WO2025212096A1

WO2025212096A1 - Additive compatibility in acidizing fluids using nanobubbles

Info

Publication number: WO2025212096A1
Application number: PCT/US2024/023212
Authority: WO
Inventors: Enrique Antonio REYES; Antonio Recio; Kristina Henkel HOLAN; Aaron M BEUTERBAUGH
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2024-04-05
Filing date: 2024-04-05
Publication date: 2025-10-09
Anticipated expiration: 2026-10-05

Abstract

Acidizing fluids can be used in a variety of oil and gas operations such as matrix acidizing, fracture acidizing, and acid washing. Some additives included in acidizing fluids may not be compatible with the fluid at the low pH. A plurality of nanobubbles can be used in the acidizing fluid to increase the additive compatibility.

Description

ADDITIVE COMPATIBILITY IN ACIDIZING FLUIDS USING NANOBUBBLES

Technical Field

[0001] Enhanced recovery of oil or gas from a subterranean formation can utilize stimulation techniques. Stimulation techniques can include fracturing operations and acidizing operations. A fracturing fluid and acidizing fluid can include a variety of additives to provide desirable properties to the stimulation fluids. Nanobubbles can be used to stabilize additives in acidizing fluids.

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 preferred embodiments.

[0003] Fig. l is a diagram illustrating a stimulation system according to certain embodiments.

[0004] Fig. 2 is a diagram illustrating a well system in which a fracturing stimulation operation can be performed.

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 of 71 °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. The near- wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore. 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, fn 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, enhanced oil recovery, chemical squeezes, pressure support floods, 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] Stimulation treatment fluids can include fracturing fluids and acidizing fluids. Stimulation techniques can be used to help increase or restore oil, gas, or water production. As used herein, the term "stimulate" means increasing the permeability of a subterranean formation. One example of a stimulation technique is hydraulic fracturing. In hydraulic fracturing, a fracturing fluid, which can also be an acidizing fluid, is pumped at a sufficiently high flow rate and high pressure through the wellbore and into the near wellbore region to create or enhance a fracture in the subterranean formation. Creating a fracture means making a new fracture or complex fracture network in the formation. Enhancing a fracture means enlarging a pre-existing fracture or fissure in the formation. A frac pump is used to pump the fracturing fluid into the wellbore and formation at high rates and pressures, for example, at a flow rate in excess of the fracture gradient of the subterranean formation.

[0011] A fracturing fluid is commonly a slurry containing undissolved solids, for example proppant, and other dissolved or undissolved additives. A newly created or extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, the proppant is placed in the fracture via the liquid continuous phase of the fluid to keep the fracture propped open.

[0012] Another example of a stimulation technique is an acidizing treatment. There are several types of acidizing treatments. In a first example, matrix acidizing is a stimulation operation performed below the pressure necessary to fracture the formation in an effort to restore the natural permeability of the formation. In matrix acidizing an acid or a delayed acid is used to degrade any filtercake accumulated in the formation, sediments, or mud solids on the wall of the wellbore, on wellbore equipment, and within the pores of the subterranean formation. A matrix acidizing fluid can also be introduced into a reservoir when there is an opportunity to improve fluid injectivity through the generation of higher hydraulic conductivity conduits, referred to as wormholes such as would be observed from carbonate acidizing. Permeability refers to how easily fluids can flow through a material. For example, if the permeability is high, then fluids will flow more easily and more quickly through the subterranean formation. If the permeability is low, then fluids will flow less easily and more slowly through the subterranean formation. A matrix acidizing treatment is performed by pumping an acidic treatment fluid into the well and into the pores of the formation. In this form of acidization, the acidic treatment fluid dissolves the sedimentary materials or minerals as well as mud solids that are decreasing the permeability of the formation; thereby, enlarging the natural pores of the formation and stimulating the flow of oil, gas, or water.

[0013] A second example, fracture acidizing is a stimulation operation performed when an acid or delayed acid is pumped into a well above the fracture gradient of the subterranean formation to fracture and clean the formation. While matrix acidizing is done at a low enough pressure to keep from fracturing the formation, fracture acidizing involves pumping highly pressurized acid or delayed acid into the well; thereby, fracturing the formation and also dissolving the sediments that have decreased permeability. A matrix acidizing fluid may not include proppant; whereas a fracture acidizing fluid may include proppant. A variant of acid fracturing is high-rate matrix acidizing in which the acidizing fluid is pumped at a high flow rate that would normally cause fractures, but the formation has a sufficient permeability, either primary or secondary, that fractures are not created. In these situations, and in order to create fractures, more aggressive measures are implemented to achieve the opening, propagation, or elongation, and propping of fractures.

[0014] Another example of an acidizing treatment is acid washing (also referred to as pickling) where an acid is used to clean tubing strings and wellbore equipment from scale, rust, or other undesirables. As used herein, a “delayed acid” means any molecule or ion that cannot function as an acid (i.e., donate a proton) at the time the fluid is introduced into the well, but rather functions as an acid at some period of time after introduction into the well. It is to be understood that “introduction” means at the wellhead.

[0015] Acidizing fluids contain additives to impart desirable properties to the fluid. Some additives include, but are not limited to, surfactants and corrosion inhibitors. A surfactant can lower the interfacial tension between two liquids or between a solid and a liquid. As such, a surfactant can be used to reduce the surface tension between the solids of a subterranean formation and a treatment fluid. A surfactant can also be used to change the wettability of the surface of solids of a formation. Wettability means the preference of a surface to be in contact with one liquid or gas rather than another. Accordingly, “oil-wet” means the preference of a surface to be in contact with an oil phase rather than a water phase or gas phase, and “water-wet” means the preference of a surface to be in contact with a water phase rather than an oil phase or gas phase. A surfactant can be used to change the wettability of the surface of the solids from being oil-wet to being water-wet. These changes can enhance imbibition causing the treatment fluid to penetrate farther into the formation, thereby degrading or dissolving more filtercake formation, sediments, or mud solids, which increases porosity and permeability of the formation and oil or gas production. Corrosion inhibitors can be used to reduce or eliminate the harmful corrosion of tubing or casing string or wellbore equipment caused by acidic fluids.

[0016] Other additives can also be included in an acidizing fluid. For example, viscosifiers can be used to increase the viscosity of the fluid, and suspending agents can be used to help suspend insoluble particles such as proppant or diverting agent particulates in the base fluid, surfactants, and fluid loss control additives, among others. One significant disadvantage is that due to the very high total acidity (e.g., greater than 5% w/v total acidity) of these treatment fluids, some additives can be incompatible or become unstable in the treatment 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 concentration of an acid; the type of acid; or the polarity of organic solvents, mutual solvents, or co-solvents, inorganic salts or electrolytes, nonpolar organic solvents, and surfactants, within the treatment 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 treatment fluid. Incompatibility or instability of the additive within the fluid leads to decreased functionality and efficiency.

[0017] Thus, there is a long-felt need for increasing the compatibility and stability of additives in acidizing fluids. It has been discovered that the inclusion of nanobubbles can increase the compatibility, stability, functionality, and efficiency of the additives. Some of the many advantages to the use of nanobubbles is that an increase in compatibility or stability of the additive occurs, the concentration of the additive can be decreased compared to acidizing fluids without the nanobubbles, and additional additives that improve the compatibility of the noncompatible additive are not needed. [0018] An acidizing fluid can include: a base fluid, wherein the base fluid comprises water, and wherein the acidizing fluid has or obtains a pH less than or equal to 5.5; an additive; and a plurality of nanobubbles, wherein the additive is compatible in a test treatment fluid having a pH less than or equal to 5.5 and consisting of the base fluid, the additive, and the nanobubbles and in the same proportions as the acidizing fluid; and wherein the additive is not compatible in a control test treatment fluid having a pH less than or equal to 5.5 and consisting of only the base fluid and the additive and in the same proportions as the acidizing fluid.

[0019] Methods of treating a portion of a subterranean formation can include introducing the acidizing fluid into the subterranean formation and causing or allowing the acidizing fluid to treat the portion of the subterranean formation.

[0020] It is to be understood that the discussion of any of the embodiments regarding the acidizing fluid or any ingredient in the acidizing fluid is intended to apply to all of the method and composition embodiments without the need to repeat the various embodiments throughout. Any reference to the unit “gallons” means U.S. gallons.

[0021] The acidizing fluid includes a base fluid. The base fluid includes water. The water can be selected from the group consisting of freshwater, brackish water, saltwater, produced water, and any combination thereof. The base fluid can include dissolved solids, for example, water-soluble salts. The salt can be selected from the group consisting of sodium chloride, calcium chloride, calcium bromide, potassium chloride, potassium bromide, magnesium chloride, sodium bromide, cesium bromide, cesium formate, cesium acetate, and any combination thereof. The base fluid can include undissolved particles, for example proppant or diverting agent particulates.

[0022] According to any of the embodiments, the acidizing fluid is a stimulation fluid. The stimulation fluid can be used for a stimulation operation such as matrix acidizing or fracture acidizing. As discussed above, in matrix acidizing, the acidizing fluid is introduced into the portion of the subterranean formation to be stimulated below the fracture gradient of that portion; and thus, does not create fractures in that portion. In fracture acidizing, the acidizing fluid is introduced into the portion of the subterranean formation to be stimulated at or above the fracture gradient of that portion. The acidizing fluid can also be used in an acid washing operation, a pump down operation, or an acid spearheading operation - particularly when the acid is placed into and allowed to contact equipment deployed in a wellbore in preparation for and carrying out perforation operations where there is wireline equipment in the wellbore in contact with the acid.

[0023] In the case when the acidizing fluid is used in a fracture acidizing operation, the acidizing fluid can further include proppant. As used herein, the term “proppant” means a multitude of solid, insoluble particles. The proppant can be naturally occurring, such as sand, or synthetic, such as a high-strength ceramic. Suitable proppant materials include, but are not limited to, sand (silica), walnut shells, sintered bauxite, glass beads, plastics, nylons, resins, other synthetic materials, and ceramic materials. Mixtures of different types of proppant can be used as well. The concentration of proppant in a fracture acidizing fluid can be in any concentration customarily used, and can be, for example, in the range of from about 0.01 kilograms to about 3.1 kilograms of proppant per liter of the base fluid (about 0.1 Ib/gal to about 26 Ib/gal). The size, sphericity, and strength of the proppant can be selected based on the actual subterranean formation conditions to be encountered during the fracture acidizing operation.

[0024] The acidizing fluid has or obtains a pH less than or equal to 5.5. The acidizing fluid can have or obtain a pH in a range of 5.5 to -1. The acidizing fluid can also have or obtain a pH less than or equal to 2. According to any of the embodiments, the acidizing fluid has the stated pH prior to introduction into the well. According to these embodiments, the acidizing fluid further includes an acid. Examples of acids include but are not limited to inorganic acids or organic acids, and mineral acids, such as, hydrochloric acid, hydrobromic acid, phosphoric acid, hydrofluoric acid, hypochlorous acid, chlorous acid, nitric acid, sulfuric acid, formic acid, acetic acid, chloroacetic acid, dichloroacetic acid, trichloroacetic acid, methanesulfonic acid, citric acid, maleic acid, glycolic acid, lactic acid, malic acid, oxalic acid, gluconic acid, succinic acid, tartaric acid, sulfamic acid, thioglycolic acid, sulfamic acid, trifluoroacetic acid, and propionic 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 methanesulfonic acid, formic acid, acetic 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 5.2, and combinations thereof in any proportion. According to any of the embodiments, the inorganic or mineral acid is selected from the group consisting of HC1, H3PO4, HBr, HC1O, HclCh, and any combinations thereof in any proportion. The type of acid selected can be determined based on the specific type of subterranean formation. For example, hydrofluoric acid can be a suitable acid for some formations (e. , a sandstone formation), or when siliceous or silicon-containing particulates are used.

[0025] According to other embodiments, the acidizing fluid obtains the stated pH after introduction into the well. According to these embodiments, the acidizing fluid can further include a delayed acid or retarded acid. As used herein, a “delayed acid” means any molecule or ion that cannot function as an acid (i.e., donate a proton) at the time the fluid is introduced into the well, but rather functions as an acid at some period of time after introduction into the well. 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. Retarded acids can have a low pH in the acidic range at the wellhead; however, the nature of the treatment fluid impacts the reactivity with formation materials by slowing the rate of reaction. Nanobubbles potentially have the ability to both delay the acid formation by slowing hydrolysis of an ester for example, or retard an acid by interacting with a proton’s ability to dissolve formation material. It is to be understood that “introduction” means at the wellhead. A delayed or retarded 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 the water of the base fluid or water in a reservoir fluid to form an acid. A delayed acid can also be part of a delayed acid breaker system. Furthermore, strong acids (e.g., HC1, HNO3, methanesulfonic acid, and chloroacetic acid), or acids that are weak acids e.g., H3PO4, formic acid, acetic acid, lactic acid, citric acid, gluconic acid, and glycolic acid) can be retarded by forming one of various types of complexes with organonitrogen bases (Lewis bases) and zwitterions; for example, urea hydrochloride or alkylamine hydrochloride, or alkylamine alcoholhydrochloride complexes, and amino acid hydrochloride complexes referred to as retarded HC1 acids, where the amino acid is any of the known amino acids, such as glycine, lysine, taurine, proline, etc., where alkyl can be methyl, ethyl, propyl, butyl and any corresponding isomer, and the acid can be any suitable Bronsted acid such as HC1, HF, H3PO4, formic acid, or methanesulfonic acid. According to any of the embodiments, the nanobubbles are the delayed acid as will be discussed in more detail below.

[0026] 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.

[0027] 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 generating activator 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; and an ethyl methanesulfonate.

[0028] The volume of acid or delayed acid used in the acidizing fluid can range from 10 to 800 gallons per foot of the formation being treated. The concentration of the acid or the delayed acid can be in the range of 1% to 35% weight by weight of the base fluid “w/w,” alternatively 5% to 28% w/w.

[0029] The acidizing fluid also includes an additive. The additive can be incompatible in the acidizing fluid at a pH less than or equal to 5.5. As used herein, the term “incompatible” means the miscibility, stability, solubility, and/or dispersibility of the additive in the acidizing fluid is insufficient for the additive to function according to the desired function (e.g, as a corrosion inhibitor, friction reducer, surfactant, etc. , the concentration of the additive needs to be increased in order to provide the desired function, or the efficiency of the additive is reduced below a desired efficiency level. As used herein, the term “compatible” means the miscibility, stability, solubility, and/or dispersibility of the additive in the acidizing fluid is sufficient for the additive to function according to the desired function (e.g., as a corrosion inhibitor, friction reducer, surfactant, etc.}, the concentration of the additive does not need to be increased in order to provide the desired function, or the efficiency of the additive is at or above a desired efficiency level. According to any of the embodiments, the acidizing fluid can include more than one additive that is incompatible in an acidizing fluid without the nanobubbles (e.g, the control test treatment fluid). The additive may be incompatible in the acidizing fluid depending on other types of additives that are included in the acidizing fluid. By way of example, the additive may only be incompatible when another additive that has an opposing charge than the additive is also included in the fluid. Accordingly, in some cases, the incompatible additives listed below may be compatible depending on the other types of additives that are included. However, it is to be understood that the acidizing fluid includes one or more additives that are incompatible in an acidizing fluid having a pH less than or equal to 5.5 without the nanobubbles. [0030] According to any of the embodiments, a test treatment fluid having a pH less than or equal to 5.5 and consisting of the base fluid, the additive, and the nanobubbles and in the same proportions as the acidizing fluid has an efficiency level that is greater than that of a control test treatment fluid having a pH less than or equal to 5.5 and consisting of only the base fluid and the additive and in the same proportions as the acidizing fluid. 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 concentration as the test treatment fluid. Different test treatment fluids can also be tested to determine the efficiency level 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 level and performance of the test treatment fluids. It is to be understood that while the acidizing 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 acidizing fluid to include other additives, such as stabilizing additives to provide the desired compatibility, efficiency level, and performance. 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 acidizing fluid can contain other ingredients, but it is the nanobubbles that create the desirable additive compatibility, efficiency level, and performance. Therefore, while it may not be possible to perform a test in a wellbore for the specific acidizing 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.

[0031] The additive can be viscosifier or gelling agent, a friction reducer, a viscoelastic surfactant, a corrosion inhibitor, scale control additive, or other types of additives. The viscosifier or gelling agent can be a cross-linked polymer including without limitation guar, xanthan, and combinations thereof. The friction reducer can be a non-cross-linked polymer. The non-cross-linked polymer can be selected from polysaccharide-based polymers, polyacrylamide, derivatives of polyacrylamide, and copolymers of polyacrylamide (for example, polyacrylamide co-polyacrylic acid), and other water-soluble polymers, such as guar gum, guar gum derivatives, polysaccharides and derivatives, and cellulose derivatives. A cationic or anionic polymer can have charge dependent incompatibility in the acidizing fluid. Non-ionic polymers may be compatible in the acidizing fluid.

[0032] Viscoelastic surfactants and corrosion inhibitor blends can also have charge dependent incompatibility and are composed of different heteroatomic molecules that are primarily organic (hydrophobic or minimally water-miscible) with varied molecular weight typically less than 5,000 g/mole. A “surfactant” in the context of acidizing fluids refers to classes of additives that can function as dispersants, emulsifiers, non-emulsifiers, surface tension reducers, hydrotropes, kosmotropes, chaotropes, capillary pressure lowering agents, wetting agents, foaming agents, demulsifying agents, or anti-sludging agents. Anionic dispersants are likely incompatible, whereas non-ionic dispersants are likely compatible in the acidizing fluid.

[0033] Corrosion inhibitors can be incompatible in the acidizing fluid; specifically, a corrosion inhibitor for strong acids (e.g., HC1, HNO3, methanesulfonic acid, and chloroacetic acid), or for weaker acids (e.g., H3PO4, formic acid, acetic acid, lactic acid, citric acid, gluconic acid, glycolic acid, urea hydrochloride complexes, and amino acid hydrochloride complexes referred to as retarded HC1 acids). 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-allyloxycinnamaldehyde; 4-(3- propenal)cinnamaldehyde; p-sodium sulfocinnamaldehyde; p- trimethylammoniumcinnamaldehyde sulfate; p-trimethylammoniumcinnamaldehyde; 0- 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-amyl cinnamaldehyde; 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; where the carbon atom forms an imidazoline group, and one or more aldehyde oligomers being formed by the condensation reaction of, for instance benzaldehyde and acetaldehyde. The corrosion inhibitor can further comprise 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. The corrosion inhibitor can also be 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.

[0034] The scale control additive can be a metal ion control additive such as a complexing or chelating agent, or a scale inhibitor. Examples of scale inhibitors as the metal ion control additives include but are not limited to ethylenediaminetetraacetic acid (EDTA), hydroxy ethylethylenediaminetriacetic acid (HEDTA), methylglycinediacetic acid (MGDA), tetrasodium glutamate diacetate (GLDA), nitrilotriacetic acid (NTA), trans- 1,2- diaminocy cl ohexane-N,N,N',N' -tetraacetic acid (CDTA); ethylenedioxybi s(ethyliminodi(acetic acid)) (EGTA); diethylenetriaminepentaacetic acid (DTP A), hydroxyethyliminodiacetate (HEIDA), iminodiacetic acid (IDA), triethylenetetramine-N,N,N,,N",N"„N"'-hexaacetic acid (TTHA) (and N,N'-bis(butanamide) derivative); 1,4,7, 10-tetraazacyclododecane- 1,4,7, 10- tetraacetic acid (DOT A); ethylenediamine-N,N' -disuccinic acid (EDDS), hydroxyiminodisuccinic acid (HIDS) and monovalent salts thereof; polyhydroxy carboxylic acids such as citric acid, glycolic acid, lactic acid, maleic acid, gluconic acid, glucaric acid, tartaric acid, and monovalent salts thereof.

[0035] The additive that is incompatible in the acidizing fluid can also include gas foamers, catalysts, clay control agents, biocides, antifoam agents, carbon dioxide scavengers (particulate-based scavengers such as zeolites or carbon powder may be incompatible based on the hydrophobicity of the fluid), lubricants (likely incompatible due to the hydrophobicity of the chemistry), water-insoluble breakers, anionic or cationic emulsifiers, emulsion thinners, or emulsion thickeners, and lost circulation additives (anionic additives likely not compatible).

[0036] The additive can be in a concentration typically used depending on the function of the additive and type of additive. It is to be understood that the concentration of the additive need not be increased to perform the additive’s function because the nanobubbles provide a mechanism whereby the additive becomes compatible with the acidizing fluid. According to any of the embodiments, a test treatment fluid having a pH less than or equal to 5.5 and consisting of the base fluid, the additive, and the nanobubbles and in the same proportions as the acidizing fluid has an efficiency level that is greater than that of a control test treatment fluid having a pH less than or equal to 5.5 and consisting of only the base fluid and the additive and in the same proportions as the acidizing fluid. By way of example, if the additive is a corrosion inhibitor, then the level of corrosion inhibition is greater in the test treatment fluid compared to the control test treatment fluid. By way of another example, if the additive is a viscosifier, then the viscosity of the test treatment fluid can be greater than the viscosity of the control test treatment fluid. It is to be understood that the concentration of the additive in the test treatment fluid is the same as in the control test treatment fluid.

[0037] The acidizing fluid can further include other additives. The other additives can be compatible in the acidizing fluid. It is to be understood that in some cases, depending on the other additives that are included in the acidizing fluid and the charges of the other additives (e.g., cationic or anionic) and the hydrophobicity of the other additives, some of the compatible additives listed below may be incompatible in the acidizing fluid. By way of example, a low HLB surfactant, which prefers an oil-phase, can have solubility issues in an acidizing fluid being mostly water based. The nanobubbles have a hydrophobic character that can assist with improving the solubility of hydrophobic additives into the water.

[0038] An intensifier agent can be used in formations where the temperature exceeds the capability of corrosion inhibitors to prevent excessive and damaging corrosion to the wellbore tubing and equipment. Examples of intensifier agents can comprise a group 15 metal source selected from the group consisting of antimony trioxide; antimony tetraoxide; antimony pentoxide; an antimony halide compound; antimony trichloride; antimony pentachloride; antimony trifluoride, antimony pentafluoride; antimony tartrate; antimony citrate; an alkali metal salt of antimony tartrate; antimony citrate; potassium pyroantimonate; an antimony adduct of ethylene glycol; a bismuth oxide compound; bismuth trioxide; bismuth tetraoxide; bismuth pentaoxide; a bismuth halide; bismuth trichloride; bismuth tribromide; bismuth triiodide; bismuth tartrate; bismuth citrate; an alkali metal salt of bismuth tartrate, an alkali metal salt of bismuth citrate; a bismuth oxyhalogen; or any mixtures thereof. Examples of compatible corrosion inhibitors include, but are not limited to, quaternary nitrogen containing compounds, aldehyde-containing compounds, and Mannich reaction products, thiazole, derivatives thereof, or any combinations.

[0039] Compatible additives can also include without limitation bridging agents, hydrogen sulfide scavengers, oxygen scavengers (for example hydrazine and ascorbic acid are compatible provided solubility limits are not exceeded), salts as weighting agents, inert solids (compatible depending on hydrophobicity), non-ionic emulsifiers, pH control additives, buffers, crosslinkers, stabilizers, mutual solvents, oxidizers, reducers, consolidating agents, complexing agents, particulate materials, a tackifying agent, resins, proppant, bactericides, and biocides.

[0040] The acidizing 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 400 nanometers (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, oxygen, carbon dioxide, nitrogen, a single type of hydrocarbon gas e.g., methane or propane), a mixture of different types of hydrocarbon gases, hydrogen, inert gases such as argon, ammonia gas, or chlorine gas.

[0041] According to any of the embodiments, the acidizing 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. According to any of the embodiments, the acidizing fluid may be substantially free of a surfactant.

[0042] As discussed above, the nanobubbles can be a delayed acid. Accordingly, the pH of the acidizing fluid at the time of introduction can be greater than or equal to 5.5 or 8 and the gas of the nanobubbles can function as an acid by being able to donate a proton at a period of time after introduction into the subterranean formation. By way of example, the gas can be physically separated from chemically interacting with the water in the base fluid during introduction; and thus, not capable of donating a proton and functioning as an acid. After introduction, the nanobubbles can coalesce, for example due to the temperature of the formation, until a sufficient number of the nanobubbles cavitate thereby releasing the gas to mix with the water, thereby functioning as an acid and reducing the pH of the acidizing fluid to a pH less than or equal to 5.5 or 2.

[0043] As discussed above, the additive is incompatible in the acidizing fluid 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 additive being able to function as intended. In other words, to be effective and functional, the additive may need to dissolve in the base fluid. Accordingly, if only a small amount of the total amount of the additive does solubilize in the base fluid, then the additive 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 additive may be needed. The additive is compatible in a test treatment fluid consisting of the base fluid, the additive, and the nanobubbles and in the same proportions as the acidizing fluid compared to a control test treatment fluid consisting of only the base fluid and the additive and in the same proportions as the acidizing fluid wherein the additive is not compatible in the control test treatment fluid.

[0044] The nanobubbles can make the additive compatible with the acidizing fluid by a variety of ways. One reason why the additive can be incompatible with the base fluid is because the pH is in the acidic range. The nanobubbles, when used as a delayed acid, can make the additive compatible with the base fluid by allowing the pH of the base fluid to be greater than or equal to 5.5 prior to and during introduction into the subterranean formation, which obviates the incompatibility issue based on pH. Without being limited by theory, it is believed that after introduction the nanobubbles can coalesce and cavitate, thereby releasing a gas from the nanobubbles, which can react with water in the fluid to lower the pH of the acidizing fluid to less than or equal to 5.5 or 2. However, according to this example, the additive has already been used for its intended purpose and any incompatibility is moot. That is by delaying generation of the acid via coalescence or cavitation of the nanobubbles, the pH of the fluid is greater than or equal to 5.5 and the additive is thus compatible with the acidizing fluid and the additive may already have performed its function before generation of the acid. However, without the nanobubbles and the delayed acid formation, the additive would be incompatible with the acidizing fluid. [0045] When the acidizing fluid is at a pH less than or equal to 5.5 or 2 prior to and during introduction into the subterranean formation, the nanobubbles can also possess a desired hydrophobicity and surface activity leading to improved additive compatibility. Without being limited by theory, the nanobubbles can provide a phase transfer system whereby hydrophobic material transfers into the aqueous phase and can provide an interface between metallurgies and the additive. The increased surface area created by the nanobubbles can not only make the additive compatible with the acidizing fluid but can also decrease the total concentration of additive that is needed to perform the desired function and be effective.

[0046] A well system 10 of Fig. 1 can include an acidizing fluid producing apparatus 20, a fluid source 30, a proppant 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 acidizing fluid producing apparatus 20 can combine additives with a fluid (e.g., liquid or substantially liquid) from fluid source 30, to produce an acidizing stimulation fluid that is used to stimulate a formation. The stimulation fluid can be a fluid for ready use in a stimulation treatment of the well 60 or a concentrate to which additional fluid is added prior to use in a stimulation treatment of the well 60. In other instances, the stimulation fluid producing apparatus 20 can be omitted and the stimulation fluid sourced directly from the fluid source 30.

[0047] The proppant source 40 can include a proppant for combining with a fracturing acidizing fluid. The system may also include additive source 70 that provides one or more additives (e.g., friction reducers, surfactants, corrosion inhibitors, viscosifiers, and/or other optional additives) to alter the properties of the acidizing fracturing fluid.

[0048] The pump and blender system 50 can receive the acidizing fluid and combine it with other components, including proppant from the proppant source 40 and/or additional additives from the additive source 70. The resulting mixture may be pumped into the well 60 under a pressure sufficient to create or enhance one or more fractures in a subterranean zone, for example, to stimulate production of fluids from the zone. The resulting mixture may also be pumped into the well 60 at a pressure less than the fracture pressure of the subterranean formation. The acidizing fluid producing apparatus 20, fluid source 30, and/or proppant source 40 can each be equipped with one or more metering devices (not shown) to control the flow of fluids, proppant, 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 acidizing fluids using continuous mixing or “on-the-fly” methods.

[0049] The step of introducing any of the acidizing fluids can comprise pumping the acidizing fluid into the subterranean formation. Fig. 2 shows the well 60 during an acidizing fracturing operation in a portion of a subterranean formation 102. The acidizing fracturing operation can be performed, for example, using the fracturing acidizing fluids. The subterranean formation can be penetrated by a well. The step of introducing can also include introducing any of the acidizing fluids into the well. The well includes a wellbore 104. The wellbore 104 extends from the surface 106, and the acidizing fluid 108 (e.g., an acidizing fracturing fluid) is introduced into a portion of the subterranean formation 102. The wellbore 104 can include a casing 110 that is cemented or otherwise secured to the wellbore wall. The wellbore 104 can be uncased or include uncased sections. Perforations can be formed in the casing 110 to allow acidizing fluids and/or other materials to flow into the subterranean formation 102. In cased wells, perforations can be formed using shaped charges, a perforating gun, hydro-jetting and/or other tools.

[0050] The well is shown with a work string 112. The pump and blender system 50 can be coupled to the work string 112 to pump the acidizing fluid 108 into the wellbore 104. The work string 112 can include coiled tubing, j ointed pipe, and/or other structures that allow fluid to flow into the wellbore 104. The work string 112 can include flow control devices, bypass valves, ports, and or other tools or well devices that control a flow of fluid from the interior of the work string 112 into the subterranean formation 102. For example, the work string 112 can include ports (not shown) located adjacent to the wellbore wall to communicate the acidizing fluid 108 directly into the subterranean formation 102, and/or the work string 112 can include ports that are spaced apart from the wellbore wall to communicate the acidizing fluid 108 into an annulus that is located between the outside of the work string 112 and the wall of the wellbore.

[0051] The well system can include one or more sets of packers 114 that create one or more wellbore intervals. According to some embodiments, the methods also include creating or enhancing one or more fractures within the subterranean formation using the acidizing fracturing fluid. When the acidizing fracturing fluid is introduced into wellbore 104 (e.g., in Fig. 2, the wellbore interval located between the packers 114) at a sufficient hydraulic pressure, one or more fractures 116 may be created in the subterranean formation 102. The proppant particulates in the acidizing fracturing fluid may enter the fractures 116 where they may remain after the fluid flows out of the wellbore. The proppant can be placed into the one or more fractures during the step of introducing. The proppant can form a proppant pack within the one or more fractures.

[0052] An embodiment of the present disclosure is an acidizing fluid comprising: a base fluid, wherein the base fluid comprises water, wherein the acidizing fluid has or obtains a pH less than or equal to 5.5; an additive; and a plurality of nanobubbles. Optionally, a test treatment fluid having a pH less than or equal to 5.5 and consisting of the base fluid, the additive, and the nanobubbles and in the same proportions as the acidizing fluid has an efficiency level that is greater than that of a control test treatment fluid having a pH less than or equal to 5.5 and consisting of only the base fluid and the additive and in the same proportions as the acidizing fluid. Optionally, the acidizing fluid is a stimulation fluid, and wherein the stimulation fluid is used for a matrix acidizing or fracture acidizing operation. Optionally, the acidizing fluid has or obtains a pH less than or equal to 2. Optionally, the acidizing fluid further comprises an acid selected from the group consisting of inorganic acids, organic acids, mineral acids, and combinations thereof. Optionally, the acidizing fluid further comprises a delayed acid or retarded acid. Optionally, the delayed acid is a delayed acid precursor. Optionally, the plurality of nanobubbles are the delayed acid. Optionally, the additive is selected from a viscosifier or gelling agent, a friction reducer, a viscoelastic surfactant, a corrosion inhibitor, a scale control additive, gas foamers, catalysts, clay control agents, biocides, antifoam agents, carbon dioxide scavengers, lubricants, water-insoluble breakers, anionic or cationic emulsifiers, emulsion thinners, or emulsion thickeners, or lost circulation additives. 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- 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; and the viscosifier is selected from a cationic or anionic polymer. Optionally, the fluid further comprises a second additive, wherein the second additive is compatible in the test treatment fluid and not compatible in the control test treatment fluid. Optionally, the fluid further comprises one or more additional additives, wherein the one or more additional additives are compatible in the test treatment fluid and the control test treatment fluid. 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.

[0053] Another embodiment of the present disclosure is a method of treating a subterranean formation comprising: introducing an acidizing fluid into the subterranean formation, wherein the acidizing fluid comprises: a base fluid, wherein the base fluid comprises water, and wherein the acidizing fluid has a pH less than or equal to 5.5 prior to or after introduction into the subterranean formation; an additive; and a plurality of nanobubbles; and causing or allowing the acidizing fluid to treat the subterranean formation. Optionally, the base fluid has the pH less than or equal to 5.5 prior to introduction into the subterranean formation, and wherein the acidizing fluid further comprises an acid selected from the group consisting of inorganic acids, organic acids, mineral acids, and combinations thereof. Optionally, the base fluid has the pH less than or equal to 5.5 after introduction into the subterranean formation, and wherein the acidizing fluid further comprises a delayed acid. Optionally, a test treatment fluid having a pH less than or equal to 5.5 and consisting of the base fluid, the additive, and the nanobubbles and in the same proportions as the acidizing fluid has an efficiency level that is greater than that of a control test treatment fluid having a pH less than or equal to 5.5 and consisting of only the base fluid and the additive and in the same proportions as the acidizing fluid. Optionally, the acidizing fluid is a stimulation fluid, and wherein the stimulation fluid is used for a matrix acidizing or fracture acidizing operation. Optionally, the acidizing fluid has or obtains a pH less than or equal to 2. Optionally, the acidizing fluid further comprises an acid selected from the group consisting of inorganic acids, organic acids, mineral acids, and combinations thereof. Optionally, the acidizing fluid further comprises a delayed acid or retarded acid. Optionally, the delayed acid is a delayed acid precursor. Optionally, the plurality of nanobubbles are the delayed acid. Optionally, the additive is selected from a viscosifier or gelling agent, a friction reducer, a viscoelastic surfactant, a corrosion inhibitor, a scale control additive, gas foamers, catalysts, clay control agents, biocides, antifoam agents, carbon dioxide scavengers, lubricants, water-insoluble breakers, anionic or cationic emulsifiers, emulsion thinners, or emulsion thickeners, or lost circulation additives. 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-amyl cinnamaldehyde; 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; and the viscosifier is selected from a cationic or anionic polymer. Optionally, the fluid further comprises a second additive, wherein the second additive is compatible in the test treatment fluid and not compatible in the control test treatment fluid. Optionally, the fluid further comprises one or more additional additives, wherein the one or more additional additives are compatible in the test treatment fluid and the control test treatment fluid. 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.

[0054] 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.

[0055] 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.

[0056] 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. An acidizing fluid comprising: a base fluid, wherein the base fluid comprises water, wherein the acidizing fluid has or obtains a pH less than or equal to 5.5; an additive; and a plurality of nanobubbles.

2. The acidizing fluid according to claim 1, wherein a test treatment fluid having a pH less than or equal to 5.5 and consisting of the base fluid, the additive, and the nanobubbles and in the same proportions as the acidizing fluid has an efficiency level that is greater than that of a control test treatment fluid having a pH less than or equal to 5.5 and consisting of only the base fluid and the additive and in the same proportions as the acidizing fluid.

3. The acidizing fluid according to claims 1 or 2, wherein the acidizing fluid is a stimulation fluid, and wherein the stimulation fluid is used for a matrix acidizing or fracture acidizing operation.

4. The acidizing fluid according to any one of the preceding claims, wherein the acidizing fluid has or obtains a pH less than or equal to 2.

5. The acidizing fluid according to any one of the preceding claims, wherein the acidizing fluid further comprises an acid selected from the group consisting of inorganic acids, organic acids, mineral acids, and combinations thereof.

6. The acidizing fluid according to any one of the preceding claims, wherein the acidizing fluid further comprises a delayed acid or retarded acid.

7. The acidizing fluid according to claim 6, wherein the delayed acid is a delayed acid precursor.

8. The acidizing fluid according to claim 6, wherein the plurality of nanobubbles are the delayed acid.

9. The acidizing fluid according to claim 1, wherein the additive is selected from a viscosifier or gelling agent, a friction reducer, a viscoelastic surfactant, a corrosion inhibitor, a scale control additive, gas foamers, catalysts, clay control agents, biocides, antifoam agents, carbon dioxide scavengers, lubricants, water-insoluble breakers, anionic or cationic emulsifiers, emulsion thinners, or emulsion thickeners, or lost circulation additives.

10. The acidizing fluid according to claim 9, 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-allyloxycinnamaldehyde; 4-(3-propenal)cinnamaldehyde; p- sodium sulfocinnamaldehyde; p-trimethylammoniumcinnamaldehyde sulfate; p- trimethylammoniumcinnamaldehyde; o-m ethyl 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-pentyl cinnamaldehyde; 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; and the viscosifier is selected from a cationic or anionic polymer.

11. The acidizing fluid according to claim 1, further comprising a second additive, wherein the second additive is compatible in the test treatment fluid and not compatible in the control test treatment fluid.

12. The acidizing fluid according to claim 1, further comprising one or more additional additives, wherein the one or more additional additives are compatible in the test treatment fluid and the control test treatment fluid.

13. The acidizing 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.

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

15. The acidizing 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.

16. A method of treating a subterranean formation comprising: introducing an acidizing fluid into the subterranean formation, wherein the acidizing fluid comprises: a base fluid, wherein the base fluid comprises water, and wherein the acidizing fluid has a pH less than or equal to 5.5 prior to or after introduction into the subterranean formation; an additive; and a plurality of nanobubbles; and causing or allowing the acidizing fluid to treat the subterranean formation.

17. The method according to claim 16, wherein a test treatment fluid having a pH less than or equal to 5.5 and consisting of the base fluid, the additive, and the nanobubbles and in the same proportions as the acidizing fluid has an efficiency level that is greater than that of a control test treatment fluid having a pH less than or equal to 5.5 and consisting of only the base fluid and the additive and in the same proportions as the acidizing fluid.

18. The method according to claim 16, wherein the base fluid has the pH less than or equal to 5.5 prior to introduction into the subterranean formation, and wherein the acidizing fluid further comprises an acid selected from the group consisting of inorganic acids, organic acids, mineral acids, and combinations thereof.

19. The method according to claim 16, wherein the base fluid has the pH less than or equal to 5.5 after introduction into the subterranean formation, and wherein the acidizing fluid further comprises a delayed acid.

20. The method according to claim 16, wherein the additive is selected from a viscosifier or gelling agent, a friction reducer, a viscoelastic surfactant, a corrosion inhibitor, a scale control additive, gas foamers, catalysts, clay control agents, biocides, antifoam agents, carbon dioxide scavengers, lubricants, water-insoluble breakers, anionic or cationic emulsifiers, emulsion thinners, or emulsion thickeners, or lost circulation additives.