Nanobubble enhanced treatment fluids

Abstract

Compositions and methods for treating a subterranean formation. A treatment fluid is introduced into a wellbore penetrating the subterranean formation. The treatment fluid is formulated from an aqueous base fluid, a polysiloxane surfactant, a Gemini surfactant, and a nanobubble dispersion comprising a plurality of nanobubbles. The treatment fluid is used to contact a hydrocarbon gas in the subterranean formation.

Description

[0001] NANOBUBBLE ENHANCED TREATMENT FLUIDS

[0002] TECHNICAL FIELD

[0003] The present disclosure relates generally to wellbore operations, and more particularly, to the use of a treatment fluid comprising nanobubbles to mitigate potential issues caused by condensate banking during the production phase of a well.

[0004] BACKGROUND

[0005] During the production phase of a well the wellbore pressure may decrease which may induce certain hydrocarbon fluids to form a condensate, thereby dropping out heavy end crude chemical components within the well or subterranean formation. The hydrocarbon condensate may block pores or channels in the formation, which may damage the formation and potentially reduce production. The unwanted formation of this hydrocarbon condensate is referred to as condensate banking. Fluorocarbon surfactants may be added during production to reduce the surface tension of the wellbore fluids and prevent the formation of hydrocarbon condensate. However, the use of fluorocarbon surfactants may not be ideal in all operations.

[0006] A reduction in condensate banking may improve production and prevent formation damage. Accordingly, the prevention of hydrocarbon condensate may be an important part of a production operation. The present invention provides improved methods for treating a well to prevent condensate banking.

[0007] BRIEF DESCRIPTION OF THE DRAWINGS

[0008] Illustrative examples of the present disclosure are described in detail below with reference to the attached drawing figures, which are incorporated by reference herein, and wherein:

[0009] FIG. 1 is a schematic illustrating a system of surface equipment for the preparation and delivery of a treatment fluid to a wellbore in accordance with one or more examples described herein;

[0010] FIG. 2 is a schematic illustrating the placement of a treatment fluid into a fracture in a subterranean formation in accordance with one or more examples described herein; and

[0011] FIG. 3 is a schematic illustrating the treatment of an injection well in accordance with one or more examples described herein. The illustrated figures are only exemplary and are not intended to assert or imply any limitation with regard to the environment, architecture, design, or process in which different examples may be implemented.

[0012] DETAILED DESCRIPTION

[0013] The present disclosure relates generally to wellbore operations, and more particularly, to the use of a treatment fluid comprising nanobubbles to mitigate potential issues caused by condensate banking during the production phase of a well.

[0014] In the following detailed description of several illustrative examples, reference is made to the accompanying drawings that form a part hereof, and in which is shown by way of illustration specific examples that may be practiced. These examples are described in sufficient detail to enable those skilled in the art to practice them, and it is to be understood that other examples may be utilized, and that logical structural, mechanical, electrical, and chemical changes may be made without departing from the spirit or scope of the disclosed examples. To avoid detail not necessary to enable those skilled in the art to practice the examples described herein, the description may omit certain information known to those skilled in the art. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the illustrative examples are defined only by the appended claims.

[0015] Unless otherwise indicated, all numbers expressing quantities of ingredients, properties such as molecular weight, reaction conditions, and so forth used in the present specification and associated claims are to be understood as being modified in all instances by the term “about.” Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending upon the desired properties sought to be obtained by the examples of the present invention. At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claim, each numerical parameter should at least be construed in light of the number of reported significant digits and by applying ordinary rounding techniques. It should be noted that when “about” is at the beginning of a numerical list, “about” modifies each number of the numerical list. Further, in some numerical listings of ranges some lower limits listed may be greater than some upper limits listed. One skilled in the art will recognize that the selected subset will require the selection of an upper limit in excess of the selected lower limit.

[0016] In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.” Unless otherwise indicated, as used throughout this document, “or” does not require mutual exclusivity.

[0017] The terms uphole and downhole may be used to refer to the location of various components relative to the bottom or end of a well. For example, a first component described as uphole from a second component may be further away from the end of the well than the second component. Similarly, a first component described as being downhole from a second component may be located closer to the end of the well than the second component.

[0018] The terms upstream and downstream may be used to refer to the location of various components relative to one another in regards to the flow of a sample through said components. For example, a first component described as upstream from a second component will encounter a sample before the downstream second component encounters the sample. Similarly, a first component described as being downstream from a second component will encounter the sample after the upstream second component encounters the sample.

[0019] The present disclosure relates generally to wellbore operations, and more particularly, to the use of a treatment fluid comprising nanobubbles to mitigate potential issues caused by condensate banking during the production phase of a well. Advantageously, the treatment fluids comprise nanobubble formulations that are compatible with polysiloxane and Gemini surfactants. As a further advantage, the treatment fluid does not comprise a fluorocarbon surfactant. The combination of the poly siloxane surfactant, the Gemini surfactant, and the nanobubbles provides a treatment fluid that may reduce the surface tension of a wellbore fluid to a very low level during the production of gaseous hydrocarbons. This reduction in the surface tension of may prevent the formation of hydrocarbon condensates during the production of the well. Additionally, the nanobubbles may improve the efficiency of the polysiloxane and Gemini surfactants at the oil / water / rock interface as well as allow the hydrophobic polysiloxanes to maintain ideal wetting conditions on the formation faces.

[0020] The treatment fluids comprise a dispersion of nanobubbles in a liquid carrier. The nanobubble dispersion comprises a plurality of nanobubbles. Nanobubbles are bubbles having a mean diameter between about 50 nm to about 1000 nm. The nanobubbles are formed on the surface either at the wellsite or at an offsite location and then transported to the wellsite. After their formation, the nanobubbles may then be combined with the other components of the treatment fluid. When the treatment fluid is not needed, the treatment fluid containing the nanobubbles may be stored or transported to another location for later use.

[0021] The nanobubbles may be formed by any suitable manner. One mechanical method for forming the nanobubbles generally includes using a tube, in particular, a ceramic tube coated with a metallic oxide to inject nanobubbles into a liquid carrier. Through the wall of the tube, pores are machined or otherwise disposed in the tube wall and used to provide a channel from the interior of the tube to the exterior of the tube. It is preferable, but not required to use a tube having a constant pore size. The tube is placed within a container or vessel in which a liquid carrier (e.g., water) is flowed. The liquid carrier is flowed around the tube in a way to generate a turbulent flow of the liquid carrier, for example, the liquid carrier may be introduced into the vessel at an oblique or right angle relative to the tube. A gas is introduced into the lumen of the tube at a pressure greater than the fluid pressure in the vessel, thereby forcing the gas through the pores in the tube and into the liquid carrier flowing in the vessel. The pore size in the tube wall produces nanobubbles of the desired size as the gas is flowed through the pores into the liquid carrier.

[0022] Ceramic may be used as the tube material, but generally the tube can be produced from any rigid material adapted for maintaining a desired pore size when its lumen is filled with a pressurized gas. Maintaining a constant pore size can be beneficial for controlling the diameter range and mean diameter of the nanobubbles formed in the liquid carrier. As such, preferred materials for the tube are those having sufficient strength or wall thickness for maintaining a constant pore size when a pressurized gas is introduced into the lumen of the tube.

[0023] In a specific example, the tube is a single channel ceramic membrane coated with metallic oxides (such as alumina, titania, zirconia, manganese, or combinations thereof). However, it is to be understood that the tube is not limited to any form or size of structure and can be in the form of monolith, multichannel tubes, etc. A singular mean pore size between about 50 nm to about 1000 nm is used depending on the size of the bubble desired. Specific examples of metallic oxide coatings are AI2O3 or TiCb crystalline coatings with a known mean pore size. The tube length, diameter, and size of the lumen can be any value sufficient for introduction of the gas into the liquid carrier.

[0024] In some examples, the liquid carrier may be an aqueous fluid. In other examples, an organic liquid may be used. The choice of the liquid carrier may be selected based on the other components of the treatment fluid and the chosen wellbore operation. In some examples, the liquid carrier is free or substantially free of surfactants. The liquid carrier should be flowed around the tube in a turbulent manner to prevent the nanobubbles from coalescing into larger bubbles. The liquid carrier may be introduced into the vessel at an oblique or right angle relative to the tube in order to enhance the turbulence of the liquid carrier.

[0025] A selected gas is introduced into the tube under pressure from a gas source. The gas may be air, oxygen, hydrogen, nitrogen, carbon dioxide, argon, helium, or combinations thereof. As the tube is closed (apart from its inlet), the gas can only exit through the pores of the tube. A pressure differential is maintained between the gas pressure inside the lumen of the tube and the liquid pressure outside the tube so that gas is forced through the pores of the tube. The gas emerges from the tube lumen as nanobubbles pulled into the turbulently flowing stream of the liquid carrier on the outside of the tube. The turbulent flow of the liquid carrier performs two functions. The liquid carrier removes the nanobubbles from the surface of the tube and carries away the nanobubbles as they form to prevent the nanobubbles from coalescing into large bubbles. The velocity of the liquid carrier may be any velocity sufficient for pulling the nanobubbles into the liquid carrier as the liquid carrier flows over the pores of the tube.

[0026] The gas used to prepare the nanobubbles may be air, oxygen, hydrogen, nitrogen, carbon dioxide, argon, helium, or combinations thereof. In preferred examples, the gas in the nanobubbles remains in a gaseous state at downhole conditions, such as a pressure in a range of from about 1000 to 3000 pounds per square inch (psi) and at a temperature of at least about 100° C. It some examples, it is preferable that the gas does not transition to a critical or supercritical state while downhole. This transition may negatively impact the stability of the nanobubble.

[0027] In some optional examples, the nanobubbles may be further configured to improve stability or add functionalization. Surfactants or other types of surface modifiers may be added to the nanobubble dispersion (i.e., the dispersed nanobubbles within the liquid carrier) and / or the treatment fluid. Ionic surfactants, such as SDS (sodium dodecyl sulphate), CTAB (cetyltrimethylammonium bromide), and DTAB (dodecyltrimethylammonium bromide); nonionic surfactants, such as the TWEEN™ series of detergents, e.g., TWEEN-20™ polyoxyethylene (20) sorbitan monolaurate, and TRITON X-100™ (octylphenol ethoxylate); and / or zwitterionic surfactants, such as CBS (cocamidopropyl hydroxysultaine), may be introduced to the nanobubble dispersion and / or the treatment fluid. Surface functionalization of the nanobubbles may be selected based upon the target subterranean formation of the wellbore and / or the properties of the hydrocarbon fluid within the subterranean formation. Surface functionalization may be performed through the use of surface modifiers configured to add functional groups such as -COOH, -OH, and -C=O. In some optional examples, the nanobubble surface ionization (exterior surface charge) may be selected based upon the properties of the treatment fluid and / or the hydrocarbon fluid within the subterranean formation. Functionalization either through the addition of surfactants and / or other types of surface modifiers may be used to modify the exterior surface charge of the nanobubble to impart attraction or repulsion to other charged surfaces, such as water molecules and / or other nanobubbles. In some examples, surface polarization may include common surface modifiers that either add dipoles or induce ionic polarization such as zwitterionic surfactants. In some examples, the nanobubble surfaces may be modified to repel other nanobubbles to prevent coalescence and increase the residence time and overall stability of the nanobubbles in the treatment fluid. The use of surface modifiers is optional, and these materials may not be present in all examples.

[0028] In some examples, the nanobubbles are produced and dispersed within the carrier liquid without the inclusion of surfactants or any functionalizing additives. In some examples, the nanobubble dispersion may consist entirely of the nanobubbles and the carrier liquid. In some examples, the nanobubbles may be natively charged in a sufficient matter to repel each other and maintain stability in an aqueous fluid. In particular, some examples of the nanobubbles, such as those comprising air, may be negatively charged without the use of surfactants or functionalizing agents. As such, surfactants may not be necessary to provide nanobubbles having a mechanically induced repulsive character in the liquid carrier or the treatment fluid. In some examples, the nanobubble dispersion may be negatively charged, positively charged, or contain a mixture of negatively and positively nanobubbles.

[0029] The nanobubbles have a mean diameter in a range of between about 50 nm to about 1000 nm. For example, the nanobubbles may have a mean diameter ranging from about 50 nm to about 1000 nm, about 50 nm to about 750 nm, about 50 nm to about 500 nm, about 75 nm to about 200 nm, or about 50 nm to about 150 nm. In some examples, the nanobubbles have a unimodal distribution of diameters. In some examples, the nanobubbles have a multimodal distribution of diameters.

[0030] The nanobubble dispersion described herein comprises a sufficiently concentrated volume of nanobubbles dispersed in the liquid carrier. In some examples, the nanobubbles have a population in the liquid carrier of between about 1 million to about 100 million nanobubbles per mL of liquid carrier. When the nanobubble dispersion is added to the treatment fluid, the population of the nanobubbles in the treatment fluid will vary based on the population of the nanobubbles in the dispersion and the volume of the nanobubble dispersion added to the treatment fluid as a portion of the total volume of the treatment fluid.

[0031] In some examples, the nanobubbles have a droplet resonance time of at least 24 days under ambient conditions at the surface. Ambient conditions include temperatures ranging from about 33° F to about 130° F. For example, the nanobubbles may have a droplet resonance time of at least 3 days, at least 5 days, at least 10 days, at least 15 days, at least 20 days, or at least 24 days. To prepare the treatment fluid, a volume of the nanobubble dispersion is combined with one or more of the other components of the treatment fluid. The combining of the treatment fluid components may occur in any order. The nanobubble dispersion is combined with one or more of the other components of the treatment fluid at the surface, either at the wellsite or another location to then be transported to the wellsite. As the nanobubble dispersion is combined with the other components of the treatment fluid, the nanobubbles within the dispersion will then disperse within the treatment fluid.

[0032] The concentration of the nanobubble dispersion in a treatment fluid may range from about 0.1% w / v to about 20% w / v. The concentration may range from any lower limit to any upper limit and encompass any subset between the upper and lower limits. Some of the lower limits listed may be greater than some of the listed upper limits. One skilled in the art will recognize that the selected subset may require the selection of an upper limit in excess of the selected lower limit. Therefore, it is to be understood that every range of values is encompassed within the broader range of values. For example, the concentration of the nanobubble dispersion in the treatment fluid may range from about 0.1% (w / v) to about 20% (w / v), from about 0.5% (w / v) to about 20% (w / v), from about 1% (w / v) to about 20% (w / v), from about 2% (w / v) to about 20% (w / v), from about 3% (w / v) to about 20% (w / v), from about 4% (w / v) to about 20% (w / v), from about 5% (w / v) to about 20% (w / v), from about 6% (w / v) to about 20% (w / v), from about 7% (w / v) to about 20% (w / v), from about 8% (w / v) to about 20% (w / v), from about 9% (w / v) to about 20% (w / v), from about 10% (w / v) to about 20% (w / v), from about 11% (w / v) to about 20% (w / v), from about 12% (w / v) to about 20% (w / v), from about 13% (w / v) to about 20% (w / v), from about 14% (w / v) to about 20% (w / v), from about 15% (w / v) to about 20% (w / v), from about 16% (w / v) to about 20% (w / v), from about 17% (w / v) to about 20% (w / v), from about 18% (w / v) to about 20% (w / v), or from about 19% (w / v) to about 20% (w / v). As another example, the concentration of the nanobubble dispersion in the treatment fluid may range from about 0.1% (w / v) to about 20% (w / v), from about 0.1% (w / v) to about 19% (w / v), from about 0.1% (w / v) to about 18% (w / v), from about 0.1% (w / v) to about 17% (w / v), from about 0.1% (w / v) to about 16% (w / v), from about 0.1% (w / v) to about 15% (w / v), from about 0.1% (w / v) to about 14% (w / v), from about 0.1% (w / v) to about 13% (w / v), from about 0.1% (w / v) to about 12% (w / v), from about 0.1% (w / v) to about 11% (w / v), from about 0.1% (w / v) to about 10% (w / v), from about 0.1% (w / v) to about 9% (w / v), from about 0.1% (w / v) to about 8% (w / v), from about 0.1% (w / v) to about 7% (w / v), from about 0.1% (w / v) to about 6% (w / v), from about 0.1% (w / v) to about 5% (w / v), from about 0.1% (w / v) to about 4% (w / v), from about 0.1% (w / v) to about 3% (w / v), from about 0.1% (w / v) to about 2% (w / v), from about 0.1% (w / v) to about 1% (w / v), or from about 0.1% (w / v) to about 0.5% (w / v). With the benefit of this disclosure, one of ordinary skill in the art will be readily able to prepare a treatment fluid having a desirable concentration of dispersed nanobubbles for use in a given wellbore operation.

[0033] The treatment fluid additionally comprises a polysiloxane surfactant. The polysiloxane surfactant may be combined with the other treatment fluid components in any order. A general structure of the polysiloxane is shown below:

[0034] R1is independently selected from a (C1-C5) alkyl. At each occurrence, R2is independently selected from the group consisting of -R1and -L'-PE-R3. At each occurrence, L1is independently selected from the group consisting of a bond and a (Ci-Cs)alkylene. At each occurrence, PE is -(O-R4)n-O-. At each occurrence, R4is independently a substituted or unsubstituted (C1-C5) alkylene. At each occurrence, R3is independently selected from the group consisting of -H, methyl, and ethyl. The variable n is about 1 to about 100,000. The polysiloxane includes at least one polyether. The treatment fluid may comprise mixtures of different polysiloxanes or may use a single polysiloxane species.

[0035] The concentration of the polysiloxane surfactant in a treatment fluid may range from about 0.0001% w / w to about 10% w / w. The concentration may range from any lower limit to any upper limit and encompass any subset between the upper and lower limits. Some of the lower limits listed may be greater than some of the listed upper limits. One skilled in the art will recognize that the selected subset may require the selection of an upper limit in excess of the selected lower limit. Therefore, it is to be understood that every range of values is encompassed within the broader range of values. For example, the concentration of the polysiloxane surfactant in the treatment fluid may range from about 0.0001% (w / w) to about 10% (w / w), from about 0.001% (w / w) to about 10% (w / w), from about 0.01% (w / w) to about 10% (w / w), 0.1% (w / w) to about 10% (w / w), from about 0.5% (w / w) to about 10% (w / w), from about 1% (w / w) to about 10% (w / w), from about 2% (w / w) to about 10% (w / w), from about 3% (w / w) to about 10% (w / w), from about 4% (w / w) to about 10% (w / w), from about 5% (w / w) to about 10% (w / w), from about 6% (w / w) to about 10% (w / w), from about 7% (w / w) to about 10% (w / w), from about 8% (w / w) to about 10% (w / w), or from about 9% (w / w) to about 10% (w / v). As another example, the concentration of the polysiloxane in the treatment fluid may range from about 0.0001% (w / w) to about 10% (w / w), from about 0.0001% (w / w) to about 9% (w / w), from about 0.0001% (w / w) to about 8% (w / w), from about 0.0001% (w / w) to about 7% (w / w), from about 0.0001% (w / w) to about 6% (w / w), from about 0.0001% (w / w) to about 5% (w / w), from about 0.0001% (w / w) to about 4% (w / w), from about 0.0001% (w / w) to about 3% (w / w), from about 0.0001% (w / w) to about 2% (w / w), from about 0.0001% (w / w) to about 1% (w / w), from about 0.0001% (w / w) to about 0.5% (w / w), from about 0.0001% (w / w) to about 0.1% (w / w), from about 0.0001% (w / w) to about 0.01% (w / w), or from about 0.0001% (w / w) to about 0.001% (w / w). With the benefit of this disclosure, one of ordinary skill in the art will be readily able to prepare and select a polysiloxane surfactant having a desirable concentration for use in a given treatment fluid.

[0036] The treatment fluid additionally comprises a Gemini surfactant. Gemini surfactants contain two hydrophilic head groups and two hydrophobic tails which are linked by a spacer at the head groups or along the hydrophobic tails. An example of a Gemini surfactant linked at the hydrophilic head groups is illustrated below.

[0037] The polar heads of the Gemini surfactant may include, but are not limited to, quaternary alcohols, quaternary alkoxylated alcohols, quaternary amine salts, and the like. The polar heads may be the same or different on an individual Gemini surfactant. The spacer, identified as X, that links the polar heads together or the hydrophobic tails together may include, but is not limited to, bis -functionalized alkyl-, alkenyl-, alkynyl-, aryl-moieties, the like, derivatives thereof, or any combinations thereof. Specific examples of X include, but are not limited to, axobenzene, ethylene oxide, perylene tetracarboxylic diimide, stilbene, tetracarboxylic diimide, polyoxylethylene, 2-butynyl, methylene, polyether, the like, derivatives thereof, or any combinations thereof. The hydrophobic tails of the Gemini surfactant, identified as Y, may include, but are not limited to, linear or branched carbon chains containing 1 - 25 methylene units, cyclized alkyl-moieties (e.g., cyclopropane, cyclobutane, cyclopentane, cyclopentane, cyclohexane, cycloheptane), cyclized alkenyl-moieties (e.g., cyclopentene, cylcohexene, , cyclohexadiene, cycloheptene, cycloheptadiene) alkenyl-moieties, bis-alkynyl-moieties, aryl moieties (e.g., bis-aryl-moieties), the like, derivatives thereof, or any combinations thereof. The hydrophobic tails may be the same or different on an individual Gemini surfactant. The treatment fluid may comprise mixtures of different Gemini surfactants or may use a single Gemini surfactant species. One specific species of Gemini surfactant that may be used in some examples is 2,4,7,9-tetramethyldec-5-yne-4,7-diol.

[0038] The concentration of the Gemini surfactant in a treatment fluid may range from about 0.0001% w / w to about 10% w / w. The concentration may range from any lower limit to any upper limit and encompass any subset between the upper and lower limits. Some of the lower limits listed may be greater than some of the listed upper limits. One skilled in the art will recognize that the selected subset may require the selection of an upper limit in excess of the selected lower limit. Therefore, it is to be understood that every range of values is encompassed within the broader range of values. For example, the concentration of the Gemini surfactant in the treatment fluid may range from about 0.0001% (w / w) to about 10% (w / w), from about 0.001% (w / w) to about 10% (w / w), from about 0.01% (w / w) to about 10% (w / w), 0.1% (w / w) to about 10% (w / w), from about 0.5% (w / w) to about 10% (w / w), from about 1% (w / w) to about 10% (w / w), from about 2% (w / w) to about 10% (w / w), from about 3% (w / w) to about 10% (w / w), from about 4% (w / w) to about 10% (w / w), from about 5% (w / w) to about 10% (w / w), from about 6% (w / w) to about 10% (w / w), from about 7% (w / w) to about 10% (w / w), from about 8% (w / w) to about 10% (w / w), or from about 9% (w / w) to about 10% (w / v). As another example, the concentration of the Gemini surfactant in the treatment fluid may range from about 0.0001% (w / w) to about 10% (w / w), from about 0.0001% (w / w) to about 9% (w / w), from about 0.0001% (w / w) to about 8% (w / w), from about 0.0001% (w / w) to about 7% (w / w), from about 0.0001% (w / w) to about 6% (w / w), from about 0.0001% (w / w) to about 5% (w / w), from about 0.0001% (w / w) to about 4% (w / w), from about 0.0001% (w / w) to about 3% (w / w), from about 0.0001% (w / w) to about 2% (w / w), from about 0.0001% (w / w) to about 1% (w / w), from about 0.0001% (w / w) to about 0.5% (w / w), from about 0.0001% (w / w) to about 0.1% (w / w), from about 0.0001% (w / w) to about 0.01% (w / w), or from about 0.0001% (w / w) to about 0.001% (w / w). With the benefit of this disclosure, one of ordinary skill in the art will be readily able to prepare and select a Gemini surfactant having a desirable concentration for use in a given treatment fluid.

[0039] The treatment fluids described herein comprise an aqueous base fluid, for example, freshwater, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated saltwater, including saturated saltwater produced from subterranean formations), seawater, or any combination thereof. Generally, the aqueous base fluid may be from any source provided that the aqueous base fluid does not contain an excess of compounds that may undesirably affect other components in the treatment fluid. In the case of brines, the aqueous base fluid may comprise a monovalent brine or a divalent brine. Suitable monovalent brines may include, for example, sodium chloride brines, sodium bromide brines, potassium chloride brines, potassium bromide brines, and the like. Suitable divalent brines can include, for example, magnesium chloride brines, calcium chloride brines, calcium bromide brines, zinc bromide brines, and the like. One of ordinary skill in the art, with the benefit of this disclosure, should be readily able to select an aqueous base fluid for a chosen application.

[0040] The concentration of the aqueous base fluid in the treatment fluid may range from about 1% (w / v) to about 99% (w / v). The concentration of the aqueous base fluid in the treatment fluid may range from any lower limit to any upper limit and encompass any subset between the upper and lower limits. Some of the lower limits listed may be greater than some of the listed upper limits. One skilled in the art will recognize that the selected subset may require the selection of an upper limit in excess of the selected lower limit. Therefore, it is to be understood that every range of values is encompassed within the broader range of values. For example, the concentration of the aqueous base fluid in the treatment fluid may range from about 1 % (w / v) to about 99% (w / v), from about 5% (w / v) to about 99% (w / v), from about 10% (w / v) to about 99% (w / v), from about 15% (w / v) to about 99% (w / v), from about 20% (w / v) to about 99% (w / v), from about 25% (w / v) to about 99% (w / v), from about 30% (w / v) to about 99% (w / v), from about 35% (w / v) to about 99% (w / v), from about 40% (w / v) to about 99% (w / v), from about 45% (w / v) to about 99% (w / v), from about 55% (w / v) to about 99% (w / v), from about 60% (w / v) to about 99% (w / v), from about 65% (w / v) to about 99% (w / v), from about 70% (w / v) to about 99% (w / v), from about 75% (w / v) to about 99% (w / v), from about 80% (w / v) to about 99% (w / v), from about 85% (w / v) to about 99% (w / v), from about 90% (w / v) to about 99% (w / v), or from about 95% (w / v) to about 99% (w / v). As another example, the concentration of the aqueous base fluid in the treatment fluid may range from about 1 % (w / v) to about 99% (w / v), from about 1% (w / v) to about 95% (w / v), from about 1% (w / v) to about 90% (w / v), from about 1% (w / v) to about 85% (w / v), from about 1% (w / v) to about 80% (w / v), from about 1% (w / v) to about 75% (w / v), from about 1% (w / v) to about 70% (w / v), from about 1% (w / v) to about 65% (w / v), from about 1% (w / v) to about 60% (w / v), from about 1% (w / v) to about 55% (w / v), from about 1% (w / v) to about 50% (w / v), from about 1% (w / v) to about 45% (w / v), from about 1% (w / v) to about 40% (w / v), from about 1% (w / v) to about 35% (w / v), from about 1% (w / v) to about 30% (w / v), from about 1% (w / v) to about 25% (w / v), from about 1 % (w / v) to about 20% (w / v), from about 1 % (w / v) to about 15% (w / v), from about 1 % (w / v) to about 10% (w / v), or from about 1% (w / v) to about 5% (w / v). With the benefit of this disclosure, one of ordinary skill in the art will be able to prepare a treatment fluid having a sufficient concentration of an aqueous base fluid for a given application.

[0041] In some optional examples, the treatment fluids may further comprise an additive. The additive may be used to adjust a property of the treatment fluid, for example, viscosity, density, etc. Examples of the additives include, but are not limited to, silica scale control additives, corrosion inhibitors, surfactants, gel stabilizers, anti-oxidants, polymer degradation prevention additives, relative permeability modifiers, scale inhibitors, iron control agents, particulate diverters, salts, fluid loss control additives, gas, catalysts, clay control agents, dispersants, flocculants, scavengers (e.g., H2S scavengers, CO2 scavengers or O2 scavengers), gelling agents, lubricants, friction reducers, bridging agents, viscosifiers, weighting agents, solubilizers, hydrate inhibitors, consolidating agents, bactericides, clay stabilizers, breakers, delayed release breakers, the like, or any combination thereof. With the benefit of this disclosure, one of ordinary skill in the art and the benefit of this disclosure will be able to formulate a treatment fluid having properties suitable for a desired application.

[0042] In some examples, the treatment fluid does not comprise any surfactants besides the polysiloxane surfactant(s) and the Gemini surfactant(s). In some examples, the treatment fluid is substantially free of a fluorocarbon surfactant. In a more specific example, the treatment fluid does not comprise a fluorocarbon surfactant.

[0043] The treatment fluids have a density suitable for a particular application. By way of example, the treatment fluids may have a density in a range of from about 9 pounds per gallon (“Ib / gal”) to about 20 Ib / gal, in a range of from about 12 Ib / gal to about 20 Ib / gal, or in a range of from about 14 Ib / gal to about 20 Ib / gal. With the benefit of this disclosure, those of ordinary skill in the art will readily recognize the appropriate density of a treatment fluid for a particular application. The treatment fluid may be used as a stimulating fluid to help produce a wellbore fluid as well as to mitigate potential issues caused by condensate banking during the production of a well. The treatment fluid may reduce the surface tension of a wellbore fluid to a very low level during production, for example during production of gaseous hydrocarbons. This reduction in the surface tension of the wellbore fluid may pre vent the formation of hydrocarbon condensates, thereby preventing the potential issues caused by condensate banking. Additionally, the nanobubbles may improve the efficiency of the polysiloxane and Gemini surfactants at the oil / water / rock interface as well as allow the hydrophobic polysiloxanes to maintain ideal wetting conditions on the formation faces. In some examples, the treatment fluid may be introduced into an injection well to stimulate another nearby producing well.

[0044] As a further benefit, the treatment fluid may comprise chemically inert, non-toxic, and, if desired, non-flammable materials. While the treatment fluid may be primarily used as a stimulating fluid, it may also provide a means for debris removal from the near-wellbore region that does not require the use of strong acids or other materials that may harm personnel or downhole equipment, or even require on-site specialized storage and training to use. The treatment fluid does not require chemical flowback from the reservoir to remove either unspent acid or reaction byproducts. Matrix acidification byproducts of reservoir materials may generate insoluble byproducts that may in and of themselves damage the near-wellbore region. The treatment fluid may remove debris that interferes with flow while also not creating insoluble byproducts itself.

[0045] FIG. 1 illustrates a schematic of the surface and near-surface portions of a system 100 that delivers the treatment fluid described herein to a downhole location, according to one or more examples. It should be noted that while FIG. 1 generally depicts a land-based system, it is to be recognized that like system 100 may be operated in subsea locations as well. As depicted in FIG. 1, system 100 includes a mixing tank 105, in which a treatment fluid is formulated. The treatment fluid may be conveyed to a pump 140 which elevates the treatment fluid to a desired pressure to drive the treatment fluid to wellhead 115 via line 110, where the treatment fluid enters wellbore conduit 120. Conduit 120 extends from wellhead 115 into a wellbore 125 penetrating subterranean formation 130. Wellhead 115 is illustrated as comprising a derrick, but it is to be understood that other wellhead 115 arrangements such as a Christmas tree may be used in some examples. Wellbore 125 may be any type of wellbore including vertical, horizontal, deviated, etc. The illustrated portion of wellbore 125 is cased with a casing 135. In some alternative examples, wellbore 125 may be uncased. Upon being ejected from conduit 120, the treatment fluid may subsequently enter into subterranean formation 130 as described in FIG. 2 below. Pump 140 is configured to raise the fluid pressure of the treatment fluid to a desired pressure before its introduction into conduit 120. The treatment fluid may be introduced into the wellbore 125 to stimulate the production of hydrocarbon fluids, such as hydrocarbon gases, and to prevent the formation of condensate banking as the wellbore pressure decreases during production. The treatment fluid may be introduced into the wellbore 125 during or after drilling of the wellbore 125. The treatment fluid may be introduced into the wellbore 125 during or after fracturing of the wellbore 125. The treatment fluid may be introduced into the wellbore during or after performing an enhanced oil recovery operation in the wellbore 125. The treatment fluid may be introduced into the wellbore 125 during or after performing a completion operation in the wellbore 125, such as cementing a portion of the wellbore. The treatment fluid may be introduced into the wellbore 125 during or after a different wellbore treatment operation, such as treating the wellbore 125 with a fluid pill (e.g., a fluid loss control pill), an acidizing operation, etc.

[0046] FIG. 2 illustrates a schematic of the downhole portion of the system 100 illustrated in FIG. 1, according to one or more examples. In the example of FIG. 2, the treatment fluid is introduced into the wellbore 125 after a fracturing fluid has been used to form one or more fractures in the subterranean formation 130. As depicted in FIG. 2, conduit 120 extends from the wellhead 115 (as illustrated in FIG. 1) into wellbore 125 penetrating subterranean formation 130. After descending through the heel 145 of the wellbore 125, the conduit 120 is coupled to one or more packers 150 positioned to isolate an interval of wellbore 125. A treatment fluid 155, as described herein, may exit tubular 120 through openings 160. The treatment fluid 155 may be introduced into the subterranean formation 130 via a primary fracture 165 of other such opening into the subterranean formation 130. The treatment fluid 155 may contact a hydrocarbon fluid within the fracture 165 to reduce the surface tension of the hydrocarbon fluid and to prevent the formation of condensate. The treatment fluid 155 may also contact the fracture faces or rock faces to wet the fracture / rock faces. The treatment fluid 155 and the hydrocarbon carbon fluid may be flowed out of the wellbore 125.

[0047] It is to be recognized that system 100 is merely exemplary in nature, and various additional components may be present that have not necessarily been depicted in FIGS. 1 and 2 in the interest of clarity. Non-limiting additional components that may be present include, but are not limited to, supply hoppers, valves, condensers, adapters, joints, gauges, sensors, compressors, pressure controllers, pressure sensors, flow rate controllers, flow rate sensors, temperature sensors, and the like. It should be clearly understood that the examples illustrated by FIGS. 1 and 2 are merely general applications of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited in any manner to the details of FIGS. 1 and 2 as described herein.

[0048] FIG. 3 is a schematic showing one example of a system 200 for an injection well 205. Some portions of the injection well 205 are illustrated as uncased; however, it is to be understood that the injection well 205 may have portions that are cased or uncased as desired. A treatment fluid 230 may be introduced into the wellbore 220 via the Christmas tree 235, or any other sufficient injection point into the wellbore 220. Although system 200 depicts a Christmas tree 235 at the wellhead, other wellhead arrangements may be used for the wellbore operation. In the illustrated example, the treatment fluid 230 is introduced into conduit 240 to the bottom of the wellbore 220 and up through the annulus 245 where it may contact the target formation interval 210. The treatment fluid 230 flows into the adjacent subterranean formation of the formation interval 210 to contact any hydrocarbon fluids within. The treatment fluid 230 is not flowed back but may enter into the subterranean formation 225 at the targeted formation interval 210. The treatment fluid 230 drives the hydrocarbon fluids into a nearby producing well also penetrating subterranean formation 225. As the treatment fluid 230 drives the hydrocarbon fluids into the producing well, the treatment fluid 230 prevents the formation of condensate in this targeted formation interval 210.

[0049] It should be clearly understood that the system 200 illustrated by FIG. 3 is merely a general application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited in any manner to the details of FIG. 3 as described herein.

[0050] The treatment fluids disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with or which may come into contact with the treatment fluids such as, but not limited to, wellbore casing, wellbore liner, completion string, insert strings, drill string, coiled tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole motors and / or pumps, cement pumps, surface-mounted motors and / or pumps, centralizers, turbolizers, scratchers, floats (e.g., shoes, collars, valves, etc.), logging tools and related telemetry equipment, actuators (e.g., electromechanical devices, hydromechanical devices, etc.), sliding sleeves, production sleeves, plugs, screens, filters, flow control devices (e.g., inflow control devices, autonomous inflow control devices, outflow control devices, etc.), couplings (e.g., electro-hydraulic wet connect, dry connect, inductive coupler, etc.), control lines (e.g., electrical, fiber optic, hydraulic, etc.), surveillance lines, drill bits and reamers, sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers, cement plugs, bridge plugs, and other wellbore isolation devices, or components, and the like.

[0051] Provided are treatment fluids for treating a wellbore in accordance with the disclosure and the illustrated FIGs. An example treatment fluid comprises an aqueous base fluid, a polysiloxane surfactant, a Gemini surfactant, and a nanobubble dispersion comprising a plurality of nanobubbles.

[0052] Additionally or alternatively, the treatment fluids may include one or more of the following features individually or in combination. The nanobubbles may comprise a mean diameter between about 50 nm to about 1000 nm. The nanobubbles may be positively charged. The nanobubbles may be negatively charged. The nanobubbles may comprise a mixture of positive and negative charges. The nanobubble dispersion may be present in the treatment fluid in a concentration of about 0.1% w / v to about 20% w / v. The nanobubbles may envelop a gas selected from the group consisting of air, oxygen, carbon dioxide, nitrogen, hydrogen, argon, ammonia, chlorine, or any combination thereof. The polysiloxane surfactant may comprise the structure: wherein R1is independently selected from a (C1-C5) alkyl; R2is independently selected from the group consisting of -R1and -L'-PE-R*; L1is independently selected from the group consisting of a bond and a (Ci-Cs)alkylene; PE is -(O-R4)n-O-; R4is independently a substituted or unsubstituted (C1-C5) alkylene; R is independently selected from the group consisting of - H, methyl, and ethyl; and the variable n is about 1 to about 100,000. The Gemini surfactant may comprise two polar heads individually selected from the group consisting of quaternary alcohols, quaternary alkoxylated alcohols, and quaternary amine salts; wherein the Gemini surfactant further comprises two hydrophobic tails individually selected from the group consisting of linear or branched carbon chains containing 1 - 25 methylene units, cyclized alkyl-moieties, alkenyl- moieties, bis-alkynyl- moieties, and bis-aryl-moieties; wherein the Gemini surfactant further comprises a spacer that links either the polar heads together or the hydrophobic tails together; wherein the spacer is selected from the group consisting of bisfunctionalized alkyl-, alkenyl-, alkynyl-, and aryl-moieties. The polysiloxane surfactant may be present in the treatment fluid in a concentration of about 0.0001% w / w to about 10% w / w. The Gemini surfactant may be present in the treatment fluid in a concentration of 0.0001 % w / w to about 10% w / w. The treatment fluid may be substantially free of a fluorocarbon surfactant. The treatment fluid may not comprise a fluorocarbon surfactant. The nanobubbles may have a population size of about 1 million to about 100 million per mL of the treatment fluid.

[0053] Provided are methods for treating a wellbore with a treatment fluid in accordance with the disclosure and the illustrated FIGs. An example method comprises introducing a treatment fluid into a wellbore penetrating the subterranean formation. The treatment fluid comprises an aqueous base fluid, a polysiloxane surfactant, a Gemini surfactant, and a nanobubble dispersion comprising a plurality of nanobubbles. The method further comprises contacting a hydrocarbon gas in the subterranean formation with the treatment fluid.

[0054] Additionally or alternatively, the method may include one or more of the following features individually or in combination. The method may further comprise altering the wettability of a rock face of the subterranean formation. The nanobubbles may comprise a mean diameter between about 50 nm to about 1000 nm. The nanobubbles may be positively charged. The nanobubbles may be negatively charged. The nanobubbles may comprise a mixture of positive and negative charges. The nanobubble dispersion may be present in the treatment fluid in a concentration of about 0.1% w / v to about 20% w / v. The nanobubbles may envelop a gas selected from the group consisting of air, oxygen, carbon dioxide, nitrogen, hydrogen, argon, ammonia, chlorine, or any combination thereof. The polysiloxane surfactant may comprise the structure: wherein R1is independently selected from a (C1-C5) alkyl; R2is independently selected from the group consisting of -R1and -L'-PE-R3; L1is independently selected from the group consisting of a bond and a (Ci-Cs)alkylene; PE is -(O-R4)n-O-; R4is independently a substituted or unsubstituted (C1-C5) alkylene; R3is independently selected from the group consisting of - H, methyl, and ethyl; and the variable n is about 1 to about 100,000. The Gemini surfactant may comprise two polar heads individually selected from the group consisting of quaternary alcohols, quaternary alkoxylated alcohols, and quaternary amine salts; wherein the Gemini surfactant further comprises two hydrophobic tails individually selected from the group consisting of linear or branched carbon chains containing 1 - 25 methylene units, cyclized alkyl -moieties, alkenyl- moieties, bis-alkynyl- moieties, and bis-aryl-moieties; wherein the Gemini surfactant further comprises a spacer that links either the polar heads together or the hydrophobic tails together; wherein the spacer is selected from the group consisting of bisfunctionalized alkyl-, alkenyl-, alkynyl-, and aryl-moieties. The polysiloxane surfactant may be present in the treatment fluid in a concentration of about 0.0001% w / w to about 10% w / w. The Gemini surfactant may be present in the treatment fluid in a concentration of 0.0001 % w / w to about 10% w / w. The treatment fluid may be substantially free of a fluorocarbon surfactant. The treatment fluid may not comprise a fluorocarbon surfactant. The nanobubbles may have a population size of about 1 million to about 100 million per mL of the treatment fluid.

[0055] Provided are systems for treating a wellbore with a treatment fluid in accordance with the disclosure and the illustrated FIGs. An example system comprises a treatment fluid comprising an aqueous base fluid, a polysiloxane surfactant, a Gemini surfactant, and a nanobubble dispersion comprising a plurality of nanobubbles. The system further comprises mixing equipment configured to mix the aqueous base fluid, the polysiloxane surfactant, the Gemini surfactant, and the nanobubble dispersion and pumping equipment configured to pump the treatment fluid in the wellbore.

[0056] Additionally or alternatively, the system may include one or more of the following features individually or in combination. The nanobubbles may have a population size of about 1 million to about 100 million per mL of the treatment fluid. The nanobubbles may comprise a mean diameter between about 50 nm to about 1000 nm. The nanobubbles may be positively charged. The nanobubbles may be negatively charged. The nanobubbles may comprise a mixture of positive and negative charges. The nanobubble dispersion may be present in the treatment fluid in a concentration of about 0.1% w / v to about 20% w / v. The nanobubbles may envelop a gas selected from the group consisting of air, oxygen, carbon dioxide, nitrogen, hydrogen, argon, ammonia, chlorine, or any combination thereof. The polysiloxane surfactant may comprise the structure:

[0057] wherein R1is independently selected from a (C1-C5) alkyl; R2is independently selected from the group consisting of -R1and -L'-PE-R3; L1is independently selected from the group consisting of a bond and a (Ci-Cs)alkylene; PE is -(O-R4)n-O-; R4is independently a substituted or unsubstituted (C1-C5) alkylene; R3is independently selected from the group consisting of - H, methyl, and ethyl; and the variable n is about 1 to about 100,000. The Gemini surfactant may comprise two polar heads individually selected from the group consisting of quaternary alcohols, quaternary alkoxylated alcohols, and quaternary amine salts; wherein the Gemini surfactant further comprises two hydrophobic tails individually selected from the group consisting of linear or branched carbon chains containing 1 - 25 methylene units, cyclized alkyl-moieties, alkenyl- moieties, bis-alkynyl- moieties, and bis-aryl-moieties; wherein the Gemini surfactant further comprises a spacer that links either the polar heads together or the hydrophobic tails together; wherein the spacer is selected from the group consisting of bisfunctionalized alkyl-, alkenyl-, alkynyl-, and aryl-moieties. The polysiloxane surfactant may be present in the treatment fluid in a concentration of about 0.0001% w / w to about 10% w / w. The Gemini surfactant may be present in the treatment fluid in a concentration of 0.0001 % w / w to about 10% w / w. The treatment fluid may be substantially free of a fluorocarbon surfactant. The treatment fluid may not comprise a fluorocarbon surfactant.

[0058] The preceding description provides various examples of the systems and methods of use disclosed herein which may contain different method steps and alternative combinations of components. It should be understood that, although individual examples may be discussed herein, the present disclosure covers all combinations of the disclosed examples, including, without limitation, the different component combinations, method step combinations, and properties of the system. It should be understood that the compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps. The systems and methods can also “consist essentially of or “consist of the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces.

[0059] For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited. In the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.

[0060] One or more illustrative examples incorporating the examples disclosed herein are presented. Not all features of a physical implementation are described or shown in this application for the sake of clarity. Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned, as well as those that are inherent therein. The particular examples disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown other than as described in the claims below. It is therefore evident that the particular illustrative examples disclosed above may be altered, combined, or modified, and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and / or any optional element disclosed herein.

[0061] Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the disclosure as defined by the following claims.

Claims

WHAT IS CLAIMED IS:

1. A treatment fluid for a wellbore, the treatment fluid comprises: an aqueous base fluid, a polysiloxane surfactant, a Gemini surfactant, and a nanobubble dispersion comprising a plurality of nanobubbles.

2. The treatment fluid of claim 1, wherein the nanobubbles comprise a mean diameter between about 50 nm to about 1000 nm.

3. The treatment fluid of claim 1, wherein the nanobubbles are positively charged.

4. The treatment fluid of claim 1, wherein the nanobubbles are negatively charged.

5. The treatment fluid of claim 1 , wherein the nanobubbles comprise a mixture of positive and negative charges.

6. The treatment fluid of claim 1, wherein the nanobubble dispersion is present in the treatment fluid in a concentration of about 0.1% w / v to about 20% w / v.

7. The treatment fluid of claim 1, wherein the nanobubbles envelop a gas selected from the group consisting of air, oxygen, carbon dioxide, nitrogen, hydrogen, argon, ammonia, chlorine, or any combination thereof.

8. The treatment fluid of claim 1, wherein the polysiloxane surfactant comprises the structure:wherein R1is independently selected from a (C1-C5) alkyl; R2is independently selected from the group consisting of -R1and -L'-PE-R3; L1is independently selected from the group consisting of a bond and a (Ci-Cs)alkylene; PE is -(O-R4)n-O-; R4is independently a substituted or unsubstituted (C1-C5) alkylene; R3is independently selected from the group consisting of - H, methyl, and ethyl; and the variable n is about 1 to about 100,000.

9. The treatment fluid of claim 1, wherein the Gemini surfactant comprises two polar heads individually selected from the group consisting of quaternary alcohols, quaternary alkoxylated alcohols, and quaternary amine salts; wherein the Gemini surfactant further comprises two hydrophobic tails individually selected from the group consisting of linear or branched carbon chains containing 1 - 25 methylene units, cyclized alkyl-moieties, alkenyl- moieties, bis-alkynyl- moieties, and bis-aryl-moieties; wherein the Gemini surfactant further comprises a spacer that links either the polar heads together or the hydrophobic tails together; wherein the spacer is selected from the group consisting of bis-functionalized alkyl-, alkenyl-, alkynyl-, and aryl-moieties.

10. The treatment fluid of claim 1, wherein the polysiloxane surfactant is present in the treatment fluid in a concentration of about 0.0001% w / w to about 10% w / w.

11. The treatment fluid of claim 1, wherein the Gemini surfactant is present in the treatment fluid in a concentration of 0.0001% w / w to about 10% w / w.

12. The treatment fluid of claim 1, wherein the treatment fluid is substantially free of a fluorocarbon surfactant.

13. A method for treating a subterranean formation, the method comprises:introducing a treatment fluid into a wellbore penetrating the subterranean formation, the treatment fluid comprising: an aqueous base fluid, a polysiloxane surfactant, a Gemini surfactant, and a nanobubble dispersion comprising a plurality of nanobubbles; contacting a hydrocarbon gas in the subterranean formation with the treatment fluid.

14. The method of claim 13, further comprising altering the wettability of a rock face of the subterranean formation.

15. The method of claim 13, wherein the nanobubbles comprise a mean diameter between about 50 nm to about 1000 nm.

16. The method of claim 13, wherein the treatment fluid is substantially free of a fluorocarbon surfactant.

17. A system for drilling a wellbore, the system comprises: a treatment fluid comprising: an aqueous base fluid, a polysiloxane surfactant, a Gemini surfactant, and a nanobubble dispersion comprising a plurality of nanobubbles; mixing equipment configured to mix the aqueous base fluid, the polysiloxane surfactant, the Gemini surfactant, and the nanobubble dispersion; and pumping equipment configured to pump the treatment fluid in the wellbore.

18. The system of claim 17, wherein the nanobubbles comprise a mean diameter between about 50 nm to about 1000 nm.

19. The system of claim 17, wherein the nanobubbles have a population size of about 1 million to about 100 million per mL of the treatment fluid.

20. The system of claim 17, wherein the treatment fluid does not comprise a fluorocarbon surfactant.