[go: up one dir, main page]

WO2008070035A2 - Emulsions stabilisées par des particules et utilisées pour améliorer la récupération des hydrocarbures - Google Patents

Emulsions stabilisées par des particules et utilisées pour améliorer la récupération des hydrocarbures Download PDF

Info

Publication number
WO2008070035A2
WO2008070035A2 PCT/US2007/024763 US2007024763W WO2008070035A2 WO 2008070035 A2 WO2008070035 A2 WO 2008070035A2 US 2007024763 W US2007024763 W US 2007024763W WO 2008070035 A2 WO2008070035 A2 WO 2008070035A2
Authority
WO
WIPO (PCT)
Prior art keywords
emulsion
particles
component
carbon dioxide
liquid
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2007/024763
Other languages
English (en)
Other versions
WO2008070035A8 (fr
WO2008070035A3 (fr
Inventor
Dan S. Golomb
David Ryan
Gene Barry
Peter Swett
Michael Woods
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
University of Massachusetts Amherst
Original Assignee
University of Massachusetts Amherst
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by University of Massachusetts Amherst filed Critical University of Massachusetts Amherst
Priority to US12/516,901 priority Critical patent/US20100243248A1/en
Priority to CA002670986A priority patent/CA2670986A1/fr
Publication of WO2008070035A2 publication Critical patent/WO2008070035A2/fr
Publication of WO2008070035A8 publication Critical patent/WO2008070035A8/fr
Publication of WO2008070035A3 publication Critical patent/WO2008070035A3/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/164—Injecting CO2 or carbonated water
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/005—Waste disposal systems
    • E21B41/0057—Disposal of a fluid by injection into a subterranean formation
    • E21B41/0064—Carbon dioxide sequestration
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
    • Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells

Definitions

  • Hydrocarbon (e.g., crude oil, or simply oil) recovery may be classified as primary, secondary and tertiary recovery.
  • 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 is another popular tertiary recovery method.
  • liquid or supercritical CO 2 is injected via a bore pipe.
  • Carbon dioxide is readily miscible with crude oil and reduces its viscosity, thereby allowing the oil/CO 2 mixture to more easily flow toward the pumped well.
  • CO 2 injection is followed by pressurized water injection or alternating floods of liquid CO 2 . Pressurized water drives the less viscous oil/CO 2 mixture toward the pumped well. This method is called water-alternate-gas injection (WAG).
  • WAG water-alternate-gas injection
  • Carbon dioxide flooding alone, or WAG injection may not always result in more oil being recovered.
  • the low density and low viscosity liquid CO 2 or supercritical CO 2 has 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.
  • coal beds typically contain hydrocarbon gases, primarily methane (CH 4 ). 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.
  • the present invention can be directed to a tertiary method of subterranean hydrocarbon recovery.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • recovery of a hydrocarbon gas can also produce, as discussed elsewhere herein, a water component from such a formation.
  • 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.
  • 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.
  • 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.
  • particles utilized in conjunction with such an emulsion can be dimensioned from about 5 nanometers or less to about 100 microns or more.
  • particle dimension can be about 5x to about 5Ox smaller than a dimensional aspect of any such dispersed phase.
  • the present invention can also be directed to a method of using a particle-stabilized emulsion for tertiary oil recovery.
  • 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.
  • an emulsion can be as described above or elsewhere herein.
  • 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.
  • a particulate component can be selected from limestone particles and/or compositional components (e.g., without limitation CaCO 3 ) thereof.
  • 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.
  • 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.
  • 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.
  • 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.
  • carbon dioxide component(s) can comprise greater than about 1 wt. % of the emulsion to about 99 wt. %.
  • a particle component can be selected from one or more of the particles described above or elsewhere herein.
  • a particle component can be selected from coal particles and/or compositional components thereof.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • EOR enhanced oil recovery
  • ECBM enhanced coal bed methane
  • 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 (CO 2 -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-CO 2 (A/C) emulsion) stabilized by fine hydrophobic particles, into the formation.
  • CO 2 -in-aqueous (C/ A) emulsion aqueous-in-CO 2 (A/C) emulsion
  • the particle stabilized C/A or A/C emulsions have a higher viscosity than liquid or supercritical CO 2 alone, they may have a better sweep efficiency for driving out the crude oil, and less of the injected CO 2 may be lost to upward buoying and sideways fingering in the formation.
  • 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., CO 2 flooding).
  • 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.
  • mixing or dispersing immiscible liquids 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.
  • 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.
  • a larger part of the hydrophilic particles may be wetted by the continuous aqueous phase; in AJC 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.
  • 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.
  • 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.
  • 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.
  • the liquid or supercritical CO 2 released 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.
  • 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.
  • 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.
  • WAG water alternate gas technology
  • the procedure can be performed in multiple numbers of steps.
  • such procedures for oil extraction can be used in conjunction with WAG technology.
  • 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.
  • 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.
  • 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.
  • hydrophilic particles e.g. pulverized limestone or sand
  • hydrophobic particles e.g. pulverized coal, petrocoke, carbon black
  • 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 CO 2 component 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 CO 2 has a propensity to dislocate CH 4 from the surface of coal granules; (b) The re-injection of a CO 2 -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 CO 2 -produced water emulsion into the coal bed or another subterranean formation (e.g. saline aquifers) disposes of CO 2 that otherwise would be emitted into the atmosphere, to reduce a factor contributing to global warming.
  • a subterranean formation e.g. saline aquifers
  • 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.
  • 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 CO 2 to water) and physical properties (e.g., density, viscosity, and rheology) of the phases of emulsion, as described in more detail below.
  • chemical properties e.g., pH, ionic strength, solubility, and ratio of CO 2 to water
  • physical properties e.g., density, viscosity, and rheology
  • a method of recovering or extracting oil or a hydrocarbon gas from a subterranean formation comprises introducing an emulsion comprising supercritical CO 2 , an aqueous liquid, and an emulsifying agent comprising a particulate material, into a subterranean formation, and extracting oil/gas from the subterranean formation.
  • the emulsion comprises supercritical CO 2 and an aqueous liquid.
  • the emulsion may comprise a continuous phase comprising supercritical CO 2 and a dispersed phase comprising an aqueous liquid, or the emulsion may comprise a dispersed phase comprising supercritical CO 2 and a continuous phase comprising an aqueous liquid.
  • such a method comprises introducing an emulsion comprising a continuous or dispersed phase including greater than about 1% by weight of liquid CO 2 , 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.
  • the emulsion comprises a continuous phase comprising greater than about 1% by weight of liquid CO 2 and 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 CO 2 and a continuous phase comprising an aqueous liquid.
  • a related system comprises supercritical CO 2 , an aqueous liquid, and a particulate material in fluid communication with an emulsion-forming apparatus for forming an emulsion comprising the supercritical CO 2 , 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.
  • the emulsion formed by such a system comprises a continuous phase comprising supercritical CO 2 and a dispersed phase comprising an aqueous liquid.
  • the emulsion comprises a dispersed phase comprising supercritical CO 2 and a continuous phase comprising an aqueous liquid.
  • a related system comprises liquid CO 2 , 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 CO 2 , a continuous or dispersed phase comprising an aqueous liquid, and an emulsifying agent comprising a particulate material.
  • the liquid CO 2 , 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.
  • the emulsion formed by such a system comprises a continuous phase comprising greater than about 1 % by weight of liquid CO 2 and a dispersed phase comprising an aqueous liquid.
  • the emulsion comprises a dispersed phase comprising greater than about 1% by weight of liquid CO 2 and a continuous phase comprising an aqueous liquid.
  • a series of emulsions are provided.
  • the emulsion comprises a plurality of droplets of an aqueous liquid dispersed in a continuous phase comprising supercritical CO 2 , and an emulsifying agent comprising a particulate material.
  • 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 CO 2 , and an emulsifying agent comprising a particulate material.
  • 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 CO 2 , and an emulsifying agent comprising a particulate material.
  • the first liquid is supercritical CO 2 .
  • the first liquid may be supercritical CO 2 and the second liquid may be an aqueous liquid.
  • the second liquid is supercritical CO 2 and the first liquid is an aqueous liquid.
  • a method of this invention comprises extracting a hydrocarbon component from a mixture of hydrocarbons.
  • the method comprises introducing an emulsion comprising supercritical CO 2 , 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.
  • the emulsion comprises supercritical CO 2 and an aqueous liquid.
  • the emulsion may comprise a continuous phase comprising supercritical CO 2 and a dispersed phase comprising an aqueous liquid, or the emulsion may comprise a dispersed phase comprising supercritical CO 2 and a continuous phase comprising an aqueous liquid.
  • 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 CO 2 , 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.
  • the emulsion comprises a continuous phase comprising greater than about 1% by weight of liquid CO 2 and a dispersed phase comprising an aqueous liquid.
  • the emulsion comprises a dispersed phase comprising greater than about 1 % by weight of liquid CO 2 and a continuous phase comprising an aqueous liquid.
  • a related system for recovering a component from a mixture comprises supercritical CO 2 , an aqueous liquid, and a particulate material in fluid communication with an emulsion-forming apparatus for forming an emulsion comprising the supercritical CO 2 , 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.
  • the emulsion of such system comprises supercritical CO 2 and an aqueous liquid.
  • the emulsion may comprise a continuous phase comprising supercritical CO 2 and a dispersed phase comprising an aqueous liquid, or the emulsion may comprise a dispersed phase comprising supercritical CO 2 and a continuous phase comprising an aqueous liquid.
  • a related system for recovering a component from a mixture comprises liquid CO 2 , 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 CO 2 .
  • the system also includes a continuous or dispersed phase comprising an aqueous liquid, and an emulsifying agent comprising a particulate material.
  • the liquid CO 2 , 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.
  • the emulsion comprises a continuous phase comprising greater than about 1% by weight of liquid CO 2 and a dispersed phase comprising an aqueous liquid.
  • the emulsion may comprise a dispersed phase comprising greater than about 1% by weight of liquid CO 2 and a continuous phase comprising an aqueous liquid.
  • emulsion 8 includes droplets 10 (also known as "globules") of a dispersed phase 14 (i.e., the isolated phase stabilized by an emulsifying agent).
  • 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 CO 2 or other gases).
  • continuous phase 18 can comprise supercritical or liquid carbon dioxide (i.e., an A/C-type emulsion).
  • the continuous • phase can comprise an aqueous liquid (e.g., water) (i.e., an C/A-type emulsion).
  • aqueous liquid e.g., water
  • 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.
  • particle stabilized emulsions can be referred to or are commonly known as "Pickering emulsions”.
  • liquid or supercritical CO 2 may 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.
  • A/C or C/A emulsions can also include other fluids in the continuous or dispersed phases in addition to liquid or supercritical CO 2 (e.g., to form a ternary mixture).
  • the continuous or dispersed phase can include greater than about 1% by weight of liquid or supercritical CO 2 .
  • 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 CO 2 .
  • droplet means an isolated phase having any shape, for example cylindrical, spherical, ellipsoidal, tubular, irregular shapes, etc.
  • 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
  • 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.
  • emulsions described herein have a CO 2 continuous phase and an aqueous dispersed phase.
  • 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 CO 2 , and an emulsifying agent comprising a particulate material.
  • the continuous phase may comprise greater than about 1% by weight of liquid CO 2 .
  • the continuous phase can include between about 1%-about 100%, about 50%-about 100%, or about 70%-about 100% by weight of liquid CO 2 .
  • the continuous phase consists essentially of liquid CO 2 .
  • Emulsions comprising an aqueous continuous phase and a CO 2 dispersed phase are also provided.
  • emulsions described herein include supercritical CO 2 as the continuous or dispersed phase.
  • 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 CO 2 .
  • the emulsion can further include an emulsifying agent comprising a particulate material.
  • the first liquid of the dispersed phase is supercritical CO 2 .
  • the second liquid of the continuous phase may be an aqueous liquid.
  • the second liquid is supercritical CO 2
  • the first liquid may be an aqueous liquid.
  • emulsion 30 includes a plurality of liquid CO 2 droplets 34 in seawater continuous phase 36.
  • Calcium carbonate (CaCO 3 ) particles 38 are used as an emulsifying agent to stabilize the droplets.
  • 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.
  • particle stabilized oil-in-aqueous (O/A) and aqueous- in-oil (A/O) emulsions are contemplated.
  • aqueous- in-oil (A/O) emulsions are also known as oil-in- water (O/W) and water-in-oil (W/O) emulsions, respectively).
  • 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.
  • 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).
  • 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.
  • emulsion 40 including droplets 42 of water in a dodecane continuous phase 44.
  • the droplets are stabilized by carbon black particles 48.
  • 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.
  • the aqueous liquid can comprise one or more additives, such as salts
  • 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).
  • 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
  • DMSO dimethyl sulfoxide
  • the oil portion of an emulsion can be any liquid that is immiscible with an aqueous liquid such as water.
  • 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 C] 0 -C 2O hydrocarbons can also be used.
  • 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.
  • 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).
  • 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.
  • 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.
  • the viscosity of supercritical carbon dioxide is typically in the range of 20 to 100 ⁇ Pa-s, whereas typical liquids have viscosities of approximately 500 to 1000 ⁇ Pa-s.
  • 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.
  • 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.
  • 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.
  • the viscosity of the liquid may be in the range of, e.g., between 10-200 ⁇ Pa-s.
  • a continuous and/or dispersed phase consisting essentially of a supercritical or cryogenic liquid may have a viscosity in the above range.
  • a continuous and/or dispersed phase comprising a supercritical or cryogenic liquid may have a viscosity in the range of between 200-1,500 ⁇ Pa-s.
  • 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 ⁇ Pa-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.
  • 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.
  • 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 determines, at least in part, whether a CO 2 -in-aqueous (C/ A) or aqueous-in-CO 2 (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.
  • C/ A CO 2 -in-aqueous
  • A/C aqueous-in-CO 2
  • Particles having some hydrophobic character are preferentially wetted by the carbon dioxide phase; hence, they promote A/C-type emulsions.
  • the hydrophobic or hydrophilic character of the particulate materials is naturally occurring or inherent in the material.
  • particulate materials can be treated by a process such as heating or coating, which can change the surface characteristics of the materials.
  • 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.
  • 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
  • Particles may comprise the class of particles referred to as nanoparticles.
  • 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.
  • the particle size is adjusted to the dispersed droplet diameter.
  • 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.
  • 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.
  • 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.
  • particulate materials can include metal oxides, metal sulfides, and/or metal sulfates.
  • a particulate material is formed of a rock or a mineral.
  • 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
  • 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.
  • 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.
  • 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 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.
  • 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.
  • a suitable emulsifying agent e.g., a particulate material
  • 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.
  • an emulsion comprising an aqueous liquid and carbon dioxide
  • a water-soluble, carbon dioxide-insoluble dye is added without mixing to an emulsion
  • the dye may form a separate phase, since it is not miscible with the continuous, carbon dioxide phase.
  • the dye may dissolve in the continuous, aqueous phase giving the appearance of dissolution of the dye in the entire mixture.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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).
  • 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.
  • 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.
  • higher ratios of particulate material to dispersed phase material may be used.
  • 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).
  • a particle sheath model e.g., a monolayer or multi-layer sheath model.
  • An example is given for liquid CO 2 droplets in an aqueous continuous phase and a particulate material comprising CaCO 3 .
  • the mass ratio of CaCO 3 /CO 2 is estimated at 0.2: 1. Because not all particles have a uniform size, different ratios of CaCO 3 /CO 2 may be used; for example, 0.4: 1, that is, for every 1 kg Of CO 2 , 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.
  • 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.
  • emulsions described herein are formed by shear forces.
  • suitable materials, techniques, conditions e.g., temperature and pressure
  • emulsions described herein are formed using a high-pressure batch reactor, as shown 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.
  • 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.
  • 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, CO 2 -in-aqueous, aqueous-in-CO 2 , aqueous-in-oil, and oil-in-aqueous emulsions.
  • 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.
  • a static mixer is used to form an emulsion.
  • An example of a static mixer is illustrated in FIG. 5.
  • static mixer 92 is tubular and includes alternating helical mixing blades 96 with no moving parts.
  • the static mixer is a Kenics-type static mixer.
  • the components of an emulsion e.g., liquid or supercritical CO 2 , particles, and an aqueous liquid
  • 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).
  • 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).
  • 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.
  • 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 1 12 for forming, for example, CO 2 -in-aqueous, aqueous-in-CO 2 , oil-in-aqueous, or aqueous-in-oil emulsions.
  • injection apparatus 118 e.g., an injection well or pump
  • 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.
  • the oil in the reservoir is typically immobile or very viscous.
  • 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.
  • 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.
  • 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).
  • the resulting extracted mixture may include carbon dioxide, an oil or gas, water (e.g., in the case of a water-in-CO 2 or a CO 2 -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 CO 2 .
  • This compressed carbon dioxide can act as, or be added to, source of carbon dioxide 104.
  • 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.
  • all or a portion of the carbon dioxide component can be emulsified with produced water, for sequestration.
  • separator 164 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 CO 2 deposits, gas wells, CO 2 separated from natural gas wells, from coal gasification processes, from separating CO 2 in 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 CO 2 is a major by-product.
  • CO 2 may be obtained as a by-product from steam-hydrocarbon reformers used in the production of ammonia, gasoline, and other chemicals.
  • 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.
  • 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 CO 2 .
  • gases produced from these process may include, in addition to CO 2 , contaminants such as water, SO x , and NO x , the CO 2 may 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 CO 2 e.g., containing at least 90% CO 2
  • the carbon dioxide can then be placed in an insulated storage vessel.
  • 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.
  • aqueous liquids can be used in emulsions described herein.
  • water from a well on site of the subterranean formation can be used.
  • well water, sea water, or other sources of water can be imported.
  • waste water from an oil refinement process may be used in forming emulsions described herein.
  • 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.
  • 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.
  • particulate material 102, carbon dioxide 104, and aqueous liquid 108 (and/or oil 109) are shown as separate sources.
  • one or more materials can be premixed prior to forming an emulsion.
  • the particulate material is mixed with water to form a slurry prior to formation of an emulsion with carbon dioxide.
  • 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.
  • FIG. 8 One particular system for recovering oil from a subterranean formation is shown in FIG. 8.
  • a C/A or AJC emulsion can be introduced into the subterranean formation via an injection well.
  • CO 2 released 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 CO 2 emulsion 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.
  • methods described herein involving particle-stabilized emulsions can remove up to or greater than 60% of the oil originally contained in the reservoir.
  • 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.
  • Liquid and supercritical carbon dioxide are available, as known in the art.
  • Industrial-grade liquid carbon dioxide was supplied from 50 Ib 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:
  • reagent grade CaCO 3 was used, obtained from Fisher Scientific. An SEM image of the reagent-grade CaCO 3 particles shows these particles to be mostly rhombohedral calcite crystals.
  • EDX Energy dispersive X-ray
  • flyash collected by an electrostatic precipitator (ESP) at the Salem Harbor, Massachusetts, 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.
  • 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.
  • Carbon black was obtained from the Cabot Corp., Billerica, Massachusetts. It is composed of 100% carbon. It was used without further processing.
  • Particle-stabilized CO 2 -in-aqueous liquid (C/ A) and aqueous liquid-in-CO 2 (AJC) macroemulsions were formed in a high-pressure batch reactor (HPBR) with view windows using an apparatus similar to the one shown in FIG. 4.
  • HPBR high-pressure batch reactor
  • 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-B VM2), and a 3.2 mm port for admitting CO 2 .
  • 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 Ib 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 CO 2 was 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 CO 2 . The pressure in the HPBR was 17.2 MPa and the temperature was 15° C.
  • Example Ic 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 CO 2 was added by means of a syringe pump. Unless otherwise indicated, the proportions of
  • A/C macroemulsions 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 CO 2 . 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 CO 2 /(20 mL of H 2 O) was used.
  • Example Id 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 where n, (d p ) is the number of particles counted that have a size d p , and N 1 is the total number of particles counted. The mean size, (d p ) meim , and standard deviation of the particles used in this study are tabulated in Table 1.
  • 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 ⁇ m of Pulverized Materials Used for Stabilizing C/A and A/C Type Emulsions
  • 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 CO 2 and Ql 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 CO 2 under the same pressure and mixing conditions. Most globules settled in the bottom of the cell. Even though the density of supercritical CO 2 (-800 kg m '3 ) is smaller than that of liquid CO 2 (-930 kg m "3 at 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 CO 2 was 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 CaCO 3 (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 CO 2 droplets was clearly visible.
  • 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 globule diameter was in the 80-150 micron range.
  • 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/cm 3 ), 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
  • 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 CO 2 is 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.
  • A/C aqueous liquid-in-carbon dioxide
  • activated Carbon When activated carbon (AC) was dispersed in liquid CO 2 under 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.
  • AC activated carbon
  • Carbon Black did disperse in liquid CO 2 without 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.
  • Pulverized coal also dispersed readily in liquid CO 2 without agglomeration.
  • a A/C macroemulsion was formed where water droplets were sheathed with coal particles dispersed in CO 2 .
  • 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 Figure 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.
  • Figure 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.
  • Figure 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.

Landscapes

  • Engineering & Computer Science (AREA)
  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Fluid Mechanics (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Physics & Mathematics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Organic Chemistry (AREA)
  • Materials Engineering (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Colloid Chemistry (AREA)
  • Emulsifying, Dispersing, Foam-Producing Or Wetting Agents (AREA)
  • Physical Or Chemical Processes And Apparatus (AREA)
  • Extraction Or Liquid Replacement (AREA)

Abstract

Particules hydrophiles et hydrophobes utilisées pour stabiliser des émulsions employées pour extraire et/ou récupérer les hydrocarbures.
PCT/US2007/024763 2006-12-01 2007-12-03 Emulsions stabilisées par des particules et utilisées pour améliorer la récupération des hydrocarbures Ceased WO2008070035A2 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
US12/516,901 US20100243248A1 (en) 2006-12-01 2007-12-03 Particle Stabilized Emulsions for Enhanced Hydrocarbon Recovery
CA002670986A CA2670986A1 (fr) 2006-12-01 2007-12-03 Emulsions stabilisees par des particules et utilisees pour ameliorer la recuperation des hydrocarbures

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US87208106P 2006-12-01 2006-12-01
US60/872,081 2006-12-01

Publications (3)

Publication Number Publication Date
WO2008070035A2 true WO2008070035A2 (fr) 2008-06-12
WO2008070035A8 WO2008070035A8 (fr) 2008-08-07
WO2008070035A3 WO2008070035A3 (fr) 2008-10-16

Family

ID=39492831

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2007/024763 Ceased WO2008070035A2 (fr) 2006-12-01 2007-12-03 Emulsions stabilisées par des particules et utilisées pour améliorer la récupération des hydrocarbures

Country Status (3)

Country Link
US (1) US20100243248A1 (fr)
CA (1) CA2670986A1 (fr)
WO (1) WO2008070035A2 (fr)

Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2011007172A3 (fr) * 2009-07-14 2011-05-05 Statoil Asa Procédé
WO2011123588A1 (fr) * 2010-04-02 2011-10-06 E. I. Du Pont De Nemours And Company Dispositif mécanique de dispersion de populations de biomasse
WO2012088430A1 (fr) * 2010-12-22 2012-06-28 Kemira Oyj Procédé de récupération de bitume à partir d'un minerai de sables bitumineux par moussage et addition d'une poudre de ciment
WO2012119058A3 (fr) * 2011-03-03 2013-06-27 Battelle Memorial Institute Injections de fluide en fond de trou, procédés de séquestration de co2 et procédés de récupération de matériaux hydrocarbonés
WO2016159834A1 (fr) * 2014-12-25 2016-10-06 Общество С Ограниченной Ответственностью "Автостанкопром" Liquide pour extraction de gaz et de pétrole basse pression
WO2016167836A1 (fr) * 2015-04-14 2016-10-20 Saudi Arabian Oil Company Acide émulsifié supercritique de dioxyde de carbone
CN111701586A (zh) * 2020-06-09 2020-09-25 山西大学 一种光催化还原CO2制备甲醇的Pickering微泡体系构建方法及应用
EP3702025A3 (fr) * 2012-11-12 2020-10-28 Saudi Arabian Oil Company Densification de dioxyde de carbone avec une dispersion de capsules ayant une affinité pour le dioxyde de carbone

Families Citing this family (67)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2010024949A2 (fr) * 2008-03-04 2010-03-04 Brigham Young University Procédés de séquestration stable de dioxyde de carbone dans un aquifère
US8197562B2 (en) * 2008-10-03 2012-06-12 Exxonmobil Research And Engineering Company Modification of rheological properties of coal for slurry feed gasification
US9222013B1 (en) 2008-11-13 2015-12-29 Cesi Chemical, Inc. Water-in-oil microemulsions for oilfield applications
US8157003B2 (en) * 2008-12-18 2012-04-17 Stillwater Energy Group, Llc Integrated carbon management system for petroleum refining
KR101197211B1 (ko) * 2010-11-29 2012-11-02 한국지질자원연구원 초임계 이산화탄소의 지층 내 주입효율 향상을 위한 유체온도 제어 시스템 및 방법
DK177294B1 (en) * 2011-05-10 2012-10-08 Maersk Olie & Gas Enhanced oil recovery
US8939208B2 (en) * 2011-06-13 2015-01-27 Nalco Company Additives for improving hydrocarbon recovery
US9879512B2 (en) 2011-06-13 2018-01-30 Ecolab Usa Inc. Additives for improving hydrocarbon recovery
CA2841150A1 (fr) * 2011-06-24 2012-12-27 Maurice B. Dusseault Sequestration de gaz a effet de serre par generation d'un front gaz/solution saline instable
CA2841345C (fr) * 2011-07-11 2016-03-22 Cabot Corporation Emulsification de petrole et adsorption d'hydrocarbures polycycliques aromatiques a l'aide de fines particules servant de dispersants
DK2838970T3 (en) 2012-04-15 2017-03-20 Flotek Chemistry Llc Density formulations for foam filling
US11407930B2 (en) 2012-05-08 2022-08-09 Flotek Chemistry, Llc Compositions and methods for enhancement of production of liquid and gaseous hydrocarbons
US9200192B2 (en) 2012-05-08 2015-12-01 Cesi Chemical, Inc. Compositions and methods for enhancement of production of liquid and gaseous hydrocarbons
RU2015135612A (ru) * 2013-01-25 2017-03-03 Винтерсхол Хольдинг Гмбх Способ извлечения нефти
BR112015013995A2 (pt) * 2013-01-25 2017-07-11 Wintershall Holding GmbH emulsão estabilizada por partículas sólidas, processo para a preparação de uma emulsão estabilizada por partículas sólidas, e, uso de emulsão estabilizada por partículas sólidas
US11254856B2 (en) 2013-03-14 2022-02-22 Flotek Chemistry, Llc Methods and compositions for use in oil and/or gas wells
US10717919B2 (en) 2013-03-14 2020-07-21 Flotek Chemistry, Llc Methods and compositions for use in oil and/or gas wells
US9428683B2 (en) 2013-03-14 2016-08-30 Flotek Chemistry, Llc Methods and compositions for stimulating the production of hydrocarbons from subterranean formations
US10287483B2 (en) 2013-03-14 2019-05-14 Flotek Chemistry, Llc Methods and compositions for use in oil and/or gas wells comprising a terpene alcohol
US9068108B2 (en) 2013-03-14 2015-06-30 Cesi Chemical, Inc. Methods and compositions for stimulating the production of hydrocarbons from subterranean formations
US10000693B2 (en) 2013-03-14 2018-06-19 Flotek Chemistry, Llc Methods and compositions for use in oil and/or gas wells
US9321955B2 (en) 2013-06-14 2016-04-26 Flotek Chemistry, Llc Methods and compositions for stimulating the production of hydrocarbons from subterranean formations
US11180690B2 (en) 2013-03-14 2021-11-23 Flotek Chemistry, Llc Diluted microemulsions with low surface tensions
US10421707B2 (en) 2013-03-14 2019-09-24 Flotek Chemistry, Llc Methods and compositions incorporating alkyl polyglycoside surfactant for use in oil and/or gas wells
US10577531B2 (en) 2013-03-14 2020-03-03 Flotek Chemistry, Llc Polymers and emulsions for use in oil and/or gas wells
US9884988B2 (en) 2013-03-14 2018-02-06 Flotek Chemistry, Llc Methods and compositions for use in oil and/or gas wells
US10941106B2 (en) 2013-03-14 2021-03-09 Flotek Chemistry, Llc Methods and compositions incorporating alkyl polyglycoside surfactant for use in oil and/or gas wells
US9868893B2 (en) 2013-03-14 2018-01-16 Flotek Chemistry, Llc Methods and compositions for use in oil and/or gas wells
US10053619B2 (en) 2013-03-14 2018-08-21 Flotek Chemistry, Llc Siloxane surfactant additives for oil and gas applications
US10590332B2 (en) 2013-03-14 2020-03-17 Flotek Chemistry, Llc Siloxane surfactant additives for oil and gas applications
US9464223B2 (en) 2013-03-14 2016-10-11 Flotek Chemistry, Llc Methods and compositions for use in oil and/or gas wells
MX2015017408A (es) * 2013-06-19 2017-05-01 j lewis Michael Proceso para recuperacion mejorada de petroleo usando captura de dioxido de carbono.
US9388335B2 (en) * 2013-07-25 2016-07-12 Schlumberger Technology Corporation Pickering emulsion treatment fluid
US10060237B2 (en) * 2013-11-22 2018-08-28 Baker Hughes, A Ge Company, Llc Methods of extracting hydrocarbons from a subterranean formation, and methods of treating a hydrocarbon material within a subterranean formation
US9879511B2 (en) * 2013-11-22 2018-01-30 Baker Hughes Incorporated Methods of obtaining a hydrocarbon material contained within a subterranean formation
US9708525B2 (en) * 2014-01-31 2017-07-18 Baker Hughes Incorporated Methods of using nano-surfactants for enhanced hydrocarbon recovery
US9708896B2 (en) 2014-01-31 2017-07-18 Baker Hughes Incorporated Methods of recovering hydrocarbons using a suspension
US9890625B2 (en) 2014-02-28 2018-02-13 Eclipse Ior Services, Llc Systems and methods for the treatment of oil and/or gas wells with an obstruction material
US9890624B2 (en) 2014-02-28 2018-02-13 Eclipse Ior Services, Llc Systems and methods for the treatment of oil and/or gas wells with a polymeric material
CA2891278C (fr) 2014-05-14 2018-11-06 Cesi Chemical, Inc. Methodes et compositions destinees aux puits de petrole ou de gaz
CA3042567C (fr) 2014-07-28 2021-12-14 Flotek Chemistry, Llc Methodes et compositions associees aux couches gelifiees dans les puits de petrole ou de gaz
US10669635B2 (en) 2014-09-18 2020-06-02 Baker Hughes, A Ge Company, Llc Methods of coating substrates with composite coatings of diamond nanoparticles and metal
US9873827B2 (en) * 2014-10-21 2018-01-23 Baker Hughes Incorporated Methods of recovering hydrocarbons using suspensions for enhanced hydrocarbon recovery
WO2016064718A1 (fr) * 2014-10-21 2016-04-28 Baker Hughes Incorporated Suspensions permettant la récupération assistée d'hydrocarbures et procédés de récupération d'hydrocarbures utilisant les suspensions
US10167392B2 (en) 2014-10-31 2019-01-01 Baker Hughes Incorporated Compositions of coated diamond nanoparticles, methods of forming coated diamond nanoparticles, and methods of forming coatings
US10047275B2 (en) * 2014-12-04 2018-08-14 Saudi Arabian Oil Company Hydrocarbon recovery using complex water and carbon dioxide emulsions
US10155899B2 (en) 2015-06-19 2018-12-18 Baker Hughes Incorporated Methods of forming suspensions and methods for recovery of hydrocarbon material from subterranean formations
US10266750B2 (en) * 2015-09-02 2019-04-23 Chevron U.S.A. Inc. Oil recovery compositions and methods thereof
US20210189227A1 (en) * 2016-04-07 2021-06-24 Halliburton Energy Services, Inc. Pickering emulsions used in wellbore servicing fluids and methods
US10934472B2 (en) 2017-08-18 2021-03-02 Flotek Chemistry, Llc Compositions comprising non-halogenated solvents for use in oil and/or gas wells and related methods
WO2019108971A1 (fr) 2017-12-01 2019-06-06 Flotek Chemistry, Llc Procédés et compositions pour stimuler la production d'hydrocarbures à partir de formations souterraines
AU2017443974B2 (en) * 2017-12-19 2023-06-01 Halliburton Energy Services, Inc. Pickering foam drilling fluids
CN109999684B (zh) * 2019-04-22 2021-07-13 中国石油大学(华东) 一种二氧化碳流度控制装置及方法
US11492541B2 (en) * 2019-07-24 2022-11-08 Saudi Arabian Oil Company Organic salts of oxidizing anions as energetic materials
US11104843B2 (en) 2019-10-10 2021-08-31 Flotek Chemistry, Llc Well treatment compositions and methods comprising certain microemulsions and certain clay control additives exhibiting synergistic effect of enhancing clay swelling protection and persistency
US11118439B2 (en) * 2019-12-06 2021-09-14 Saudi Arabian Oil Company Displacing fluid for enhanced oil recovery
US11512243B2 (en) 2020-10-23 2022-11-29 Flotek Chemistry, Llc Microemulsions comprising an alkyl propoxylated sulfate surfactant, and related methods
US11384280B1 (en) 2021-03-26 2022-07-12 Saudi Arabian Oil Company Adsorption improved water in supercritical CO2 encapsulation for improved oil recovery
US11905464B2 (en) 2021-03-26 2024-02-20 Saudi Arabian Oil Company Covalent organic frameworks for improved oil recovery
US11912939B2 (en) * 2021-03-26 2024-02-27 Saudi Arabian Oil Company Magnetic covalent organic frameworks as stabilizer and marker for subsurface monitoring
US20240318069A1 (en) * 2021-03-26 2024-09-26 Saudi Arabian Oil Company Super hydrophobic 2d nanosheet materials for improved oil recovery
US12071589B2 (en) 2021-10-07 2024-08-27 Saudi Arabian Oil Company Water-soluble graphene oxide nanosheet assisted high temperature fracturing fluid
US12025589B2 (en) 2021-12-06 2024-07-02 Saudi Arabian Oil Company Indentation method to measure multiple rock properties
US12012550B2 (en) 2021-12-13 2024-06-18 Saudi Arabian Oil Company Attenuated acid formulations for acid stimulation
US11905804B2 (en) 2022-06-01 2024-02-20 Saudi Arabian Oil Company Stimulating hydrocarbon reservoirs
US12104118B2 (en) * 2022-07-20 2024-10-01 Saudi Arabian Oil Company Advanced encapsulation for downhole water capture and improved oil recovery
US12305496B1 (en) 2024-04-24 2025-05-20 Saudi Arabian Oil Company Hydraulic treatment of subterranean formations using oxidant, nanoparticles, and carbon dioxide

Family Cites Families (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
FR2854071B1 (fr) * 2003-04-25 2009-01-30 Ethypharm Sa Procede de dispersion de substances hydrosolubles ou hydrophiles dans un fluide a pression supercritique

Cited By (14)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2011007172A3 (fr) * 2009-07-14 2011-05-05 Statoil Asa Procédé
US9234407B2 (en) 2009-07-14 2016-01-12 Statoil Petroleum As Process for simultaneously extracting and upgrading by controlled extraction a heavy hydrocarbon mixture
WO2011123588A1 (fr) * 2010-04-02 2011-10-06 E. I. Du Pont De Nemours And Company Dispositif mécanique de dispersion de populations de biomasse
GB2490077A (en) * 2010-04-02 2012-10-17 Du Pont A mechanical device for dispersing biomass populations
CN102822311A (zh) * 2010-04-02 2012-12-12 纳幕尔杜邦公司 用于分散生物质群体的机械装置
WO2012088430A1 (fr) * 2010-12-22 2012-06-28 Kemira Oyj Procédé de récupération de bitume à partir d'un minerai de sables bitumineux par moussage et addition d'une poudre de ciment
US9091156B2 (en) 2011-03-03 2015-07-28 Battelle Memorial Institute Downhole fluid injection systems, CO2 sequestration methods, and hydrocarbon material recovery methods
WO2012119058A3 (fr) * 2011-03-03 2013-06-27 Battelle Memorial Institute Injections de fluide en fond de trou, procédés de séquestration de co2 et procédés de récupération de matériaux hydrocarbonés
EP3702025A3 (fr) * 2012-11-12 2020-10-28 Saudi Arabian Oil Company Densification de dioxyde de carbone avec une dispersion de capsules ayant une affinité pour le dioxyde de carbone
WO2016159834A1 (fr) * 2014-12-25 2016-10-06 Общество С Ограниченной Ответственностью "Автостанкопром" Liquide pour extraction de gaz et de pétrole basse pression
WO2016167836A1 (fr) * 2015-04-14 2016-10-20 Saudi Arabian Oil Company Acide émulsifié supercritique de dioxyde de carbone
US10066156B2 (en) 2015-04-14 2018-09-04 Saudi Arabian Oil Company Supercritical carbon dioxide emulsified acid
US10717924B2 (en) 2015-04-14 2020-07-21 Saudi Arabian Oil Company Supercritical carbon dioxide emulsified acid
CN111701586A (zh) * 2020-06-09 2020-09-25 山西大学 一种光催化还原CO2制备甲醇的Pickering微泡体系构建方法及应用

Also Published As

Publication number Publication date
CA2670986A1 (fr) 2008-06-12
US20100243248A1 (en) 2010-09-30
WO2008070035A8 (fr) 2008-08-07
WO2008070035A3 (fr) 2008-10-16

Similar Documents

Publication Publication Date Title
US20100243248A1 (en) Particle Stabilized Emulsions for Enhanced Hydrocarbon Recovery
Panchal et al. A systematic review on nanotechnology in enhanced oil recovery
US5927404A (en) Oil recovery method using an emulsion
RU2412341C2 (ru) Способ извлечения нефти с использованием пенистой эмульсии с нефтяной сплошной фазой
US5855243A (en) Oil recovery method using an emulsion
US10308859B2 (en) Methods and compositions for use in oil and/or gas wells
Dong et al. Formation damage prevention using microemulsion in tight sandstone gas reservoir
Bader Seawater versus produced water in oil-fields water injection operations
WO2010148204A2 (fr) Émulsions stabilisées par des particules pour extraction d'hydrocarbures à partir de sables bitumineux et de schiste bitumineux
Gomari et al. New insights into application of nanoparticles for water-based enhanced oil recovery in carbonate reservoirs
Jafarbeigi et al. Experimental core flooding investigation of new ZnO− γAl2O3 nanocomposites for enhanced oil recovery in carbonate reservoirs
El Shafey Effect of nanoparticles and polymer nanoparticles implementation on chemical flooding, wettability and interfacial tension for the enhanced oil recovery processes
Sakthivel et al. Influence of carbon nanodots on the Carbonate/CO2/Brine wettability and CO2-Brine interfacial Tension: Implications for CO2 geo-storage
CN105419750A (zh) 用于油井和/或气井的方法和组合物
Nutskova et al. Research of oil-based drilling fluids to improve the quality of wells completion
López et al. Cardanol/SiO2 nanocomposites for inhibition of formation damage by asphaltene precipitation/deposition in light crude oil reservoirs. part ii: nanocomposite evaluation and coreflooding test
Mosavat Utilization of carbonated water injection (CWI) as a means of improved oil recovery in light oil systems: pore-scale mechanisms and recovery evaluation
ElMofty Surfactant enhanced oil recovery by wettability alteration in sandstone reservoirs
Elnaggar et al. Oil Recovery Enhancement by N2 Nanobubbles
Kazemi et al. Static and dynamic investigation of effective parameters on water injection performance in the presence of nanofluids
Abdullah et al. Nanomaterials in petroleum industry
CA2840675A1 (fr) Procede de destabilisation d'emulsions bitume-eau et eau-huile au moyen de chaux
Birdi Surface chemistry and geochemistry of hydraulic fracturing
Acosta et al. Surfactant technologies for remediation of oil spills
Kuznetsova et al. Surfactant solutions for low-permeable polimictic reservoir flooding

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 07853226

Country of ref document: EP

Kind code of ref document: A2

WWE Wipo information: entry into national phase

Ref document number: 2670986

Country of ref document: CA

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 07853226

Country of ref document: EP

Kind code of ref document: A2

WWE Wipo information: entry into national phase

Ref document number: 12516901

Country of ref document: US