Nanobubbles to stabilize scale dissolvers

Abstract

In oil and gas wells, scale can build up on tubing strings, downhole tools, wellbore walls, or within the near-wellbore region. A variety of treatment fluids used in oil and gas operations can include a scale dissolver. The scale dissolver can be incompatible with the other additives, for example when the scale control additive has a different charge than the other additives whereby the scale dissolver needs to be in a much higher concentration in order to dissolve the scale. The addition of nanobubbles in the treatment fluid can stabilize the fluid and make the scale dissolver more efficient, even at lower concentrations, in dissolving the scale and minimize the amount of hydrogen sulfide gas that is produced during dissolution.

Description

NANOBUBBLES TO STABILIZE SCALE DISSOLVERSTechnical Field

[0001] Oil and gas treatment fluids can include scale dissolvers and other additives. Nanobubbles can be used to stabilize the scale dissolvers in the treatment 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 embodiments.

[0003] Fig. l is a diagram illustrating a treatment fluid delivery system according to certain embodiments.Detailed Description of the Invention

[0004] 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.

[0005] 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 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 or solid particles as the dispersed phase; an emulsion, which includes acontinuous 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 (also called the external phase) of a heterogeneous fluid and is the liquid that is in the greatest percentage by volume of a treatment fluid.

[0006] A well can include, without limitation, an oil, gas, or water production well, an injection well, a monitoring well, or a geothermal well. The well can also be a storage well where the permanent or temporary entrapment of industrial emissions containing gases such as carbon dioxide (CO2); other gases such as nitrogen oxides (NOx) or sulfur oxides (SOx); or halogenated gases such as fluorocarbons, oxygenated fluorocarbons, chlorocarbons, or other organo-halogenated small molecules (Ci to C5). As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, 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.

[0007] 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.

[0008] 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, cement compositions, workover fluids, enhanced recovery 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.

[0009] The deposition and accumulation of inorganic and organic scale on wellbore (e.g., tubing strings or downhole tools) and subterranean surfaces occurs in almost every oil and gas operation. Scale buildup occurs when water is present and dissolved ions interact with the water. Because oil and gas treatment fluids almost always contain some amount of water and dissolved ions, scale buildup can cause issues in nearly every oil and gas operation. Common inorganic scales are calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfides, iron oxides, iron carbonate, lead sulfide, zinc sulfide, the various silicates and phosphates and other divalent or trivalent oxides, or any of a number of compounds that are insoluble or slightly soluble in water.

[0010] Metal sulfate scaling can occur from the deposition of metal sulfates on surfaces within a wellbore, for example, the surfaces of wellbore tools and equipment. Metal sulfate scaling can reoccur frequently over the lifetime of the well. The metal sulfate scale can coat perforations, casing, production tubulars, valves, pumps, and downhole completion equipment. Metal sulfate scaling can lead to decreases in production and recovery by creating artificial chokes and restricting flowthrough of produced fluids. In extreme cases, metal sulfate scaling may require abandonment if the scaling is so severe that the well is no longer economically viable. Metal sulfate scaling can occur when brines or treatment fluids containing metals and / or sulfates contact a formation or other fluid also including metals and / or sulfates and together form a concentration of metal sulfate exceeding the solubility of the solvent fluid. The formation of metal sulfate can be influenced by temperature, pressure, pH, and any other factors that can affect the metal sulfate solubility of a solvent fluid.

[0011] Scale dissolvers can be introduced into a wellbore to dissolve and remove scale buildup. The type of scale dissolver that is used is dependent on the specific type of scale to be dissolved. By way of example, iron sulfide scales are composed of different polymorphs of which pyrite and pyrrhotite are the most difficult to dissolve with any dissolver other than verystrong protic acids such as hydrochloric acid (HC1), hydrofluoric acid (HF), nitric acid (HNO3), or perchloric acid (HCIO4) or highly concentrated solutions of organic acids containing formic, acetic, or methanesulfonic acid. However, acids used as a scale dissolver can create additional risks - especially in high temperature wells due to corrosivity issues and generation of toxic hydrogen sulfide gas during application. If present in a reservoir, additional mitigating processes and capital investment are needed at every stage of the lifecycle of the well to protect the health and safety of personnel and protect the environment. Thus, in order to circumvent the use of strong acids such as those listed above, the use of alternative scale dissolvers can be used. Among these alternatives, for example, HC1 complexes with surfactants, amino acids, urea, and alkylamines can be used. These are not considered strong acids because their rate of reaction is orders below that of the parent acid (e.g., hydrochloric acid).

[0012] Another problem with the use of strong acids or other types of scale dissolvers is the concentration of the scale dissolver typically is in a high concentration, for example greater than 50 weight percent (wt.%) of the treatment fluid, in order to effectively dissolve the scale. Such high concentrations can pose health and safety risks and can also cause damage such as corrosion to wellbore equipment. Yet another problem with current scale dissolver fluids is the subterranean formation, wall of the wellbore, or surfaces of downhole equipment can be coated with hydrocarbon liquid. The hydrocarbon liquid can impede the ability of the scale dissolver to contact the scale to be dissolved, which not only decreases the efficiency of the scale dissolver but can also result in some scale being left on the surfaces. Yet another problem with scale dissolvers is they may be incompatible in the treatment fluid, for example, incompatible with other additives in the treatment fluid.

[0013] Thus, there is a long-felt need for improved scale dissolver treatment fluids that solve the aforementioned problems. It has been discovered that the inclusion of nanobubbles can increase the compatibility, stability, functionality, and efficiency of scale dissolvers. Some of the many advantages to the use of nanobubbles is that an increase in compatibility or stability of the scale dissolver occurs, the concentration of the scale dissolver can be decreased compared to treatment fluids without the nanobubbles, and the efficiency of the scale dissolver can be increased, for example, by carrying surface active species that can dissolve scale even on material that is coated with a hydrocarbon liquid.

[0014] A treatment fluid can include: a base fluid; a scale dissolver; and a plurality of nanobubbles, wherein the scale dissolver is compatible in a test treatment fluid consisting of the base fluid, the scale dissolver, and the nanobubbles and in the same proportions as the treatment fluid and wherein the scale dissolver is not compatible in a control test treatment fluid consisting of only the base fluid and the scale dissolver and in the same proportions as the treatment fluid.

[0015] Methods of treating a portion of a subterranean formation can include introducing the treatment fluid into the subterranean formation.

[0016] It is to be understood that the discussion of any of the embodiments regarding the treatment fluid or any ingredient in the treatment 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.

[0017] The treatment fluid can be used in a variety of oil or gas operations. The treatment fluid can be, for example, a drilling fluid, a spacer fluid, a cement composition, a workover fluid, a stimulation fluid, or for recovery operations such as with water and chemical injection operations, for example water flooding or enhanced recovery operations.

[0018] The treatment fluid can be a solution, a dispersion, a colloid, an emulsion, or an invert emulsion. The treatment 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 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 (cycloparaffm). 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.

[0019] The base fluid or an internal phase of the treatment fluid can comprise water. The water can be selected from the group consisting of freshwater, seawater, brine, and anycombination 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, and any combination thereof. The treatment 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.

[0020] The subterranean formation can include a wellbore that penetrates the subterranean formation. The wellbore can include a pipe string, such as a tubing string or a casing string and a tubing string. One or more downhole tools or equipment can be disposed within the pipe string. Examples of downhole tools or equipment can include electro submersible pumps (ESPs), intelligent completions and its associated components and systems, inflow control devices (ICDs), sand control devices such as screens, liners and perforated liners, or gas lift equipment. There can be an annulus located between the inside of a wellbore wall and the outside of the pipe string. At least a portion of the pipe string, surface of the downhole tools, and / or the wellbore wall can have scale buildup. The scale can be without limitation, calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, or metal silicates or phosphates or oxides (e.g, magnesium silicate, calcium phosphonate, iron oxide).

[0021] The treatment fluid also includes the scale dissolver. The scale dissolver can dissolve the scale. As used herein, “dissolve the scale” means to cause the scale to solubilize in the base fluid, be removed from the surface (e.g., tubing string, wall of the wellbore, or downhole tool), or be broken into insoluble pieces that are removed from the surface. The scale dissolver can be selected from inorganic or organic salts, an acid, salts of an acid, or derivatives of an acid. Examples of inorganic or organic salts include without limitation a phosphonated aminocarboxylate. Examples of the phosphonated aminocarboxylate include, but are not limited to, N-Phosphonomethyl iminodiacetic acid (“PMIDA”), aminotris (methylenephosphonic acid) (“AMP”), N,N-bis(phosphonomethyl)glycine (“BPMG”); additionally, phosphono-based multicarboxylic acids can also be used, such as phosphonobutanetricarboxylic acid (“PBTC”), 2- carboxyethyl phosphonic acid (“CEP A”), 2-hydroxyphosphonocarboxylic acid (“HPAA”), a salt thereof, a hydrate thereof, an acid thereof, an ester thereof, any derivative thereof, or any combination thereof. The phosphonated aminocarboxylate can be chosen based on variety offactors including its impact on metal sulfate scale solubility, temperature stability, rate of metal sulfate scale dissolution, compatibility with high pH base fluids, and minimal or no inducement of corrosion of the wellbore equipment.

[0022] Examples of acids include but are not limited to inorganic acids, organic acids, and mineral acids, such as, hydrochloric acid, hydrobromic acid, phosphoric acid, hydrofluoric acid, hypochlorous acid, chlorous acid, formic acid, 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, 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 3.5, 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, HCIO2, and any combinations thereof in any proportion.

[0023] The scale dissolver fluid can also include strong oxidants or radicals, for example, ozone; organic or inorganic peroxides and peroxide-generating substances; nitrosyl radicals containing or generating scale reactive species; sulfonyl radicals containing or generating scale reactive species; halide radicals where the halide is any of Group 17 or VIIA; superoxides; hydroperoxides that are generated in the fluid; or other oxidizer species including a persulfate salt, a permanganate salt, a bromate salt, a perbromate salt, a chlorate salt, a perchlorate salt, an iodate salt, a periodate salt, and mixtures thereof. These generated substances or species can be used in conjunction with the scale dissolver and can help dissolve other types of scale that may be present that the scale dissolver does not dissolve.

[0024] The treatment fluid can have a pH in the acidic range, for example in the range of 0 to 4.5. The treatment fluid can have a pH near neutral, for example in the range of 5.5 to 7.5. The treatment fluid can have a pH in the basic or caustic range, for example in the range of 7.5 to 12.5. The pH of the treatment fluid can be affected by the specific type of acid used and the concentration of the acid as well as the downhole conditions in the wellbore, such as thebottomhole temperature. As used herein, the term “bottomhole” means at the location of the scale to be dissolved.

[0025] The scale dissolver can be selected depending on the specific type of scale to be dissolved. By way of example, if the scale is a metal sulfate, then the scale dissolver can be a phosphonated aminocarboxylate; a carboxylated alkanol, a carboxylated alkyl halide, and / or a multi-carboxylic acid. By way of another example, if the scale is a mixed scale of interspersed calcium carbonate and calcium sulfate, then the scale dissolver can be phosphonomethyliminodiacetic acid, N,N-bis(phosphonomethyl)glycine, or a combination thereof. Active scale dissolvers include both dissolvers and auxiliary agents or co-catalysts. Depending on the concentration of these agents, different formulations can include aminopoly carboxy lie acid or an aminopolycarboxylic acid, comprising one of: ethylenediaminetetraacetic acid (EDTA), hydroxy ethyl ethylenedi aminetri acetic acid (HEDTA), methylglycinediacetic acid (MGDA), tetrasodium glutamate diacetate (GLDA), nitrilotriacetic acid (NTA), diethylenetriaminepentaacetic acid (DTP A), trans- 1,2-diaminocyclohexane- N,N,N’,N’ -tetraacetic acid (CDTA); ethylenedioxybis(ethyliminodi(acetic acid)) (EGTA); diethylenetriaminepentaacetic acid (DTP A), hydroxy ethyliminodiacetate (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; a phosphonoalkyl moiety such as N-(phosphonomethyl) iminodiacetic acid (PMIDA, N-(carboxymethyl)-N-(phosphonomethyl)glycine, glycine, N,N'-1.2-ethanediylbis(N-(phosphonomethyl), glyphosine; aminotrimethylene phosphonic acid, sodium aminotris(methylenephosphonate), N-(2-hydroxyethyl)iminobis (methylphosphonic acid), P,P'-((2-propen-l-ylimino)bis(methylene))bis-, phosphonic acid, P,P',P"- (nitrilotris(methylene))tris-, (nitrilotris(methylene))trisphosphonic acid, ((methylimino)_,dimethylene)bisphosphonic acid, phosphonic acid, P,P',P",P"'-(oxybis(2,l- ethanediylnitrilobis (methylene))tetrakis-, ((propylimino)bis(methylene))diphosphonic acid, P,P',P"-(nitrilotris(methylene))tris-, (ethylenedinitrilo)-tetramethylenephosphonic acid, ethylene- bis(nitrilodimethylene)tetraphosphonic acid, (ethylenebis(nitrilobis(methylene)))tetrakisphosphonic acid, tetrasodium tetrahydrogen (ethane-1.2-diylbis(nitrilobis(methylene)))tetrakisphosphonate, 6-(bis(phosphonomethyl)amino)hexanoic acid, (phenylmethyl)imino)bis_,(methylene)bisphosphonic acid, phosphonobutane tricarboxylic acid, 2-hydroxyhosphono dicarboxylic acid, or, a combinations thereof. Additionally, pentazinc; [bis[2-[bis(phosphonomethyl)amino]ethyl]amino] methylphosphonic acid, pentanickel; [bis[2-[bis(phosphonomethyl)amino] ethyl]amino] methylphosphonic acid, pentacadmium; [bis[2- [bis(phosphonomethyl)amino]ethyl]amino]methylphosphonic acid, pentamanganese; [bi s[2- [bis(phosphonomethyl)amino]ethyl]amino]methylphosphonic acid, nitrilotri(methylphosphonic acid), n,n-bis(phosphonomethyl)glycine, iminodi(methylphosphonic acid), (aminomethyl)phosphonic acid, methylenediphosphonic acid, diethylenetriaminepentakis(methylphosphonic acid), 2-hydroxyethyl imino bis(methylene)) bisphosphonic acid, amino-tris(methylenephosphonate), poly(vinyl phosphonic acid), sulfosuccinic acid, benzene sulfonic acid, naphthalene sulfonic acid, vinyl sulfonic acid, poly vinyl sulfonic acid, styrene sulfonic acid, polystyrene sulfonic acid, polyacrylic acid, polyhydroxy carboxylic acids such as citric acid, glycolic acid, lactic acid, maleic acid, gluconic acid, glucaric acid, tartaric acid, halogenated alkyl or aryl carboxylic acids, and their monovalent salts and combinations thereof.

[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 treatment 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 and performance of the additives with the nanobubbles compared to a control or other fluid without the nanobubbles that require a higher concentration of the additives to match the efficiency and performance of the test treatment fluids. It is to be understood that while the treatment fluid can contain other ingredients, it is the nanobubbles that are primarily or wholly responsible for providing the requisite compatibility of the additives in the base fluid. Therefore, it is not necessary for the treatment 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 treatment fluid can contain other ingredients, but it is the nanobubbles that create thedesirable additive compatibility. Therefore, while it may not be possible to perform a test in a wellbore for the specific treatment 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.

[0027] The scale dissolver can be in a concentration in a range of 1% to 50% weight by volume of the treatment fluid (w / v). According to any of the embodiments, the scale dissolver is in a concentration in the treatment fluid that is less than the concentration of the scale dissolver in a treatment fluid without the nanobubbles to provide the same percentage of scale dissolution. Accordingly, the scale dissolver can be in a concentration typically used or even in a lower concentration than typically used. It is to be understood that the concentration of the scale dissolver need not be increased to dissolve the specific type of scale because the nanobubbles provide a mechanism whereby the scale dissolver becomes compatible with the treatment fluid. As used herein, the term “incompatible” means the miscibility, stability, solubility, and / or dispersibility of the scale dissolver in the treatment fluid are insufficient for the effective dissolution of the scale, the concentration of the scale dissolver needs to be increased in order to effectively dissolve the scale, or the efficiency of the scale dissolver is reduced below a desired efficiency level. As used herein, the term “compatible” means the miscibility, stability, solubility, and / or dispersibility of the scale dissolver in the treatment fluid are sufficient for the effective dissolution of the scale the concentration of the scale dissolver does not need to be increased in order to effectively dissolve the scale, or the efficiency of the scale dissolver is above a desired efficiency level. The desired efficiency level can be, for example, at least 40 weight %, 50 weight %, or 60 weight % of the scale is dissolved using testing conditions of a time of 4 hours and a testing temperature of 250°F (96.2°C). That is, without the nanobubbles, the scale dissolver is incompatible in the treatment fluid or control test treatment fluid whereby less than 40 weight % of the scale is dissolved using the testing conditions. However, with the nanobubbles, the scale dissolver is compatible in the treatment fluid or the test treatment fluid whereby 40+ weight % of the scale is dissolved using the testing conditions. The incompatibility can be a function of the concentration that is needed in the fluid for dissolving the scale. The concentration of the scale dissolver in the fluid reaches a maximum activity (i.e., the dissolving power or capacity), which is a function of chemical saturation based on the solubility constantand / or thermodynamic characteristics for example. The inclusion of the nanobubbles can circumvent this limitation.

[0028] The scale dissolver can be incompatible in the treatment fluid due to an interaction with other additives in the treatment fluid. Other additives include without limitation surface active agents that are used in demulsification, wetting of a surface (making it water wet) or de-wetting (facilitating the contacting of an aqueous chemical species of a mineral surface that is oil-wet), foaming agents, corrosion inhibitors, scale inhibitors, interfacial tension reducing agents, relative permeability modifiers, or nanoparticles.

[0029] The treatment 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 treatment 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 the group consisting of air, oxygen, carbon dioxide, nitrogen, nitrogen oxides, acidic gases with a vapor pressure that facilitates the generation of hydronium species from a molecule bearing an -HX species, wherein X is a halide such as fluorine, chlorine, bromine, or iodine, a single type of hydrocarbon gas (e.g., methane or propane), a mixture of different types of hydrocarbon gases, liquified natural gas, flaring gas, flue gas, hydrogen, inert gases such as argon, ammonia gas, chlorine gas, and any combinations thereof.

[0030] According to any of the embodiments, the treatment 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 treatment fluid may be substantially free of a surfactant.

[0031] The treatment fluid can include a solvent. The solvent can be organic solvents, such as glycols or glycol ethers; strongly polar organic solvents, such as cyclic ethers and substituted cyclic ethers, or furfuryl or tetrahydrofurfuryl alcohols; or paraffinic solvents,such as benzene, toluene, xylene, and aliphatic petroleum distillates (such as heptane and octane). The treatment fluid can include redox active metal ions, thiophosphates, radical initiators or radical generators. The treatment fluid can also include an electrolyte or brine (El) as the scale dissolver where E = Na, K, Cs, Ca, Ba, Zr, Mg, Mn, Bi, Sb, or Sr and I = a Group 17 or VIIA ion, a carboxylate, an oxyanion, carbonates, borates, phosphates, or sulfates.

[0032] The treatment fluid can be used with an exothermic composition, for example when there is a need to increase or modify the exposure time of the treatment fluid with the scale to be dissolved, or when the bottomhole temperature is less than a temperature whereby the scale dissolver is capable of dissolving the scale, or when the location of the scale to be dissolved is in a near-wellbore region. The exothermic composition can include at least 2 ingredients that chemically react and produce heat. For example, the exothermic composition can include a salt of ammonium ions having an inorganic or organic counterion, a phosphonium or sulfonium ion and respective counterion and a salt of an oxy anion metal where the oxyanion is one of EOXwhere E = B, N, P, S, or a halide and x = 2, 3, 4, 5, etc. to balance the redox states.

[0033] Depending on the type of treatment fluid (e.g, drilling fluid, stimulation fluid, etc.), the treatment fluid can further include other additives. The other additives can be a dispersing agent, weighting agents, a tackifying agent, resins, proppant, oxygen scavengers, alcohols, fluid-loss control additives, oxidizers, bactericides, biocides, cement set retarders, strength retrogressive additives, and combinations thereof.

[0034] After introduction into the wellbore, the nanobubbles can coalesce, for example due to the temperature of the formation, until a sufficient number of the nanobubbles cavitate. When an acid is used as the scale dissolver, the acid can be a delayed acid such that the pH of the treatment fluid is not in the acidic range until after cavitation or coalescence of the nanobubbles. Upon cavitation, the scale dissolver is then free to dissolve the scale.

[0035] The nanobubbles provide many advantages. One being the scale dissolver is able to dissolve the scale with little or no formation of hydrogen sulfide gas. Another unique advantage is the nanobubbles provide an increased surface area for the scale dissolver and can enhance the treatment fluid’s penetration or infiltration at the location of the scale buildup creating better contact of the scale dissolver and the scale, which leads to faster and more efficient dissolution of the scale. The increase in surface area can also mean the concentration of the scale dissolver can be decreased and still perform very effectively compared to a fluidwithout the nanobubbles. These advantages not only decrease the total time needed to dissolve the scale, but also provide lower operating costs due to the decreased concentration. Another advantage is the nanobubble fluids can allow re-use of produced water by minimizing the contaminant load while cleaning and re-conditioning the produced water for further use in the same oil and gas operation.

[0036] According to any of the embodiments, the treatment fluid can provide scale dissolution of 75% or greater in a reaction time of less than 4 hours, greater than 80% dissolution in a reaction time of less than 2 hours, or greater than 80% dissolution in a reaction time of less than 1 hour.

[0037] A well system 10 of Fig. 1 can include a treatment 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 treatment fluid producing apparatus 20 can combine additives with a fluid (e.g., liquid or substantially liquid) from fluid source 30, to produce a treatment fluid. The treatment fluid can be a fluid for ready use in a treatment operation of the well 60 or a concentrate to which additional fluid is added prior to use in a treatment of the well 60. In other instances, the treatment fluid producing apparatus 20 can be omitted and the treatment fluid sourced directly from the fluid source 30.

[0038] The additive source 40 can include an additive for combining with a base fluid. The system may also include additional additive source 70 that provides one or more additional additives (e.g., friction reducers, surfactants, corrosion inhibitors, viscosifiers, and / or other optional additives) to alter the properties of the treatment fluid.

[0039] The pump and blender system 50 can receive the treatment fluid and combine it with other components, including additives from the additive source 40 and / or additive source 70. The resulting mixture may be pumped into the well 60. The treatment fluid producing apparatus 20, fluid source 30, and / or additive source 40 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 treatment fluids using continuous mixing or “on-the-fly” methods.

[0040] The step of introducing any of the treatment fluids can comprise pumping the treatment fluid into the subterranean formation. The subterranean formation can be penetratedby a well. The step of introducing can also include introducing any of the treatment fluids into the well. The well includes a wellbore. The wellbore extends from the surface, and the treatment fluid is introduced into a portion of the subterranean formation. The wellbore can include a casing that is cemented or otherwise secured to the wellbore wall. The wellbore can be uncased or include uncased sections. Perforations can be formed in the casing to allow treatment fluids and / or other materials to flow into the subterranean formation. In cased wells, perforations can be formed using shaped charges, a perforating gun, hydro-jetting and / or other tools.

[0041] The well can include a work string. The pump and blender system 50 can be coupled to the work string to pump the treatment fluid into the wellbore. The work string can include coiled tubing, jointed pipe, and / or other structures that allow fluid to flow into the wellbore. The work string 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 into the subterranean formation. For example, the work string can include ports located adjacent to the wellbore wall to communicate the treatment fluid directly into the subterranean formation, and / or the work string can include ports that are spaced apart from the wellbore wall to communicate the treatment fluid into an annulus that is located between the outside of the work string and the wall of the wellbore.

[0042] An embodiment of the present disclosure is a treatment fluid comprising: a base fluid; a scale dissolver; and a plurality of nanobubbles. Optionally, the scale dissolver is compatible in a test treatment fluid consisting of the base fluid, the scale dissolver, and the nanobubbles and in the same proportions as the treatment fluid, and wherein the scale dissolver is not compatible in a control test treatment fluid consisting of only the base fluid and the scale dissolver and in the same proportions as the treatment fluid. Optionally, the base fluid comprises a hydrocarbon liquid, water, or combinations thereof. Optionally, the scale dissolver dissolves a scale selected from calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, metal silicates or phosphates or oxides, or combinations thereof. Optionally, the scale dissolver is selected from inorganic or organic salts, an acid, salts of an acid, or derivatives of an acid. Optionally, the inorganic or organic salts are selected from the group consisting of: a phosphonated aminocarboxylate including N-Phosphonomethyl iminodiacetic acid, aminotris (methylenephosphonic acid), N,N-bis(phosphonomethyl)glycine; phosphono-based multicarboxylic acids including phosphonobutanetricarboxylic acid, 2-carboxyethyl phosphonic acid, 2-hydroxyphosphonocarboxylic acid, a salt thereof, a hydrate thereof, an acid thereof, an ester thereof, any derivative thereof, or any combination thereof. Optionally, the acid, the salts of an acid, or the derivatives of an acid are selected from the group consisting of inorganic acids, organic acids, mineral acids, and combinations thereof.Optionally, the inorganic acids, organic acids, or mineral acids are selected from the group consisting of hydrochloric acid, hydrobromic acid, phosphoric acid, hydrofluoric acid, hypochlorous acid, chlorous acid, formic acid, 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, sulfamic acid, thioglycolic acid, sulfamic acid, trifluoroacetic acid, propionic acid, 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, an organic acid having a pKa constant less than or equal to 3.5, and any combinations thereof in any proportion. Optionally, the treatment fluid further comprises strong oxidants or radicals including ozone; organic or inorganic peroxides and peroxide-generating substances; nitrosyl radicals containing or generating scale reactive species; sulfonyl radicals containing or generating scale reactive species; halide radicals where the halide is any of Group 17 or VIIA; superoxides; or hydroperoxides that are generated in the fluid.Optionally, the scale dissolver is in a concentration in a range of 1% to 50% weight by volume of the treatment fluid. Optionally, the scale dissolver is in a concentration in the treatment fluid that is less than the concentration of the scale dissolver in a treatment fluid without the nanobubbles to provide the same percentage of scale dissolution. 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 nanobubbles is selected from the group consisting of air, oxygen, carbon dioxide, nitrogen, nitrogen oxides, acidic gases with a vapor pressure that facilitates the generation of hydronium species from a molecule bearing an -HX species, wherein X is a halide including fluorine, chlorine, bromine, or iodine, a single type of hydrocarbon gas, a mixture of different types of hydrocarbon gases, liquified natural gas, flaring gas, flue gas, hydrogen, inert gases, and any combination thereof.

[0043] Another embodiment of the present disclosure is a method of treating a subterranean formation comprising: introducing a treatment fluid into the subterranean formation, wherein scale buildup is present in the subterranean formation, and wherein the treatment fluid comprises: a base fluid; a scale dissolver; and a plurality of nanobubbles. Optionally, the scale dissolver is compatible in a test treatment fluid consisting of the base fluid, the scale dissolver, and the nanobubbles and in the same proportions as the treatment fluid, and wherein the scale dissolver is not compatible in a control test treatment fluid consisting of only the base fluid and the scale dissolver and in the same proportions as the treatment fluid; and causing or allowing the scale dissolver to dissolve at least a portion of the scale buildup. Optionally, the base fluid comprises a hydrocarbon liquid, water, or combinations thereof. Optionally, the scale dissolver dissolves a scale selected from calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, metal silicates or phosphates or oxides, or combinations thereof. Optionally, the scale dissolver is selected from inorganic or organic salts, an acid, salts of an acid, or derivatives of an acid. Optionally, the inorganic or organic salts are selected from the group consisting of: a phosphonated aminocarboxylate including N-Phosphonomethyl iminodiacetic acid, aminotris (methylenephosphonic acid), N,N-bis(phosphonomethyl)glycine; phosphono-based multicarboxylic acids including phosphonobutanetri carboxylic acid, 2-carboxyethyl phosphonic acid, 2-hydroxyphosphonocarboxylic acid, a salt thereof, a hydrate thereof, an acid thereof, an ester thereof, any derivative thereof, or any combination thereof. Optionally, the acid, the salts of an acid, or the derivatives of an acid are selected from the group consisting of inorganic acids, organic acids, mineral acids, and combinations thereof. Optionally, the inorganic acids, organic acids, or mineral acids are selected from the group consisting of hydrochloric acid, hydrobromic acid, phosphoric acid, hydrofluoric acid, hypochlorous acid, chlorous 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, propionic acid, 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, an organic acid having a pKa constant less than or equal to 3.5, and any combinations thereof in any proportion. Optionally, the treatment fluid further comprises strong oxidants or radicalsincluding ozone; organic or inorganic peroxides and peroxide-generating substances; nitrosyl radicals containing or generating scale reactive species; sulfonyl radicals containing or generating scale reactive species; halide radicals where the halide is any of Group 17 or VIIA; superoxides; or hydroperoxides that are generated in the fluid. Optionally, the scale dissolver is in a concentration in a range of 1% to 50% weight by volume of the treatment fluid. Optionally, the scale dissolver is in a concentration in the treatment fluid that is less than the concentration of the scale dissolver in a treatment fluid without the nanobubbles to provide the same percentage of scale dissolution. 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 nanobubbles is selected from the group consisting of air, oxygen, carbon dioxide, nitrogen, nitrogen oxides, acidic gases with a vapor pressure that facilitates the generation of hydronium species from a molecule bearing an -HX species, wherein X is a halide including fluorine, chlorine, bromine, or iodine, a single type of hydrocarbon gas, a mixture of different types of hydrocarbon gases, liquified natural gas, flaring gas, flue gas, hydrogen, inert gases, and any combination thereof.

[0044] 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.

[0045] 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 componentsand 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.

[0046] 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 treatment fluid comprising: a base fluid; a scale dissolver; and a plurality of nanobubbles.

2. The treatment fluid according to claim 1, wherein the scale dissolver is compatible in a test treatment fluid consisting of the base fluid, the scale dissolver, and the nanobubbles and in the same proportions as the treatment fluid; and wherein the scale dissolver is not compatible in a control test treatment fluid consisting of only the base fluid and the scale dissolver and in the same proportions as the treatment fluid.

3. The treatment fluid according to claim 1 or 2, wherein the scale dissolver dissolves a scale selected from calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, metal silicates or phosphates or oxides, or combinations thereof.

4. The treatment fluid according to claim 1, wherein the scale dissolver is selected from inorganic or organic salts, an acid, salts of an acid, or derivatives of an acid.

5. The treatment fluid according to claim 4, wherein the inorganic or organic salts are selected from the group consisting of: a phosphonated aminocarboxylate including N- Phosphonomethyl iminodiacetic acid, aminotris (methylenephosphonic acid), N,N- bis(phosphonomethyl)glycine; phosphono-based multicarboxylic acids including phosphonobutanetricarboxylic acid, 2-carboxy ethyl phosphonic acid, 2- hydroxyphosphonocarboxylic acid, a salt thereof, a hydrate thereof, an acid thereof, an ester thereof, any derivative thereof, or any combination thereof.

6. The treatment fluid according to claim 4, wherein the acid, the salts of an acid, or the derivatives of an acid are selected from the group consisting of inorganic acids, organic acids, mineral acids, and combinations thereof.

7. The treatment fluid according to claim 6, wherein the inorganic acids, organic acids, or mineral acids are selected from the group consisting of hydrochloric acid, hydrobromic acid, phosphoric acid, hydrofluoric acid, hypochlorous acid, chlorous 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, propionic acid, 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, an organic acid having a pKa constant less than or equal to 3.5, and any combinations thereof in any proportion.

8. The treatment fluid according to claim 1, wherein the treatment fluid further comprises strong oxidants or radicals including ozone; organic or inorganic peroxides and peroxidegenerating substances; nitrosyl radicals containing or generating scale reactive species; sulfonyl radicals containing or generating scale reactive species; halide radicals where the halide is any of Group 17 or VIIA; superoxides; or hydroperoxides that are generated in the fluid.

9. The treatment fluid according to claim 1, wherein the scale dissolver is in a concentration in a range of 1% to 50% weight by volume of the treatment fluid.

10. The treatment fluid according to claim 1, wherein the scale dissolver is in a concentration in the treatment fluid that is less than the concentration of the scale dissolver in a treatment fluid without the nanobubbles to provide the same percentage of scale dissolution.

11. The treatment 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.

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

13. The treatment 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.

14. A method of treating a subterranean formation comprising: introducing a treatment fluid into the subterranean formation, wherein scale buildup is present in the subterranean formation, and wherein the treatment fluid comprises: a base fluid; a scale dissolver; and a plurality of nanobubbles; and causing or allowing the scale dissolver to dissolve at least a portion of the scale buildup.

15. The method according to claim 14, wherein the scale dissolver is compatible in a test treatment fluid consisting of the base fluid, the scale dissolver, and the nanobubbles and in the same proportions as the treatment fluid; and wherein the scale dissolver is not compatible in a control test treatment fluid consisting of only the base fluid and the scale dissolver and in the same proportions as the treatment fluid.

16. The method according to claims 14 or 15, wherein the scale dissolver dissolves a scale selected from calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, metal silicates or phosphates or oxides, or combinations thereof.

17. The method according to any one of claims 14 - 16, wherein the scale dissolver is selected from inorganic or organic salts, an acid, salts of an acid, or derivatives of an acid.

18. The method according to any one of claims 14 - 17, wherein the scale dissolver is in a concentration in a range of 1% to 50% weight by volume of the treatment fluid.

19. The method according to any one of claims 14 - 18, wherein the plurality of nanobubbles have a mean diameter ranging from 50 to 400 nanometers.

20. The method according to any one of claims 14 - 19, wherein the plurality of nanobubbles have a population ranging from 1 to 100 million nanometer-sized bubbles per milliliter of the base fluid.

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