g., filtered) to remove waste materials, contaminants, and the like, prior to formation of the emulsion.
Particulate materials 102 may be imported from a variety of sources or may be created on site. For example, in one embodiment, particulate materials may be obtained from or near the subterranean formation, such as from top layer 124 (e.g., sandstone or coal particles) as shown in FIG. 7. Precursors of particulate materials may be pulverized off site or on site to produce particulate material suitable for use in emulsions described herein.
In the embodiment illustrated in FIG. 7, particulate material 102, carbon dioxide 104, and aqueous liquid 108 (and/or oil 109) are shown as separate sources. However, in other embodiments, one or more materials can be premixed prior to forming an emulsion. For example, in one embodiment the particulate material is mixed with water to form a slurry prior to formation of an emulsion with carbon dioxide. In another embodiment, the particulate material is mixed with carbon dioxide to form a slurry prior to formation of an emulsion with another liquid. Other pre-mixtures of components can also be used.
One particular system for recovering oil from a subterranean formation is shown in FIG. 8. In the illustrative embodiment shown in FIG. 8, a C/A or A/C emulsion can be introduced into the subterranean formation via an injection well. CO₂released from the emulsion can partition into the oil of the formation, dissolve at least a portion of the oil, thereby reducing the viscosity of the oil, and leave behind a slurry of fine particles in water. The CO₂emulsion, because of its superior viscosity and sweep efficiency, as well as its ability to displace oil from the formation granules, can drive the oil toward a production well, enabling significantly more oil to be recovered than with present primary and secondary recovery methods alone.
Methods described herein comprising extracting a hydrocarbon or some component hydrocarbons from a mixture of hydrocarbons can result in efficient recovery of the component hydrocarbon or component hydrocarbons from the mixture. For instance, in certain embodiments involving the recovery of crude oil from a subterranean formation, methods described herein may result in recovery of 20-80% of the remaining crude from the formation.
Methods described herein comprising extracting oil from a subterranean formation may be suitable for spent oil reservoirs where primary and/or secondary oil recovery has already been performed. For example, in certain embodiments where primary and/or secondary oil recovery has been performed at an oil reservoir and 30% of the oil from the reservoir has been removed by the primary or secondary methods, methods described herein involving particle-stabilized emulsions can remove up to or greater than 60% of the oil originally contained in the reservoir. In some embodiments, a mixture of components can be removed from a subterranean formation and the mixture can be treated outside of the subterranean formation in order to extract a component from the mixture.

EXAMPLES OF THE INVENTION

The following non-limiting examples and data illustrate various aspects and features relating to the methods and/or systems of the present invention, including the preparation of particulate-stabilized emulsions over range of physical properties and functional effects, as are available through the synthetic methodologies described herein. In comparison with the prior art, the present methods and/or systems provide results and data which are surprising, unexpected and contrary thereto. While the utility of this invention is illustrated through the use of several methods/systems and emulsions, together with various continuous and dispersed phases thereof, it will be understood by those skilled in the art that comparable results are obtainable with various other methods/systems and emulsions/continuous phases/dispersed phases, as are commensurate with the scope of this invention.
Materials.
Carbon Dioxide. Liquid and supercritical carbon dioxide are available, as known in the art. Industrial-grade liquid carbon dioxide was supplied from 50 lb siphon cylinders (Northeast Airgas). Water was either water that was deionized and filtered in a laboratory still (Millipore Milli-RO), municipal tap water, or artificial seawater (3.5 wt % reagent-grade NaCl). The following representative particles were used:
1. Hydrophilic Particles. 1.a. Limestone. Mined pulverized limestone (96.5% CaCO₃, 2% MgCO₃, 1% silica and silicates, and 0.5% others) supplied by Huber Engineered Materials, Quincy, Ill., was used with a bulk specific gravity of 2.7 and a solubility of 0.0035 g/(100 mL of H₂O) at 100° C. The pulverized samples can be purchased with different size distributions. In this study, Hubercarb Q1 and Q6 with nominal median particle sizes of 1 and 6 μm, respectively, were used. A scanning electron microscope (SEM) image of sample Q6 shows some particles are crystalline (rhombohedral) and others are irregular. For some runs, reagent grade CaCO₃was used, obtained from Fisher Scientific. An SEM image of the reagent-grade CaCO₃particles shows these particles to be mostly rhombohedral calcite crystals.
1.b. Sand. Ordinary beach sand was brought to the laboratory, ground in a Patterson-Kelley V-shaped wet/dry blender charged with ˜200 g of sand, 500 mL of water, and 200 g of ˜1 cm silicon nitride grinding pebbles. After about 24 h, the pulverized sand was recovered by Buechner filtration, and the filter cake was air-dried and then sieved through a U.S. mesh 325 sieve. Most particles appear to be crystalline, probably quartz. Energy dispersive X-ray (EDX) spectroscopic analysis shows the most abundant element in the sand is Si with some trace metals, Ca, Mg, Fe, and Al.
1.c. Flyash. Flyash collected by an electrostatic precipitator (ESP) at the Salem Harbor, Mass., coal-fired power plant was used without further processing. An SEM image of the flyash particles shows some particles are crystalline, some are amorphous, and there are a fair number of glassy spheres. EDX analysis shows the major elements are Si and Al, with minor elements Ca, Fe, and Mg and trace elements K, S, and Ti.
1.d. Shale. A piece of shale was ground to a fine powder in a rotary pulverizer using hardened steel plates and then sieved through a U.S. mesh 325 sieve. An SEM image of the shale particles shows the particles appear rather amorphous. Most shales are composed of clay minerals and quartz, 60-65% SiO₂, 16-18% Al₂O₃, with the rest being Fe₂O₃, MgO, CaO, Na₂O, K₂O, TiO₂, and other trace metal oxides.
1.e. Magnesium Silicate. Pulverized lizardite, a rock rich in magnesium silicate, was obtained from the U.S. Department of Energy Albany Research Center, Albany, Oreg., and used as received. An SEM image of the lizardite particles shows the particle shape is irregular.
2. Hydrophobic Particles. 2.a. Teflon. Teflon powder is commonly used for lubricating purposes. Several grams from a local hardware store and used it without further processing. An SEM image of the Teflon powder shows particle shape is irregular.
2.b. Activated Carbon. Norit Darco G-60, −100 U.S. mesh size was used without further processing.
2.c. Carbon Black. Carbon black was obtained from the Cabot Corp., Billerica, Mass. It is composed of 100% carbon. It was used without further processing.
2.d. Coal. Pulverized coal was obtained from the Salem Harbor, Mass., coal-fired power plant. The coal is of Colombian origin, bituminous, dried, 65% carbon, and 6.6% ash. The coal was pulverized in a ball mill at the power plant and used without further processing. An SEM image of the coal particles shows particles are irregular in shape, although some are crystalline, possibly due to sand and other crustal materials excavated together with the carbonaceous coal, commonly referred to as ash.
The following examples illustrate preparation of particle-stabilized emulsions, for use in either EOR or ECBM-related methods, according to certain embodiments of the invention.

Example 1a

Particles-stabilized CO₂-in-aqueous liquid (C/A) and aqueous liquid-in-CO₂(A/C) macroemulsions were formed in a high-pressure batch reactor (HPBR) with view windows using an apparatus similar to the one shown in FIG. 4. The reactor included a stainless steel pressure cell of 85 mL internal volume equipped with tempered glass windows (PresSure Products G03XC01B). The windows were placed 180° apart, with one illuminated with a 20 W, 12 V compact halogen bulb and the other allowing observation with a video camera. The view window diameter was 25 mm. The window diameter was used as a scale for determining droplet diameter sizes. The reactor was equipped with a pressure-relief valve (Swagelok R3⁻ A), a thermocouple (Omega KMQSS-125G-6), a pressure gauge (Swagelok PGI-63B), a bleed valve (Swagelok SS-BVM2), and a 3.2 mm port for admitting CO₂. A cylindrical magnetic stir bar with a cross shape on top (VWR Spinplus) was utilized for internal mixing. Unless otherwise indicated, the stir bar rotated at 1300 rpm. Reactor temperature was adjusted by application of hot air from a heat gun or solid dry ice chips.

Example 1b

For preparation of C/A macroemulsions, the following procedure was carried out: a slurry of the hydrophilic particles in water was prepared, a measured volume of the slurry was added to the HPBR through an opening, the opening was closed, and a measured volume of liquid or supercritical CO₂was added by means of a syringe pump. Unless otherwise indicated, the proportions of the ingredients were as follows: 10 g of particulate matter suspended in 65 mL of water and ˜18-20 mL (balance) of liquid CO₂. The pressure in the HPBR was 17.2 MPa and the temperature was 15° C.

Example 1c

For preparation of A/C macroemulsions, the preceding procedure was reversed. First, the dry matter was added to the HPBR, followed by injection of liquid CO₂. After agitation, a high-pressure syringe pump was used to inject water to a set pressure of 17.2 MPa. For the A/C emulsions, a proportion of ˜65 mL of CO₂/(20 mL of H₂O) was used.

Example 1d

For most particles used in these representative, non-limiting examples, the particle size was determined from SEM images. In each frame, nearly all particles were counted and measured. For spherical particles, their diameter was measured; for crystalline or irregular particles, the average of two dimensions was taken, one along the long axis and the other along the short axis. The mean diameter was estimated as 27
(d _p)_mean =[Σn,(d _p)×d _p ]/N _t (1)
where n, (d_p) is the number of particles counted that have a size d_p, and N_tis the total number of particles counted. The mean size, (d_p)_mean, and standard deviation of the particles used in this study are tabulated in Table 1.

Example 1e

For dispersed phase droplet size determination, the HPBR window diameter (25 mm) was used as a scale. The diameter of droplets near the window was measured under magnification and compared with the window diameter.

TABLE 1

Mean Particle Size and (Standard Deviation) in μm of Pulverized
Materials Used for Stabilizing C/A and A/C Type Emulsions

(a) (hydrophilic)

	limestone	limestone	CaCO₃	sand
particle	(Q6)	(Q1)	(Fisher)	SiO₂	flyash	shale	lizardite

mean,	2 (1.7)	0.55 (0.4)	3.1 (1.6)	4.3 (5.7)	2.5 (3.4)	4.2 (6.0)	4.8 (3.9)
size μm

(b) Hydrophobic

particle	carbon black^a	coal	teflon

mean,	0.12	4.2 (4.4)	1.8 (1.0)
size μm

^aManufacturer data;
( ) standard deviation

The following examples provide results and observations relating to the emulsions prepared above, and illustrate various properties and functional characteristics which can be utilized in the context of oil or hydrocarbon gas recovery.
Hydrophilic Particles.

Example 2a

Limestone. Both Hubercarb as mined pulverized limestone and Fisher Chemical reagent-grade CaCO₃gave stable C/A macroemulsions. A C/A macroemulsion formed with Hubercarb Q6 particles with mean particle size of 0.55 (0.4) microns, where the number in parentheses is the standard deviation. A non-uniform macroemulsion was formed, with heavier globules settling at the bottom of the water column, median-size globules being neutrally buoyant, and large globules floating on top of the water column. The large globules appeared to be partially covered with a sheath of particles.
A C/A macroemulsion stabilized by Hubercarb Q6 particles with mean particle size of 2 (1.7) microns was formed. After thorough mixing and a rest period, most globules settled in the bottom of the pressure cell, indicating that the globules were heavier than the surrounding water. The globule diameter was in the range of 200-300 microns.
Macroemulsions were also formed with supercritical CO₂and Q1 particles. The pressure in the cell was 17.2 MPa at a temperature of 45-47° C. A stable macroemulsion formed with a globule diameter in the 100-150 micron range, smaller than that with liquid CO₂under the same pressure and mixing conditions. Most globules settled in the bottom of the cell. Even though the density of supercritical CO₂(˜800 kg m⁻³) is smaller than that of liquid CO₂(−930 kg M⁻³at 17.2 MPa and 15° C.), the gross density of the supercritical globules was greater than that of the surrounding water.
Limestone particle-stabilized macroemulsions were also formed in a solution of 3.5 wt % NaCl in deionized water. The globule diameter was similar to that formed in deionized water alone, and all the initially present liquid CO₂was emulsified. However, no systematic measurements were performed on emulsion yield as a function of NaCl concentration.
Macroemulsions were also formed with Fisher Chemical C-65 reagent-grade CaCO₃(mean particle size 3.1 (1.6) microns). Under mild mixing conditions (400-500 rpm), rather large globules were formed, in the 500-800 micron diameter range. The sheath of crystalline particles adhering to the surface of CO₂droplets was clearly visible.

Example 2b

Sand. The milled and sieved sand particles had a mean particle size of 4.3 (5.7) microns. The large standard deviation indicates a wide distribution of particle size. The sand particles produced a stable C/A macroemulsion, probably due to the hydrophilic silica content of sand. The globule diameter was in the 200-300 micron range.

Example 2c

Fly ash. The unprocessed flyash particles had a mean particle size of 2.5 (3.1) microns. The large standard deviation indicates a wide distribution of sizes, but most particles were in the submicron to a few micron size range. The size of the particles, plus their hydrophilic character (similar to sand), was conducive for the formation of a stable C/A macroemulsion. The globule diameter was in the 80-150 micron range.

Example 2d

Shale. The pulverized shale had a mean particle size of 4.2 (6.0) microns with a wide distribution of sizes. Pulverized shale produced a stable C/A macroemulsion, probably due to the hydrophilic character of shale's major ingredients, clay minerals and quartz. The globule diameter was in the 80-150 micron range. Because of the small bulk density of shale (2.0-2.2 g/cm³), most pulverized shale-sheathed globules floated on top of the water column.

Example 2e

Magnesium Silicate. The pulverized lizardite had a mean particle size of 4.8 (3.9) microns. The appropriate particle size and the hydrophilic character of magnesium silicate produced a stable C/A macroemulsion. The globule diameter was in the 80-130 micron range.
Hydrophobic Particles.

Example 3a

Teflon. Teflon powder is strongly hydrophobic. One gram of the powdered resin produced an aqueous liquid-in-carbon dioxide (A/C) macroemulsion, where water is the dispersed phase and CO₂is the continuous phase. Water droplets sheathed with Teflon particles were evident, and no phase separation occurred during several hours of observation, which indicates that a stable A/C macroemulsion was formed.

Example 3b

Activated Carbon. When activated carbon (AC) was dispersed in liquid CO₂under pressure, the AC agglomerated into clumps. Under the conditions employed, upon addition of water and stirring, a black mass ensued in which it was difficult to discern distinct globules.

Example 3c

Carbon Black. Carbon black (CB) did disperse in liquid CO₂without agglomeration. Upon addition of water with stirring, a black, inscrutable liquid ensued. However, no phase separation occurred after several hours of observation, suggesting that a stable A/C emulsion was formed.

Example 3d

Coal. Pulverized coal also dispersed readily in liquid CO₂without agglomeration. Upon addition of water with stirring, a A/C macroemulsion was formed where water droplets were sheathed with coal particles dispersed in CO₂.

Example 4

With reference to FIGS. 9A-B and illustrating broader aspects of this invention, an A/O type emulsion representing but one embodiment of this invention, which also represents an A/C emulsion as another embodiment, was formed by mixing 70 mL dodecane and 30 mL of tapwater in a batch reactor. Three grams of Teflon® particles was added. The resulting A/O type emulsion was injected into a glass cylinder 200 shown in FIG. 9A containing sand saturated with crude oil, simulating a subterranean formation. The cylinder was equipped with a central injection tube 206 extending to the bottom 207 of glass cylinder 200. In FIG. 9A the emulsion was introduced through tube 206 in direction 208 and exits tube 206 at the bottom 207 of cylinder 200 creating an upward flow 209 flushing the oil 214 from the oil saturated sand. The cleaned sand 212 is readily visible. Laboratory analysis of similar experiments showed that 80% of the original oil in place (OIP) was extracted and recovered by the emulsion. FIG. 9B shows an identical crude oil saturated sand column 210 after flushing with water followed by dodecane alone (no emulsion). Oil saturated sand 224 is not thoroughly cleaned of the oil and layers of water 222 and crude oil 220 are clearly visible.
While several embodiments of the present invention have been described and illustrated herein, those of ordinary skill in the art will readily envision a variety of other means and/or structures for performing the functions and/or obtaining the results and/or one or more of the advantages described herein, and each of such variations and/or modifications is deemed to be within the scope of the present invention. More generally, those skilled in the art will readily appreciate that all parameters, dimensions, materials, and configurations described herein are meant to be exemplary and that the actual parameters, dimensions, materials, and/or configurations will depend upon the specific application or applications for which the teachings of the present invention is/are used. Those skilled in the art will recognize, or be able to ascertain using no more than routine experimentation, many equivalents to the specific embodiments of the invention described herein. It is, therefore, to be understood that the foregoing embodiments are presented by way of example only and that, within the scope of the appended claims and equivalents thereto, the invention may be practiced otherwise than as specifically described and claimed. The present invention is directed to each individual feature, system, article, material, kit, and/or method described herein. In addition, any combination of two or more such features, systems, articles, materials, kits, and/or methods, if such features, systems, articles, materials, kits, and/or methods are not mutually inconsistent, is included within the scope of the present invention.

Claims

1. A tertiary method of subterranean hydrocarbon recovery, said method comprising:

providing a subterranean formation comprising a residual hydrocarbon component, said component selected from an oil and a gas;

contacting said subterranean formation with a fluid medium comprising an emulsion comprising at least one of a liquid carbon dioxide component and a supercritical carbon dioxide component and an aqueous component, said emulsion comprising a particulate component selected from hydrophilic particles and combinations thereof and hydrophobic particles and combinations thereof, said particulate component in an amount sufficient for at least partial emulsification, said contact for at least one of a time and at a pressure at least partially sufficient to displace said hydrocarbon component from said formation; and

recovering said hydrocarbon component and at least a portion of said fluid medium.

2. The method of claim 1 wherein said subterranean formation comprises a residual oil.

3. The method of claim 2 wherein said fluid medium comprises an emulsion comprising a dispersed phase comprising a said carbon dioxide component, a continuous phase comprising a said aqueous component, and a hydrophilic particle component.

4. The method of claim 3 wherein said hydrophilic particle component is selected from limestone particles, sand particles, gypsum particles, fly ash particles, clay particles and combinations of said components.

5. The method of claim 1 wherein said subterranean formation comprises a residual hydrocarbon gas.

6. The method of claim 5 wherein said fluid medium comprises an emulsion comprising a dispersed phase comprising a said aqueous component, a continuous phase comprising a said carbon dioxide component, and a hydrophobic particle component.

7. The method of claim 6 wherein said hydrophobic particle component is selected from coal particles, carbon black particles, activated carbon particles, asphaltene particles, petrocoke particles, resin particles, fluorocarbon particles, protenaceous particles and combinations of said components.

8. The method of claim 5 wherein said carbon dioxide component of said recovered fluid medium is emulsified with a produced water component of said formation, said emulsion comprising hydrophobic particles and combinations thereof.

9. The method of claim 8 wherein said carbon dioxide-produced water emulsion is introduced to a subterranean formation.

10. The method of claim 1 wherein one of a continuous phase and a dispersed phase of said emulsion comprises a said carbon dioxide component comprising greater than about 1 weight percent of said emulsion.

11. The method of claim 1 wherein said particles are dimensioned from about 5 nanometers to about 100 microns.

12. The method of claim 11 wherein said particle dimension is about 5 to about 50 times smaller than a dimensional aspect of a dispersed phase of said emulsion.

13. A method of using a particle-stabilized carbon dioxide emulsion for tertiary oil recovery, said method comprising:

providing a subterranean formation comprising a residual oil component;

contacting said subterranean formation with an emulsion comprising at least one of a liquid carbon dioxide component and a supercritical carbon dioxide component, and an aqueous component, said emulsion comprising a particulate component selected from hydrophilic particles and combinations thereof and hydrophobic particles and combinations thereof, said particulate component in an amount sufficient for at least partial emulsification, said contact for at least one of a time and at a pressure at least partially sufficient to displace said residual oil from said formation; and

recovering said residual oil.

14. The method of claim 13 wherein said emulsion comprises a dispersed phase comprising a said carbon dioxide component, a continuous phase comprising a said aqueous component and a hydrophilic particle component.

15. The method of claim 14 wherein said hydrophilic particle component is selected from limestone particles, sand particles, gypsum particles, fly ash particles, clay particles and combinations of said components.

16. The method of claim 15 wherein said particle component is selected from limestone particles and components thereof.

17. The method of claim 13 wherein said particle dimension is about 5 to about 50 times smaller than a dimensional aspect of a dispersed phase of said emulsion.

18. The method of claim 13 comprising recovery of a said carbon dioxide component of said emulsion.

19. A method of using a particle-stabilized carbon dioxide emulsion for coal bed hydrocarbon gas recovery, said method comprising:

providing a coal bed formation comprising a residual hydrocarbon gas component;

contacting said coal bed formation with an emulsion comprising at least one of a liquid carbon dioxide component and a supercritical carbon dioxide component, and an aqueous component, said emulsion comprising a particulate component selected from hydrophilic particles and combinations thereof and hydrophobic particles and combinations thereof, said particulate component in an amount sufficient for at least partial emulsification, said contact between said emulsion and said coal bed for a time and at a pressure at least partially sufficient to displace said residual gas from said formation; and

recovering said hydrocarbon gas component and at least one of a portion of said emulsion and a carbon dioxide component thereof.

20. The method of claim 19 wherein one of a continuous phase and a dispersed phase of said emulsion comprises a said carbon dioxide component comprising greater than about 1 weight percent of said emulsion.

21. The method of claim 19 wherein said emulsion comprises a dispersed phase comprising a said aqueous component, a continuous phase comprising a said carbon dioxide component, and a hydrophobic particle component.

22. The method of claim 21 wherein said hydrophobic particle component is selected from coal particles, carbon black particles, activated carbon particles, asphaltene particles, petrocoke particles, resin particles, fluorocarbon particles, protenaceous particles and combinations of said components.

23. The method of claim 22 wherein said hydrophobic particles are selected from coal particles.

24. The method of claim 19 wherein said carbon dioxide component of said recovered emulsion is emulsified with a produced-water component of said coal bed, said emulsion comprising hydrophobic particles and combinations thereof.

25. The method of claim 24 wherein said carbon dioxide-produced water emulsion is introduced into a subterranean formation.