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    • 专利摘要:
    The present disclosure describes methods for administering treatment chemicals into a subterranean formation using processing fluids that include nanoemulsions. In some embodiments, the methods include the use of a treatment fluid comprising a water-based fluid and a nanoemulsion comprising a water-soluble inner phase, a water-soluble outer phase and a surfactant, the microemulsion being formed by mechanically induced shear fracture, and introducing the treatment fluid into at least a portion of the subterranean formation at or above a pressure sufficient to create or enhance at least one fracture in the subterranean formation .
    公开号:FR3059039A1
    申请号:FR1759961
    申请日:2017-10-23
    公开日:2018-05-25
    发明作者:Liang Xu；Kai He；Zhiwei Yue；Yang Peng
    申请人:Halliburton Energy Services Inc；
    IPC主号:
    专利说明:

    NANOEMULSIONS FOR USE IN
    SUBTERRANEAN FRACTURING TREATMENTS
    CONTEXT
    The present invention relates to methods of treating underground formations.
    Treatment fluids can be used in a variety of underground treatment operations. In the present context, the terms “treat” and “treatment” and their grammatical equivalents describe any underground operation which uses a fluid in association with obtaining a desired function and / or for a desired purpose. The use of these terms does not imply any particular action by the treatment fluid. Illustrative processing operations may include, for example, fracturing operations, gravelling operations, acidification operations, dissolution and removal of encrustations, consolidation operations, etc. For example, hydraulic fracturing is generally used for the stimulation of narrow gas reservoirs using fracturing fluids, e.g., crosslinked gelled fluids and / or groundwater treatment fluids.
    Chemical additives including, without limitation, scale inhibitors, friction reducers, biocides, clay swelling inhibitors, oxygen scavengers and surfactants, are often incorporated into the fracturing fluid to treat newly fractured areas of a formation. Among other reasons, these treatments can be used to facilitate the flow of hydrocarbons, to clean up and prevent damage to the formation and to facilitate the return of the fracturing fluid. Viscosified fluids and emulsions have been used in the art to transport such processing chemicals to various regions of a formation. However, certain regions of the underground formations, particularly those in which fracturing treatments are carried out, may have low permeabilities, hindering the flow of viscosified treatment fluids, conventional emulsions and chemicals to these regions. In addition, the stability of a viscosified treatment fluid and / or a conventional emulsion can be disturbed in the well, eg, when subjected to high shear forces.
    BRIEF DESCRIPTION OF THE FIGURES
    These drawings illustrate certain aspects of some of the embodiments of the present disclosure, and should not be used to limit or define the claims.
    Figure 1 is a diagram illustrating an example of a well treatment system which can be used in accordance with certain embodiments of the present disclosure.
    FIG. 2 is a diagram illustrating an example of an underground formation in which a fracturing operation can be carried out in accordance with certain embodiments of the present disclosure.
    Figures 3 A to 3 F are graphs illustrating data relating to droplet size distributions for certain microemulsions and nanoemulsions in accordance with certain embodiments of the present disclosure.
    While embodiments of this disclosure have been illustrated, such embodiments do not imply a limit on the disclosure, and no such limit should be deduced. The subject of the invention disclosed is capable of considerable modification, alteration and equivalent in form and function, as will be apparent to specialists in the relevant field and who benefit from this disclosure. The illustrated and described embodiments of this disclosure are only examples, and are not an exhaustive description of the disclosure.
    DESCRIPTION OF CERTAIN EMBODIMENTS
    The present disclosure relates to systems and methods for treating underground formations. More particularly, the present disclosure relates to thermodynamically unstable nanoemulsions, and methods and systems relating to their use in the administration of downhole treatment chemicals.
    The present disclosure describes methods and systems for administering treatment chemicals in an underground formation using treatment fluids which include nanoemulsions. In the present context, the term "nanoemulsion" describes a dispersion of two immiscible liquids (eg, an aqueous phase and an oily phase) in a kinetically stable but thermodynamically unstable state (eg, not the most thermodynamically state stable possible). This can be achieved, at least in part, when there is an energy barrier between the state of nanoemulsion and the state in which the two liquids are separated which is greater than the amount of free energy in the system. This is contrary to microemulsions, which are formed when two immiscible liquids self-assemble in a dispersion to reach a thermodynamically stable state. In some embodiments, the droplets of the internal phase in the external phase of the nanoemulsions of the present disclosure may have an average radius of less than about 1000 nm, or otherwise less than about 500 nm, or otherwise, less than about 100 nm. These droplet sizes can be confirmed or measured by any known means including, without limitation, techniques for particle analysis by dynamic light diffraction. In certain embodiments, the nanoemulsions of the present disclosure may be formed by a mechanically induced shear rupture of the two immiscible liquids, or by a phase inversion temperature process. The shear used in certain embodiments to form certain nanoemulsions of the present disclosure can be applied to the surface and / or the bottom of the well in the formation by any known means including, without limitation, mechanical mixers. In some embodiments, mechanical shear can be generated when two immiscible liquids pass through a perforation in tubing or other equipment placed in the underground formation. In some embodiments, unlike microemulsions, the nanoemulsions of the present disclosure may remain substantially stable as emulsions when subjected to high mechanical shear, such as shear undergone by a fluid in a fracturing mixer or when it flows through the perforations in a casing.
    The treatment fluids of the present disclosure generally include an aqueous base fluid and a nanoemulsion comprising a continuous or external water-soluble aqueous phase, a discontinuous or internal water-soluble oily phase and a surfactant. The methods of the present disclosure generally include: using a treatment fluid of the present disclosure; and introducing the process fluid into at least a portion of the underground formation. In the present context, the term “water soluble” or variations thereof, describes a substance having a certain degree of water solubility, whether it is completely soluble in water or only partially soluble in water.
    The nanoemulsions of the present disclosure can, among other functions, help transport a surfactant and / or other treatment chemicals into the porosity of an underground formation in which it can be used to treat the formation. Such surfactants can, among other functions, modify the wettability of surfaces in the formation, facilitate the flow of certain fluids (e.g., hydrocarbons) out of the formation, reduce the flow of certain fluids (e.g. water) in the formation, and perform other desirable functions in an underground operation. In certain embodiments, the nanoemulsions of the present disclosure may be particularly useful in the administration of processing chemicals and / or otherwise to penetrate the formation matrix into unconventional formations, such as formations comprising shale having low porosity and / or permeability.
    Among several potential advantages of the methods and compositions of this disclosure, of which only some are mentioned here, the methods, compositions and systems of this disclosure can demonstrate superior kinetic stability than other types of emulsions known in the art. domain (eg, microemulsions) under certain conditions such as high shear, high temperatures and / or high pressures. This may allow the compositions of the present disclosure to be stored for a longer period of time, to remain more stable when subjected to such conditions in use and / or other benefits or advantages. Additionally, in some embodiments, the nanoemulsions of the present disclosure may have narrower particle size distributions, more spherical droplet sizes, and / or more consistent properties when heated and / or cooled compared to other types of emulsions known in the art. In some embodiments, the nanoemulsions of the present disclosure may also be formed and / or stabilized with lower concentrations of surfactant than other nanoemulsions and / or microemulsions known in the art, which could reduce the associated cost. to their preparation and / or use. In some embodiments, the droplets of the microemulsions may dissociate into even smaller droplets than those of the original microemulsion when subjected to high shear (eg, a shear rate at or above 40 s "1 , or moreover at or greater than 80 s1, or moreover at or greater than 100 s "1) without forming aggregates larger than the droplets of the original nanoemulsion. Among other objectives, these smaller droplets may be able to penetrate deeper into the pore spaces of an underground formation (particularly, formations with low permeability, than the droplets of microemulsions and conventional emulsions known in the art ). This can facilitate administration of the surfactant and / or other additives deeper into the formation, particularly in low permeability formations.
    The nanoemulsions of the present disclosure generally include two or more immiscible liquids, such as a polar fluid (eg, aqueous) and a non-polar fluid (eg, oil-based). The nanoemulsions of the present disclosure are generally thermodynamically unstable, but demonstrate superior kinetic stability compared to conventional microemulsions and emulsions known in the art, eg, when subjected to high shear or other conditions. In certain embodiments, the nanoemulsions of the present disclosure, once formed, can remain kinetically stable at ambient temperature and pressure for a period as short as 24 h or as long as several months. In certain embodiments, the droplets of the discontinuous phase in the nanoemulsions of the present disclosure may have an average radius of about 100 nm or less, about 50 nm or less, about 10 nm or less or about 5 nm or less. The two phases of the nanoemulsion can be included in any quantity and / or appropriate ratio. For example, in some embodiments, the nanoemulsion may include a polar phase and a non-polar phase in a ratio ranging from about 99: 1 to about 1:99. In some embodiments, the polar phase and the non-polar phase may be present in a ratio ranging from about 10: 1 to about 1: 1, for example. In some embodiments, the polar phase and the non-polar phase may be present in a ratio of about 4: 1, for example.
    In nanoemulsions comprising a polar phase, the polar phase can comprise, for example, any type of water and / or any aqueous liquid which is miscible with water. Examples of such liquids may include, without limitation, fresh water (e.g., water which does not contain a significant amount of salts or other additives added thereto, with the exception of generally available from water sources), salt water (e.g., water containing one or more salts dissolved in it), brine (e.g., saturated seawater), seawater, alcohols (e.g., methanol, ethanol, n-propanol, isopropanol, n-butanol, sec-butanol, l isobutanol and t-butanol), glycerins, glycols (e.g., polyglycols, propylene glycol and ethylene glycol), polyglycolamines, polyols, and any derivative thereof, or any combination of them. In certain embodiments, a large amount of alcohols, glycerins, glycols and / or polyols may be absent from the nanoemulsions of the present disclosure. In nanoemulsions comprising an oil-based or oleaginous phase, the oil-based phase can comprise any type of oil-based liquid which has at least a solubility in water of 1%. Examples of such liquids can include, without limitation, oils, hydrocarbons, esters, ethers, non-polar organic liquids, etc., for example. In certain embodiments, the oil-based or oil-based phase may comprise one or more water-soluble solvents, including, without limitation, alcohols and / or biodegradable solvents, for example.
    The surfactants used in the nanoemulsions of the present disclosure may include any surfactant, or a combination of surfactants, which is capable of emulsifying two immiscible fluids to form a nanoemulsion. Surfactants can also be used to treat part of the underground formation, e.g., by modifying the wettability of one or more downhole surfaces (measured by any known method, including, without limitation, measurements contact angles) and / or to facilitate the flow of certain types of fluids through the pore spaces in the formation.
    Depending on the given application, the surfactant can be cationic, anionic, nonionic or amphoteric, can act as an emulsifier or demulsifier / separator, and / or can be a monomer or a polymer. The types of cationic surfactants which may be suitable for certain embodiments of the present disclosure include, without limitation, methyl arginine esters, alkanolamines, alkylenediamines, alkylamines, alkylamine salts, salts of of quaternary ammonium such as trimethyltallowammonium chloride, amine oxides, alkyltrimethyl amines, triethylamines, alkyldimethylbenzylamines, alkylamidobetaines such as cocoamidopropylbetaine, alpha-olefin sulfonate, C6 to alkylethoxylate sulfate , trimethylcocoammonium chloride, derivatives thereof, and combinations thereof, for example. The types of anionic surfactants which may be suitable for certain embodiments of the present disclosure include, without limitation, alkyl sulfates of alkali metals, alkyl ether sulfonates, alkyl sulfonates, alkylaryl sulfonates, linear and branched alkyl ester sulfates and sulfonates, polypropoxylated alcohol sulfates, polyethoxylated alcohol sulfates, polyethoxylated polypropoxylated alcohol sulfates, alkyl disulfonates, alkylaryl disulfonates, alkyl disulfates , alkyl sulfosuccinates, alkyl ether sulfates, linear and branched ether sulfates, alkali metal carboxylates, fatty acid carboxylates, alkyl phosphate ester carboxylates, alkyl ether carboxylates, N-acylamino acids, N-acylglutamates, N-acylpolypeptides, alkylbenzenesulfonates, paraffinic sulfonates, α-olefinsulfonates, lignosulfates, d es derivatives of sulfosuccinates, polynaptylmethylsulfonates, alkyl sulfates, alkylethersulfates, monoalkylphosphates, polyalkylphosphates, fatty acids, alkali salts of acids, alkali salts of fatty acids, alkali salts of acids, sodium salts of acids, sodium salts of fatty acids, alkyl ethoxylate, soaps, derivatives thereof, and combinations thereof, for example. The types of nonionic surfactants which may be suitable for certain embodiments of the present disclosure include, without limitation, amides, diamides, polyglycol esters, alkyl polyglycosides, sorbitan esters, methylglucoside esters and alcohol ethoxylates and alcohol oxylalkylates, alkylphenol oxylalkylates, nonionic esters such as sorbitan alkoxylate esters of sorbitan esters, castor oil alkoxylates, alkoxylates fatty acids, lauric alcohol alkoxylates, nonylphenol alkoxylates, octylphenol alkoxylates, tridecyl alcohol alkoxylates, and combinations thereof, and derivatives thereof, for example. Examples of nonionic surfactants which may be suitable include, without limitation, alkylphenol ethoxylates, nonylphenol ethoxylates, octylphenol ethoxylates, tridecyl alcohol ethoxylates, mannide monooleate, isostearate sorbitan, sorbitan laurate, sorbitan monoisostearate, sorbitan monolaurate, sorbitan monooleate, sorbitan monopalmitate, sorbitan monostearate, sorbitan oleate, sorbitan palmitate, sesquioleate sorbitan stearate, sorbitan trioleate, sorbitan tristearate, and combinations thereof, and derivatives thereof, etc.
    In certain embodiments, the surfactant may include an alkyl polyglycoside or a derivative thereof (e.g., functionalized sulfonates, functionalized betaines and / or inorganic salts of the alkyl polyglycoside) in a non-aromatic solvent such as an ethoxylated alcohol, an alkoxylated alcohol, a glycol ether, a disubstituted amide, a mixture of glycerin and acetone, isopropylidene glycerol, methanol, polyols, triethanolamine, acid ethylenediaminetetraacetic, N, N-dimethyl-9-decenamide, methyl soy ester, methyl canola ester, a mixture of methyl laurate and methyl myristate, a mixture of methyl soyate and ethyl lactate, alcohol alkoxysulfates, sulfonates, any combination, and any derivative thereof. In certain embodiments, the surfactant may include an ethoxylated amine (e.g., ethoxylated tallow amine) or a derivative thereof. Examples of specific mixtures of surfactants which may be suitable for use in certain embodiments of the present disclosure may include, without limitation, the following compounds: mixtures of methyl 9-decenoate and alkoxyl sulfate alcohol; mixtures of C15 olefins, an ethoxylated alcohol and the alcohol alkoxyl sulfate; and mixtures of ethoxylated alcohol and ethoxylated amine, for example.
    The surfactants of the present disclosure can be included in any amount suitable to produce a kinetically stable nanoemulsion. In some embodiments, the surfactant (including all associated solvents) may be present in an amount less than about 500 parts per million (ppm). In some embodiments, the surfactant can be present in an amount ranging from about 50 ppm to about 500 ppm. In some embodiments, the surfactant can be present in an amount ranging from about 100 ppm to about 300 ppm. In some embodiments, the surfactant can be present in an amount ranging from about 100 ppm.
    The nanoemulsions of the present disclosure may also include one or more co-surfactants. In the present context, a "co-surfactant" describes a surfactant which participates in the aggregation of molecules in a nanoemulsion but which does not aggregate on its own. Co-surfactants which may be suitable for the nanoemulsions of the present disclosure include, without limitation, alcohols (e.g., propanol, butanol, pentanol in their various isomerization structures, ethoxylated and propoxylated alcohols) , glycols, glycerols, polyols, phenols, thiols, isopropylidene, carboxylates, sulfonates, ketones, acrylamides, sulfonates, pyrrolidones, any derivative thereof is any combination of them.
    The processing fluids used in the methods and systems of the present disclosure may include any water-based fluid known in the art in which the nanoemulsion can be diluted. The term “base fluid” describes the major component of the fluid (unlike the compounds dissolved and / or suspended in it), and does not describe any particular condition or property of this fluid such as its weight, its quantity, its pH, etc. The aqueous fluids which may be suitable for use in the methods and systems of the present disclosure may include water from any source. Examples of such aqueous fluids may include, without limitation, fresh water (eg, water which does not contain a significant amount of salts or other additives added thereto, apart from those found in generally available sources of water), salt water (e.g. water containing one or more salts dissolved in it), brine (e.g. saturated sea water ), seawater, or any combination thereof. In most embodiments of the present disclosure, the aqueous-based fluid comprises one or more ionic species, such as those formed by salts dissolved in water. For example, seawater and / or produced water may include a variety of divalent cationic species dissolved therein. In certain embodiments, the density of the aqueous-based fluid can be adjusted, among other objectives, to allow for additional particulate transport and suspension in the compositions of the present disclosure. In some embodiments, the pH of the aqueous-based fluid may be adjusted (e.g., with a buffer or other pH adjusting agent) to a specific level, which could depend, among other factors, on types of viscosifiers, acids and other additives included in the fluid. A person skilled in the art, with the benefit of this disclosure, will know when such density and / or pH adjustments are necessary.
    The nanoemulsions of the present disclosure can be included in a process fluid of the present disclosure in any suitable concentration. In some embodiments, the nanoemulsion may be included in a process fluid in an amount of from about 0.1 gallons per 1000 gallons of process fluid (gpt) to about 10 gpt by volume. In some embodiments, the nanoemulsion may be included in a processing fluid in an amount of from about 0.5 gpt to about 5 gpt by volume. In some embodiments, the nanoemulsion may be included in a processing fluid in an amount of from about 1 gpt to about 2 gpt by volume.
    In certain embodiments, the processing fluids used in the methods and systems of the present disclosure may optionally include any number of additional additives. The nanoemulsions of the present disclosure may, among other objectives, facilitate the administration of surfactants and other optional treatment additives to certain regions (eg, regions of low permeability) of a formation. Examples of such additional additives include, without limitation, salts, additional surfactants, acids, propellant particles, diversions, fluid loss control additives, gas, nitrogen, arbone dioxide, surface modifiers, tackifiers, foaming agents, corrosion inhibitors, fouling inhibitors, catalysts, clay control agents, biocides , friction reducers, anti-foaming agents, bridging agents, flocculants, H2S scavengers, CO2 scavengers, oxygen scavengers, lubricants, viscosifiers, breakers, agents weights, modifiers of relative permeability, resins, wetting agents, coating enhancers, filter cake removing agents, antifreezes (e.g., ethylene glycol), etc. In some embodiments, one or more of these additional additives (eg, a crosslinking agent) can be added to the process fluid and / or activated after at least partial hydration of the viscosifier in the fluid. A specialist in the field, with the benefit of this disclosure, will recognize the types of additives that can be added to the fluids of this disclosure for a given application.
    The nanoemulsions and / or process fluids of the present disclosure can be prepared using any suitable method and / or equipment, (e.g., mixers, mixers, agitators, etc.) known in the art. the domain at any time before use. The nanoemulsions and / or process fluids can be prepared, at least in part, at the well site or at any location off the site, and can optionally be stored for a period of time (e.g., at minus one month) either at the site level or in an off-site location. In some embodiments, the nanoemulsion and / or other components of the process fluid can be measured directly in a base fluid to form a process fluid. In some embodiments, the base fluid may be mixed with the nanoemulsion and / or other components of the treatment fluid at the site of the well at which the operation or treatment is performed, either by batch mixing or continuous mixing ("on the fly"). The term "on the fly" is used herein to include methods of combining two or more components in which a flow of one element is continuously introduced into a flow of another component so that flows are combined and mixed while continuing to flow as a single flow as part of continuous processing. Such mixing can also be described as "real time" mixing. In other embodiments, the nanoemulsions and / or processing fluids of this disclosure may be prepared, in whole or in part, at an off-site location and transported to the site when processing or operation is carried out. By introducing a treatment fluid of the present disclosure into a portion of an underground formation, the components of the treatment fluid may be mixed together at the surface and introduced into the formation together, or one or more components may be introduced the rormation at the level of the surface separately from the other components so that the components mix or intermingle in a part of the formation to form a treatment fluid. In both cases, the treatment fluid is intended to be introduced into at least part of the underground formation for the purposes of this disclosure.
    The present disclosure, in certain embodiments, describes methods of using treatment fluids to perform a variety of underground treatments, including, without limitation, hydraulic fracturing treatments, acidification treatments, and drilling operations . In some embodiments, the processing fluids of the present disclosure can be used in the treatment of part of an underground formation, e.g., in acidification treatments, such as matrix acidification or acidification of the fracture. In some embodiments, a process fluid can be introduced into an underground formation. In some embodiments, the process fluid can be introduced into a wellbore which penetrates an underground formation. In some embodiments, the process fluid can be introduced at a pressure sufficient to create or improve one or more fractures within the underground formation (eg, hydraulic fracturing).
    Certain embodiments of the methods and compositions disclosed herein may directly or indirectly affect at least one component or at least one piece of equipment associated with the preparation, introduction, recovery, recycling, reuse and / or elimination of the disclosed compositions. For example, with reference to Figure 1, the disclosed methods and compositions may directly or indirectly affect one or more components or pieces of equipment associated with an exemplary fracturing system 10, according to one or more embodiments. In some cases, the system 10 includes an apparatus 20 producing a fracturing fluid, a source of fluid 30, a source of proppant 40 and a pump and mixer system 50 and is located on the surface of the well site. at which there is a well 60. In some cases, the fracturing fluid producing apparatus 20 combines a nanoemulsion with the fluid (eg, liquid or substantially liquid) from the fluid source 30, to produce a fracturing fluid which can be used to fracture the formation. The fracturing fluid may be a “ready to use” fluid in a well 60 fracture stimulation treatment or a concentrate to which other fluids are added before use in a well 60 fracture stimulation. some embodiments, the fracturing fluid producing apparatus Z0 can be omitted and the fracturing fluid is taken directly from the fluid source 30. In some embodiments, the billing fluid can include water, a fluid hydrocarbon, polymer gel, foam, air, wet gases and / or other fluids.
    The support agent source 40 may include a support agent for association with the fracturing fluid. In some embodiments, one or more particulate treatment materials of the present disclosure may be provided in the proppant source 40 and may thus combine the fracturing fluid with the proppant. The system may also include a source of additive 70 which provides one or more additives (e.g., a nanoemulsion of the present disclosure, gelling agents, surfactants, weighting agents and / or other additives) in order to modify the properties of the fracturing fluid. For example, the other additives 70 may be included in order to reduce pumping friction, in order to reduce or eliminate the reaction of the fluid with the geological formation in which the well is dug, to function as surfactants and / or to have other functions.
    The pump and mixer system 50 receives the fracturing fluid and mixes it with other components, including the propellant from the propellant source 40 and / or the additional fluid from the additives 70. The The mixture thus obtained can be pumped to the bottom of well 60 with sufficient pressure to create or improve one or more fractures in an underground area, eg, to stimulate the production of fluid from the area. In particular, in certain cases, the apparatus for producing fracturing fluid 20, the source of fluid 30 and / or the source of support agent 40 can be equipped with one or more measuring devices (not illustrated) for monitor the flow of fluids, propellant particles and / or other compositions to the pumping and mixing system 50. Such measurement systems can allow the pumping and mixing system 50 to be supplied from one, some or all of the different sources at any given time, and may facilitate the preparation of fracturing fluids in accordance with this disclosure using continuous mixing or "on the fly" methods. Thus, for example, the pump and mixer system 50 can supply only fracturing fluid to the well at one time, only proppant particles at other times, and combinations of these two components. at other times.
    FIG. 2 illustrates the well 60 during a fracturing operation in a part of the underground formation of interest 102 surrounding a wellbore 104. The wellbore 104 extends from the surface 106, and the fluid fracturing 108 is applied to part of the underground formation 102 surrounding the horizontal part of the wellbore.
    Even if is illustrated as deviating towards i nonzontaie, the well of rorage 1 can include geometries and orientations horizontal, vertical, inclined, curved and other types of geometries and orientations of wellbore, and the fracturing treatment can be applied to an underground area surrounding any part of the wellbore. The wellbore 104 may include tubing 110 which is cemented or otherwise attached to the wall of the wellbore. The wellbore 104 can be uncased or included in uncased sections. Perforations can be formed in the casing 110 to allow the flow of fracturing fluids and / or other materials into the underground formation 102. In the cased wells, the perforations can be formed using shaped charges, a barrel perforation, hydrojetting and / or other tools.
    The well is illustrated with a work train 112 hanging from the surface 106 into the well 104. The pump and mixer system 50 is coupled to a work train 112 to pump the fracturing fluid 108 into the well. drilling 104. Work train 112 may include coiled tubing, hinged pipe, and / or other structures that allow fluid to flow into well bore 104. Work train 112 may include regulators flow, bypass valves, orifices, and / or other tools or well devices that regulate flow of fluid from the interior of the work train 112 into the underground area 102. For example, the work train 112 may include orifices adjacent to the wall of the wellbore for transmitting the fracturing fluid 108 directly into the underground formation 102, and / or the work train 112 may include orifices which are spaced from the wall of the wellbore to transmit the fracturing fluid 108 in a ring in the wellbore between the work train 112 and the wall of the wellbore.
    The work train 112 and / or the wellbore 104 may include one or more shutter sets 114 which plug the ring between the work train 112 and the wellbore 104 to define an interval of the wellbore 104 in which the fracturing fluid 108 will be pumped. FIG. 2 illustrates two shutters 114, one defining an upward limit of the interval well and the other defining the bottom end of the interval. When the fracturing fluid 108 is introduced into the wellbore 104 (e.g., in Figure 2, the area of the wellbore 104 between the plugs 114) at sufficient hydraulic pressure, one or more fractures 116 can be created in the underground zone 102. The particulate matter of the proppant (and / or the particulate matter of treatment of the present disclosure) in the fracturing fluid 108 can penetrate the fractures 116 where it can remain after the flow of the fluid fracturing outside the wellbore. These particulates of the proppant can "support" the fractures 116 so that the tluids can flow more freely through the fractures 116. Even if not specifically illustrated here, the disclosed methods and compositions can also directly or indirectly affect any transport or delivery equipment used to transport the compositions to the fracturing system 10, such as, for example, any transport vessel, conduit, pipeline, cart, tube and / or hose used for fluidly move the compositions from one location to another, pumps, compressors or motors used to set the compositions in motion, any valve or related seal used to regulate the pressure or the flow rate of the compositions, and all the sensors (ie. i.e. pressure and temperature), gauges and / or combinations thereof, etc.
    One embodiment of the present disclosure is a method comprising: providing a treatment fluid comprising an aqueous based fluid and a nanoemulsion comprising an internal water soluble phase, an external water soluble phase and a surfactant; and introducing the process fluid into at least a portion of the underground formation at or above sufficient pressure to create or improve at least one fracture in the underground formation.
    In one or more embodiments described in the preceding paragraph, the internal water-soluble phase comprises an oil-based fluid and the external phase comprises an aqueous fluid. In one or more embodiments described above, the water-soluble internal phase comprises droplets having an average radius of about 100 nm or less measured using the dynamic diffraction particle analysis technique light. In one or more embodiments described above, the surfactant is present in the nanoemulsion in an amount of about 500 parts per million or less. In one or more embodiments described above, the surfactant comprises at least one surfactant selected from a nonionic surfactant, an anionic surfactant, a cationic surfactant, an amphoteric surfactant, and any combination of them. In one or more embodiments described above, the surfactant is a demulsifier or a breaker. In one or more embodiments described above, the surfactant comprises at least one surfactant selected from an alcohol alkoxysulfate, an ethoxylated alcohol, and any combination thereof. In one or more embodiments described above, the surfactant comprises one or more solvents. In one or more embodiments described above, the underground formation includes an unconventional formation. In one or more embodiments described above, the underground formation includes scmste. In one or more embodiments described above, the nanoemulsion also comprises at least one treatment additive chosen from a salt, an acid, a deflecting agent, a fluid loss control additive, a gas, a surface modification, a tackifier, a foaming agent, a corrosion inhibitor, a fouling inhibitor, a catalyst, a clay control agent, a biocide, a friction reducer, an anti foaming agent, a bridging agent, a flocculant, an H2S scavenger, a CO2 scavenger, an oxygen scavenger, a lubricant, a viscosifier, a breaking agent, a weighting agent, a relative permeability modifier, a resin , a wetting agent, a coating improving agent, a filter cake removing agent, an antifreeze, or any combination thereof. In one or more embodiments described above, the treatment fluid is introduced into the underground formation using one or more pumps. In one or more embodiments described above, the nanoemulsion is formed by shearing at least two immiscible fluids in a mixer.
    Another embodiment of the present disclosure is a method comprising: using a treatment fluid containing an aqueous-based fluid and a nanoemulsion comprising: an internal non-polar phase soluble in water, an external polar phase soluble in water and a nonionic surfactant which comprises an alcohol alkoxysulfate, an ethoxylated alcohol, isopropylidene glycerol, one or more polyols, water, and the introduction of the treatment fluid into at least one part of an underground formation at or above sufficient pressure to create or improve at least one fracture in the underground formation.
    In one or more embodiments described in the preceding paragraph, the underground formation comprises a non-conventional formation. In one or more embodiments described above, the internal water-soluble non-polar phase comprises droplets having an average radius of about 100 nm or less measured using an analysis technique. particle by dynamic light diffraction. In one or more embodiments described above, the nonionic surfactant is present in the nanoemulsion in an amount of about 500 parts per million or less. In one or more embodiments described above, the surfactant is a demulsifier or a breaker.
    Another embodiment of the present disclosure is a method comprising: providing a treatment fluid comprising an aqueous based fluid and a nanoemulsion comprising an internal water soluble phase, an external water soluble phase and a surfactant, wherein the water-soluble internal phase comprises droplets having an average radius of about 100 nm or less measured using a dynamic light diffraction particle analysis technique; and introducing the process fluid into at least a portion of the underground formation at or above sufficient pressure to create or improve at least one fracture in the underground formation.
    In one or more embodiments described in the preceding paragraph, the surfactant is present in the nanoemulsion in an amount of about 500 parts per million or less.
    In order to allow a better understanding of the present disclosure, the following examples of certain aspects of certain embodiments are given. The following examples are not the only examples which may be given according to the present disclosure and are not intended to limit the scope of the disclosure or the claims. EXAMPLES EXAMPLE 1
    The concentration of an example surfactant of the present disclosure (including a mixture of ethoxylated alcohol, ethoxylated amine, isopropylidene glycerol, polyols and water) was calculated by measuring the surface tension of an oil-in-water nanoemulsion at various concentrations. The results of these measurements are given in Table 1 below.
    Table 1
    As demonstrated above, the surfactant provided adequate surface tension to stabilize a nanoemulsion at a concentration of about 100 ppm. EXAMPLE 2
    The nanoemulsion of Example 1 having a surfactant concentration of 100 ppm was tested for its kinetic stability under high shear compared to a conventional microemulsion product of the following composition (based on FTSS data in free access) : 5-10% citrus extract as oily phase, 5-10% ethoxylated amine, 1-5% branched ethoxylated alcohol and 15-40% ethanol / isopropyl alcohol solvent. The droplet size distributions in the nanoemulsion and the microemulsion were measured using a DelsaMax dynamic light diffraction particle analyzer (scanning particle size 0.4 to 10,000 nm), at times in pure samples (100% concentration) and samples diluted to a concentration of one gallon per 1000 gallons (gpt) in an aqueous solution of KC1 at 4%. Then, the diluted samples were subjected to high shear (4000 rpm) in a high shear mixer for 30 minutes, and the size distributions of their droplets were measured after shear. The plots from the dynamic light diffraction device showing the droplet size distributions of the various samples are shown in Figures 3A to 3F, and the droplet rays, with the highest peaks in these distributions, are shown in the following Table 2 for each sample.
    Table 2
    As demonstrated above, the nanoemulsions of the present disclosure were able to maintain smaller droplet sizes even after being subjected to high shear.
    Consequently, the present invention is well suited to achieve the purposes and obtain the advantages mentioned here as well as those which are inherent in the present description. The particular embodiments disclosed above are illustrative in nature only, and the teachings of this disclosure may be varied and practiced in different but equivalent ways which will be apparent to a specialist in the field who benefits from these teachings. While many changes can be made by a specialist in the field, such changes are encompassed within the spirit of the subject matter defined by the appended claims. In addition, there is no limitation to the construction or design details described herein, other than those described in the claims below. It is therefore obvious that the given illustrative embodiments disclosed above may be altered or modified and all variations of this type are considered to be within the scope and spirit of this disclosure. In particular, each range of values (eg, "from about a to about b" or, equivalently, "from about a to b", or, equivalently, "from about ab") disclosed here should be understood as describing the power play (the set of all subsets) of the respective range values. The terms in the claims have a clear and ordinary meaning unless explicitly stated is clearly defined by the claimant.
    权利要求:
    Claims (20)
    [1" id="c-fr-0001]
    What is claimed:
    1. A method comprising: providing a treatment fluid comprising an aqueous based fluid and a nanoemulsion comprising an internal water soluble phase, an external water soluble phase and a surfactant; and introducing the process fluid into at least part of an underground formation at or above sufficient pressure to create or improve at least one fracture in the underground formation.
    [2" id="c-fr-0002]
    2. The method of claim 1, wherein the water-soluble internal phase comprises an oil-based fluid and the external phase comprises an aqueous fluid.
    [3" id="c-fr-0003]
    3. The method of claim 1, wherein the water-soluble internal phase comprises droplets having an average radius of about 100 nm or less measured using the technique of particle analysis by dynamic diffraction of the light.
    [4" id="c-fr-0004]
    The method of claim 1, wherein the surfactant is present in the nanoemulsion in an amount of about 500 parts per million or less.
    [5" id="c-fr-0005]
    5. The method of claim 1, wherein the surfactant comprises at least one surfactant selected from a nonionic surfactant, an anionic surfactant, a cationic surfactant, an amphoteric surfactant, and any combination of those -this.
    [6" id="c-fr-0006]
    6. The method of claim 1, wherein the surfactant is a demulsifier or a breaker.
    [7" id="c-fr-0007]
    7. The method of claim 1, wherein the surfactant comprises at least one surfactant selected from an alcohol alkoxysulfate, an ethoxylated alcohol, and any combination thereof.
    [8" id="c-fr-0008]
    8. The method of claim 1, wherein the surfactant comprises one or more solvents.
    [9" id="c-fr-0009]
    9. The method of claim 1, wherein the underground formation comprises an unconventional formation.
    [10" id="c-fr-0010]
    10. The method of claim 1, wherein the underground formation comprises shale.
    [11" id="c-fr-0011]
    11. The method of claim 1, wherein the nanoemulsion also comprises at least one treatment additive chosen from a salt, an acid, a deflecting agent, a fluid loss control additive, a gas, a modifying agent. surface, tackifier, foaming agent, corrosion inhibitor, fouling inhibitor, catalyst, clay control agent, biocide, friction reducer, anti-foaming agent, agent bridging agent, a flocculant, an H2S scavenger, a CO2 scavenger, an oxygen scavenger, a lubricant, a viscosifier, a breaking agent, a weighting agent, a modifier of the relative permeability, a resin, a wetting agent , a coating enhancer, a filter cake removing agent, an antifreeze, or any combination thereof.
    [12" id="c-fr-0012]
    12. The method of claim 1, wherein the treatment fluid is introduced into the underground formation using one or more pumps.
    [13" id="c-fr-0013]
    13. The method of claim 1, wherein the nanoemulsion is formed by shearing at least two immiscible fluids in a mixer.
    [14" id="c-fr-0014]
    14. A process comprising: the use of a treatment fluid containing an aqueous-based fluid and a nanoemulsion comprising: an internal non-polar phase soluble in water, an external polar phase soluble in water, and an agent a nonionic surfactant which comprises an alcohol alkoxysulfate, an ethoxylated alcohol, isopropylidene glycerol, one or more polyols, and water; and introducing the process fluid into at least part of an underground formation at or above sufficient pressure to create or improve at least one fracture in the underground formation.
    [15" id="c-fr-0015]
    15. The method of claim 14, wherein the underground formation comprises an unconventional formation.
    [16" id="c-fr-0016]
    16. The method of claim 14, wherein the water-soluble nonpolar internal phase comprises droplets having an average radius of about 100 nm or less measured using a diffraction particle analysis technique light dynamics.
    [17" id="c-fr-0017]
    17. The method of claim 14, wherein the nonionic surfactant is present in the nanoemulsion in an amount of about 500 parts per million or less.
    [18" id="c-fr-0018]
    18. The method of claim 14, wherein the surfactant is a demulsifier or a breaker.
    [19" id="c-fr-0019]
    19. A method comprising: the use of a treatment fluid comprising an aqueous-based fluid and a nanoemulsion comprising an internal water-soluble phase, an external water-soluble phase and a surfactant, in which the phase internal water-soluble includes droplets having an average radius of about 100 nm or less measured using a particle analysis technique using dynamic light diffraction; and introducing the process fluid into at least part of an underground formation at or above sufficient pressure to create or improve at least one fracture in the underground formation.
    [20" id="c-fr-0020]
    20. The method of claim 19, wherein the surfactant is present in the nanoemulsion in an amount of about 500 parts per million or less.
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    法律状态:
    2018-09-28| PLFP| Fee payment|Year of fee payment: 2 |
    2020-06-05| RX| Complete rejection|Effective date: 20200429 |
    优先权:
    申请号 | 申请日 | 专利标题
    IBWOUS2016/063118|2016-11-21|
    PCT/US2016/063118|WO2018093392A1|2016-11-21|2016-11-21|Nanoemulsions for use in subterranean fracturing treatments|
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