METHOD FOR INHIBITING FORMATION OF SCALE IN SUBTERRANEAN GEOLOGICAL FORMATION

Description

CROSS-REFERENCE TO RELATED APPLICATION

The present disclosure claims the benefit of Saudi patent application Ser. No. 1020246519 filed on Nov. 19, 2024, with the Saudi Authority for Intellectual Property Office, which is incorporated herein by reference in its entirety.

BACKGROUND

Technical Field

The present disclosure is directed to scale inhibition, and particularly relates to a method for inhibiting the formation of scale in a subterranean geological formation.

Description of Related Art

The “background” description provided herein is for the purpose of generally presenting the context of the disclosure. Work of the presently named inventors, to the extent it is described in this background section, as well as aspects of the description which may not otherwise qualify as prior art at the time of filing, are neither expressly nor impliedly admitted as prior art against the present disclosure.

In oil and gas production, scale refers to the undesirable precipitation and accumulation of solids within wellbores, pipelines, and production equipment. Scale formation is an operational challenge, leading to decreased efficiency, increased maintenance costs, and equipment malfunctions. The primary components of scale include mineral deposits such as calcium carbonate (CaCO₃), iron carbonate (FeCO₃), calcium sulfate (CaSO₄), and barium sulfate (BaSO₄), which can reduce flow capacity in processing systems. Calcium sulfate, a major contributor to sulphate scale deposits, frequently forms in oil fields, particularly during enhanced oil recovery (EOR) operations where seawater is injected to improve production efficiency. Sulphate scale can arise from the interaction of sulfate ions in seawater with barium (Ba²⁺) and strontium (Sr²⁺) cations in reservoir water. Additionally, scale formation can occur during fracturing or stimulation operations due to the incompatibility between injected fluids and formation fluids, and is exacerbated when operational conditions, such as temperature, change. Calcium sulfate scale can manifest in three stable forms: gypsum (CaSO₄.2H₂O), anhydrite (CaSO₄), and hemi-hydrate (CaSO₄.0.5H₂O), with gypsum typically crystallizing at temperatures below 100° C. and anhydrite forming at higher temperatures.

Traditional methods for scale removal have relied on mechanical techniques, such as water jetting or chemical treatments using acids and chelating agents to dissolve scale deposits. However, these approaches have limitations, including environmental concerns, rising costs, challenges related to wellbore cleanup, and issues with thermal stability. Therefore, focusing on scale inhibition rather than removal is more advantageous. Utilizing surfactants as scale inhibitors presents a more economical and practical alternative, offering a sustainable and efficient solution for scale management. Surfactants are recognized for their surface-active properties, which are prevent the crystallization and growth of scale-forming minerals.

Accordingly, one object of the present disclosure is to provide a method for inhibiting scale formation in oil and gas operations using amphoteric amphiphiles that can enhance operational efficiency and sustainability in high-pressure, high-temperature environments.

SUMMARY

In an exemplary embodiment, a method for inhibiting the formation of scale in a subterranean geological formation is described. The method includes injecting a scale inhibiting composition into a subterranean geological formation comprising a target zone. The scale inhibiting composition includes water, and an amphiphilic polymer selected from the group consisting of S1, S2, and combinations thereof, where the structure of S1 is:

• • the structure of S2 is:

• • where x is in a range from 4 to 20 and n is in a range from 3 to 15, and where the amphiphilic polymer is dissolved in the scale inhibiting composition in an amount such that the concentration of the amphiphilic polymer at the target zone is equal to or greater than 500 parts per million (ppm).

In some embodiments, x is in a range from 8 to 16 and n is in a range from 5 to 13.

In some embodiments, x is in a range from 10 to 14 and n is in a range from 7 to 11.

In some embodiments, the scale inhibiting composition includes S1 and the average molecular weight of S1 is in a range from 885 to 925 g/mol.

In some embodiments, the average molecular weight of S1 is in a range from 895 to 915 g/mol.

In some embodiments, the scale inhibiting composition includes S2 and the average molecular weight of S2 is in a range from 805 to 845 g/mol.

In some embodiments, the average molecular weight of S2 is in a range from 815 to 835 g/mol.

In some embodiments, the scale inhibiting composition further includes NaHCO₃ in an amount of from 0.1 to 1.0 g/L, Na₂SO₄ in an amount of from 0.1 to 10.0 g/L, NaCl in an amount of from 30 to 180 g/L, CaCl₂) in an amount of from 1 to 100 g/L, and MgCl₂ in an amount of from 15 to 50 g/L. The total amount of S1 and S2 is from 250 to 1,500 ppm based on the mass of S1 and S2 and the total mass of the composition.

In some embodiments, the temperature at the target zone is 90° C.

In some embodiments, the scale inhibiting composition includes S1 and the thermal stability of S1 is greater than 250° C.

In some embodiments, the scale inhibiting composition includes S1 and the thermal stability of S1 is greater than 265° C.

In some embodiments, the scale inhibiting composition includes S2 and the thermal stability of S2 is greater than 265° C.

In some embodiments, the scale inhibiting composition includes S2 and the thermal stability of S2 is greater than 280° C.

In some embodiments, the scale inhibiting composition includes S1 and needle shaped scale formation is not observed in the target zone for at least 3 days.

In some embodiments, needle shaped scale formation is not observed in the target zone for at least 6 days

In some embodiments, the scale inhibiting composition includes S2, where x is in a range from 10 to 14, and n is in a range from 7 to 11.

In some embodiments, scale formation is not observed in the target zone for at least 1 day after injecting the scale inhibiting composition.

In some embodiments, S2 is dissolved in the scale inhibiting composition in an amount such that the concentration of S2 at the target zone is equal to or greater than 1000 ppm and scale formation is not observed in the target zone for at least 2 days.

In some embodiments, scale formation is not observed in the target zone for at least 4 days after injecting the scale inhibiting composition.

In some embodiments, scale formation is not observed in the target zone for at least 6 days after injecting the scale inhibiting composition.

The foregoing general description of the illustrative embodiments and the following detailed description thereof are merely exemplary aspects of the teachings of this disclosure and are not restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of this disclosure and many of the attendant advantages thereof will be readily obtained as the same becomes better understood by reference to the following detailed description when considered in connection with the accompanying drawings, wherein:

FIG. 1A is a schematic flowchart depicting a method for inhibiting the formation of scale in a subterranean geological formation, according to certain embodiments.

FIG. 1B shows chemical structures of lauryl polyoxyethylene amidopropyl hydroxy sulfobetaine (S1) and lauryl polyoxyethylene amidopropyl carboxybetaine sulfonate (S2), according to certain embodiments.

FIG. 2 is a diagram depicting the experimental progression of amphiphiles used at a concentration of 500 parts per million (ppm), according to certain embodiments.

FIG. 3 is a diagram depicting the experimental progression of amphiphiles used at a concentration of 1000 ppm, according to certain embodiments.

DETAILED DESCRIPTION

In the drawings, like reference numerals designate identical or corresponding parts throughout the several views. Further, as used herein, the words “a”, “an” and the like generally carry a meaning of “one or more”, unless stated otherwise.

Furthermore, the terms “approximately,” “approximate”, “about” and similar terms generally refer to ranges that include the identified value within a margin of 20%, 10%, or preferably 5%, and any values therebetween.

As used herein, the words “a” and “an” and the like carry the meaning of “one or more”. Within the description of this disclosure, where a numerical limit or range is stated, the endpoints are included unless stated otherwise. Also, all values and subranges within a numerical limit or range are specifically included as if explicitly written out.

As used herein, the terms “compound”, “surfactant”, and “product” are used interchangeably, and are intended to refer to a chemical entity, whether in the solid, liquid or gaseous phase, and whether in a crude mixture or purified and isolated.

As used herein, the term “solvate” refers to a physical association of a compound of this disclosure with one or more solvent molecules, whether organic or inorganic. This physical association includes hydrogen bonding. In certain instances, the solvate will be capable of isolation, for example when one or more solvent molecules are incorporated in the crystal lattice of the crystalline solid. The solvent molecules in the solvate may be present in a regular arrangement and/or a non-ordered arrangement. The solvate may comprise either a stoichiometric or nonstoichiometric amount of the solvent molecules. Solvate encompasses both solution phase and isolable solvates. Exemplary solvents include, but are not limited to, water, methanol, ethanol, n-propanol, isopropanol, n-butanol, isobutanol, tert-butanol, ethyl acetate and other lower alkanols, glycerine, acetone, dichloromethane (DCM), dimethyl sulfoxide (DMSO), dimethyl acetate (DMA), dimethylformamide (DMF), isopropyl ether, acetonitrile, toluene, N-methylpyrrolidone (NMP), tetrahydrofuran (THF), tetrahydropyran, other cyclic mono-, di- and tri-ethers, polyalkylene glycols (e.g. polyethylene glycol, polypropylene glycol, propylene glycol), and mixtures thereof in suitable proportions. Exemplary solvates include, but are not limited to, hydrates, ethanolates, methanolates, isopropanolates and mixtures thereof. Methods of solvation are generally known to those of ordinary skill in the art.

As used herein, the term “tautomer” refers to constitutional isomers of organic compounds that readily convert by tautomerization or tautomerism. The interconversion commonly results in the formal migration of a hydrogen atom or proton, accompanied by a switch of a single bond and adjacent double bond. Tautomerism is a unique case of structural isomerism, and because of the rapid interconversion, tautomers are generally considered to be the same chemical compound. In solutions in which tautomerization is possible, a chemical equilibrium of the tautomers will be reached. The exact ratio of the tautomers depends on several factors including, but not limited to, temperature, solvent and pH. Exemplary common tautomeric pairs include, but are not limited to, ketone and enol, enamine and imine, ketene and ynol, nitroso and oxime, amide and imidic acid, lactam and lactim (an amide and imidic tautomerism in heterocyclic rings), and open-chain and cyclic forms of an acetal or hemiacetal (e.g., in reducing sugars).

As used herein, the term “stereoisomer” refers to isomeric molecules that have the same molecular formula and sequence of bonded atoms (i.e. constitution), but differ in the three-dimensional orientations of their atoms in space. This contrasts with structural isomers, which share the same molecular formula, but the bond connection of their order differs. By definition, molecules that are stereoisomers of each other represent the same structural isomer. Enantiomers are two stereoisomers that are related to each other by reflection, they are non-superimposable mirror images. Every stereogenic center in one has the opposite configuration in the other. Two compounds that are enantiomers of each other have the same physical properties, except for the direction in which they rotate polarized light and how they interact with different optical isomers of other compounds. Diastereomers are stereoisomers not related through a reflection operation, they are not mirror images of each other. These include meso compounds, cis- and trans- (E- and Z-) isomers, and non-enantiomeric optical isomers. Diastereomers seldom have the same physical properties. In terms of the present disclosure, stereoisomers may refer to enantiomers, diastereomers, or both.

Conformers, rotamers, or conformational isomerism refers to a form of isomerism that describes the phenomenon of molecules with the same structural formula but with different shapes due to rotations around one or more bonds. Different conformations can have different energies, can usually interconvert, and are not typically isolatable. There are some molecules that can be isolated in several conformations. Atropisomers are stereoisomers resulting from hindered rotation about single bonds where the steric strain barrier to rotation is high enough to allow for the isolation of the conformers. In terms of the present disclosure, stereoisomers may refer to conformers, atropisomers, or both.

In terms of the present disclosure, stereoisomers of the ring systems, stereogenic centers, and the like can all be present in the compounds, and all such stable isomers are contemplated in the present disclosure. S- and R- (or L- and D-) stereoisomers of the compounds of the present disclosure are described and may be isolated as a mixture of isomers or as separated isomeric forms. All processes or methods used to prepare compounds of the present disclosure and intermediates made therein are part of the present disclosure. When stereoisomeric products are prepared, they may be separated by conventional methods, for example, by chromatography, fractional crystallization, or use of a chiral agent.

As used herein, the term ‘surfactant’ refers to a compound that lowers the surface tension (or interfacial tension) between two liquids, between a liquid and a gas, or between a liquid and a solid. The surfactant may also be a gemini surfactant of any of the types listed previously. The surfactant may serve a role as a water-wetting agent, a defoamer, a foamer, a detergent, a dispersant, or an emulsifier.

As used herein, the term ‘thermal stability’ refers to the ability of a material or substance to maintain its properties and performance characteristics when subjected to varying temperatures over time. This includes resistance to degradation, decomposition, or phase changes when exposed to heat.

The present disclosure is intended to include all isotopes of atoms occurring in the present compounds. Isotopes include those atoms having the same atomic number but different mass numbers. By way of general example, and without limitation, isotopes of hydrogen include deuterium and tritium, isotopes of carbon include ¹³C and ¹⁴C, isotopes of nitrogen include ¹⁴N and ¹⁵N, and isotopes of oxygen include ¹⁶O, ¹⁷O and ¹⁸O. Isotopically labeled compounds of the disclosure can generally be prepared by conventional techniques known to those of ordinary skill in the art or by processes and methods analogous to those described herein, using an appropriate isotopically labeled reagent in place of the non-labeled reagent otherwise employed.

Aspects of the present disclosure are directed to a scale inhibition method using amphoteric amphiphiles, specifically a lauryl polyoxyethylene aminopropyl hydroxy sulfobetaine (S1) and a lauryl polyoxyethylene aminopropyl carboxy betaine sulfonate (S2). The amphiphiles of the present disclosure provide a cost-effective and sustainable solution that addresses sulfate scale formation in the oil and gas industry.

FIG. 1A illustrates a flow chart of a method 50 for inhibiting scale formation in a subterranean geological formation. The subterranean geological formation may include, but is not limited to, a depleted oil reservoir, a depleted gas reservoir, a sour reservoir, a hydrocarbon hydrocarbon-bearing subterranean formation, a saline formation, or an un-minable coal bed. The order in which the method 50 is described is not intended to be construed as a limitation, and any number of the described method steps can be combined in any order to implement the method 50. Additionally, individual steps may be removed or skipped from the method 50 without departing from the spirit and scope of the present disclosure.

At step 52, the method 50 includes injecting a scale inhibiting composition (also referred to as composition) into a subterranean geological formation. The scale inhibiting composition may be injected through any typical means onsite, such as pumping the scale inhibiting composition from a reservoir through tubing into the wellbore. Typically, the scale inhibiting composition would be stored in tanks until injected, and the typical means for adding and removing material from the wellbore may be used. A pump may be used to pump the scale inhibiting composition into the wellbore through tubing, with increased pressure delivering the scale inhibiting composition downhole. In addition, the scale inhibiting composition may be injected alone, with other fluids, or mixed with other fluids or solids before injection.

The composition can be used to remove accumulated scale or it can be applied preventatively on surfaces that are prone to scale formation. The surfaces the composition is applied to may include natural surfaces such as geological surfaces, surfaces in subterranean formations, or surfaces of an oil or gas reservoir, as well as surfaces of artificially placed or deliberately introduced materials or wellbore equipment whose surface is also prone to scale deposition. However, the removal of scale from other surfaces of the type disclosed herein is also contemplated. In some embodiments, the composition can be used for the removal of at least a portion of scale and/or prevent scale formation on wellbore equipment surfaces, surfaces that are in fluid communication with the wellbore and/or subterranean formation, and for surfaces in communication with fluids traveling to and/or from the wellbore and/or subterranean formation (such as produced fluids). Non-limiting examples of wellbore equipment that might accumulate scale on one or more surfaces include heating turbines, heat exchangers, safety valves, casings, production tubing, mandrels, pipes, separators, pumps, tubulars, vessels, completion equipment (e.g., screens, etc.), downhole tools and any other piece of equipment that might come in contact with a wellbore fluid, whether such fluid is produced or part of a servicing fluid.

The composition includes an amphiphilic polymer dissolved in water. As used herein, the term ‘amphiphilic polymer’ refers to the polymer that possesses both hydrophilic (water-attracting) and hydrophobic (water-repelling) segments within its molecular structure. This dual nature allows amphiphilic polymers to interact with both aqueous and non-aqueous environments, enabling them to self-assemble into various structures, such as micelles, vesicles, or films. The amphiphilic polymer is selected from S1, S2, and combinations thereof.

In one or more embodiments, the amphiphilic polymer is S1, where the structure of S1 is:

• • or a salt, a solvate, a stereoisomer, or a mixture thereof.

In one or more embodiments, the amphiphilic polymer is S2, where the structure of S2 is:

• • or a salt, a solvate, a stereoisomer, or a mixture thereof.

In one or more embodiments, x in S1 and S2 is in a range from 4 to 20, and n is in a range from 3 to 15. In some embodiments, x is in a range from 8 to 16, and n is in a range from 5 to 13. In some embodiments, x is in a range from 10 to 14, and n is in a range from 7 to 11. In some embodiments, x is in a range from 11 to 13. In some embodiments, the scale inhibiting composition includes S2, where x ranges from 10 to 14, and n ranges from 7 to 11. In some embodiments, x is in a range from 11 to 13.

In some embodiments, the composition includes S1, and the average molecular weight of S1 ranges from 885 to 925 g/mol, preferably 895 to 915 g/mol, and yet more preferably about 905.24 g/mol. In some embodiments, the scale inhibiting composition includes S2, and the average molecular weight of S2 ranges from 805 to 845 g/mol, preferably 815 to 835 g/mol, and yet more preferably about 825.14 g/mol. In some embodiments, the composition includes S1 and/or S2, and the total amount of S1 and S2 ranges from 250 to 1,500 ppm based on the mass of S1 and S2 and the total mass of the composition.

The amphiphilic polymer is dissolved in water. The water may be deionized water, seawater, synthetic seawater, formation water, or combinations thereof. In a preferred embodiment, the water is seawater or formation water. In some embodiments, the ratio of the seawater/synthetic seawater to the formation water is in the range of 1:4 to 4:1, preferably 1:3 to 3:1, preferably 1:2 to 2:1, preferably 1:1.

In one or more embodiments, seawater includes NaHCO₃ in an amount of from 0.1 to 1.0 g/L, more preferably 0.1 to 0.2 g/L, and yet more preferably 0.165 g/L; Na₂SO₄ in an amount of from 0.1 to 10.0 g/L, more preferably 3.0 to 8.0 g/L, and yet more preferably 6.339 g/L; NaCl in an amount of from 30 to 180 g/L, more preferably 35 to 45 g/L, and yet more preferably 41.172 g/L; CaCl₂) in an amount of from 1 to 100 g/L, more preferably 2 to 5 g/L, and yet more preferably 2.387 g/L; and MgCl₂ in an amount of from 15 to 50 g/L, more preferably 16 to 18 g/L, and yet more preferably 17.644 g/L.

In one or more embodiments, formation water includes NaHCO₃ in an amount of from 0.1 to 1.0 g/L, more preferably 0.4 to 0.6 g/L, and yet more preferably 0.487 g/L; Na₂SO₄ in an amount of from 0.1 to 10.0 g/L, more preferably 0.25 to 1.0 g/L, and yet more preferably 0.518 g/L; NaCl in an amount of from 30 to 180 g/L, more preferably 35 to 45 g/L, and yet more preferably 41.172 g/L; CaCl₂) in an amount of from 1 to 100 g/L, more preferably 2 to 5 g/L, and yet more preferably 2.387 g/L; and MgCl₂ in an amount of from 15 to 50 g/L, more preferably 16 to 18 g/L, and yet more preferably 17.644 g/L.

In some embodiments, the seawater and formation water may have different salts including, but not limited to, potassium chloride (KCl), calcium sulfate (CaSO₄), magnesium sulfate (MgSO₄), lithium chloride (LiCl), strontium chloride (SrCl₂), and sodium thiosulfate (Na₂S₂O₃).

Any salt mixture found in seawater or formation water may be used for the preparation of the scale inhibiting composition. In some embodiments, the scale inhibiting composition is prepared using seawater and/or formation water. In a preferred embodiment, the scale inhibiting composition was prepared using five salts: sodium chloride (NaCl), calcium chloride (CaCl₂)), magnesium chloride (MgCl₂), sodium bicarbonate (NaHCO₃), and sodium sulfate (Na₂SO₄). In one or more embodiments, the scale inhibiting composition includes NaHCO₃ in an amount of from 0.1 to 1.0 g/L, more preferably 0.16 to 0.5 g/L; Na₂SO₄ in an amount of from 0.1 to 10.0 g/L, more preferably 0.3 to 7.0 g/L; NaCl in an amount of from 30 to 180 g/L, more preferably 40 to 160 g/L; CaCl₂) in an amount of from 1 to 100 g/L, more preferably 2 to 70 g/L; and MgCl₂ in an amount of from 15 to 50 g/L, more preferably 17 to 21 g/L.

In some embodiments, the composition includes formation water. The formation water includes NaHCO₃ in an amount of from 0.1 to 1.0 g/L, more preferably 0.1 to 0.2 g/L, and yet more preferably 0.487 g/L; NaCl in an amount of from 30 to 180 g/L, more preferably 35 to 45 g/L, and yet more preferably 41.172 g/L; CaCl₂) in an amount of from 1 to 100 g/L, more preferably 2 to 5 g/L, and yet more preferably 2.387 g/L; and MgCl₂ in an amount of from 15 to 50 g/L, more preferably 16 to 18 g/L, and yet more preferably 17.644 g/L.

In some embodiments, the composition may include any suitable additives. Exemplary additives include, but are not limited to, weighting agents, emulsifiers, viscosities, fluid-loss control agents, bridging agents, pH controlling agents, defoamers, clay stabilizers, other anti-scale compounds, deflocculants, lubricants, gelling agents, corrosion inhibitors, rheology control modifiers or thinners, high temperature/high pressure control additives, acids, alkalinity agents, pH buffers, fluorides, gases, nitrogen, carbon dioxide, surface modifying agents, tackifying agents, foamers, catalysts, clay control agents, biocides, bactericides, friction reducers, antifoam agents, dispersants, flocculants, H₂S scavengers, CO₂ scavengers, oxygen scavengers, friction reducers, breakers, relative permeability modifiers, resins, particulate materials (e.g., proppant particulates), wetting agents, coating enhancement agents, filter cake removal agents, odorants, shale stabilizers, and the like. A person of ordinary skill in the art, with the benefit of this disclosure, will recognize the types and suitable amounts of additives that may be included in the scale inhibiting composition for a particular application, without undue experimentation.

The composition is injected into the subterranean geological formation through a wellbore. In one or more embodiments, the wellbore is present in at least one of an oil well, a gas well, a production well, an injection well, a naturally flowing well, an artificially lifted well, a high-temperature well, a steam-assisted gravity drainage well, a steam injector well, or a geothermal well. The wellbore may be formed in the subterranean geologic formation by known techniques.

The step of injecting the scale inhibiting composition includes any subsequent steps needed to deliver the scale inhibiting composition to the target zone, which could include pumping and opening or closing any applicable valves to allow the scale inhibiting composition to reach the target zone. Delivering the scale inhibiting composition to the target zone could be accomplished through any typical means onsite. When required, measures may be taken to hold or keep the scale inhibiting composition in the wellbore or target area including under pressure, such as plugs or valves. Furthermore, the scale inhibiting composition could be used on equipment not downhole, so therefore the scale inhibiting composition could be used in any typical means to clean or soak equipment that is not currently downhole.

The target zone may be any section or area of formation and/or equipment in the formation where scale formation has or could occur. The temperature at the target zone is in the range of 30-150° C., preferably 40-140° C., preferably 50-130° C., preferably 60-120° C., preferably 70-110° C., preferably 80-100° C., preferably 90° C. In some embodiments, the temperature at the target zone is 90° C. Hence it is desirable that the composition is stable at such temperatures.

In some embodiments, the scale inhibiting composition includes S1 and the thermal stability of S1 is greater than 250° C., preferably 265° C., preferably 282° C. In some embodiments, the scale inhibiting composition includes S2, and the thermal stability of S2 is greater than 265° C., preferably 280° C., preferably 296° C.

In some embodiments, the concentration of the amphiphilic polymer at the target zone is equal to or greater than 500 parts per million (ppm), preferably greater than 550 ppm, preferably 600 ppm, preferably 650 ppm, preferably 700 ppm, preferably 750 ppm, preferably 800 ppm, preferably 850 ppm, preferably 900 ppm, preferably 950 ppm, preferably 1000 ppm. In a preferred embodiment, the concentration of the amphiphilic polymer at the target zone ranges from 550-1000 ppm. While concentrations below 1000 ppm are preferred, concentrations above 1000 ppm may be used if beneficial.

In some embodiments, the composition includes S1, and needle-shaped scale formation is not observed in the target zone for at least 1 day, preferably at least 3 days, preferably at least 6 days after injecting the composition. In some embodiments, S1 is dissolved in the composition in an amount such that the concentration of S1 at the target zone is equal to 500 ppm or 1000 ppm and round shaped scale is observed in the target zone after 1 day, more so after 6 days.

In some embodiments, S2 is dissolved in composition in an amount such that the concentration of S2 at the target zone is equal to or greater than 1000 ppm and scale formation is not observed in the target zone for at least 2 days, preferably at least 4 days, preferably at least 6 days after injecting the composition.

EXAMPLES

The following examples demonstrate a method for inhibiting the formation of scale in a subterranean geological formation. The examples are provided solely for illustration and are not to be construed as limitations of the present disclosure, as many variations thereof are possible without departing from the spirit and scope of the present disclosure.

Example 1: Material and Methods

In the present disclosure, amphoteric amphiphiles were utilized as scale inhibitors. The detailed chemical structures of these surfactants are provided in FIG. 1B. The amphiphiles S1 and S2 exhibit distinct chemical properties. S1 has the chemical formula [C₄₃H₈₈N₂O₁₅S], containing functional groups such as amide, quaternary ammonium, and sulfonate, with a molecular weight of 905.24 g/mol. S2 has the chemical formula [C₄₂H₈₄N₂O₁₃], featuring functional groups including amide, quaternary ammonium, and carboxylate, with a molecular weight of 825.14 g/mol. Characteristics of the surfactants include their zwitterionic behavior resulting from the distribution of positive and negative charges, solubility in distilled water, seawater, and formation water, and thermal stability at 282° C. for S1 and 296° C. for S2. These properties render the amphiphiles effective scale inhibitors, capable of interacting with scale-forming ions while maintaining stability under harsh environmental conditions.

The seawater (SW) and formation water (FW) compositions are listed in Table 1. The total dissolved solids concentrations in SW and FW are 67707 ppm and 241688 ppm respectively.

TABLE 1
Composition of SW and FW

	Salts	Seawater (g/L)	Formation Water (g/L)

	NaHCO3	0.165	0.487
	Na2SO4	6.339	0.518
	NaCl	41.172	150.446
	CaCl2•2H2O	2.387	69.841
	MgCl2•6H2O	17.644	20.396

For scale inhibition test, the incompatibility scenario was generated by mixing both synthetic brines in a 1:1 ratio. To evaluate their inhibition potential, surfactants were added at two different concentrations, and the scale inhibition tests were performed at 90° C.

The experimental data presented in Table 2 illustrate the performance of tested surfactants in preventing scale formation at a temperature of 90° C. For a comparative study, a control experiment was also carried out by mixing synthetic seawater and formation water in a 1:1 ratio. In the control experiment, needle-shaped scales were observed after 24 h and continued to increase with the passage of time (FIG. 3). To test the practicable applicability of the synthesized surfactants, two different concentrations (500 ppm and 1000 ppm) of the S1 and S2 were prepared similarly to the control experiment. S1 at both concentrations remained clear after 24 h, demonstrating no immediate precipitation. However, after aging for one-week (7 days), minimal precipitation was observed at both the concentrations. The morphology of the precipitates was different from the control sample. Instead of the needle-shaped scales detected in the control sample, the participates in the surfactant treated samples appeared round particles, resembling halite minerals. This difference can be visually observed in the sequential photographs presented in FIG. 2 and FIG. 3. On the other hand, S2 demonstrated increased performance in scale inhibition compared to S1. Its effectiveness is directly proportional to the concentration, with higher concentrations yielding excellent results. At a concentration of 500 ppm, S2 displayed negligible precipitation or scale formation compared to S1 after 7 days. However, upon increasing the concentration to 1000 ppm no signs of scale or precipitation was observed, highlighting the 5 stability and effectiveness of the surfactant in sea brine. The images clearly show the absence of scales or precipitation for S2 in FIG. 2 and FIG. 3.

TABLE 2
Scale testing at 90° C. with different concentrations
of amphoteric amphiphiles (S1 and S2).

	Amphiphiles
Formula-	Concen-	Temper-
tions	trations	ature	1 day	7 days
Base (SW:	—	90° C.	Needle shaped	Needle shaped
FW)			scale	scale
Amphiphile	500 ppm		Round shaped	Round shaped
S1			precipitation	precipitation
	1000 ppm		Round shaped	Round shaped
			precipitation	precipitation
Amphiphile	500 ppm		No scale or	Negligible
S2			precipitation	precipitation
	1000 ppm		No scale or	No scale or
			precipitation	precipitation

The present disclosure involves using synthesized amphoteric amphiphiles as scale inhibitors in high-pressure, high-temperature (HPHT) oil and gas wells. This provides an effective solution to the ongoing issue of sulphate scale formation in oil and gas operations, particularly with challenging scales such as anhydrite (CaSO₄). Zwitterionic surfactants demonstrate increased performance compared to traditional scale inhibitors, offering advantages in thermal stability, long-term scale prevention, and environmental friendliness.

The efficacy of the amphoteric amphiphiles in preventing scale formation is attributed to their enhanced stability and performance in high-salinity brine environments, where most commercial surfactants tend to precipitate. Specifically, S2, which contains a carboxylate functional group, exhibits increased inhibition properties compared to S1, which contains a sulfonate functional group.

The present disclosure highlights the role of surfactant concentrations in scale inhibition efficiency, with higher concentrations correlating to improved inhibition performance, indicating that optimized dosing may maximize scale prevention. The amphoteric amphiphiles not only prevent sulfate scales under high pressure and high temperature (HPHT) conditions but also enhance operational and cost efficiencies by potentially eliminating the need for mechanical scale removal and harsh chemical solutions. This advancement aligns with industry goals of reducing operational disruptions and costs associated with scale management.

Furthermore, using low concentrations of the amphiphiles effectively prevents scale formation, thereby reducing expenses and operational challenges related to workover and scale removal processes. This approach facilitates continuous production without the drawbacks associated with scale buildup.

The present disclosure underscores the potential of zwitterionic surfactants as an eco-friendly and efficient solution for managing sulphate scales in HPHT wells. It also overcomes complex operational challenges while supporting economic diversification and sustainability. Numerous modifications and variations of the present disclosure are possible in light of the above teachings. It is, therefore, to be understood that within the scope of the appended claims, the invention may be practiced otherwise than as specifically described herein.