REMOVAL OF A MINERAL PHASE FROM A SURFACE ASSOCIATED WITH A WELL

Abstract

The compositions for removing a mineral phase from a surface composition for removing an inorganic sulfate scale mineral phase include a phosphonoalkyl aminopolycarboxylic acid chelating agent; a wettability modifier comprising a dibasic ester and a surfactant, wherein the surfactant comprises one or more anionic alkyl sulfonate or anionic aryl sulfonate; a pH adjusting agent; a scale-converting agent; and water. The methods for removing a mineral phase from a surface include contacting the mineral phase with an aqueous solvent fluid that is one of the present compositions; and removing the oil-wetted mineral phase from the surface with the aqueous solvent fluid. The compositions and methods provide improved repair of mineral phases from well-associated surfaces.

Description

This disclosure relates to methods and fluid compositions for enhanced repair of mineral phases of surfaces associated with wells. Operations to extract an underground product from the earth through a well often use treatment fluids to facilitate or implement the process. Hydrocarbons, such as oil and gas, are underground products commonly extracted from reservoirs, areas of the earth that contain the hydrocarbons. A reservoir can be located far below the earth's surface, and the earth may include one or more formations that lie above and / or form the reservoir. A formation is a region of the earth with a distinct lithology that describes the physical characteristics of the rock within the formation, such as its mineral content. Illustrative extraction operations may include, for example, drilling, completion, stimulation, and production. Stimulation operations may include, for example, fracturing and acidizing. In various operations, a treatment fluid is delivered downhole. For example, illustrative treatment fluids include fracturing fluids, cementing fluids, completion fluids, drilling mud, and production chemicals. Hydrocarbons are extracted or treatment fluids are delivered downhole using systems that may include surfaces, such as metal surfaces (e.g., pipes, tubing, flow lines), or equipment, including downhole devices and tools. Other fluids in contact with surfaces that are extracted from or introduced into the downhole include mineral matrices (e.g., subsurface formations). Inorganic scale can accumulate on surfaces during extraction and recovery operations. Inorganic scale forms from substances that precipitate onto the surfaces of fluids that come into contact with them during extraction. Inorganic scale tends to create restrictions that lead to artificial throttling of the production tubing or short casing strings, resulting in reduced production and costly equipment damage. The severity of such scale can accumulate to the point where flow is no longer economically viable for continuous operation, requiring frequent equipment interventions if remedial measures are not taken to remove the scale.The formation of inorganic scale in the wellbore, tubing, and equipment remains a production-restricting problem. This precipitation, crystallization, or accumulation can occur. ML / a / ZUZZ / UI OI / u in or within a naturally occurring or artificially created fracture (hydraulic fracturing, fracturing). Under certain circumstances, the proppant pack located in either a hydraulic fracture or a fracturing package may experience scaling. In other operations, scaling may occur in or within the reservoir itself when the well is an injection well. In such cases, scaling may result from the introduction of improperly treated or conditioned water and / or the processes associated with the introduction of an acidizing or other descaling fluid. For example, formation damage can occur when an incorrect or unsuitable fluid is first introduced into a well or reservoir and then comes into contact with an acidizing or descaling fluid that has incompatible physicochemical characteristics. Inorganic scale is typically wetted with oil in a production well, making it difficult to effectively achieve near-complete dissolution (>90%) with a water-based solvent fluid without incurring extended periods of time (e.g., days) and the need for purging or washing stages with an organic solvent before applying an aqueous solvent fluid to remove the scale. Furthermore, conventional scale removal processes tend to involve purging (a stage called post-purging) with a sufficiently strong mineral acid, such as hydrochloric acid, or a strong organic acid, such as methanesulfonic acid, or, in some cases, formic or acetic acid, after applying the aqueous solvent fluid to remove the scale. BRIEF DESCRIPTION OF THE DRAWINGS The methods for removing a mineral phase from a surface associated with a well are described with reference to the following figures. The same numbers are used in all figures to refer to similar features and components. The features shown in the figures are not necessarily to scale. Certain features of the methods may be exaggerated or somewhat schematically depicted, and some details may be omitted for the sake of clarity and conciseness. Figure 1 represents a system configured to supply various solvent fluids to a downhole location according to one or more embodiments; Figure 2 represents a system configured to supply various solvent fluids to a subsea downhole location according to one or more embodiments; and Figure 3 is a schematic illustrating a downhole portion of the example solvent fluid supply system illustrated in Figure 1 or Figure 2 according to one or more of the embodiments. DETAILED DESCRIPTION OF THE INVENTION This disclosure provides compositions and methods for removing a mineral phase from a surface. The compositions and methods involve an aqueous solvent fluid comprising a phosphonoalkyl aminopolycarboxylic acid chelating agent, a wettability modifier, a pH adjusting agent, a scale converter, and water. The wettability modifier comprises a dibasic ester and an anionic alkyl sulfonate or anionic aryl sulfonate. In one or more embodiments, the wettability modifier includes an alcohol. The compositions and methods do not require the use of a secondary mineral or organic acid stage to remove the mineral phase. That is, the methods may simply involve contacting the mineral phase with the compositions in a one-stage dissolution process.The compositions and methods are capable of achieving at least 50% or more, for example, at least 75%, such as at least 90%, dissolution of the mineral phase in a contact period of between 0.5 and 72 hours, for example, between 0.5 and 8 hours, such as between 0.5 and 6 hours. Mineral phase on a surface The mineral phase may include a scale deposit, or formation material that has the geochemical constitution of the deposit, or a mineral introduced artificially or intentionally into an underground formation or well. In other cases, the specific origin of the mineral phase to be removed may be uncertain. The scale deposit may be an inorganic scale. The inorganic scale may be an inorganic sulfate scale. The inorganic sulfate scale may be any metal sulfate, such as polymorphs of calcium sulfate, such as gypsum, anhydrite, basanite, or hemihydrate, or other divalent sulfate minerals containing magnesium, barium, or strontium. Other metals that may be present in the inorganic sulfate scale include aluminum, iron, titanium, zirconium, cobalt, copper, zinc, or manganese. Other less common metals include lithium, beryllium, vanadium, scandium, chromium, cadmium, silver, lead, bismuth, or antimony.The mineral phase is deposited on a surface associated with a well. The surface may be a metallic surface. For example, the surface may be a conduit surface, such as casing, production tubing, short casing, marine riser, umbilical tubing, chemical injection tubing, a pipe surface, or a flowline surface; or an equipment surface, which includes downhole tools and devices, such as electric submersible pumps (ESPs), valves, manifolds, inlet flow control devices, meters, or mandrels. Alternatively, the surface may be a non-metallic surface, such as in an open hole (OH) with or without a short casing, or a plastic pipe surface.The non-metallic surface can be a mineral matrix, where the mineral phase can constitute part or all of the matrix, such as a formation. ML / a / ZUZZ / UI OI / u underground geological. In addition, the mineral phase may be located or deposited in the "topside" elements or configuration of an offshore structure, where some of the listed elements are present, but others were not specifically mentioned and are located above the waterline. The topside configuration refers to equipment for drilling, producing, and processing hydrocarbons and fluids extracted and transported from the underground formation. The platform or operation includes offshore structures such as FPSOs (floating production storage and offloading units) and semi-submersibles. System Well types include hydrocarbon (oil and / or gas) producing wells, geothermal wells, water injection wells for pressure support (including steam-assisted gravity drainage (SAGD) or water-alternating-gas (WAG) wells), and waste wells. The surface refers to any wellbore surface, such as a wellbore, casing, short casing, tubing, flowline, surface tubing, or surface equipment, such as separators, heat exchangers, tanks, or similar structures. In subsea wells, there can be several configurations. For example, fouling can occur in the flowline above the subsea wellhead, below the wellhead in the drilled zone, or above the drilled zone where mandrels, manifolds, and other equipment are located.Fouling can occur in the flow line above the subsea wellhead, below the wellhead in the drilling zone, or above the drilling zone where mandrels, manifolds, or similar components are located. Figure 1 shows an illustrative schematic of a system that can supply the solvent fluid of this disclosure to the surface with the inorganic fouling, according to one or more embodiments. The surface may be in a downhole location. The term downhole, as used herein, refers to a location below the earth's surface, such as a location within a well or fluidly connected to it. It should be noted that, although Figure 1 generally depicts a land-based system, it should be recognized that similar systems may also be operated in subsea locations. As depicted in Figure 1, the system may include a mixing tank in which the fluids of the embodiments herein may be stored or formulated.The fluids can be conveyed through line 112 to wellhead 114, where they enter tubular 116. Tubular 116 extends from wellhead 114 into underground formation 118. Tubular 116 is illustrative of a production tubing. After being ejected from tubular 116, the fluids can then penetrate underground formation 118. A pump 120 can be configured to raise the fluid pressure to a desired level before introduction into the formation. ΜΛ / a / ZUZZ / UI OI / u tubular 116. Figure 2 shows an illustrative schematic of a subsea riser structure in fluid communication with a subsurface formation. As shown in Figure 2, the tubular 230 extends from the platform or vessel 232 to the well 234, which extends below the seabed 236 and penetrates the subsurface formation 238. The derrick 240 is located on the platform or vessel 232 above the waterline 242. The subsea riser extends between the platform or vessel 232 and the well 234, spanning at least the distance between the waterline 242 and the seabed 236, and also passes through a blowout preventer 246. The tubular 230 is located within the subsea riser structure 244, and the ring 248 is defined between them. It should be recognized that the systems depicted in Figures 1 and 2 are illustrative only, and various additional components may be present that are not necessarily shown in Figure 1 or Figure 2 for the sake of clarity. The dissolving fluid can be used to contact inorganic scale on the surface of the pipe in the aforementioned group or other equipment at aboveground locations where inorganic scale may form upstream of a well or at downhole locations.Additional, but not limited to, components that may be present include casing, supply hoppers, valves, condensers, adapters, gaskets, gauges, sensors, compressors, pressure controllers, pressure sensors, flow rate controllers, an inlet flow control device, solvent devices, flow rate sensors, temperature sensors, a marine riser, an umbilical pipe, a chemical injection line, a subsea flow line, electric submersible pumps (ESPs), manifolds, and inlet flow control devices. The solvent fluid is supplied through components that allow for its injection. For example, the solvent fluid can be injected through the main line, which is the flow line that carries hydrocarbons and fluids from the well to a gathering facility.Alternatively, for example, the solvent fluid can be injected using a coiled pipe. Figure 3 is a schematic illustrating a downhole portion 30 of the example solvent fluid delivery system 10 illustrated in Figure 1. As illustrated, tubular 316 is disposed within well 340 and comprises an inorganic scale 345. Tubular 316 is illustrative of a production tubing. In some examples, the inorganic scale 345 may restrict fluid flow through tubular 316. In the illustrated example, the inorganic scale 345 is disposed on the inside of tubular 316. In some examples, the inorganic scale 345 may be disposed on the outside of tubular 316. Solvent fluid 350 is pumped into tubular 316 to the target location where the inorganic scale 345 is disposed. Solvent fluid 350 can be MA / a / ZUZZ / UI OI / u pump to the target location by any method, as will be evident to a person of average skill. The solvent fluid 350 may be conveyed to the target location through tubular 316, through a ring between tubular 316 and the underground formation wall 318, or through a ring between tubular 316 and a conduit concentric with tubular 316. When placed at the target location, the solvent fluid 350 may remain stationary. The well need not be shut in or sealed, as the solvent fluid 350 comes into contact with the metal sulfate scale 345, although the well may be shut in or sealed if desired. By remaining stationary, it is understood that the pumping of the solvent fluid 350 is stopped and the solvent fluid 350 does not circulate in well 340.Then, the solvent fluid 350 can be brought into contact with the metal sulfate scale 345 and dissolve at least a portion of the inorganic scale 345 during a desired reaction time. Solvent fluid Compositions for removing a mineral phase from a surface are solvent fluids that include a phosphonoalkyl aminopolycarboxylic acid chelating agent, a wettability modifier comprising an anionic alkyl sulfonate and / or anionic aryl sulfonate surfactant, a base fluid, a pH adjusting agent, a scale converter, and optionally, a synergistic agent. N-(Phosphonomethyl)iminodiacetic acid (PMIDA) is an example of a phosphonoalkyl aminopolycarboxylic acid chelating agent. In particular, PMIDA has groups with phosphonic (R-(CH2)x-(O)P(OH)2) and aminocarboxylic (RN-(CH2)x-C(O)(OH)2) functional groups. Linear alkylbenzenesulfonate surfactants are illustrative of anionic salts that are an anionic alkyl sulfonate surfactant and an anionic aryl sulfonate surfactant. The solvent fluid can be formed by combining a chelating agent fluid with a wettability modifier in the presence of a pH adjuster and a scale converter. The chelating agent fluid may include the chelating agent, one or more other components, and water as the base fluid. Water can also be the base fluid of the solvent fluid. Alternatively, the solvent fluid can be formed by combining the chelating agent, the wettability modifier, one or more other components, and water as the base fluid. The solvent fluid does not require the use of a secondary mineral or organic acid stage to remove the mineral phase. That is, methods for removing a mineral phase with the solvent fluid can simply involve contacting the mineral phase with the compositions in a single-stage dissolution process. A person of intermediate skill will understand that the solvent fluid can be used in a method for removing a mineral phase that includes other process stages, such as post-purge or displacement fluid, where there may be multiple cycles of the single-stage process. MA / a / ZUZZ / UI OI / u for example, n stages with a new and fresh treatment fluid, where n is an integer, at least 2. The dissolving fluid is effective in achieving at least 50% or more, for example, at least 75%, such as at least 90%, dissolution of the mineral phase within a contact period of between 0.5 and 72 hours, for example, between 0.5 and 8 hours, such as between 0.5 and 6 hours. A person of average skill will understand that the characteristics found in a well can limit the effect of the dissolving fluid. Dissolving at least 90% or at least 75% of the calcium sulfate scale can be achieved within the limits of physical inspection or verification, which is only measured or detected indirectly by comparing the production rate, or productivity, or another parameter, such as the temperature within the well, or by measuring the pressure drop along the production string, or, in more rigorous processes, by using a video camera image of the well.Therefore, the dissolution rate can be at least 90% or at least 75% according to the specification and data validation, whereas, under field circumstances, the amount that can be dissolved may be at least 50% due to insufficient surface-to-mass contact, for example. The lower dissolution capacity is not a consequence of the fluid properties, but rather of the operating and field conditions. chelating agent The chelating agent is capable of chelating a metal ion in the mineral phase. The metal ions that the chelating agent can chelate include group 2 or HA (alkaline earth metals), group 13 or NIA, and transition metals (groups 3 through 12). Chelation involves the formation of two or more metal-ligand bonds, where the chelating agent is a multidentate ligand. In one or more embodiments, the chelating agent is a phosphonoalkyl aminopolycarboxylic acid chelating agent. The chelating agent is present in the solvent fluid in an amount effective for the solvent fluid to remove a certain amount of the mineral phase. For example, the solvent fluid containing the chelating agent can remove at least 50% of the mineral phase, at least 75% of the mineral phase, or at least 90% of the mineral phase. For example, the chelating agent can be present in the amount of 5–40% by weight in the solvent fluid.In one or more embodiments, the chelating agent has a certain degree of biodegradability. In one or more embodiments, the chelating agent is a phosphonoalkyl chelating agent, i.e., a chelating agent that includes a phosphonoalkyl moiety. The chelating agent may be an organic compound. Therefore, the phosphonoalkyl chelating agent may be an organic phosphonoalkyl compound, i.e., an organic compound that includes a phosphonoalkyl moiety. Suitable organic compounds that include a phosphonoalkyl moiety include N-(phosphonomethyl)iminodiacetic acid (PMIDA) or salts thereof, N-(carboxymethyl)-N-(phosphonomethyl)glycine, glycine, N,N'-1,2-ethanendilbis(N-(phosphonomethyl) ML / a / ZUZZ / UI OI / u glyphosine; aminotrimethylenephosphonic acid; sodium aminotris(methylenephosphonate); N-(2-hydroxyethyl)aminobis(methylphosphonic acid), phosphonic acid, P,P'-((2-propen-1-ethylamino)bis(methylene))bis-; phosphonic acid, P,P',P-(nitrotris(methylene))tris-; (nitrotris(methylene))triphosphonic acid; ((methylamino)-dimethylene)bisphosphonic acid; phosphonic acid, P,P',P,P'-(oxybis(2,1-ethanylnitrilobis(methylene))tetrakis-; ((propylamino)bis(methylene))diphosphonic acid; phosphonic acid; P,P',P-(nitrilotris(methylene))tris-; (ethylenedinitril)-tetramethylenephosphonic acid; ethylenebis(nitrilodimethylene)tetraphosphonic acid; (ethylenebis(nitrilobis-(methylene)))-tetrakisphosphonic acid; tetrasodium tetrahydrogen (ethan-1,2-diylbis(nitrilobis-(methylene)))-tetrakisphosphonate; 6-(bis(phosphonomethyl)amino)hexanoic acid; acid (phenylmethyl)amino)-bis(methylene)bisphosphonic acid; phosphonobutantricarboxylic acid, 2-hydroxyphosphonodicarboxylic acid;a sodium, potassium or ammonium salt of any member of the group herein and mixtures thereof; and any combination thereof.; In one or more embodiments, chelating agents that include a phosphonoalkyl portion have the following structure: MA / a / ZUZZ / UI OI / u OR4 O=P-OR5 R1 may be selected from the group consisting of: an (Oi to Cw) alkyl, an (Oi to Cw) alkenyl, an (Ci to Cio) alkynyl, an acyl, an aryl, acetate, a carboxyl, a hydrogen atom, and a phosphonate. R2 may be selected from the group consisting of: an (Oi to Ce) alkyl, an (Ci to Cw) alkenyl, an (Ci to Cw) alkynyl, an acyl, an aryl, acetate, a carbonyl, a hydrogen atom, a phosphonate, or a phosphonoalkylamine. R3 may be selected from the group consisting of: an (C1 to Cw) alkyl, an (Ci to Cw) alkenyl, an (Ci to Cw) alkynyl, an acyl, an aryl, acetate, a hydrogen atom, and a phosphonoalkylamine. Each of R4 and R5 can be independently selected from the group consisting of: an (Ci to Cw) alkyl, an (Ci to Cw) alkenyl, an (Ci to Cw) alkynyl, an acyl, an aryl, acetate, H, Li, Na, K, Cs, NH4, or a phosphonoalkylamine. In one or more embodiments, x can be an integer in the range of about 1 to about 6.In one or more embodiments, y can be an integer in the range from about 0 to about 6. In one or more embodiments, z can be an integer in the range from about 0 to about 6. In one or more embodiments, the chelating agent comprising a phosphonoalkyl portion may comprise a metallated diacetoaminophosphonate. As used herein, the term metallated refers to the conjugate base form of the species, where the metal is a group 1, 2, or 3 metal or a divalent, trivalent, or quadrivalent cationic or positively charged ionic species. In one or more embodiments, the organic compound comprising a phosphonoalkyl portion may comprise an N(phosphonoalkyl)iminodiacetic acid salt. In one or more embodiments, the organic compound comprising a phosphonoalkyl portion may comprise an N(phosphonomethyl)iminodiacetic acid salt having the following structure: OR1< O -P-OR2 MA / a / ZUZZ / UI OI / u R4O^..J OR3 EITHER Each of R1, R2, R3, and R4 can be selected independently from the group consisting of: H, Li, Na, K, Cs, Be, Mg, Ca, Sr, Ba, Cr, Fe, Mn, Co, Ni, Cu, Ga, In, NH4+, and any combination thereof. PMIDA is an effective chelating agent for a wide variety of metal ions with a consistent stability range. In one or more embodiments, chelating agents that include a phosphonoalkyl portion have the following structure: R4OSxO r5o-px R1^ R1 may be selected from the group consisting of: an (Ci to Cio) alkyl, an (Ci to Cio) alkenyl, an (Ci to Cw) alkynyl, an acyl, an aryl, acetate, a carboxyl, a hydrogen atom, and a phosphonate. R2 may be selected from the group consisting of: an (Ci to Ce) alkyl, an (Ci to Cw) alkenyl, an (Ci to Cio) alkynyl, an acyl, an aryl, acetate, a carbonyl, a hydrogen atom, a phosphonate, or a phosphonoalkylamine. R3 may be selected from the group consisting of: an (Ci to Cw) alkyl, an (Ci to Cio) alkenyl, an (Ci to Cio) alkynyl, an acyl, an aryl, acetate, a hydrogen atom, and a phosphonoalkylamine. Each of R4 and R5 can be selected independently from the group consisting of: an (Ci to Cw) alkyl, an (Ci to Cw) alkenyl, an (Ci to Cw) alkynyl, an acyl, an aryl, acetate, H, Li, Na, K, Cs, Be, Mg, Ca, Sr, Ba, Cr, Fe, Mn, Co, Ni, Cu, Ga, In, NHL, or a phosphonoalkylamine. In one or more embodiments, x may be an integer in the range of about 1 to about 6. In one or more embodiments, y may be an integer in the range of about 0 to about 6. In one or more embodiments, z may be an integer in the range of about 0 to about 6. In one or more embodiments, the chelating agent is an aminocarboxylic acid chelating agent. As used herein, the term aminopolycarboxylic acid chelating agent refers to a compound having one or more amino groups and two or more carboxylic acid groups, any salt of such acid, any derivative of such acid, or any combination thereof. Suitable aminopolycarboxylic acid chelating agents that have some degree of biodegradability include glutamic diacetic acid (GLDA), methylglycine diacetic acid (MGDA), β-alanine diacetic acid (β-ADA), ethylenediaminedisuccinic acid, S,S-ethylenediaminedisuccinic acid (EDDS), aminodisuccinic acid (IDS), hydroxyiminodisuccinic acid (HIDS), polyaminodisuccinic acid, N-bis[2-(1,2-dicarboxyethoxy)ethyl]glycine (BCA6), N-bis[2-(1,2-dicarboxyethoxy)ethyl]aspartic acid (BCA5), Nbis[2-(1,2-dicarboxyethoxy)ethyl]methylglycine (MCBA5), and N-tris[(1,2-dicarboxyethoxy)ethyl]amine (TCA6),N-bis[2-(carboxymethox¡)ethyl]gl¡c¡ne (BCA3), N-bis[2-(met¡lcarbox¡methox¡)andl]glycine (MCBA3), N-methyliminodiacetic acid (MIDA), iminodiacetic acid (IDA), N-(iminodiacetamide),ethic acid hydroxymethyl-iminodiacetic, 2-(2carboxyethylamino)succinic acid (CEAA), 2-(2-carboxymethylamino)succinic acid (CMAA), dietritic acid, tr-nethyl,n-disuccinic acid, 1,6hexamet¡lend¡am¡nN,N'-d¡succin¡co, tetraethylenepentamine-N,Nd¡succin¡co, 2hydroxypropylene-1,3-d¡am¡nNN,N'-d¡succyn¡co, 1,amine-dipropylene acid,N'amine-dipropylene 1,3-propylend¡am¡nN,N'-disuccin¡co, c¡sc¡clohexandiamine-N,N'-d¡succinic acid, transcyclohexandiamine-N,N'-disuccin¡co acid, et¡lenb¡s(ox¡colene,dNcctrile)-acid glucoheptanoic, cysteic acid-Ν,Ν-diacetic acid, cysteic acid-N-monoacetic acid, alanine-N-monoacetic acid, N-(3-hydroxysucc¡nyl) aspartic acid, N-[2-(3-hydroxysuccinyl,)]Aspartic acid-N,N-diacetic acid, aspartic acid-N-monoacetic acid, any salt of these, any derivative of these, or any combination thereof. Particularly suitable biodegradable chelating agents that can be used in a solvent fluid include, for example, MGDA, GLDA, EDDS, -ADA, IDS, TCA6, BCA3, BCA5, BCA6, MCBA3, and MCBA5. In one or more embodiments, additional chelating agents may be included in the solvent fluid, such as, for example, ethylenediaminetetraacetic acid (EDTA), propylenediaminetetraacetic acid (PDTA), nitrilotriacetic acid (NTA), N-(2-hydroxyethyl)ethylenediaminetetraacetic acid (HEDTA), diethylenetriaminepentaacetic acid (DTPA), hydroxyethylaminodiacetic acid (HEIDA), cyclohexylenediaminediaminetetraacetic acid (CDTA), diphenylaminesulfonic acid (DPAS), acid, MA / a / ZUZZ / UI OI / u ethylenediaminedi(o-hydroxyphenylacetic) (EDDHA), any salt of these, any derivative of these or similar. In one or more embodiments, the chelating agent is selected from combinations of any of the chelating agents described herein. In one or more embodiments, one or more chelating agents may be added to the solvent fluid separately from the wettability modifier composition. In such embodiments, the solvent fluid may include the chelating agent in an amount of approximately 0.005 wt% to approximately 60 wt% by volume of the base fluid in the treatment fluid. In one or more embodiments, the solvent fluid may include one or more wettability modifiers of this disclosure in an amount of approximately 0.01 wt% to approximately 40 wt% by volume of the base fluid. In one or more embodiments, the solvent fluid may include one or more wettability modifier compositions of this disclosure in an amount of approximately 0.05 wt% to approximately 20 wt% by volume of the base fluid.In one or more embodiments, the solvent fluid may include one or more wettability modifier compositions of the present disclosure in an amount of about 0.05% by weight to about 5% by weight per volume of the base fluid. In one or more embodiments, chelating agents may be added to the aqueous phase of the wettability modifier composition, and the wettability modifier composition, in turn, may be added to the solvent fluid. In such embodiments, the aqueous phase of the wettability modifier composition may include the chelating agent in an amount from about 0.005 wt% to about 10 wt% by volume of the aqueous phase. In one or more embodiments, the aqueous phase of the wettability modifier compositions may include one or more of the wettability modifier compositions of this disclosure in an amount from about 0.01 wt% to about 5 wt% by volume of the aqueous phase.In one or more embodiments, the aqueous phase of the wettability modifier compositions may include one or more surfactant compositions of this disclosure in an amount of about 0.05% by weight to about 2% by weight by volume of the aqueous phase. Wettability modifier The wettability modifier is capable of converting the surface of the mineral phase from oil-wet to water-wet. The wettability modifier is present in the solvent fluid in an amount effective in improving the removal of the mineral phase by the solvent fluid compared to a reference solvent fluid that is identical except that it omits the wettability modifier. For example, the MA / a / ZUZZ / UI OI / u wettability modifier may be present in the amount of 0.1 to 2% v / v in the solvent fluid. The improvement may be in the amount of time it takes the solvent fluid to dissolve a quantity of the mineral phase, for example, the amount of time to dissolve a quantity of the mineral phase. The wettability modifier is effective in enabling the solvent fluid to achieve at least 50% or more, for example, at least 75%, such as at least 90%, dissolution of the mineral phase in a contact period of between 0.5 and 72 hours, for example, between 0.5 and 8 hours, such as between 0.5 and 6 hours. The wettability modifier may include a nonionic or anionic surfactant, or a combination of nonionic and / or ionic surfactants. A nonionic species does not dissociate into its ionic species, for example, in a neutral pH aqueous solution. As used herein, anionic and nonionic are used to describe the organic portion of an organic molecule or a salt thereof. An ionic organic portion may form an ionic bond with another element or another portion of the molecule. It should be understood that anionic is a type of ionic species. Nonionic surfactants contain a hydrophilic head containing covalently bonded oxygen to a hydrophobic tail, where the latter is more strongly attracted to hydrocarbons and the former to water. Anionic surfactants are organic substances that, when dissolved in water, form negatively charged particles called anions.These anionic surfactants have negatively charged hydrophilic ends that are used to attract water. The wettability modifier can be an emulsion. The emulsion can be a microemulsion. The microemulsion can have droplet sizes of the internal phase of the emulsion in the external phase of the emulsion ranging from approximately 0.001 micrometers to approximately 1,000 micrometers, from approximately 1 micrometer to approximately 1,000 micrometers, or from approximately 1 micrometer to approximately 100 micrometers. The emulsion can also be a nanoemulsion. The nanoemulsion can have droplet sizes of the internal phase of the emulsion in the external phase of the emulsion ranging from approximately 1 nm to approximately 1,000 nm, from approximately 5 nm to approximately 200 nm, or from approximately 10 nm to approximately 100 nm. The wettability modifier can be a non-emulsifier. Non-emulsifiers are used to reduce the tendency for emulsions to form by lowering the interfacial tension between the hydrocarbon and water. These emulsions can clog formations, making it difficult to contact the mineral phase with the chelating agent fluid. Non-emulsifiers can be used to break any emulsions that may have formed on the mineral surface. When the wettability modifier includes a diethanolamide of a TOFA or an ethoxylated ester of a TOFA, the TOFA may be an alkanolamide surfactant, which is a (C1-C50) hydrocarbyl amide having R1 and R2 groups substituted on the amide nitrogen, in MA / a / ZUZZ / UI OI / u where each of R1 and R2 is selected independently from the group consisting of -H, (C1-C50)hydrocarbyl and -(C1-C50)hydrocarbylene-OH, wherein at least one of R1and R2is (C1-C50)hydrocarbylene-OH. An alkanolamide surfactant that has the structure: ΜΛ / a / ZUZZ / UI OI / u R2 where R3 is a substituted or unsubstituted (C12-C25)-hydrocarbyl of a resin oil fatty acid having the structure R3-C(O)-OH, and each of R1 and R2 is independently (C1-C10)alkyl-OH. For example, R3 is a substituted or unsubstituted (C16-C18)-hydrocarbyl of a resin oil fatty acid having the structure R3-C(O)-OH. The term "substituted," as used herein, in conjunction with a molecule or organic group as defined herein, refers to the state in which one or more hydrogen atoms contained therein are replaced by one or more non-hydrogen atoms. The wettability modifiers 1 and 2 used in the examples contain a resin oil fatty acid diethanolamide (TOFA) intermediate. The TOFA intermediate is believed to have superior interfacial tension reduction, as well as phase resolution properties.TOFA was used in previous applications as counterflow aids and treatment fluids for formations and produced oil. A wettability modifier component shall be deemed to be specifically described by a class of compounds with the additional description of a quantitative value, for example, the value of a parameter, such as HLB, RSN, or KB. For example, each of the following descriptions shall be deemed to be of the type known to persons of the mid-level trade: TOFA diethanolamide (HLB 7), ethoxylated sorbitol alcohol (RSN 16), emulsified 9-decenoic acid methyl ester (KB 85); with a secondary ethoxylated alcohol (HLB 12), TOFA diethanolamide (HLB 7), TOFA ethoxylated ester (HLB 14), ethoxylated phenol-formaldehyde resin (RSN 11), tridecyl alcohol (HLB 9), C12-C16 ethoxylated alcohol (HLB 12), glycerol-initiated polyol (RSN 16), ethoxylated nonylphenyl NPE oligomer (HLB 9), or resin alkoxylate (RSN 13). C12-C16 indicates 12-16 carbon atoms.HLB is the hydrophilic-lipophilic equilibrium, which is a measure of the degree to which a surfactant is hydrophilic or lipophilic, where lower values ​​indicate increased lipophilicity and higher values ​​indicate increased hydrophilicity. Those in the mid-level trade are familiar with its determination, for example, using the Griffin method or the Davies method (Griffin WC: Classification of Surface-Active Agents by HLB, Journal of the Society of Cosmetic Chemists 1 (1949): 311; Griffin WC: Calculation of HLB Values ​​of Non-Ionic Surfactants, Journal of the Society of Cosmetic Chemists 5 249 (1954): 249; Davies, JT, A. Quantitative Kinetic Theory of Emulsion Type I. Physical Chemistry of the Emulsifying Agent, Gas / Liquid and Liquid / Liquid Interface, Proceedings of the International Congress of Surface Activity (1957): 426-438). RSN is the relative solubility amount, which is a measure of the relative surfactant solubility in water and in oil, where smaller amounts indicate an increase in oil solubility and larger amounts indicate an increase in water solubility. People of intermediate skill are familiar with its determination, for example, by an empirical method of adding a volume of water in milliliters to produce turbidity in a composition of 1 g of surfactant and 30 mL of benzene / dioxane solvent (Jiangying Wu et al., Development of a method for measurement of relative solubility of nonionic surfactants, Colloids and Surfaces A: Physicochem. Eng. Aspects 232 (2004): 229). KB is the kauri-butanol value, which is a measure of the resistance of a solvent.People in the mid-level trade are familiar with its determination, for example, when measuring the amount of solvent that can be added to kauri resin in butyl alcohol without causing cloudiness according to the ASTM D1133 standard test method for the kauri-butanol value of hydrocarbon solvents. Wettability modifier formulation 1 In one or more embodiments, the wettability modifier includes a mixture of an anionic surfactant, an alcohol, and water. The mixture may optionally include a solvent, such as an organic solvent. The organic solvent may be an oil. The mixture may additionally include water. The present inventors discovered that wettability modifiers containing an anionic alkyl sulfonate or anionic aryl sulfonate surfactant improve the performance of a phosphonoalkyl aminopolycarboxylic acid chelating agent for mineral phase removal. Furthermore, the present inventors discovered that an anionic alkyl sulfonate or anionic aryl sulfonate provides a further improvement when an organic solvent, for example, a dibasic ester solvent, is included in the wettability modifier. An anionic surfactant may include an anionic salt. The anionic salt may be an anionic alkyl sulfonate or an anionic aryl sulfonate. The anionic salt may be a linear alkylbenzenesulfonate salt, an alpha-olefin sulfonate salt, an oleic sulfonate salt, a branched alkylbenzenesulfonate salt, a lauryl sulfate salt, an alkyldiphenyloxide disulfonate salt, a combination of an alkyl sulfonate and an aryl sulfonate salt (molecular weight 250–600), an alkonoate salt, or combinations thereof. The salt may include a cation source, for example, one or more of triethylamine, isopropylamine, iodine, or sodium. The cation may be monovalent, divalent, or have a higher valency. The alkyldiphenyloxide disulfonate salt can be a C6-C18 diphenyloxide disulfonate salt. The solvent can be a dibasic ester. The solvent can be dimethyl 2-methylglutarate, methyl 9-decenoate, methyl 9-dodecenoate, N,N-dimethyl 9-decenamide, diethylcarbonate, triethyl citrate. ML / a / ZUZZ / UI OI / u dimethyl 2-methylglutarate, dodecylacetate, 1-dodecyl-2-pyrrolidinone, 2-dodecyl-pyrrolidinone, N(CgH^nCHs-pyrrolidinone (where n is from about 1 to about 22), n-octylpyrrolidinone, dibutyl ether, isoamyl ether, di-n-amyl ether, dihexyl ether, heptyl ether, dioctyl ether, dodecyl ether, benzylhexyl ether, di-n-alkyl ethers having the formula O[(CH2)xCH3]2 (where x is from about 3 to about 35), a linear or branched dibasic ester having the formula CH3OC(O)(CH2)xC(O)OCH3 (where x is from about 2 to about 10), CH3OC(O)(CH2)xCHCH3(CH2)yC(O)OCH3 (where each of x and y is independently from about 2 to about 10), CH3OC(O)(CH2)xC(CH3)2(CH2)yC(O)OCH3 (where each of x and y is independently from about 2 to about 10), a linear or branched dibasic -ru- W ester having the structure .or (where each of xyz is independently from about 0 to about 10, where y is from about 0 to about 6, where each R is independently selected from the group consisting of methyl, ethyl, n-propyl, isopropyl, n-butyl, and sec-butyl, and where Ri is H or CH3) or any combination thereof. In one or more embodiments, the solvent may include a linear dibasic ester, a branched dibasic ester, and combinations thereof. In one or more embodiments, the solvent may include one or more alkyl esters of alkylated dibasic esters (Kb value of 45–90). In one or more embodiments, the solvent may include one or more N-alkylpyrrolidinines (Kb value of 91–130).In one or more embodiments, the solvent may include dimethyl 2-methylglutarate, 1-dodecyl-2-pyrrolidinone, N-(C2H4)nCH3-pyrrolidinone (where n is from about 6 to about 12), dimethyl succinate, dimethyl glutarate, dimethyl adipate, dimethyl2-methyladipate, or combinations thereof. The alcohol can be an alkyl alcohol, an aromatic alcohol, or combinations thereof. The alkyl alcohol can be one or more of methanol, ethanol, 1-propanol, 2-propanol, 1-butanol, 2-butanol, 3-butanol, and the like, or combinations thereof. Wettability modifier formulation 2

[0044] In one or more embodiments, the wettability modifier includes a non-ionic mixture of an alkanolamide and an alkoxylated alcohol, for example, a mixture containing a TOFA diethanolamide (HLB 7) and an ethoxylated sorbitol alcohol (RSN 16), and water. Wettability modifier formulation 3 In one or more embodiments, the wettability modifier includes a non-ionic microemulsion that is a mixture of an emulsified 9-decenoic acid methyl ester (KB value of 85), a secondary ethoxylated alcohol (HLB 12), a diethanolamide of a TOFA (HLB 7), an ethoxylated ester of a TOFA (HLB 14), an ethoxylated phenol-formaldehyde resin (RSN 11) and a tridecyl alcohol (HLB 9), and water. Wettability modifier formulation 4 In one or more embodiments, the wettability modifier includes a non-ionic non-emulsifying mixture of a nonylphenyl ethoxylated oligomer (NPE) (HLB 9) and a resin alkoxylate (RSN 13), and water. Wettability modifier formulation 5 In one or more embodiments, the wettability modifier includes a mixture of a C12-C16 ethoxylated alcohol (HLB 12) and a glycerol-initiated polyol (RSN 16), and water. Base fluid The solvent fluid is aqueous. The solvent fluid may be free of water-insoluble or water-immiscible agents. Examples of suitable aqueous fluids include fresh water, salt water, brine, seawater, and / or any other aqueous fluid that does not interact undesirably with the other components used in accordance with the present embodiments or with the underground formation. Other components The solvent fluid also contains a pH adjusting agent and a scale-converting agent. In one or more embodiments, the solvent fluid excludes synergistic agents. The pH adjusting agent provides a neutral or alkaline pH to the solvent fluid. The pH adjusting agent is a base, specifically a Brønsted base. The pH adjusting agent can be a strong base, meaning a base that completely dissociates in water. The pH adjusting agent can be used to adjust the pH of the solvent fluid to a value of at least 7. The pH adjusting agent can be used to adjust the pH of the solvent fluid to a value greater than 9. The pH adjusting agent can be used to adjust the pH of the solvent fluid to a maximum value of 10. The pH adjusting agent can be a metal hydroxide, such as lithium hydroxide, sodium hydroxide, cesium hydroxide, potassium hydroxide, or similar, or ammonium-containing hydroxides, specifically NH₄OH and quaternary ammonium hydroxides R₄NOH, where R can be a C₁-C₁₀ alkyl group.When used, the pH adjusting agent is present in the solvent fluid in an amount effective to provide a neutral or alkaline pH to the solvent fluid. The scale-converting agent converts scale into an alternative form. For example, the scale-converting agent can convert calcium sulfate into a form that is more soluble in, for example, the solvent fluid, another treatment fluid, and / or acidic fluid. The scale-converting agent can be a metal carbonate or metal bicarbonate of a Group 1 metal or NH4+. For example, the scale-converting agent can be a salt of sodium, potassium, lithium, cesium, or ammonium bicarbonate. ML / a / ZUZZ / UI OI / u When used, the scale-converting agent is present in the solvent fluid in an amount effective to convert the scale into an alternative form. Synergistic agents The solvent fluid optionally also contains a synergistic agent. In one or more embodiments, the solvent fluid excludes synergistic agents. Alternatively, in one or more embodiments, the solvent fluid includes a synergistic agent. The synergistic agent increases the scale-dissolving activity of the solvent fluid. The synergistic agent may be a complexing agent. Alternatively, or in combination, the synergistic agent may act as a catalyst. The synergistic agent may be a carboxylic or polycarboxylic acid, such as a hydroxy(poly)carboxylic acid. Examples include acids, or their respective metal salts, of oxalic, lactic, maleic, malonic, gluconic, glucaric, acetic, hydroxyacetic, citric, or glucoheptonic acids. The synergistic agent may be an organochloride. For example, the organochloride may be a C2 or C3 organochloride. The auxiliary agent may include halide, halocarboxylate, carboxylate, or other oxyanions. When used, the synergistic agent is present in the solvent fluid in an amount effective in increasing the scale-dissolving activity of the solvent fluid. Methods Methods for removing a mineral phase from a surface include contacting the mineral phase with an aqueous solvent fluid and removing the mineral phase with the solvent fluid. The solvent fluid, which includes a wettability modifier as a wetting additive in combination with a complexing agent, modifies the wetting phase. Specifically, the solvent fluid, including the wetting additive, overcomes undesirable wettability and thus increases the reactivity of the oil-wetted inorganic sulfate scale to the rest of the solvent composition. These wettability modifiers act as both a wetting and penetrating additive, allowing for increased penetration of the complexing agent into the scale network, resulting in greater dissolution than without the wettability modifiers. Methods may also include removing a hydrocarbon phase from the mineral phase.Therefore, the methods can be applied when the mineral phase is wetted with oil. The combination of the complexing agent and the wettability modifier improves the reactivity of oil-wetted inorganic scale with aqueous solvent fluids. The surfactant reduces the interfacial tension between the oil and water, thereby decreasing capillary pressure. The surfactant can also alter the wettability of the rock, making the formation more susceptible to wetting with water or a mixture. This reduction in interfacial tension and / or alteration of rock wettability allows the remaining solvent fluid to be more effective. The present compositions, in MA / a / ZUZZ / UI OI / u Compared to scale-dissolving compositions that include a complexing agent fluid but exclude a wettability-modifying wetting additive, the complexing agent fluid's performance as a scale solvent is improved. The wetting additive is able to modify the wetting phase from oil-wet to water-wet, allowing the solvent fluid to react in less time than a corresponding scale-dissolving composition that excludes the wetting additive. Methods for removing a mineral phase do not require the use of a secondary mineral or organic acid stage. In other words, methods for removing the mineral phase can simply involve contacting the mineral phase with the compositions in a single-stage dissolution process. A person of intermediate skill will understand that other process stages may occur in some cases, such as a post-purge or displacement fluid. Furthermore, there can be multiple cycles of the single-stage process, for example, n stages with a fresh, new treatment fluid, where n is an integer, at least 2. Methods for removing the mineral phase are capable of achieving at least 50% or more—for example, at least 75%, or at least 90%—of mineral phase dissolution within a contact period of 0.5 to 72 hours, or 0.5 to 8 hours, or 0.5 to 6 hours. A person of average skill will understand that the characteristics found in a wellbore can limit the effect of the dissolving fluid. Dissolving at least 90% of the calcium sulfate scale can be achieved within the limits of physical inspection or verification, which is only measured or detected indirectly by comparing the production rate, or productivity, or another parameter such as the temperature within the wellbore, or by measuring the pressure drop along the production string, or, in more rigorous processes, by using a video camera image of the wellbore.Therefore, the dissolution rate can be at least 90% according to the specification and data validation, but in field circumstances, the amount that can be dissolved may be at least 50% due to insufficient surface-to-mass contact, for example. The lower dissolution capacity is not a consequence of the fluid properties, but rather of the operating and field conditions. To perform these methods, well production may need to be temporarily suspended. The solvent fluid can be applied wherever a mineral phase is present, by contacting a partially or completely wetted inorganic sulfate scale with petroleum containing a mineral phase located or deposited on a surface or within a matrix. The solvent fluid can be applied in underground formations with temperatures below the decomposition temperature of the chelating agent. For example, the decomposition temperature of PMIDA in its pure form is 204°C. ML / a / ZUZZ / UI OI / u (399°F). When the methods are completed, the evacuation of the solvent fluid may vary. Production can be resumed and the solvent fluid can be evacuated from the well with a produced hydrocarbon product. Alternatively, the solvent fluid can be evacuated separately before starting. The method and solvent fluid composition also have the benefit of not requiring a secondary fluid addition stage, such as a mineral acid like hydrochloric acid, or an organic acid with sufficient acid resistance, such as acetic acid, formic acid, or methanesulfonic acid, to dissolve the byproduct of the first stage (calcium carbonate). Therefore, this disclosure provides for the removal of the mineral phase in a single-stage dissolution process without the need to contact the mineral phase with a second wash or soak using an organic or solvent to handle the contaminant or hydrocarbon residue in the inorganic material. The time it takes to dissolve sulfate scale depends on the temperature and can vary from 0.5 hours to 72 hours. For example, if an underground formation or the surface of equipment is at 200°F or higher, it may take no more than two hours to remove the scale, or no more than one hour, or no more than 0.5 hours. The compositions provide solutions that can reduce the treatment time, or shutdown period, from the standard 24-hour treatment time to two hours for dissolving anhydrite scale (CaSOU). Achieving efficiency by improving scale dissolution can translate into higher equipment utilization rates. The proposed compositions shorten the dissolution time, which represents downtime. When the temperature is between ambient and 200°F, it can take between 4 and 8 hours to remove the scale. Ambient temperature is defined as 68-73°F. The compositions and methods can be applied to geothermal well descaling, anhydrite dissolution in a reservoir matrix, and / or restimulation treatments in unconventional reservoirs. Reservoir blending may include fracture etching or matrix dissolution for selective stimulation. Restimulation treatments may include unconventional reservoirs where scaling is not confined to the wellbore, but due to the well's length and area, it is difficult to inject a treatment volume that can reach any substantial area beyond the drilled zone. One or more specific embodiments of the acidizing composition for improved fluid performance have been described. In an effort to provide a concise description of these embodiments, it is possible that not all features of an actual implementation will be described in the specification. It should be noted that, in the development of any actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made. MA / a / ZUZZ / UI OI / u to achieve specific developer objectives, such as compliance with system-related and business-related constraints, which may vary from implementation to implementation. Furthermore, it should be appreciated that such a development effort could be complex and time-consuming, but nevertheless would be a routine design, fabrication, and manufacturing task for mid-level tradespeople who benefit from this disclosure. Certain terms are used throughout the description and claims to refer to particular features or components. As someone of average skill will appreciate, different people may refer to the same feature or component by different names. This document does not purport to distinguish between components or features that differ in name but not in function. Unless otherwise stated, a numerical parameter “n” expressing quantities used in this disclosure and associated claims means approximately n. Accordingly, unless otherwise stated, reference to a numerical parameter in the specification and accompanying claims is an approximation that may vary depending on the property the numerical parameter represents and the measurement method used to determine that property. For example, the approximation may be at least that of significant digits, with each numerical parameter provided to no more than n significant digits. For example, the appropriate number of significant digits associated with a measurement method is a reference to the degree of approximation. For numerical parameters reported in alternative units, common rounding techniques apply.For example, °C and °F are alternative units, and kilogram (kg) and pound (lb) are alternative units. Whenever a numerical range with a lower and upper bound is disclosed, any number and any range included within the range is specifically disclosed. In particular, it should be understood that each range of values ​​defines each number and range encompassed within the larger range of values. The reference to "nam" indicates a closed range [n,m]. The reference to "na less than m" indicates a semi-open range [n,m]. The reference to "greater than ny up to m" indicates another semi-open range (n,m). The reference to "greater than ay less than b" indicates an open range (n,m). References throughout this descriptive report to include mean to include, among others. Similarly, references throughout this descriptive report to include means to include, among others. Reference in this specification to an embodiment, embodiments, some embodiments, certain embodiments, or similar expressions means that a particular feature or structure described in relation to the embodiment may be included in at least one embodiment hereof MA / a / ZUZZ / UI OI / u disclosure. Therefore, these phrases or similar expressions throughout this descriptive report may refer to the same form of realization, but not necessarily. To facilitate a better understanding of the disclosure, the following non-limiting examples are provided. These examples are not the only examples that could be provided and are not intended to limit the scope of the disclosure, including the claims. EXAMPLES The examples illustrate the improved performance of the solvent fluid compositions in this disclosure for dissolving mineral phases. EXAMPLE 1 This example illustrates mineral phase compositions, where each mineral phase was a scale deposit. In particular, the mineral compositions of the scale deposit samples were determined using X-ray diffraction analysis. The results shown in Table 1 demonstrate that each extract from each sample contained primarily inorganic sulfate, specifically calcium sulfate. MA / a / ZUZZ / UI OI / u Table 1. XRD mineral analysis of wellbore scale samples XRD Anhydrite (% by weight) Quartz (% by weight) Pyrite (% by weight) Ankerite (% by weight) Aragon (% by weight) Gypsum (% by weight) Inlay sample 1 97 2 1 Inlay sample 2 side 1 96 4 Inlay sample 2 side 2 91 6 3 Inlay sample 3 side 1 100 minimum quantity Inlay sample 3 side 2 87 6 Table 1 shows the results of the X-ray diffraction analyses of the samples. For samples 2 and 3, two sides of the samples were analyzed: one that had been in contact with the equipment and the other that had been exposed to the fluid. The scale samples were mostly anhydrous calcium sulfate with minimal amounts of other minerals, as confirmed by the X-ray diffraction analysis provided in Table 1. % wt is an abbreviation for percent by weight. The results in Table 1 show the measured amounts in the samples of the minerals anhydrite, quartz, pyrite, ankerite, aragonite, and gypsum, as determined by X-ray diffraction analysis. Anhydrite is understood to be anhydrous calcium sulfate, CaSO4. Quartz is understood to be silicon dioxide, SiO2. Pyrite is understood to be iron sulfide, FeS2. Ankerite is understood to be a carbonate mineral with the chemical formula Ca(Fe,Mg,Mn)(CO3)2. Aragonite is understood to be one of the crystalline forms of calcium carbonate, CaCO3, where the crystal lattice system is orthorhombic. Gypsum is understood to be a hydrated calcium sulfate with the chemical formula CaSO4·2H2O. EXAMPLE 2 This example illustrates complexing agent fluid compositions. The formulations shown in Table 2 demonstrate that two complexing agent fluids based on PMIDA as the complexing agent were prepared. Each complexing agent fluid further contained sodium bicarbonate as a scale converter and potassium hydroxide as a pH adjuster, and they differed from each other in the absence (fluid A) or presence (fluid B) of organochloride as an auxiliary agent. ML / a / ZUZZ / UI OI / u Table 2. Compositions of chelating agent fluids Fluid A Fluid B Chelating agent PMIDA 20% w / v 20% w / v Scale converting agent Sodium bicarbonate 10% w / v 10% w / v pH adjustment agent 45% KOH (w / w) up to pH 9.5 up to pH 9.5 Synergistic agent Chloroacetic acid 5% w / v 0 Base fluid Water Total balance for constitute 100 parts of volume Total equilibrium to constitute 100 parts of volume MA / a / ZUZZ / UI OI / u Table 2 shows the compositions of the two different complexing agent fluids. Both compositions A and B were 20% w / v PMIDA and 10% w / v sodium bicarbonate. Composition B additionally contained 5% w / v chloroacetic acid, an organochloride. Composition A did not contain chloroacetic acid. For each composition, a 45% w / v potassium hydroxide (KOH) solution was added in an amount sufficient to achieve a pH of 9.5. The equilibrium for each composition was water to constitute 100 parts of the total volume. % w / v is understood to be an abbreviation for percent weight / volume. % w / v is a concentration and was measured in units of g / 100 mL. Composition A was 20% w / v PMIDA, 10% w / v sodium bicarbonate, and 45% w / v of KOH, 5% w / v organochloride, and water to constitute 100 parts of total volume. Composition B was 20% w / v PMIDA, 10% w / v sodium bicarbonate, 45% by weight of KOH and water to make up 100 parts of total volume. EXAMPLE 3 This example illustrates compositions of candidates evaluated as wettability modifiers. Table 3 shows the candidate wettability modifier formulations. Each formulation included DI water and ethanol. DI water is illustrative of an aqueous base, and ethanol is illustrative of an alcohol. Each formulation did not include any solvent, solvent 1, or solvent 2. Solvent 1 contains dimethyl 2-methylglutarate. Solvent 1 is illustrative of alkyl esters of alkylated dibasic esters (Kb value of 45–90). Solvent 2 contains N-dodecyl-2-pyrrolidone. Solvent 2 is illustrative of N-alkylpyrrolidinones (Kb value of 91–130). Each formulation included one of the following surfactants: surfactant 1, surfactant 2, surfactant 3, or surfactant 4. Surfactant 1 contains a dodecylbenzenesulfonate salt. Surfactant 1 is illustrative of a linear alkylbenzenesulfonate surfactant. Surfactant 2 contains a fatty carboxylic acid diethanolamide (±).Surfactant 3 contains a branched C12-C16 alcohol, ethoxylated with 5-15 moles of ethylene oxide (±). Surfactant 4 contains benzalkonium chloride (+). The solvents and surfactants are commercially available from suitable chemical manufacturers. Table 3. Candidate wettability modifier formulations MA / a / ZUZZ / UI OI / u Formulation % by weight of deionized water % by weight of ethanol Solvent % by weight of solvent Surfactant % by weight of surfactant C-1 35 40 none - Tens. 1 25 C-2 35 40 none - Tens. 2 25 C-3 35 40 none - Tens. 3 25 C-4 35 40 none - Tens. 4 25 C-5 30 25 Solv. 1 20 Tens. 1 25 C-6 25 40 Solv. 1 10 Tens. 2 25 C-7 25 40 Solv. 2 10 Tens. 1 25 C-8 25 40 Solv. 1 10 Tens. 3 25 C-9 25 40 Solv. 1 10 Tens. 4 25 Control 60 40 none - none - EXAMPLE 4 This example illustrates the contact of a solvent fluid with a mineral phase. The respective solvent fluids were applied to three scale samples in equivalent sample-to-fluid mass ratios. Where possible, 0.5 g of mineral phase was mixed with 50 mL of solvent fluid. When the exact amount of 0.5 g of mineral phase was not available, the amount of solvent fluid was extrapolated from the amount applied to 0.5 g of mineral phase to replicate the same mass-to-volume ratio of 0.5 g of mineral phase to 50 mL of solvent fluid. The scale samples were 97–99% anhydrous calcium sulfate. The amounts are shown in the Table 8. The fluid and mineral phase sample was loaded under atmospheric conditions into a glass flask with a loose cap and immediately placed in a water bath set at 200°F (93°C) for 1 hour or 2 hours under static conditions. The flask was removed after the designated time had elapsed, and any remaining sample was discarded and weighed. EXAMPLE 5 This example illustrates the performance of candidate solvent fluids in dissolving the mineral phases, evaluated using the procedure in Example 4. To produce the samples that were evaluated using the procedure in Example 4 to obtain the results described in Example 5, 100 mL of chelating agent fluid A from Example 2 and 2 mL of candidate wettability modifier formulation from Example 3 were combined to produce the candidate solvent fluid. The test results are shown in Table 4, where each solvent fluid is identified by the respective candidate wettability modifier used in the preparation of the corresponding solvent fluid. Table 4. Dissolution of the mineral phase ML / a / ZUZZ / UI OI / u % of dissolution Formulation 1 hour 2 hours C-1 28.73% 59.87% C-2 26.62% 54.79% C-3 21.71% 50.56% C-4 40.56% 72.36% C-5 45.99% 84.89% C-6 21.08% 61.20% C-7 23.84% 61.04% C-8 26.97% 52.26% C-9 30.64% 55.56% Control 42.67% 68.35% The results presented in Table 4 demonstrate the superior performance of formulation C-5. Specifically, this formulation provided improved performance compared to the other formulations and the control. Furthermore, of the candidate formulations, only formulation C-5 resulted in greater dissolution of the calcium sulfate scale, indicative of a mineral phase, than the control. Formulation C-1 exemplifies inventive wettability formulation 1. The results for formulation C-5 shown in Table 4 demonstrate that wettability modifiers containing a linear alkylbenzenesulfonate salt, indicative of an anionic alkyl sulfonate or anionic aryl sulfonate surfactant, enhance the performance of PMIDA, indicative of a phosphonoalkyl aminopolycarboxylic acid chelating agent, for the removal of the mineral phase.The results for formulation 5, compared to formulations C-1 and C-7, demonstrate that the linear alkylbenzenesulfonate surfactant, illustrative of an anionic alkyl sulfonate or anionic aryl sulfonate surfactant, provides a greater improvement when dimethyl 2-methylglutarate, illustrative of a dibasic ester solvent, is included in the wettability modifier. Furthermore, the results for formulation C-5 demonstrate approximately 46% dissolution of the mineral phase in 1 hour and approximately 85% dissolution of the mineral phase in 2 hours, which illustrates, for example, by extrapolation, a removal of at least 90% of the mineral phase within 0.5 to 72 hours, more specifically, between 0.5 and 8 hours, and even more specifically, between 0.5 and 6 hours. SPECIFIC FORMS OF REALIZATION Methods for removing a petroleum-wetted mineral phase comprising an inorganic sulfate from a surface may include contacting the mineral phase with an aqueous solvent fluid comprising a phosphonoalkyl aminopolycarboxylic acid chelating agent, a wettability modifier, a pH adjusting agent, a scale converter, and water, wherein the wettability modifier comprises a dibasic ester and a surfactant, wherein the surfactant comprises one or more anionic alkyl sulfonate or anionic aryl sulfonate; and removing the petroleum-wetted mineral phase from the surface with the aqueous solvent fluid. The methods may include the embodiments in accordance with any of the preceding paragraphs or a combination thereof and may further include removing a hydrocarbon phase from a mineral phase surface with the aqueous solvent fluid. The methods may include embodiments according to any of the preceding paragraphs or a combination thereof, and may further include those in which the mineral phase is contacted with the aqueous solvent fluid only in a single-stage dissolution process. The methods may also include embodiments according to any of the preceding paragraphs or a combination thereof, and may further include those in which at least 50% of the mineral phase is removed within 0.5 to 72 hours. The methods may include the forms of implementation according to any of the preceding paragraphs or a combination thereof and further include where at least 50% of the mineral phase is removed within between 0.5 and 8 hours. The methods may include the forms of implementation according to any of the preceding paragraphs or a combination thereof and further include where the mineral phase comprises calcium sulfate. The methods may include embodiments in accordance with any of the preceding paragraphs or a combination thereof and further include where the surfactant comprises an anionic alkyl sulfonate. ML / a / ZUZZ / UI OI / u The methods may include embodiments in accordance with any of the preceding paragraphs or a combination thereof and further include where the anionic alkyl sulfonate comprises a linear alkylbenzenesulfonate. The methods may include embodiments according to any of the preceding paragraphs or combinations thereof and further include wherein the dibasic ester is selected from the group consisting of dimethyl 2-methylglutarate, 1-dodecyl-2-pyrrolidinone, N-(C2H4)nCH3pyrrolidinone, wherein n is from about 6 to about 12, dimethyl succinate, dimethyl glutarate, dimethyl adipate, dimethyl-2-methyladipate and combinations thereof. The methods may include embodiments in accordance with any of the preceding paragraphs or a combination thereof and further include where the dibasic ester comprises dimethyl 2-methylglutarate. The methods may include embodiments in accordance with any of the preceding paragraphs or a combination thereof and further include where the phosphonoalkyl aminopolycarboxylic acid chelating agent comprises a phosphorylated aminopolycarboxylic acid. The methods may include the embodiments in accordance with any of the preceding paragraphs or a combination thereof and further include where the phosphorylated aminopolycarboxylic acid comprises PMIDA. For example, the methods may include removing a hydrocarbon phase from the mineral phase with the aqueous solvent fluid; wherein the mineral phase is contacted with the aqueous solvent fluid only in a single-stage dissolution process; wherein at least 50% of the mineral phase is removed within 0.5 to 8 hours; wherein the mineral phase comprises calcium sulfate; wherein the anionic salt comprises a linear alkylbenzenesulfonate surfactant; wherein the wettability modifier further comprises a solvent comprising dimethyl 2-methylglutarate; and wherein the phosphonoalkyl aminopolycarboxylic acid chelating agent comprises PMIDA. Compositions for removing an inorganic sulfate mineral scale phase may include a phosphonoalkyl aminopolycarboxylic acid chelating agent; a wettability modifier comprising a dibasic ester and a surfactant, wherein the surfactant comprises one or more anionic alkyl sulfonate or anionic aryl sulfonate; a pH adjusting agent; a scale-converting agent; and water. The compositions may include the embodiments in accordance with any of the preceding paragraphs or a combination thereof and further include where the surfactant comprises an anionic alkyl sulfonate. The compositions may include the embodiments in accordance with any of the preceding paragraphs or a combination thereof and further include where the anionic alkyl sulfonate comprises a linear alkylbenzenesulfonate. Compositions may include the forms of realization according to any paragraph MA / a / ZUZZ / UI OI / u above or combination thereof and further include wherein the dibasic ester is selected from the group consisting of dimethyl 2-methylglutarate, 1-dodecyl-2-pyrrolidinone, N-(C2H4)nCH3pyrrolidinone (where n is from about 6 to about 12), dimethyl succinate, dimethyl glutarate, dimethyl adipate, dimethyl-2-methyladipate and combinations thereof. The compositions may include the embodiments in accordance with any of the preceding paragraphs or a combination thereof and further include where the dibasic ester comprises dimethyl 2-methylglutarate. The compositions may include the embodiments according to any of the preceding paragraphs or a combination thereof and further include where the phosphonoalkyl aminopolycarboxylic acid chelating agent comprises a phosphorylated aminopolycarboxylic acid. The compositions may include the embodiments in accordance with any of the preceding paragraphs or a combination thereof and further include where the phosphorylated aminopolycarboxylic acid comprises PMIDA. The disclosed embodiments, including examples, should not be construed or otherwise used as limiting the scope of the disclosure, including the claims. It should be fully recognized that the various teachings of the embodiments discussed can be employed separately or in any combination suitable for producing the desired results. Furthermore, a person of average skill will understand that the description has broad application, and the discussion of any embodiment is intended only as an example of that embodiment and is not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Claims

1. A method for removing a petroleum-wetted mineral phase comprising an inorganic sulfate from a surface, comprising: contacting the mineral phase with an aqueous solvent fluid comprising a phosphonoalkyl aminopolycarboxylic acid chelating agent, a wettability modifier, a pH adjusting agent, a scale converter, and water, wherein the wettability modifier comprises a dibasic ester and a surfactant, wherein the surfactant comprises one or more anionic alkyl sulfonate or anionic aryl sulfonate; and removing the petroleum-wetted mineral phase from the surface with the aqueous solvent fluid.

2. The method according to claim 1, further comprising removing a hydrocarbon phase from a mineral phase surface with the aqueous solvent fluid.

3. The method according to claim 2, wherein the mineral phase is brought into contact with the aqueous solvent fluid only in a single-stage dissolution process.

4. The method according to claim 1, wherein at least 50% of the mineral phase is removed within between 0.5 and 72 hours.

5. The method according to claim 4, wherein at least 50% of the mineral phase is removed within 0.5 to 8 hours.

6. The method according to claim 1, wherein the mineral phase comprises calcium sulfate.

7. The method according to claim 1, wherein the surfactant comprises an anionic alkyl sulfonate.

8. The method according to claim 7, wherein the anionic alkyl sulfonate comprises a linear alkylbenzenesulfonate.

9. The method according to claim 1, wherein the dibasic ester is selected from the group consisting of dimethyl 2-methylglutarate, 1-dodecyl-2-pyrrolidinone, N-(C2H4)nCH3-pyrrolidinone, wherein n is from about 6 to about 12, dimethyl succinate, dimethyl glutarate, dimethyl adipate, dimethyl-2-methyladipate and combinations thereof.

10. The method according to claim 9, wherein the dibasic ester comprises dimethyl 2-methylglutarate.

11. The method according to claim 1, wherein the phosphonoalkyl aminopolycarboxylic acid chelating agent comprises a phosphorylated aminopolycarboxylic acid. ML / a / ZUZZ / UI OI / u 12. The method according to claim 11, wherein the phosphorylated aminopolycarboxylic acid comprises PMIDA.

13. The method according to claim 1, further comprising: removing a hydrocarbon phase from the mineral phase with the aqueous solvent fluid; wherein the mineral phase is contacted with the aqueous solvent fluid in a single-stage dissolution process; wherein at least 50% of the mineral phase is removed within 0.5 to 8 hours; wherein the mineral phase comprises calcium sulfate; wherein the anionic salt comprises a linear alkylbenzenesulfonate surfactant; wherein the wettability modifier further comprises a solvent comprising dimethyl 2-methylglutarate; and wherein the phosphonoalkyl aminopolycarboxylic acid chelating agent comprises PMIDA.

14. A solvent composition for removing an inorganic sulfate mineral scale phase, comprising: a phosphonoalkyl aminopolycarboxylic acid chelating agent; a wettability modifier comprising a dibasic ester and a surfactant, wherein the surfactant comprises one or more anionic alkyl sulfonate or anionic aryl sulfonate; a pH adjusting agent; a scale-converting agent; and water.

15. The solvent composition according to claim 14, wherein the surfactant comprises an anionic alkyl sulfonate.

16. The solvent composition according to claim 15, wherein the anionic alkyl sulfonate comprises a linear alkylbenzenesulfonate.

17. The solvent composition according to claim 14, wherein the dibasic ester is selected from the group consisting of dimethyl 2-methylglutarate, 1-dodecyl-2-pyrrolidinone, N-(C2H4)nCH3-pyrrolidinone (where n is from about 6 to about 12), dimethyl succinate, dimethyl glutarate, dimethyl adipate, dimethyl-2-methyladipate and combinations thereof.

18. The solvent composition according to claim 17, wherein the dibasic ester comprises dimethyl 2-methylglutarate.

19. The solvent composition according to claim 14, wherein the MA / a / ZUZZ / UI OI / u phosphonoalkyl aminopolycarboxylic acid chelating agent comprises a phosphorylated aminopolycarboxylic acid.

20. The solvent composition according to claim 19, wherein the phosphorylated aminopolycarboxylic acid comprises PMIDA.

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