Charge shielding nanobubbles for corrosion inhibition

Abstract

A variety of oil and gas components can be made of a material that is corrodible. The components can be part of an oil or gas operation such as oil and gas production operations or refinery operations. A fluid can be used to reduce or prevent corrosion on corrodible surfaces of the components. The fluid can include a base fluid and a plurality of nanobubbles. The fluid can also include a corrosion inhibitor. The nanobubbles can make the corrosion inhibitor compatible in the fluid. The nanobubbles can also reduce or prevent corrosion on the surface without the use of a corrosion inhibitor.

Description

CHARGE SHIELDING NANOBUBBLES FOR CORROSION INHIBITIONTechnical Field

[0001] Corrosion inhibitors can be used to mitigate or prevent corrosion in oil and gas equipment such as for use in oil and gas operations or refinery operations. Corrosion inhibitors can be incompatible in a fluid. Nanobubbles can be used to make corrosion inhibitors compatible or the nanobubbles can protect surfaces from fluid additives or corrosive species in the fluid that cause corrosion.Brief Description of the Figures

[0002] The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the embodiments.

[0003] Fig. l is a diagram illustrating charge shielding using nanobubbles according to certain embodiments.

[0004] Fig. 2 is a diagram illustrating a treatment fluid delivery system according to certain embodiments.Detailed Description of the Invention

[0005] Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil and / or gas is referred to as a reservoir. A reservoir can be located under land or offshore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from a reservoir is called a reservoir fluid.

[0006] As used herein, a “fluid” is a substance having a continuous phase that can flow and conform to the outline of its container when the substance is tested at a temperature of71 °F (22 °C) and a pressure of one atmosphere "atm" (0.1 megapascals "MPa"). A fluid can be a liquid, gas, or a supercritical fluid. A homogenous fluid has only one phase; whereas a heterogeneous fluid has more than one distinct phase. A colloid is an example of a heterogeneous fluid. A heterogeneous fluid can be a slurry, which includes a continuous liquid phase and undissolved solid particles as the dispersed phase; an emulsion, which includes a continuous liquid phase and at least one dispersed phase of immiscible liquid droplets; a foam, which includes a continuous liquid phase and a gas as the dispersed phase; or a mist, which includes a continuous gas phase and liquid droplets as the dispersed phase. As used herein, the term "base fluid" means the solvent of a solution or the continuous phase of a heterogeneous fluid and is the liquid that is in the greatest percentage by volume of a treatment fluid.

[0007] A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, deviated, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. As used herein, “into a subterranean formation” means and includes into any portion of the well, including into the wellbore, into the near-wellbore region via the wellbore, or into the subterranean formation via the wellbore.

[0008] A portion of a wellbore can be an open hole or cased hole. In an open-hole wellbore portion, a tubing string can be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include but are not limited to the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore.

[0009] During wellbore operations, it is common to introduce a treatment fluid into the well. Examples of common treatment fluids include, but are not limited to, drilling fluids, spacer fluids, completion fluids, and stimulation fluids. As used herein, a treatment fluid is a fluid designed and prepared to resolve a specific condition of a well or subterranean formation,such as for stimulation, isolation, gravel packing, or control of gas or water coning. The term “treatment fluid” refers to the specific composition of the fluid as it is being introduced into a well. The word “treatment” in the term “treatment fluid” does not necessarily imply any particular action by the fluid.

[0010] Many components used in an oil and gas operation are made from metals or metal alloys. These components are susceptible to corrosion. Corrosion is the erosion of metals due to a chemical reaction. Corrosion can occur in a variety of ways, for example, when the metal is exposed to oxygen in the surrounding environment or when the metal is in contact with a fluid having a low enough pH, for example a pH in the acidic range. Furthermore, organic species found in hydrocarbon streams contain various species that do not necessarily lower the pH of an aqueous fluid but are still corrosive to metallic structures, namely naphthenic acid(s). Another way to characterize the corrosivity of a hydrocarbon fluid stream is by the total acid number (TAN) because sometimes it is not practical or even feasible to fully characterize the chemical make-up of a fluid stream that can contain several different chemical constituents. Corrosion of metal well components can be quite detrimental to oil or gas operations. Other types of equipment, such as pipelines, refinery equipment, boilers, separators, contactors, transfer lines, and tubing are susceptible to corrosion. The equipment subsequently exposed to these fluids can lead to corrosion if no special actions are taken, such as passivating the surface or inhibiting the corrosiveness of the fluid.

[0011] Oil and gas treatment fluids that come in contact with wellbore equipment or fluids coming in contact with other types of equipment (collectively “equipment”) can include a variety of additives, such as scale inhibitors, macromolecules, polymers, scavengers for hydrogen sulfide or oxygen, halide ions (e.g., F, Cl, Br, and I), multivalent ions (e.g., Ca, Mg, Fe, Ba, Sr, Ni, and Mn), and naturally found acids such as naphthenic acids or volatile organic acids such as acetic acid. By way of example, a treatment fluid can include a scale inhibitor to reduce or eliminate scale formation or to remove scale build-up. Some scale inhibitors can function to lower the pH of the fluid. This lower pH can help prevent scale formation or "eat" away scale build-up. Other types of scale inhibitors do not lower the pH, but still function as a scale inhibitor. However, it is not uncommon for many of these additives to cause corrosion to equipment. By way of example, a treatment fluid that contains certain types of scale inhibitors or an acid can have a low enough pH such that corrosion occurs. By way of another example, atreatment fluid containing an ester, such as a formate or source of formic acid can cause corrosion. Formic acid can be produced from an ester formate, which is an ester of formic acid. In certain downhole operations, formates, acetates, lactates, and glycolates, are commonly used in treatment fluids as a weighting agent to increase the density of the treatment fluid. However, these formates can cause corrosion because addition of the formate, upon hydrolysis, can lower the pH of the treatment fluid.

[0012] Moreover, the pH of the treatment fluid can achieve a pH lower than formic acid’s pKa when a fluid containing an acid, a complexing agent, or a chelating agent of a lower acidic pH or lower pKa is introduced into an acid gas well or sour gas well. An acid gas well is a well containing high amounts of an acid gas, such as carbon dioxide gas, and a sour gas well is a well containing high amounts of a sour gas, such as hydrogen sulfide gas. The pH of a treatment fluid containing acid additives such as a formate can decrease substantially if the fluid is introduced into an acid gas well or sour gas well. It can be difficult to predict the exact amount, if any, of carbon dioxide or hydrogen sulfide present in a particular well. Therefore, a corrosion inhibitor may be included in treatment fluids to mitigate or prevent corrosion.

[0013] Corrosion inhibitors are interfacial agents that can act in the liquid phase or in a gas or vapor phase. Most corrosion inhibitors used in a liquid phase can be cationic or anionic. The most effective corrosion inhibitors that are used in acidizing treatments are typically a mixed type whose mode of action is primarily by adsorption onto the metal substrate. A liquid cathodic inhibitor can act by way of precipitating onto a substrate or by ‘poisoning’ the substrate. Poisoning refers specifically to chemical deactivation, rather than other mechanisms of metal degradation such as thermal decomposition or physical damage. A mixed corrosion inhibitor can have multiple modes of action, namely physical, chemical, and film-forming. Film forming is generally the most effective way of preventing corrosion in acidizing fluids. In operations other than an acidizing treatment operation, such as inhibition treatments of fluids contacting surface installations and equipment, all types of corrosion inhibitors have applicability. Another class of corrosion inhibitors is scavengers, which have a different mode of operation - namely by chemically reacting with a corrosive species primarily in a condensed phase medium and not on the substrate itself.

[0014] Additives such as a corrosion inhibitor, scale control additive, weighting agent, etc. can have opposing charges (z.e., a first additive can have a positive charge and asecond additive can have a negative charge). One significant disadvantage is that due to the composition of the fluid and the charges of the additives, some additives can be incompatible or become unstable in the fluid. By way of example, the stability of an additive, whether it be the additive’s miscibility, solubility, or dispersibility, across various factors such as the pH of the fluid; or the polarity of organic solvents, mutual solvents, or co-solvents, inorganic salts or electrolytes, non-polar organic solvents, and surfactants, within the fluid is parametrically complex. The functionality (i.e., the additive’s ability to perform its function) and efficiency are highly dependent on the stability of the combination of the ingredients in the fluid.Incompatibility or instability of the additives within the fluid leads to decreased functionality and efficiency.

[0015] Thus, there is a long-felt need for increasing the compatibility and stability of fluids used for corrosion inhibition. It has been discovered that the inclusion of nanobubbles can increase the compatibility, stability, functionality, and efficiency of additives such as corrosion inhibitors. The inclusion of nanobubbles can also provide corrosion inhibition without the need for a corrosion inhibitor to be included in the fluid. Some of the many advantages to the use of nanobubbles is that an increase in compatibility or stability of corrosion inhibitors can occur, the concentration of the corrosion inhibitor can be decreased compared to fluids without the nanobubbles, additional additives that improve the compatibility of the corrosion inhibitor are not needed, and a corrosion inhibitor may not be needed as the nanobubbles provide the desired corrosion inhibition.

[0016] A system can include: an oil or gas component, wherein the oil or gas component comprises a surface that is corrodible; and a fluid in contact with the surface, wherein the fluid comprises: a base fluid; and a plurality of nanobubbles, wherein the fluid reduces or prevents corrosion to the surface.

[0017] Methods of reducing or preventing corrosion to an oil or gas component can include contacting the oil or gas component with the fluid, wherein the oil or gas component comprises a surface that is corrodible; and causing or allowing the fluid to reduce or prevent corrosion on the surface.

[0018] It is to be understood that the discussion of any of the embodiments regarding the oil or gas component or the fluid or any ingredient in the fluid is intended to apply to all ofthe system and method embodiments without the need to repeat the various embodiments throughout. Any reference to the unit “gallons” means U.S. gallons.

[0019] The oil or gas component can be any component that is used in oil and gas operations and has a surface that is corrodible. The oil and gas operation can be but is not limited to oil and gas production operations such as an oil and gas drilling operation, water injection operation, gas injection, waterflood operation, enhanced oil recovery operation, water- alternating-gas operations, fracturing operation, workover operation, acidizing operation, surface production fluid separation operation, or a refinery operation such as crude distillation, vacuum distillation, and treatment operations. The component can be without limitation a tubing string; a casing string; coil tubing; a downhole tool such as electronic submersible pumps, valves, artificial gas lift equipment, sand screens, sleeves, inflow control devices, pressure gauges, packers, autonomous control valves, bottomhole assembly units (BHA), perforating guns, wireline tools and devices; coiled tubing tools such as jetting devices; oil and gas pipelines; refinery equipment such as boilers, separators, contactors, crude distillation units, vacuum distillations units, furnaces; transfer lines; or post-production tubing. As used herein, a “downhole tool” means a tool that is used in oil and gas production operations. As used herein, a “refinery operation” means any operation that is used to refine oil or gas that has been produced from a subterranean formation.

[0020] The component has a surface that is corrodible. As used herein, the term “corrodible” means capable of being corroded. The surface can be made of a corrodible metal or metal alloy, for example, iron, copper, aluminum, zinc, nickel, chromium, tin, magnesium, manganese, molybdenum, platinum, titanium, lithium, phosphorous, silicon, or sulfur, or alloys containing any of the foregoing metals, such as martensitic carbon steels, high- or low-alloy steels as defined in API 5CT / ISO 11960, corrosion-resistant alloys (CRA) such as stainless steel, austenitic-ferritic (dual) steel, duplex stainless steel, austenitic alloys including nickel, or titanium alloys such as Grades 5, 7, or 120. As used herein, the term "metal alloy" means a mixture of two or more elements, wherein at least one of the elements is a metal. The other element(s) can be a non-metal or a different metal. An example of a metal and non-metal alloy is steel, comprising the metal element iron and the non-metal element carbon. An example of a metal and metal alloy is bronze, comprising the metallic elements copper and tin. The corrodible surface is one in which corrosion can occur. The type of corrosion can be without limitationgalvanic corrosion, pitting corrosion, microbial corrosion, high-temperature corrosion, crevice corrosion, stress cracking, or corrosion cracking.

[0021] The systems include a fluid in contact with the surface. The methods include contacting the surface with the fluid. The fluid can be a solution, a dispersion, a colloid, an emulsion, a Pickering emulsion, or an invert emulsion. The fluid includes a base fluid. The base fluid can include dissolved materials or undissolved solids. The base fluid can include a hydrocarbon liquid, or an internal phase or external phase of the treatment fluid can include a hydrocarbon liquid. The hydrocarbon liquid can be selected from the group consisting of a fractional distillate of crude oil; a fatty derivative of an acid, an ester, an ether, an alcohol, an amine, an amide, or an imide; a saturated hydrocarbon; an unsaturated hydrocarbon; a branched hydrocarbon; a cyclic hydrocarbon; and any combination thereof. Crude oil can be separated into fractional distillates based on the boiling point of the fractions in the crude oil. An example of a fractional distillate of crude oil is diesel oil. The saturated hydrocarbon can be an alkane or paraffin. The paraffin can be an isoalkane (isoparaffin), a linear alkane (paraffin), or a cyclic alkane (cycloparaffin). The unsaturated hydrocarbon can be an alkene, alkyne, or aromatic. The alkene can be an isoalkene, linear alkene, or cyclic alkene. The linear alkene can be a linear alpha olefin or an internal olefin.

[0022] The base fluid or an internal phase or external phase of the treatment fluid can comprise water. The water can be selected from the group consisting of freshwater, seawater, brine, brackish water, produced water, water refuse from an industrial or energy-generating process such as geothermal energy extraction, and any combination thereof in any proportion. The treatment fluid can further include a water-soluble salt. The water-soluble salt can be selected from the group consisting of sodium chloride, calcium chloride, calcium bromide, potassium chloride, potassium bromide, magnesium chloride, cesium chloride, cesium bromide, an ammonium halide (e.g., ammonium chloride or ammonium bromide), and any combination thereof. The base fluid can include undissolved particles, for example proppant or diverting agent particulates. The fluid can contain the water-soluble salt in a concentration in the range of about 5 to about 350 pounds per barrel (ppb) (19 to 1,353 kilograms per cubic meter "kg / m3") of the water. The salt can cause corrosion to the surface of the oil and gas component.

[0023] The fluid can include a first additive having a charge and a second additive having an opposite charge from the first additive, and wherein the plurality of nanobubblesseparate and shield the first additive from interacting with the second additive. If the first additive and the second additive are not separated and shielded from interacting, then the first and / or second additive can be incompatible in the fluid and thus not able to function for their intended purpose.

[0024] The fluid reduces or prevents corrosion to the surface. As used herein, the term “reduces” and all grammatical variations means decreases the amount of corrosion that occurs on the surface of the oil and gas component than would otherwise occur if a different fluid was used (z'.e., a fluid without the nanobubbles). According to any of the embodiments, the first additive is a corrosion inhibitor. The corrosion inhibitor can be a weak base, a nucleophile, a Lewis donor, or a Pi-donor when the corrosive fluid has a pH > 5.5, a pH > 8.5, a pH > 9.5, or a pH > 10.5. As used herein, the term "weak base" means that a substance that does not ionize completely in an aqueous solution and has a pKa greater than 7 and less than 10. The corrosion inhibitor can be selected from the group consisting of carbonates, bicarbonates, hydroxides, oxides, ethanolamines, and combinations thereof in any proportion. Examples of suitable carbonates include sodium carbonate, potassium carbonate, and cesium carbonate. Examples of suitable bicarbonates include sodium bicarbonate, potassium bicarbonate, and cesium bicarbonate. Examples of suitable hydroxides include potassium hydroxide and magnesium hydroxide. Examples of suitable oxides include manganese oxide and magnesium oxide. Examples of ethanolamines include monoethanolamine (MEA), diethanolamine (DEA), and triethanolamine (TEA). It is believed that MEA may function as a corrosion inhibitor better than DEA or TEA because the overall charge on the amine functional group is stronger with MEA compared to DEA and TEA. The corrosion inhibitor can be selected from the group consisting of an acetylenic compound; cinnamaldehyde; dicinnamaldehyde; p-hydroxycinnamaldehyde; p- methylcinnamaldehyde; p-ethylcinnamaldehyde; p-methoxycinnamaldehyde; p- dimethylaminocinnamaldehyde; p-diethylaminocinnamaldehyde; p-nitrocinnamaldehyde; o- nitrocinnamaldehyde; o-allyloxy cinnamaldehyde; 4-(3-propenal)cinnamaldehyde; p-sodium sulfocinnamaldehyde; p-trimethylammoniumcinnamaldehyde sulfate; p- trimethylammoniumcinnamaldehyde; o-methylsulfate; p-thiocyanocinnamaldehyde; p-(S- acetyl)thiocinnamaldehyde; p-(S-N,N-dimethylcarbamoylthio)cinnamaldehyde; p- chlorocinnamaldehyde; a-methylcinnamaldehyde; (P-methylcinnamaldehyde; a- chlorocinnamaldehyde; a-bromocinnamaldehyde; a-butylcinnamaldehyde; a-amylcinnamaldehyde; a-hexylcinnamaldehyde; a-bromo-p-cyanocinnamaldehyde; a-ethyl-p- methylcinnamaldehyde; p-methyl-a-pentylcinnamaldehyde; cinnamal oxime; cinnamonitrile; 5- phenyl-2,4-pentadienal; 7-phenyl-2,4,6-heptatrienal; aldehyde oligomers and mixtures thereof; a compound comprising at least one quaternary ammonium compound wherein one or more additional compounds are selected from the group consisting of unsaturated carbonyl compounds, unsaturated ether compounds, unsaturated alcohols, condensation products formed by reacting an aldehyde in the presence of a carbonyl compound and condensation products formed by reacting an aldehyde in the presence of a carbonyl compound and a nitrogen containing compound; or acetylenic alcohol selected from the group of 2-methyl-3-butyn-2-ol, 4- methyl-l-pentyn-3-ol, l-hexyn-3-ol, 4-ethyl-l-octyn-3-ol, propargyl alcohol, ethoxylated propargyl alcohol, propoxylated propargyl alcohol, benzylbutynol, 1-ethynylcyclohexanol, 5- decyne-4,7-diol, and mixtures thereof. The corrosion inhibitor can be a corrosion inhibitor for strong acids (e.g., HC1, HNO3, methanesulfonic acid, or chloroacetic acid), or for acids that are weaker acids (e.g., H3PO4, formic acid, acetic acid, lactic acid, citric acid, gluconic acid, glycolic acid, urea hydrochloride complexes, or amino acid hydrochloride complexes referred to as retarded HC1 acids). Corrosion inhibitors for acidic fluids or acidizing fluids include without limitation quaternary ammonium compounds and derivatives, compounds having moi eties selected from aldehyde, ketone, thio, aromatic, heterocyclic, fused heterocyclic, polyaromatic, or polythio moi eties, and macromolecules having a molecular weight less than 120,000 grams per mole (g / mol).

[0025] The corrosion inhibitor can be incompatible in the base fluid or incompatible with other additives in the fluid, such as the second additive. As used herein, the term “incompatible” means the fluid does not form a stable homogenous mixture and it separates at a temperature of -20°C to 250° (-4°F to 482°F) within 24 hours. As used herein, the term “compatible” means the fluid forms a stable homogenous mixture that does not separate at a temperature of -20°C to 250° (-4°F to 482°F) for 24 hours or longer.

[0026] A test treatment fluid can be used to determine the predicted performance of whether the nanobubbles provide the desired additive compatibility. As used herein, a “test treatment fluid” means a test fluid consisting of identical ingredients and in the same concentration as the acidizing fluid. As used herein, a “control test fluid” means a fluid consisting of identical ingredients except without the nanobubbles and in the same concentrationas the test treatment fluid. Different test treatment fluids can also be tested to determine the efficiency and performance of the additive with the nanobubbles compared to a control or other fluids without the nanobubbles that require a higher concentration of the additive to match the efficiency and performance of the test treatment fluids. It is to be understood that while the fluid can contain other ingredients, it is the nanobubbles that are primarily or wholly responsible for providing the requisite compatibility of the additive in the base fluid. Therefore, it is not necessary for the fluid to include other additives, such as stabilizing additives to provide the desired compatibility. It is also to be understood that any discussion related to a “test treatment fluid” or “control test treatment fluid” is included for purposes of demonstrating that the fluid can contain other ingredients, but it is the nanobubbles that create the desirable additive compatibility. Therefore, while it may not be possible to perform a test in a wellbore for the specific fluid being used, one can formulate a test treatment fluid to be tested in a laboratory to identify if the ingredients and concentration of the ingredients will provide the stated compatibility. According to any of the embodiments, a test treatment fluid consisting of the base fluid, a corrosion inhibitor, and the nanobubbles and in the same proportions as the fluid has an efficiency level that is greater than that of a control test treatment fluid consisting of only the base fluid and the corrosion inhibitor and in the same proportions as the fluid. The test treatment fluid and the control test treatment fluid can also include an additive having an opposite charge than the corrosion inhibitor. That is, at the same concentration of the corrosion inhibitor, the nanobubbles allow the corrosion inhibitor to be more effective at preventing corrosion to the corrodible surface than a fluid without the nanobubbles.

[0027] The fluid can include a second additive in addition to the corrosion inhibitor. The second additive can have an opposite charge to that of the corrosion inhibitor. By way of example, the corrosion inhibitor can be anionic (negatively charged) and the second additive can be cationic (positively charged). The opposing charges of the corrosion inhibitor and the second additive can render the corrosion inhibitor incompatible in the fluid. According to any of the embodiments, the corrosion inhibitor is compatible in a test treatment fluid consisting of the base fluid, the corrosion inhibitor, optionally the second additive, and the nanobubbles and in the same proportions as the fluid compared to a control test treatment fluid consisting of only the base fluid, the corrosion inhibitor, and optionally the second additive without the nanobubblesand in the same proportions as the fluid wherein the corrosion inhibitor is not compatible in the control test treatment fluid.

[0028] The base fluid can have a pH in a range of -2 to 12 prior to or during contact with the surface of the oil or gas component. A fluid in the acidic range (z.e., having a pH less than 7) can cause corrosion to the surface of the oil and gas component. The second additive can be an acid. The acid can be used as a scale inhibitor or a scale dissolver or an acidizing fluid used in subterranean operations such as acidizing treatments used in downhole clean-outs, workover, or stimulation operations. Examples of acids include but are not limited to inorganic acids or mineral acids, and organic acids. The inorganic or mineral acid can be selected from the group consisting of hydrochloric acid, hydrobromic acid, hydroiodic acid, boric acid, phosphoric acid, phosphonic acid, polyphosphoric acid, hydrofluoric acid, hypochlorous acid, chlorous acid, formic acid, sulfuric acid, sulfurous acid, sulfamic acid, nitric acid. Organic acids may possess a lower reactivity than strong inorganic acids (such as HC1, HNO3) and can require a lower loading of the additive. According to any of the embodiments, the organic acid is selected from the group consisting of acetic acid, chloroacetic acid, di chloroacetic acid, trichloroacetic acid, methanesulfonic acid, citric acid, maleic acid, glycolic acid, lactic acid, malic acid, oxalic acid, gluconic acid, succinic acid, tartaric acid, thioglycolic acid, tri fluoroacetic acid, propionic acid, methanesulfonic acid, formic acid, hydroiodic acid, N-(phosphonomethyl)iminodiacetic acid, a salt of N-(phosphonomethyl)iminodiacetic acid, a phosphonic acid, a salt of a phosphonic acid, any organic acid having a pKa constant less than or equal to 5.5, and combinations thereof in any proportion.

[0029] The acid can be a delayed acid or a retarded acid. As used herein, a “delayed acid” means any molecule or ion that cannot function as an acid (i.e., donate a proton) before contact with the surface of the oil and gas component, but rather functions as an acid at the time of contact with the surface of the oil and gas component. As used herein, a “retarded acid” is an acid in solution whose reactivity is slowed by addition of artificial gums or thickening agents, so that the acid penetrates deeper into a formation before being spent. A delayed acid can be, for example, encapsulated such that the encapsulating material dissolves or erodes after a desired period of time to release the acid, contained within an internal phase dispersed or emulsified in a bulk transport fluid, that then coalesces or inverts to release the acid, or an acid precursor. As used herein, an "acid precursor" is an organic compound (e.g., an ester of orthoformate or amide)that hydrolyzes and forms an acid in the presence of water. The acid precursor hydrolyzes when in contact with water, and / or as a function of temperature, or due to acid or base attack.

[0030] In some examples, when the acid is hydrofluoric acid, then the fluid can include hydrofluoric acid generating compounds that can be used as a delayed HF source. Examples of hydrofluoric acid-generating compounds or precursors include, but are not limited to, fluoroboric acid, fluorosulfuric acid, hexafluorophosphoric acid, hexafluoroantimonic acid, difluorophosphoric acid, hexafluorosilicic acid, potassium hydrogen difluoride, sodium hydrogen difluoride, polyvinylammonium fluoride, polyvinylpyridinium fluoride, pyridinium fluoride, imidazolium fluoride, ammonium fluoride, tetrafluoroborate salts, hexafluoroantimonate salts, hexafluorophosphate salts, bifluoride salts (e.g., ammonium bifluoride), perfluorinated organic compounds, boron trifluoride, and boron trifluoride complexes, derivatives thereof, and any combination thereof.

[0031] A delayed acid precursor can include, but is not limited to, esters, aliphatic polyesters, orthoesters, poly(orthoesters), poly(lactides), poly(glycolides), poly(s-caprolactones), poly(hydroxybutyrates), poly(anhydrides), ethylene glycol monoformate, ethylene glycol diformate, diethylene glycol diformate, glyceryl monoformate, glyceryl diformate, glyceryl triformate, triethylene glycol diformate, formate esters of pentaerythritol, any derivative of the foregoing, and any combinations thereof. A delayed acid precursor can be by way of one nonlimiting example, an ester of a carboxylic acid. The carboxylic acid can be, without limitation, formic acid, lactic acid, acetic acid, propionic acid, tartaric acid, or any aliphatic or aromatic acid. The acid generating inert agent used to generate the hydrofluoric acid solution is a sulfonate ester and the acid generating activator used to generate the hydrofluoric acid solution is a fluoride salt, wherein the sulfonate ester is selected from the group consisting of a methyl p- toluenesulfonate; an ethyl p-toluenesulfonate; a methyl o-toluenesulfonate; an ethyl o- toluenesulfonate; a methyl m-toluenesulfonate; an ethyl m-toluenesulfonate; a methyl methanesulfonate; an ethyl methanesulfonate; an any combinations thereof, and wherein the fluoride salt is selected from the group consisting of an ammonium fluoride; an ammonium bifluoride; a potassium fluoride; a potassium bifluoride; a sodium fluoride; a sodium bifluoride; a lithium fluoride; a lithium bifluoride; a rubidium fluoride; a rubidium bifluoride; a cesium fluoride; a cesium bifluoride; and any combinations thereof. The acid generating inert agent used to generate the hydrochloric acid solution is a sulfonate ester and the acid generatingactivator used to generate the hydrochloric acid solution is a chloride salt, wherein the sulfonate ester is selected from the group consisting of a methyl p-toluenesulfonate; an ethyl p- toluenesulfonate; a methyl o-toluenesulfonate; an ethyl o-toluenesulfonate; a methyl m- toluenesulfonate; an ethyl m-toluenesulfonate; a methyl methanesulfonate; an ethyl methanesulfonate; and any combinations thereof, and wherein the chloride salt is selected from the group consisting of an ammonium chloride; a potassium chloride; a sodium chloride; a lithium chloride; a cesium chloride; and any combinations thereof.

[0032] The concentration of the acid, retarded acid, or delayed acid can be in the range of 1% to 35% weight by weight of the base fluid “w / w,” alternatively 5% to 25% w / w.

[0033] The second additive can also be without limitation synthetic polymers, scale control additives, scale dissolving additives, fluid loss control additives, gas, catalysts, clay control agents, biocides, friction reducers, iron control agents, antifoam agents, bridging agents, dispersants, hydrogen sulfide (H2S) scavengers, carbon dioxide (CO2) scavengers, oxygen scavengers, lubricants, viscosifiers, breakers, weighting agents, inert solids, emulsifiers, emulsion thinners, emulsion thickeners, surfactants, lost circulation additives, pH control additives, buffers, crosslinkers, stabilizers, chelating agents, mutual solvents, oxidizers, reducers, consolidating agents, complexing agents, particulate materials, and any combinations thereof. The fluid can also include a third, fourth, fifth, and so on additional additives. The additional additives can be compatible in the fluid.

[0034] The fluid also includes a plurality of nanobubbles. The nanobubbles are mechanically generated in the absence of any surfactants by mechanically agitating a gas with the base fluid prior to introduction or as the acidizing fluid is being introduced into the subterranean formation. The nanobubbles can have a nanometer droplet resonance time of 24 days under ambient conditions (z.e., a temperature of 71°F (21.7°C) and a pressure of 1 atmosphere). The nanobubbles can have a mean diameter ranging from 50 to 500 nanometers (nm), preferably 50 to 400 nm. The nanobubbles can have a population ranging from 1 to 100 million nanometer-sized bubbles per milliliter of the base fluid. The gas used to form the nanobubbles can be selected from air, carbon dioxide, nitrogen, a single type of hydrocarbon gas (e.g., methane or propane), a mixture of different types of hydrocarbon gases, hydrogen gas, inert gases such as argon, or reactive gases such as oxygen, ammonia gas, chlorine dioxide (CIO2),bromine gas (Br2), fluorine gas (F2), chlorine monofluoride (C1F), ozone (O3), nitrous oxide (N2O), nitric oxide (NO), nitrogen dioxide (NO2), chlorine gas, or mixtures thereof.

[0035] As discussed above, the corrosion inhibitor can be incompatible in the fluid or incompatible with the second additive without the nanobubbles. Such incompatibility can be the result of decreased solubility in the base fluid, which can lead to a loss of some of the corrosion inhibitor being able to function as intended. In other words, to be effective and functional, the corrosion inhibitor may need to dissolve in the base fluid. Accordingly, if only a small amount of the total amount of the corrosion inhibitor does solubilize in the base fluid, then the corrosion inhibitor can be said to be incompatible and ineffective and poorly functional. Therefore, to overcome such incompatibility, ineffectiveness, and poor functionality, a much higher total concentration of the corrosion inhibitor may be needed.

[0036] The nanobubbles can make the corrosion inhibitor compatible in the fluid. According to any of the embodiments, the nanobubbles provide a charge shielding function. Fig. 1 illustrates the charge shielding capability of the nanobubbles. As can be seen, without the nanobubbles agglomeration of the oppositely charged corrosion inhibitor and the second additive can occur. This agglomeration can adversely affect the miscibility, stability, solubility, and / or dispersibility of the corrosion inhibitor in the fluid as well as adversely affecting the miscibility, stability, solubility, and / or dispersibility of the second additive. Accordingly, the corrosion inhibitor and the second additive are not available to perform their intended function, or the concentration of the corrosion inhibitor and second additive may need to be increased, or additional additives may be required to stabilize the fluid. However, and as can be seen, with the addition of the nanobubbles, the charges of the nanobubbles can separate and shield the oppositely charged corrosion inhibitor from interacting with the opposing charged second additive. In some instances, the corrosion inhibitor can be negatively charged, and the second additive can be positively charged. In other instances, the corrosion inhibitor can be positively charged, and the second additive can be negatively charged. The nanobubbles can coalesce and cavitate before or during fluid contact with the surface of the oil and gas component. Cavitation can occur by a rapid movement of a fluid away from a surface that creates a "vacuum." Upon cavitation, the corrosion inhibitor and the second additive are freed up to perform their intended function. In this manner, the corrosion inhibitor is now available to reduce or prevent corrosion to the surface of the oil and gas component.

[0037] According to any of the embodiments, the fluid may be a fluid that is not a foam. As used herein, a “foam” is a gas dispersed in a liquid in a ratio such that its bulk density approaches that of gas rather than liquid and is stabilized by a surfactant. By contrast, the nanobubbles are an artifact of mechanical agitation and are sustained in the base fluid motion and droplet size without the use of a surfactant. Other key differences between a foam and the nanobubbles is the droplet size of the nanobubbles is smaller than the droplet size of a foam, and the physical phenomena for nanobubbles is attributed to Brownian motion, whereas the physical phenomena associated with foams is attributed to buoyancy. According to any of the embodiments, the fluid may be substantially free of a surfactant.

[0038] The nanobubbles create an increased surface area for the additives in the fluid. The increased surface area created by the nanobubbles can not only make the corrosion inhibitor compatible with the fluid but can also decrease the total concentration of corrosion inhibitor that is needed to be effective. The increased surface area of nanobubbles can also decrease the concentration of the second additive and additional additives that are optionally included in the fluid.

[0039] According to any of the embodiments, the nanobubbles themselves reduce or prevent corrosion to the surface of the oil and gas component without needing to include a corrosion inhibitor in the fluid. According to these embodiments, the charge shielding capability of the nanobubbles can shield the surface of the oil and gas component from charged ions that would otherwise cause corrosion to the surface. Accordingly, the nanobubbles can provide corrosion inhibition without the need to include a separate corrosion inhibitor. By way of example, in a brine, saltwater, or seawater fluid having salt-charged cations as an electrolyte, corrosion occurs through electrochemical reactions at the interface between the metal and the electrolyte. When an oxidizing agent (z.e., the nanobubble with stabilized latent radicals) comes into contact with the metal, then electrons are transferred due to the potential difference. The reaction in which the metal loses electrons is called the “anodic reaction,” while the process in which the oxidizing agent gains the electrons from the metal is called the “cathodic reaction.” Accordingly, the nanobubbles themselves can reduce or prevent corrosion without needing a separate corrosion inhibitor.

[0040] The nanobubbles can effectively create a passivating layer on the surface of the oil and gas component. Established processes implement passivation of metallic substratesas a finishing process to prevent corrosion. In general, for stainless steel for example, the passivation process can occur after removal of corrosion from a substrate, for example by using an agent, such as nitric acid or citric acid, to remove free iron from the surface after which a protective oxide layer or passivation film is formed spontaneously. Passivation treatments require very large volumes of liquid treating solutions for the intended applications (e.g., pipelines, refineries, chemical plants, or transport and storage vessels). Passivation can be defined as the incorporation of exogenous materials that protect the surface of a corrodible metal or metal alloy by means of a chemical inhibitor, most typically by a treatment with an inhibitor solution that will remove the surface contamination and will not significantly affect the corrodible metal or metal alloy itself for the purpose of enhancing the spontaneous formation of the protective passive film. Accordingly, passivation can be thought of as controlled corrosion, that is, the acid bath dissolves, or corrodes, free iron at the surface in a uniform, controlled manner. However, when not controlled properly, runaway corrosion can occur in a phenomenon known as “flash attack.” In flash attack, the metal develops a dark, heavily etched surface, known as pitting corrosion, which is exactly the corrosion that the passive layer is intended to prevent. The nanobubbles have an inherent charge distribution, and as such, they will be able to aggregate at, and adsorb to surfaces. As an example, if the metal surface has a layer of ironoxide, then nanobubbles with some positive charge can adsorb to the surface due to electrostatic attraction. Accordingly, the nanobubbles can deliver the same benefit of passivating the surface of a metallic substrate without or with a lower fraction of active (passivating agent) due to the enhanced transport properties of nanobubble fluids and its physicochemical characteristics. According to these embodiments, the fluid can include the base fluid, the nanobubbles, and optionally a passivating agent, which can be intrinsically generated within the nanobubbles or further added for enhanced usage. The passivating agent can be a corrosion inhibitor. The passivating agent can be in a concentration in a range of 0.5 to 60 gallons per thousand gallons (gpt) of base fluid.

[0041] A well system 10 of Fig. 2 can include a fluid producing apparatus 20, a fluid source 30, an additive source 40, and a pump and blender system 50 and resides at the surface at a well site where a well 60 is located. In certain embodiments, the fluid producing apparatus 20 can combine additives with a fluid (e. ., liquid or substantially liquid) from fluid source 30, to produce a fluid that is used to in an oil or gas operation. The fluid can be a fluid for ready use intreatment of the well 60 or a concentrate to which additional fluid is added prior to use in treatment of the well 60. In other instances, the fluid producing apparatus 20 can be omitted and the fluid sourced directly from the fluid source 30.

[0042] The additive source 40 can include an additive, such as the corrosion inhibitor, for combining with a base fluid. The system may also include a second additive source 70 that provides one or more additional additives (e.g., friction reducers, surfactants, viscosifiers, and / or other optional additives) to alter the properties of the fluid.

[0043] The pump and blender system 50 can receive the fluid and combine it with other components, including additives from the additive source 40 and / or additional additives from the second additive source 70. The resulting mixture may be pumped into the well 60. The fluid producing apparatus 20, fluid source 30, and / or additive sources 40 and 70 can each be equipped with one or more metering devices (not shown) to control the flow of fluids, additives, and / or other compositions to the pumping and blender system 50. Such metering devices may permit the pumping and the blender system 50 to pull from one, some, or all of the different sources at a given time and may facilitate the preparation of fluids using continuous mixing or “on-the-fly” methods.

[0044] An embodiment of the present disclosure is a system comprising: an oil or gas component, wherein the oil or gas component comprises a surface that is corrodible; and a fluid in contact with the surface, wherein the fluid comprises: a base fluid; and a plurality of nanobubbles, wherein the fluid reduces or prevents corrosion to the surface. Optionally, the oil or gas component is used in an oil and gas operation selected from an oil and gas drilling operation, water injection operation, gas injection operation, waterflood operation, enhanced oil recovery operation, water-altemating-gas operation, fracturing operation, workover operation, acidizing operation, or surface production fluid separation operation; or used in a refinery operation selected from crude distillation, vacuum distillation, or treatment operations. Optionally, the component is selected from the group consisting of a tubing string; a casing string; coil tubing; a downhole tool selected from electronic submersible pumps, valves, artificial gas lift equipment, sand screens, sleeves, inflow control devices, pressure gauges, packers, autonomous control valves, bottomhole assembly units, perforating guns, or wireline tools and devices; coiled tubing tools; oil and gas pipelines; refinery equipment selected from boilers, separators, contactors, crude distillation units, vacuum distillations units, and furnaces; transferlines; post-production tubing; and combinations thereof. Optionally, the surface that is corrodible comprises a corrodible metal selected from iron, copper, aluminum, zinc, nickel, chromium, tin, magnesium, manganese, molybdenum, platinum, titanium, lithium, phosphorous, silicon, or sulfur, or comprises a metal alloy of any of the foregoing metals. Optionally, the fluid further comprises a corrosion inhibitor, wherein the corrosion inhibitor is compatible in a test treatment fluid consisting of the base fluid, the corrosion inhibitor, and the nanobubbles and in the same proportions as the fluid; and wherein the corrosion inhibitor is incompatible in a control test treatment fluid consisting of only the base fluid and the corrosion inhibitor and in the same proportions as the fluid. Optionally, the corrosion inhibitor is selected from the group consisting of an acetylenic compound; cinnamaldehyde; dicinnamaldehyde; p-hydroxycinnamaldehyde; p- methylcinnamaldehyde; p-ethylcinnamaldehyde; p-methoxycinnamaldehyde; p- dimethylaminocinnamaldehyde; p-diethylaminocinnamaldehyde; p-nitrocinnamaldehyde; o- nitrocinnamaldehyde; o-allyloxy cinnamaldehyde; 4-(3-propenal)cinnamaldehyde; p-sodium sulfocinnamaldehyde; p-trimethylammoniumcinnamaldehyde sulfate; p- trimethylammoniumcinnamaldehyde; o-methylsulfate; p-thiocyanocinnamaldehyde; p-(S- acetyl)thiocinnamaldehyde; p-(S-N,N-dimethylcarbamoylthio)cinnamaldehyde; p- chlorocinnamaldehyde; a-methylcinnamaldehyde; (P-methylcinnamaldehyde; a- chlorocinnamaldehyde; a-bromocinnamaldehyde; a-butylcinnamaldehyde; a- amylcinnamaldehyde; a-hexylcinnamaldehyde; a-bromo-p-cyanocinnamaldehyde; u-ethyl-p- methylcinnamaldehyde; p-methyl-a-pentylcinnamaldehyde; cinnamaloxime; cinnamonitrile; 5- phenyl-2,4-pentadienal; 7-phenyl-2,4,6-heptatrienal; aldehyde oligomers and mixtures thereof; a compound comprising at least one quaternary ammonium compound wherein one or more additional compounds are selected from the group consisting of unsaturated carbonyl compounds, unsaturated ether compounds, unsaturated alcohols, condensation products formed by reacting an aldehyde in the presence of a carbonyl compound and condensation products formed by reacting an aldehyde in the presence of a carbonyl compound and a nitrogen containing compound; or acetylenic alcohol selected from the group of 2-methyl-3-butyn-2-ol, 4- methyl-l-pentyn-3-ol, l-hexyn-3-ol, 4-ethyl-l-octyn-3-ol, propargyl alcohol, ethoxylated propargyl alcohol, propoxylated propargyl alcohol, benzylbutynol, 1-ethynylcyclohexanol, 5- decyne-4,7-diol, and mixtures thereof. Optionally, the fluid further comprises a second additive, wherein the second additive has an opposite charge from the corrosion inhibitor. Optionally, thefluid further comprises an acid, a delayed acid, or a retarded acid, and wherein the acid has a positive charge, and the corrosion inhibitor has a negative charge. Optionally, the fluid further comprises a first additive having a charge and a second additive having an opposite charge from the first additive, and wherein the plurality of nanobubbles separate and shield the first additive from interacting with the second additive. Optionally, upon cavitation of some or all of the plurality of nanobubbles, the first additive and the second additive perform their intended function. Optionally, the plurality of nanobubbles reduces or prevents corrosion to the surface, and wherein the fluid does not comprise a corrosion inhibitor. Optionally, the plurality of nanobubbles have a nanometer droplet resonance time of 24 days under a temperature of 71 °F (21 ,7°C) and a pressure of 1 atmosphere. Optionally, the plurality of nanobubbles have a mean diameter ranging from 50 to 400 nanometers. Optionally, the plurality of nanobubbles have a population ranging from 1 to 100 million nanometer-sized bubbles per milliliter of the base fluid. Optionally, a gas used to form the plurality of nanobubbles is selected from the group consisting of air; carbon dioxide; nitrogen; a single type of hydrocarbon gas; a mixture of different types of hydrocarbon gases; hydrogen gas; an inert gas; a reactive gas selected from oxygen gas, ammonia gas, chlorine dioxide gas, bromine gas, fluorine gas, chlorine monofluoride gas, ozone, nitrous oxide gas, nitric oxide gas, nitrogen dioxide gas, chlorine gas, and combinations thereof.

[0045] Another embodiment of the present disclosure is a method of reducing or preventing corrosion to an oil or gas component comprising: contacting the oil or gas component with a fluid, wherein the oil or gas component comprises a surface that is corrodible, and wherein the fluid comprises: a base fluid; and a plurality of nanobubbles; and causing or allowing the fluid to reduce or prevent corrosion on the surface. Optionally, the oil or gas component is used in an oil and gas operation selected from an oil and gas drilling operation, water injection operation, gas injection operation, waterflood operation, enhanced oil recovery operation, water-altemating-gas operation, fracturing operation, workover operation, acidizing operation, or surface production fluid separation operation; or used in a refinery operation selected from crude distillation, vacuum distillation, or treatment operations. Optionally, the component is selected from the group consisting of a tubing string; a casing string; coil tubing; a downhole tool selected from electronic submersible pumps, valves, artificial gas lift equipment, sand screens, sleeves, inflow control devices, pressure gauges, packers, autonomous control valves, bottomhole assembly units, perforating guns, or wireline tools and devices; coiled tubingtools; oil and gas pipelines; refinery equipment selected from boilers, separators, contactors, crude distillation units, vacuum distillations units, and furnaces; transfer lines; post-production tubing; and combinations thereof. Optionally, the surface that is corrodible comprises a corrodible metal selected from iron, copper, aluminum, zinc, nickel, chromium, tin, magnesium, manganese, molybdenum, platinum, titanium, lithium, phosphorous, silicon, or sulfur, or comprises a metal alloy of any of the foregoing metals. Optionally, the fluid further comprises a corrosion inhibitor, wherein the corrosion inhibitor is compatible in a test treatment fluid consisting of the base fluid, the corrosion inhibitor, and the nanobubbles and in the same proportions as the fluid; and wherein the corrosion inhibitor is incompatible in a control test treatment fluid consisting of only the base fluid and the corrosion inhibitor and in the same proportions as the fluid. Optionally, the corrosion inhibitor is selected from the group consisting of an acetylenic compound; cinnamaldehyde; dicinnamaldehyde; p-hydroxycinnamaldehyde; p- methylcinnamaldehyde; p-ethylcinnamaldehyde; p-methoxycinnamaldehyde; p- dimethylaminocinnamaldehyde; p-diethylaminocinnamaldehyde; p-nitrocinnamaldehyde; o- nitrocinnamaldehyde; o-allyloxy cinnamaldehyde; 4-(3-propenal)cinnamaldehyde; p-sodium sulfocinnamaldehyde; p-trimethylammoniumcinnamaldehyde sulfate; p- trimethylammoniumcinnamaldehyde; o-methylsulfate; p-thiocyanocinnamaldehyde; p-(S- acetyl)thiocinnamaldehyde; p-(S-N,N-dimethylcarbamoylthio)cinnamaldehyde; p- chlorocinnamaldehyde; a-methylcinnamaldehyde; (P-methylcinnamaldehyde; a- chlorocinnamaldehyde; a-bromocinnamaldehyde; a-butylcinnamaldehyde; a- amylcinnamaldehyde; a-hexylcinnamaldehyde; a-bromo-p-cyanocinnamaldehyde; a-ethyl-p- methylcinnamaldehyde; p-methyl-a-pentylcinnamaldehyde; cinnamal oxime; cinnamonitrile; 5- phenyl-2,4-pentadienal; 7-phenyl-2,4,6-heptatrienal; aldehyde oligomers and mixtures thereof; a compound comprising at least one quaternary ammonium compound wherein one or more additional compounds are selected from the group consisting of unsaturated carbonyl compounds, unsaturated ether compounds, unsaturated alcohols, condensation products formed by reacting an aldehyde in the presence of a carbonyl compound and condensation products formed by reacting an aldehyde in the presence of a carbonyl compound and a nitrogen containing compound; or acetylenic alcohol selected from the group of 2-methyl-3-butyn-2-ol, 4- methyl-l-pentyn-3-ol, l-hexyn-3-ol, 4-ethyl-l-octyn-3-ol, propargyl alcohol, ethoxylated propargyl alcohol, propoxylated propargyl alcohol, benzylbutynol, 1-ethynyl cyclohexanol, 5-decyne-4,7-diol, and mixtures thereof. Optionally, the fluid further comprises a second additive, wherein the second additive has an opposite charge from the corrosion inhibitor. Optionally, the fluid further comprises an acid, a delayed acid, or a retarded acid, and wherein the acid has a positive charge, and the corrosion inhibitor has a negative charge. Optionally, the fluid further comprises a first additive having a charge and a second additive having an opposite charge from the first additive, and wherein the plurality of nanobubbles separate and shield the first additive from interacting with the second additive. Optionally, upon cavitation of some or all of the plurality of nanobubbles, the first additive and the second additive perform their intended function. Optionally, the plurality of nanobubbles reduces or prevents corrosion to the surface, and wherein the fluid does not comprise a corrosion inhibitor. Optionally, the plurality of nanobubbles have a nanometer droplet resonance time of 24 days under a temperature of 71 °F (21.7°C) and a pressure of 1 atmosphere. Optionally, the plurality of nanobubbles have a mean diameter ranging from 50 to 400 nanometers. Optionally, the plurality of nanobubbles have a population ranging from 1 to 100 million nanometer-sized bubbles per milliliter of the base fluid. Optionally, a gas used to form the plurality of nanobubbles is selected from the group consisting of air; carbon dioxide; nitrogen; a single type of hydrocarbon gas; a mixture of different types of hydrocarbon gases; hydrogen gas; an inert gas; a reactive gas selected from oxygen gas, ammonia gas, chlorine dioxide gas, bromine gas, fluorine gas, chlorine monofluoride gas, ozone, nitrous oxide gas, nitric oxide gas, nitrogen dioxide gas, chlorine gas, and combinations thereof.

[0046] Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention 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 embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention.

[0047] As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. While compositions, systems, and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions,systems, and methods also can “consist essentially of’ or “consist of’ the various components and steps. It should also be understood that, as used herein, “first,” “second,” and “third,” are assigned arbitrarily and are merely intended to differentiate between two or more additives, etc., as the case may be, and does not indicate any sequence. Furthermore, it is to be understood that the mere use of the word “first” does not require that there be any “second,” and the mere use of the word “second” does not require that there be any “third,” etc.

[0048] Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is 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. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. 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. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

What is claimed is:

1. A system comprising: an oil or gas component, wherein the oil or gas component comprises a surface that is corrodible; and a fluid in contact with the surface, wherein the fluid comprises: a base fluid; and a plurality of nanobubbles, wherein the fluid reduces or prevents corrosion to the surface.

2. The system according to claim 1, wherein the oil or gas component is used in an oil and gas operation selected from an oil and gas drilling operation, water injection operation, gas injection operation, waterflood operation, enhanced oil recovery operation, water-alternating-gas operation, fracturing operation, workover operation, acidizing operation, or surface production fluid separation operation; or used in a refinery operation selected from crude distillation, vacuum distillation, or treatment operations.

3. The system according to claims 1 or 2, wherein the component is selected from the group consisting of a tubing string; a casing string; coil tubing; a downhole tool selected from electronic submersible pumps, valves, artificial gas lift equipment, sand screens, sleeves, inflow control devices, pressure gauges, packers, autonomous control valves, bottomhole assembly units, perforating guns, or wireline tools and devices; coiled tubing tools; oil and gas pipelines; refinery equipment selected from boilers, separators, contactors, crude distillation units, vacuum distillations units, and furnaces; transfer lines; post-production tubing; and combinations thereof.

4. The system according to any one of claims 1 - 3, wherein the surface that is corrodible comprises a corrodible metal selected from iron, copper, aluminum, zinc, nickel, chromium, tin, magnesium, manganese, molybdenum, platinum, titanium, lithium, phosphorous, silicon, or sulfur, or comprises a metal alloy of any of the foregoing metals.

5. The system according to any one of claims 1 - 4, wherein the fluid further comprises a corrosion inhibitor, wherein the corrosion inhibitor is compatible in a test treatment fluidconsisting of the base fluid, the corrosion inhibitor, and the nanobubbles and in the same proportions as the fluid; and wherein the corrosion inhibitor is incompatible in a control test treatment fluid consisting of only the base fluid and the corrosion inhibitor and in the same proportions as the fluid.

6. The system according to claim 5, wherein the corrosion inhibitor is selected from the group consisting of an acetylenic compound; cinnamaldehyde; dicinnamaldehyde; p- hydroxycinnamaldehyde; p-methylcinnamaldehyde; p-ethylcinnamaldehyde; p- methoxycinnamaldehyde; p-dimethylaminocinnamaldehyde; p-diethylaminocinnamaldehyde; p- nitrocinnamaldehyde; o-nitrocinnamaldehyde; o-allyloxy cinnamaldehyde; 4-(3- propenal)cinnamaldehyde; p-sodium sulfocinnamaldehyde; p- trimethylammoniumcinnamaldehyde sulfate; p-trimethylammoniumcinnamaldehyde; o- methyl sulfate; p-thiocyanocinnamaldehyde; p-(S-acetyl)thiocinnamaldehyde; p-(S-N,N- dimethylcarbamoylthio)cinnamaldehyde; p-chlorocinnamaldehyde; a-methylcinnamaldehyde; (P-methylcinnamaldehyde; a-chlorocinnamaldehyde; a-bromocinnamaldehyde; a- butylcinnamaldehyde; a-amylcinnamaldehyde; a-hexylcinnamaldehyde; a-bromo-p- cyanocinnamaldehyde; a-ethyl-p-methylcinnamaldehyde; p-methyl-a-pentylcinnamaldehyde; cinnamaloxime; cinnamonitrile; 5-phenyl-2,4-pentadienal; 7-phenyl-2,4,6-heptatrienal; aldehyde oligomers and mixtures thereof; a compound comprising at least one quaternary ammonium compound wherein one or more additional compounds are selected from the group consisting of unsaturated carbonyl compounds, unsaturated ether compounds, unsaturated alcohols, condensation products formed by reacting an aldehyde in the presence of a carbonyl compound and condensation products formed by reacting an aldehyde in the presence of a carbonyl compound and a nitrogen containing compound; or acetylenic alcohol selected from the group of 2-methyl-3-butyn-2-ol, 4-methyl-l-pentyn-3-ol, l-hexyn-3-ol, 4-ethyl-l-octyn-3-ol, propargyl alcohol, ethoxylated propargyl alcohol, propoxylated propargyl alcohol, benzylbutynol, 1- ethynylcyclohexanol, 5-decyne-4,7-diol, and mixtures thereof.

7. The system according to claim 5, further comprising a second additive, wherein the second additive has an opposite charge from the corrosion inhibitor.

8. The system according to claim 7, wherein the fluid further comprises an acid, a delayed acid, or a retarded acid, and wherein the acid has a positive charge, and the corrosion inhibitor has a negative charge.

9. The system according to claim 1, wherein the fluid further comprises a first additive having a charge and a second additive having an opposite charge from the first additive, and wherein the plurality of nanobubbles separate and shield the first additive from interacting with the second additive.

10. The system according to claim 9, wherein upon cavitation of some or all of the plurality of nanobubbles, the first additive and the second additive perform their intended function.

11. The system according to claim 1, wherein the plurality of nanobubbles reduces or prevents corrosion to the surface, and wherein the fluid does not comprise a corrosion inhibitor.

12. The fluid according to claim 1, wherein the plurality of nanobubbles have a nanometer droplet resonance time of 24 days under a temperature of 71 °F (21.7°C) and a pressure of 1 atmosphere.

13. The fluid according to claim 1, wherein the plurality of nanobubbles have a mean diameter ranging from 50 to 400 nanometers.

14. The fluid according to claim 1, wherein the plurality of nanobubbles have a population ranging from 1 to 100 million nanometer-sized bubbles per milliliter of the base fluid.

15. The fluid according to claim 1, wherein a gas used to form the plurality of nanobubbles is selected from the group consisting of air; carbon dioxide; nitrogen; a single type of hydrocarbon gas; a mixture of different types of hydrocarbon gases; hydrogen gas; an inert gas; a reactive gas selected from oxygen gas, ammonia gas, chlorine dioxide gas, bromine gas, fluorine gas, chlorine monofluoride gas, ozone, nitrous oxide gas, nitric oxide gas, nitrogen dioxide gas, chlorine gas, and combinations thereof.

16. A method of reducing or preventing corrosion to an oil or gas component comprising: contacting the oil or gas component with a fluid, wherein the oil or gas component comprises a surface that is corrodible, and wherein the fluid comprises: a base fluid; and a plurality of nanobubbles; and causing or allowing the fluid to reduce or prevent corrosion on the surface.

17. The method according to claim 16, wherein the fluid further comprises a first additive having a charge and a second additive having an opposite charge from the first additive, and wherein the plurality of nanobubbles separate and shield the first additive from interacting with the second additive.

18. The method according to claim 17, wherein upon cavitation of some or all of the plurality of nanobubbles, the first additive and the second additive perform their intended function.

19. The method according to claim 18, wherein the first additive is a corrosion inhibitor, wherein the corrosion inhibitor is compatible in a test treatment fluid consisting of the base fluid, the corrosion inhibitor, and the nanobubbles and in the same proportions as the fluid; and wherein the corrosion inhibitor is incompatible in a control test treatment fluid consisting of only the base fluid and the corrosion inhibitor and in the same proportions as the fluid.

20. The method according to claim 19, wherein the second additive is an acid, a delayed acid, or a retarded acid, and wherein the acid has a positive charge, and the corrosion inhibitor has a negative charge.

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