Amino acid functionalized phytic acid corrosion inhibitor compositions

Abstract

Corrosion inhibitors, corrosion inhibitor compositions, methods of making the same, and methods of using the same include a corrosion inhibitor composition having an amino acid functionalized phytic acid in a solvent composed to retain the corrosion inhibitor therein. The corrosion inhibitor composition is added to a wellbore fluid to limit corrosion on drilling and production equipment.

Description

FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCTAMINO ACID FUNCTIONALIZED PHYTIC ACID CORROSION INHIBITOR COMPOSITIONSCROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to and the benefit of United States Provisional Patent Application No. 63 / 680,375, filed on 7 August, 2024, which is hereby incorporated by reference in its entirety.BACKGROUND

[0002] Corrosion in the oil and gas industry is defined as the destructive attack of materials, primarily metals, by reaction with their environment. This is a significant concern as it can lead to material degradation and failure, affecting the smooth and uninterrupted flow of oil and gas Nearly 80% of failures occurring in the oil and gas production and pipeline operations are caused by corrosion. Corrosion typically occurs under complex conditions in oil and gas production, processing, and pipeline systems. It is often the result of the interaction between the material and an aqueous environment, leading to processes such as rusting.

[0003] In an oil and gas operation, corrosion can be caused by numerous factors, for example, the presence of water, carbon dioxide, and hydrogen sulfide can lead to internal corrosion. Other chemicals such as naphthenic acid and sulfur particles can also contribute to corrosion by reacting with iron particles or developing a surface film. High temperatures and high pressures, along with the presence of impurities in the crude oil, production fluid, and natural gas, can further exacerbate corrosion.

[0004] There are several methods used in the oil and gas industry to mitigate corrosion, such as cathodic protection, coatings and linings, and corrosion inhibitors. Cathodic protection is a technique used to control the external corrosion of a metal surface by making it the cathode of an electrochemical cell. This method can prevent corrosion in metal pipelines and storage tanks. Protective coatings, such as paints or epoxies, can help prevent corrosion by creating a barrier between the metal surface and the environment. These coatings and linings act as a physical barrier, isolating the metal from the corrosive environment. Corrosion inhibitors are chemicals that can be added to a liquid or gas to decrease the corrosion rate of a material. Corrosion inhibitors work by reducing the corrosivity of the fluid, forming a protective film on the metal surface, or both.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0005] The consequences of corrosion are the source of substantial costs within the oil and gas industry with the estimated annual cost due to corrosion to be greater than one billion dollars (USD). The effective management of corrosion is critical not only for cost reduction but also for compliance with safety, health, and environmental policies.BRIEF SUMMARY

[0006] In some embodiments, a corrosion inhibitor composition for a wellbore fluid is disclosed. The corrosion inhibitor composition includes a corrosion inhibitor having a functionalized phytic acid including one or more amino acid groups. The corrosion inhibitor includes a solvent composed to retain the corrosion inhibitor therein.

[0007] In some embodiments, the one or more amino acid groups includes one or more proteinogenic amino acids. In some embodiments, the functionalized phytic acid has a chemical structure ofwherein R1-R12 independently include a hydroxyl group or an amino acid group having a structure of:wherein Ro includes one or more heteroatoms. In some embodiments, at least five of R1-R12 independently include the amino acid group. In some embodiments, Ro includes on or more sulfur heteroatoms.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0008] In some embodiments, the one or more amino acid groups include at least one of cysteine, methionine, lysine, arginine, tryptophan, or histidine. In some embodiments, the one or more amino acid groups include amino acids other than proteinogenic amino acids. In some embodiments, the corrosion inhibitor is 35 weight percent or less of the corrosion inhibitor composition. In some embodiments, the corrosion inhibitor is 5 weight percent to 25 weight percent of the corrosion inhibitor composition. In some embodiments, the solvents includes one or more of water, a base oil, or monoethylene glycol. In some embodiments, the corrosion inhibitor composition is composed to provide corrosion resistance for more than 15 hours.

[0009] In some embodiments, a method of forming a corrosion inhibitor composition is disclosed. The method includes providing an amino acid functionalized phytic acid. The method includes adding the amino acid functionalized phytic acid to a solvent composed to retain the amino acid functionalized phytic acid therein effective to form the corrosion inhibitor composition.

[0010] In some embodiments, the method includes providing a phytic acid and reacting the phytic acid with one or more amino acids to form the amino acid functionalized phytic acid.

[0011] In some embodiments, the one or more amino acids of the method include at least one of cysteine, cystine, methionine, homocysteine, glycine, lysine, arginine, tryptophan, tyrosine, or histidine. In some embodiment, the amino acid functionalized phytic acid of the method forms less than 35 weight percent of the corrosion inhibitor composition.

[0012] In some embodiments, a method of forming a borehole extending through an earth formation is disclosed. The method includes mixing a corrosion inhibitor composition with a wellbore fluid. The corrosion inhibitor composition includes a corrosion inhibitor including a functionalized phytic acid having one or more amino acid groups and a solvent composed to retain the corrosion inhibitor therein. The method includes pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation.

[0013] In some embodiments, mixing a corrosion inhibitor composition with a wellbore fluid includes mixing the corrosion inhibitor composition including less than about 35 weight percent of the corrosion inhibitor with the wellbore fluid. In some embodiments, mixing a corrosion inhibitor composition with a wellbore fluid includes adding the corrosion inhibitor composition into the wellbore fluid effective to form a wellbore fluid mixture having 50 ppm or less of the corrosion inhibitor composition therein. In some embodiments, mixing a corrosion inhibitorFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT composition with a wellbore fluid includes flowing the corrosion inhibitor composition from a drum or barrel into the wellbore fluid.

[0014] In some embodiments, the method includes forming a borehole in the earth formation while pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation. Forming the borehole may include drilling the borehole with a drill rig.

[0015] In an embodiment, a method of collecting fluid from an earth formation is disclosed. The method includes mixing a corrosion inhibitor composition with a wellbore fluid, the corrosion inhibitor composition including a corrosion inhibitor including a functionalized phytic acid having one or more amino acid groups a solvent composed to retain the corrosion inhibitor therein. The method includes pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation.

[0016] In some examples, the method includes collecting the production fluid from the earth formation via the wellbore. In some examples, the method includes separating one or more hydrocarbons from the production fluid.

[0017] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0018] Additional features and advantages of embodiments of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such embodiments. The features and advantages of such embodiments may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features will become more fully apparent from the following description and appended claims, or may be learned by the practice of such embodiments as set forth hereinafter.BRIEF DESCRIPTION OF DRAWINGS

[0019] In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific implementations thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the variousFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example implementations, the implementations will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0020] FIG. 1 is a representation of a drilling system for drilling an earth formation to form a wellbore, according to one or more embodiments of the present disclosure;

[0021] FIG. 2 is a chemical structure of phytic acid, according to one or more embodiments of the present disclosure;

[0022] FIG. 3 is an illustration of a synthesis scheme for forming an amino acid functionalized phytic acid, according to one or more embodiments of the present disclosure;

[0023] FIG. 4 is a flow diagram of a method of forming a corrosion inhibitor composition, according to one or more embodiments of the present disclosure;

[0024] FIG. 5 is an image illustrating synthesis of phytic acid functionalized with cysteine, according to one or more embodiments of the present disclosure;

[0025] FIG. 6 is a flow diagram of a method of forming a borehole extending through an earth formation, according to one or more embodiments of the present disclosure;

[0026] FIG. 7 is a gel permeation chromatography (GPC) chromatogram of phytic acid functionalized with glycine, according to one or more embodiments of the present disclosure;

[0027] FIG. 8 is an LPR graph of phytic acid, according to one or more embodiments of the disclosure;

[0028] FIG. 9 is an LPR graph of glycine, according to one or more embodiments of the disclosure; and

[0029] FIG. 10 is an LPR graph of Example 1 (phytic acid functionalized with glycine), according to one or more embodiments of the disclosure.DETAILED DESCRIPTION

[0030] This disclosure describes the synthetic design of corrosion inhibitors including a phytic acid derived core functionalized with one or more amino acids as a novel class of corrosion inhibitor for oil and gas applications. The corrosion inhibitor compositions disclosed herein may include amino acid functionalized phytic acid corrosion inhibitors in a solution. The amino acidFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT functionalized phytic acid may be used to provide effective bonding to metal surfaces and to chelate metals in wellbore fluids to prevent corrosion and scaling on the metal surfaces of drilling and production well equipment.

[0031] The organic film-forming corrosion inhibitors including the amino acid functionalized phytic acids disclosed herein have strong surface-active chemistries including a polar group and a non-polar hydrocarbon soluble group. The polar group (head) attaches and forms a bond with metal surfaces. The attraction of the polar group to the metal surface(s) is much stronger than it is to the hydrocarbon / water interface and cannot be easily reversed. Based on this strong attraction, a persistent inhibitor film, including the amino acid functionalized phytic acid, is formed resulting in significant reduction in the corrosion potential of the wellbore fluid.

[0032] In an oil and gas operation, understanding of corrosion within the pipes, and vessel internals involves consideration of the properties of all the various fluids and entrained solids which pass through these systems, as well as the materials of construction. The chemical and physical properties of fluids as well as flow rate and velocity effects, temperature, pressure, and surface conditions must be considered. The presence of dissolved gases, especially oxygen, carbon dioxide and hydrogen sulfide has a profound effect on corrosivity.

[0033] The corrosion inhibitor compositions may be provided as a component of a wellbore fluid. In some embodiments, the corrosion inhibitor compositions are used in an oil-based or synthetic-based wellbore fluid (e.g., an oil-based drilling fluid or a synthetic-based drilling fluid, which may also be referred to as a non-aqueous wellbore or drilling fluid or an invert emulsion wellbore or drilling fluid).

[0034] This disclosure generally relates to devices, systems, and methods of manufacturing and using fluid additives for downhole applications, such as corrosion inhibitor compositions for use in wellbore fluids (e.g., production fluids or drilling fluids). The corrosion inhibitor composition may be used in a drilling fluid, such as drill-in fluids (also referred to as “reservoir drill-in fluids” (RDF)). The corrosion inhibitor composition may also be used in other wellbore fluids, such as production fluids, workover fluids, spacer fluids (e.g., a fluid introduced into the wellbore after a drilling fluid and prior to a cement composition to flush residual drilling fluid from the annulus), stimulation fluids, or other wellbore fluids. For example, the corrosion inhibitor compositions may be used in production fluids (e.g., combination of hydrocarbons, water ( and in some cases gases)) from a well, wellbore, or borehole for producing hydrocarbons, for storing hydrocarbons, or forFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT producing other fluids from a well or wellbore. The corrosion inhibitor compositions may be used during drilling of a wellbore or borehole for producing hydrocarbons, for storing hydrocarbons, or for forming other types of wellbores. The corrosion inhibitor compositions are not limited to the particular type of borehole or wellbore being drilled.

[0035] In some examples, the corrosion inhibitor constitutes less than about 25 weight percent of the corrosion inhibitor composition, which in turn is provided into a wellbore fluid at a concentration of less than 500 ppm (e.g., about 5 to about 250 ppm). Accordingly, the corrosion inhibitor may not affect or substantially affect the properties of the wellbore fluid including the corrosion inhibitor composition but may provide substantial benefits in terms of corrosion inhibition of the wellbore fluid containing the corrosion inhibitor composition. The corrosion inhibitor compositions may be titrated, dripped, poured, or otherwise added and mixed into the wellbore fluid at conditions encountered at the well site, such as at temperatures as low as -25°C.

[0036] Embodiments of the corrosion inhibitor and corrosion inhibitor compositions are described in more detail below.

[0037] FIG. 1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a borehole 102 defining a wellbore 112. The drilling system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the borehole 102 and / or wellbore 112. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110, attached to the downhole end of drill string 105. The wellbore 112 may be used to facilitate one or more of hydrocarbon recovery from the earth formation 101, carbon storage in the earth formation 101 (such as by injection of carbon dioxide into the earth formation 101 injection of other fluids into the earth formation 101, stimulation of geological formations for hydrogen generation and / or carbon dioxide storage, or other processes.

[0038] The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits wellbore (e.g., drilling) fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which wellbore fluid is pumped from the surface. The wellbore fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the borehole 102 or wellbore 112 as it is being drilled.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0039] The BHA 106 may include the bit 110 or other components. An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurementwhile-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing. The BHA 106 may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore 112. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, and / or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory.

[0040] In general, the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the drilling system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106 depending on their locations in the drilling system 100.

[0041] The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 112. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the borehole 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to the surface or may be allowed to fall downhole.

[0042] During drilling operations, a wellbore fluid (e.g., a drilling fluid) may be used to facilitate lubrication and cooling of the bit 110 and removal of cuttings of the earth formation 101. The wellbore fluid may be configured to be circulated through the drill string 105, out of the drill string 105 through the bit 110, and into the annulus between the drill string 105 and the surfaces of the earth formation 101 defining the borehole 102 (or the wellbore 112). For example, a surface pumpFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT114 may pump the wellbore fluid from a mud pit 116 which holds the wellbore fluid. In some embodiments, one or more additives may be added to the wellbore fluid, such as by providing the one or more additives to the mud pit 116.

[0043] The wellbore fluid may be used to facilitate lubrication and cooling of the bit 110 and removal of cuttings of the earth formation 101 from the borehole 102 and / or wellbore 112. The wellbore fluid may include one or more materials formulated and configured to facilitate drilling of the earth formation 101. The wellbore fluid may include a corrosion inhibitor composition formulated and configured to cause surfaces of drilling and / or production equipment to resist corrosion and scaling. Such formulation includes at least one functionalized phytic acid having one or more amino acid groups bound thereto. In addition, the corrosion inhibitor composition may further include one or more additives, such as any of the additives disclosed herein. In some embodiments, the corrosion inhibitor composition is free of conventional corrosion inhibitors not having the formula of the corrosion inhibitors disclosed herein. For example, the corrosion inhibitor composition may be free of non-functionalized phytic acid. In other embodiments, the corrosion inhibitor composition includes the corrosion inhibitor, and a solvent formulated and configured to retain the corrosion inhibitor therein.

[0044] The wellbore fluid may include a base fluid, the corrosion inhibitor composition, and optionally, one or more additives (e.g., one or more emulsifiers, surfactants, bridging materials, viscosifiers, thinners (e.g., dispersion aids), wetting agents, weighting materials, filtration control agents, shale stabilizers, pH buffers, scavengers, emulsion activators, oxygen scavengers, gelling agents, scale inhibitors, foaming agents, defoamers, solvents, rheological additives, or other additives).

[0045] In some embodiments, the wellbore fluid is an aqueous-based wellbore fluid (e.g., a water-based drilling fluid) and may be referred to as “wellbore fluid,” an “emulsion wellbore fluid,” or a “wellbore mud.” The wellbore fluid may include an emulsion wherein the continuous external phase is aqueous, and the internal discontinuous phase is oleaginous. In such examples, the wellbore fluid may be used as and referred to as a drilling fluid. In some examples, the major component (e.g., at least 50.1% by weight or volume) of the wellbore fluid may be water, such as brine, produced water, municipal water, seawater, grey water, fresh water, treated water, or combinations of the foregoing. In such examples, the wellbore fluid may be used as a production fluid. The corrosion inhibitor compositions disclosed herein may be added to the wellbore fluid.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0046] In some embodiments, the wellbore fluid is a non-aqueous-based wellbore fluid (e.g., an oil-based drilling fluid, a synthetic-based drilling fluid) and may be referred to as a “non-aqueous fluid” (NAF), an “invert wellbore fluid,” an “invert emulsion wellbore fluid,” or a “wellbore mud.” The wellbore fluid may include an invert emulsion wherein the continuous external phase is oleaginous, and the internal discontinuous phase is aqueous. In such examples, the wellbore fluid may be used as and referred to as a drilling fluid.

[0047] In embodiments where the wellbore fluid includes a non-aqueous-based wellbore fluid, such as an oil-based wellbore fluid or a synthetic-based wellbore fluid, the base fluid may include an oleaginous or oil-based fluid, such as a natural or synthetic oil. In some embodiments the oleaginous fluid is selected from the group consisting of at least one of diesel oil, mineral oil, a synthetic oil, (e.g., hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branched olefins), a mixture of alkanes with a carbon chain length ranging from Cio to C20 (e.g., Saraline 185V, commercially available from Shell PLC of London, England), polydiorganosiloxanes, siloxanes, organosiloxanes, or esters of fatty acids (e.g., straight chained, branched and cyclical alkyl ethers of fatty acids). In some embodiments, the base fluid includes a mixture of Ci6 to Cis internal olefins (an alkene in which the double bond is within the carbon chain rather than at a terminal portion (at the alpha position) of the carbon chain).

[0048] An internal phase of an emulsion of the oleaginous or oil-based fluid may include one or more salts. The one or more salts may provide a desired density to the wellbore fluid and may also reduce the effect of the wellbore fluid on hydratable clays and shales in the earth formation 101. The salts may include salts of one or more of sodium, calcium, aluminum, magnesium, zinc, potassium, strontium, or lithium, and salts of one or more of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, phosphates, sulfates, silicates, or fluorides. In some embodiments, the salt includes a divalent halide, such as an alkaline earth halide (e.g., calcium chloride (CaCE), calcium bromide (CaBn)), or a zinc halide. The salt may include cesium formate (HCOOR), sodium bromide (NaBr), potassium bromide (KBr), and cesium bromide (CsBr). The particular composition of the salt may be selected based on compatibility with the earth formation 101 and / or to match the brine phase of a completion fluid and / or a non-aqueous fluid. In some embodiments, the salt includes calcium chloride.

[0049] The salt may constitute from about 5.0 weight percent (wt%) to about 30.0 wt% of the wellbore fluid, such as from about 5.0 wt% to about 10.0 wt%, from about 10.0 to about 20.0 wt%,FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT or from about 20.0 wt% to about 30.0 wt% of the wellbore fluid. However, the disclosure is not so limited, and the weight percent of the salt and the water in the wellbore fluid may be different than that described.

[0050] While FIG. 1 illustrates a drilling system, the corrosion inhibitor compositions disclosed herein may be used in production fluids. For example, after the well is drilled, the wellbore including any production tubing (e.g., pipe), cement, sealant, other materials, or portions thereof may be contacted with by production fluid to collect contents of a well or earth formation 101. Additionally, topside equipment such as risers, separators, pumps, pipeline equipment, or the like may be contacted by the production fluid(s) during use. The production fluid may include water (e.g., produced water), one or more hydrocarbons (e.g., oil, gas), particulates (e.g., dirt, sand), salts, additives, or combinations of any of the foregoing with water. The additives include the corrosion inhibitors disclosed herein, and may further include any of the other additives disclosed herein, such as demulsifiers, scale inhibitors, additional corrosion inhibitors, hydrate inhibitors, paraffin inhibitors, biocides, defoamers, fluid loss additives, or the like.

[0051] Production fluid may be highly corrosive without treatment. For example, production fluid may initially include minimal or even no added salts, but may pick up and carry salts (e.g., dissolved or solid) after introduction into the earth formation. The production fluid (e.g., produced water or brine) may contain salts of calcium, sodium, magnesium, potassium, strontium, aluminum, barium, iron and other divalent or monovalent salts. Accordingly, the corrosion inhibitor compositions disclosed herein may be used to protect equipment from corrosion by production fluids.

[0052] In some examples, a wellbore fluid containing at least some of the corrosion inhibitor composition may be introduced into a well to carry or force hydrocarbons out of the earth formation 101 into which the well extends. For example, a wellbore fluid including water having the corrosion inhibitor disposed therein may be pumped into the well via a first orifice in a wellbore and then may be collected as the production fluid from a second annulus in the wellbore. In some examples, the first and second anulus are concentric.

[0053] In some examples, the feed of wellbore fluid into the wellbore may be continuous for a selected duration. In such examples, the corrosion inhibitor compositions disclosed herein may be continuously fed into the well bore, such as to maintain a selected concentration (e.g., about 5 ppm to about 250 ppm) in the wellbore fluid. Accordingly, any surfaces that the wellbore (e.g.,FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT production) fluid touches may be contacted with the amino acid functionalized phytic acid corrosion inhibitors disclosed herein to protect the surfaces from corrosion and scaling. The corrosion inhibiting compositions disclosed herein may be particularly useful in offshore oil and gas applications.

[0054] This disclosure describes the synthetic design of an amino acid functionalized phytic acid derived core as a novel class of corrosion inhibitor for oil and gas applications. The amino acid functionalized phytic acid is used as a corrosion inhibitor and scale inhibitor in corrosion inhibitor compositions. The corrosion inhibitor compositions include the corrosion inhibitor, at least one solvent, and optionally, one or more additives.

[0055] FIG. 2 is an illustration of the chemical structure of phytic acid 200, according to one or more examples of the disclosure. Phytic acid 200, also known as inositol hexaphosphate or IP6, is a six-fold dihydrogenphosphate ester of inositol (e.g., cyclohexane-l,2,3,4,5,6-hexol). As shown, the structure of phytic acid consists of an inositol ring at the center, surrounded by six phosphate groups linked thereto, as illustrated in FIG. 2. Any of the stereoisomers of phytic acid may be utilized for the core of the amino acid functionalized phytic acid.

[0056] The phytic acid core may be functionalized to impart one or more properties to the resulting functionalized phytic acid. As discussed in more detail below, amino acid groups bound to phytic acid have shown particular utility for corrosion inhibition and scaling inhibition.

[0057] FIG. 3 is an illustration of a synthesis scheme for forming an amino acid functionalized phytic acid, according to one or more embodiments. As shown, phytic acid 200 is functionalized with one or more amino acids to synthesize amino acid functionalized phytic acid molecules for use as corrosion inhibitors in oil and gas applications, and CO2 environments. Such functionalization takes place through substitution of the hydroxyl functional groups on one or more phosphates of the phytic acid with one or more amino acids. Acidic conditions may be used to catalyze the functionalization of the phosphate groups bound to the inositol core. The resulting functionalized phytic acid includes one or more amino acid groups bound thereto.

[0058] Partial or complete substitution of the terminal hydroxyl groups present on phytic acid with an amino acid can be achieved as described below. The reactants include phytic acid and one or more amino acids in an aqueous solution. As mentioned above, the reaction may be performed using an acid catalyst such as hydrochloric acid, sulfuric acid, or the like. Under such conditions, the hydroxyl groups of the phosphate functional groups are (hydro)lysed from the phosphate groupFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT and replaced by the carboxylic acid functional group of the amino acid to form an esterified phytic acid-amino acid compound (e.g., amino acid functionalized phytic acid).

[0059] In some examples, the heat of the reaction mixture may be raised above an ambient temperature, such as to at least about 25 °C, about 25 °C to about 90 °C, about 25 °C to about 50 °C, about 30 °C to about 45 °C, about 45 °C to about 60 °C, about 60 °C to about 75 °C, about 75 °C to about 90 °C, less than about 60 °C, less than about 50 °C, or less than about 45 °C. In some examples, a first temperature may be used for a first portion of the synthesis process and a second temperature may be used for a second portion of the synthesis process. In some examples, at least a portion the reaction between phytic acid and one or more amino acids may be carried out under negative pressure (e.g., a vacuum).

[0060] Any amino acids may be used to functionalize phytic acid. The general structure of an amino acid includes a central carbon atom (known as the alpha carbon), bonded to an amine or amino group (-NH2), a carboxyl group (-COOH), a hydrogen atom (-H), and a side chain (Ro group discussed below) that is unique to each amino acid. The side chain can range from a single hydrogen atom (as in glycine) to complex ring structures (as in tryptophan). The chemical properties of the side chain determine the characteristics and role of each amino acid. Amino acids can be classified based on the characteristics of their side chains. For example, they can be categorized as nonpolar, polar, acidic, or basic. Although any of the 20 essential or proteinogenic amino acids may be used, examples of amino acids that may be used in corrosion inhibitor compositions include glycine, cysteine, methionine, lysine, homocysteine, arginine, cystine, histidine, phenylalanine, tyrosine, or glutathione. In some examples, the one or more amino acids may include amino acids other than proteinogenic amino acids. Some amino acids that are particularly useful in corrosion inhibitor compositions include glycine, cystine, methionine, cysteine, and homocysteine. Any amino acid with heteroatoms may be useful in a corrosion inhibitor composition, such as sulfur, oxygen, or nitrogen, or the like. Sulfur heteroatoms have demonstrated particularly good corrosion inhibition effect in the corrosion inhibitor compositions disclosed herein.

[0061] As shown in FIG. 3, the amino acid functionalized phytic acid includes one or more amino acid groups bound thereto at one or more of R1-R12. Accordingly, the resulting functionalized phytic acid includes one or more amino acid groups bound thereto through the phosphorous atom(s) in the phosphate group(s). Put another way, R1-R12 of the functionalizedFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT phytic acid shown below in Formula 1 below may independently include hydroxyl groups or at least one amino acid group, such as any of the amino acids disclosed herein.

[0062] Formula 1 :

[0063] One or more of the functional groups R1-R12 may independently have the structure of Formula 2 below.

[0064] Formula 2:where Ro includes one or more heteroatoms or hydrogen(s). The one or more heteroatoms may include oxygen, nitrogen, or sulfur. Ro may include more than one hetero atom, such as one or more sulfur atoms, one or more oxygen atoms, one or more nitrogen atoms, or combinations of any of the foregoing. Ro may include a carbon chain having at least 1 carbon therein, such as 1-20 carbon units. In some examples, Ro may include an alkane, an alkene, an ether, an amide, a thiol, or a ring structure. In some examples, the at least one heteroatom may be disposed in or on a carbon ring such as in tryptophan.

[0065] While the term “amino acid” is generally reserved for the 20 amino acids used by living organisms (also known as essential amino acids), other compounds containing amino and carboxyl functional groups may also exist and be considered. In some examples, the “amino acids” may alternatively or additionally include other amino carboxylic acids such as cystine, para-FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT aminobenzoic acid (PABA), aspartic acid, ethylenediamine tetraacetic acid (EDTA), glutamic acid, aspartic acid, or the like.

[0066] In some examples, the amino acids (e.g., amino acid functional group bonded to the phosphorus) may include ketones having least one ketone functional group, one or more carboxylic acid functional groups, and one or more amine functional groups. Such examples may include multiple amino acids bonded to each other, such as with glutathione (e.g., glutamic acid, cysteine, and glycine bonded together). In some examples, the amino acid functional group may include one or more amide functional groups.

[0067] The amino acid functionalized phytic acid shown may include at least one amino acid functional group bound to the phosphorous atom(s) in the phosphate group(s). In some examples, at least one of R1-R12 independently include an amino acid functional group, such as each of Ri- R12, at least two ofRi-Ri2, at least five ofRi-Ri2, two to six ofRi-Ri2, three to eight of R1-R12, six to twelve of R1-R12, less than 12 of R1-R12, less than eight of R1-R12, less than six of R1-R12, or less than five of less than 12 of R1-R12 independently include the amino acid functional group bound to the phosphorus atom of the corresponding phosphate group. For example, at least two or at least five amino acid functional groups may be bound to any combination of the six phosphorous atoms of the phytic acid core. The number of amino acid functional groups bound to the phytic acid core may control the efficacy of the resulting amino acid functionalized phytic acid as a corrosion inhibitor and scaling inhibitor.

[0068] In some examples, each of the amino acid functional groups may be identical. In some examples, more than one type of amino acid functional group may be bound to the phytic acid core at any combination of R1-R12. Any combination of any of the amino acids disclosed herein may be bound to the phytic acid core at any combination of R1-R12. For example, any of R1-R12 may independently include glycine, cysteine, methionine, lysine, homocysteine, arginine, cystine, histidine, phenylalanine, tyrosine, or glutathione, or any combinations thereof.

[0069] During the reaction shown in FIG. 3, the amino acids may be in zwitterionic form with a carboxylate ion on the acid side and a protonated amine ion (NFbf) on the amine side. In some examples, the amino acid reactant may include at least a carboxylate ion. For example, the amino acid may be provided as a salt and may be subsequently dissolved in a solvent containing phytic acid. In such examples, the salt may be a hydrochloride salt such as glycine hydrochloride, cysteine hydrochloride, or the like. The aqueous chloride ions may act as a buffer in the reaction mixture,FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT such as when hydrochloric acid is used as a catalyst. In some embodiments, the amino acid(s) may be provided as sodium salts (e.g., glycine sodium salt hydrate, sodium arginate) or potassium salts (e.g., potassium glycinate, glutamic acid potassium salt monohydrate). Salts may be in anhydrous or hydrate forms. The hydroxyl group on one or more of the phosphate groups may be hydrolyzed and replaced by an amino acid to form an amino acid functionalized phytic acid corrosion inhibitor.

[0070] In some examples, the amino acid-functionalized phytic acid may be produced starting with a dephosphorylated phytic acid or inositol core. The core may be functionalized with phosphoric acid functional groups prior to functionalization with one or more amino acids.

[0071] Upon bonding to the phosphorous atoms on the phytic acid core, the one or more amino acid functional groups impart corrosion and scaling inhibiting characteristics to the amino acid functionalized phytic acid corrosion inhibitor.

[0072] The corrosion inhibitor may be mixed with one or more solvents to form a corrosion inhibitor composition. The corrosion inhibiting composition may be mixed with a wellbore fluid to providing one or more of corrosion or scaling inhibition on production tubing, drilling equipment, platforms, decking, and downhole as well as topside (e.g.., surface) components of a wellsite operation.

[0073] In some examples, one or more types of corrosion inhibitors may be mixed with a solvent to retain the corrosion inhibitor(s) in stable form and / or for use as an additive for drilling compositions. For example, the corrosion inhibitor (e.g., amino acid functionalized phytic acid) may be diluted to a selected weight percentage (e.g., % activity) with at least one solvent. In some examples, the corrosion inhibitor is 35 weight percent (wt%) or less of the corrosion inhibitor composition, such as about 0.1 wt% to about 35 wt%, about 1 wt% to about 10 wt%, about 10 wt% to about 20 wt%, about 20 wt% to about 30 wt%, about 1 wt% to about 15 wt%, about 5 wt% to about 25 wt%, about 15 wt% to about 35 wt%, less than about 30 wt%, or less than about 25 wt% of the corrosion inhibitor composition. In some examples, the balance of the corrosion inhibitor composition may include the solvent only.

[0074] The solvent is composed to retain the corrosion inhibitor therein. In some examples, more than one solvent may be present in the corrosion inhibitor composition. Suitable solvents include water (e.g., distilled water), aliphatic alcohols (e.g., methanol, ethanol, propanol, isopropanol, butanol, isobutanol), a base oil, monoethylene glycol, diethylene glycol, triethylene glycol, ethylene glycol monomethyl ether (2-methoxyethanol), ethylene glycol monoethyl ether (2-FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT ethoxyethanol), ethylene glycol monopropyl ether (2-propoxyethanol), Ethylene glycol monoisopropyl ether (2-isopropoxy ethanol), ethylene glycol monobutyl ether (2 -butoxyethanol), ethylene glycol monophenyl ether (2-phenoxy ethanol), ethylene glycol monobenzyl ether (2- benzyloxy ethanol), propylene glycol methyl ether, (l-methoxy-2-propanol), di ethylene glycol monomethyl ether (2-(2-methoxyethoxy)ethanol, methyl carbitol), diethylene glycol monoethyl ether (2-(2-ethoxyethoxy)ethanol, carbitol cellosolve), diethylene glycol mono-n-butyl ether (2- (2-butoxyethoxy)ethanol, butyl carbitol), dipropyleneglycol methyl ether, or mixtures of any of the foregoing.

[0075] In some examples, the corrosion inhibitor composition may include one or more additives, such as synergists, surfactants, demulsifiers, additional corrosion inhibitors (e.g., other than phytic acid-based corrosion inhibitors), scale inhibitors, hydrate inhibitors, paraffin inhibitors, biocides, defoamers, fluid loss additives, viscosifiers, or any other additives disclosed herein. In some examples, the one or more additives may include cationic, anionic, zwitterionic, or nonionic surfactants; thiols; thioacids; thiosulfates; or other derivatives. In some examples, the corrosion inhibitor composition includes at least one synergist and at least one surfactant as additives.

[0076] The one or more anionic surfactants may include carboxylates (e g., CnTEn+iCOO — X), sulfates (e.g., CnPEn+iOSC — X), sulphonates(e.g., CnfEn+i SCh — X), or phosphates, (e.g., CnH2n+iOPO(OH)O — X); where for each of the foregoing n = 8 to 16 atoms and X includes sodium, potassium, or the like. The one or more cationic surfactants may include quaternary ammonium compounds with the general formula R’R”R”’R”” N+X’, where each R group independently includes an alkyl group (e.g., C1-C22) and X is includes a halide anion such as chloride. Suitable examples of cationic surfactants include alkyl trimethyl ammonium chloride, where the alkyl group contains 8-18 C atoms (e.g., dodecyl trimethyl ammonium chloride), dialkyl dimethyl ammonium chloride where the alkyl groups having a chain length of 8-18 C atoms, or alkyl dimethyl benzyl ammonium chloride. In some examples, the cationic surfactants may include an imidazoline quaternary, such as the ditallow derivative quaternized with dimethyl sulphate.

[0077] The one or more zwitterionic surfactants may include N-alkyl betaines (e.g., derivatives of trimethyl glycine). An example of betaine surfactant is lauryl amido propyl dimethyl betaine. These alkyl betaines are sometimes described as alkyl dimethyl glycinates.

[0078] The one or more non-ionic surfactants may include alcohol ethoxylates, alkyl phenol ethoxylates, fatty acid ethoxylates, monoalkaol-amide ethoxylates, sorbitan ester ethoxylates, fattyFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT amine ethoxylates, ethylene oxi de-propylene oxide copolymers, multihydroxy products such as glycol esters, glycerol (and polyglycerol) esters, glucosides (and polyglucosides), sucrose esters, or combinations of any of the foregoing. Amine oxides and sulfinyl surfactants represent nonionic solvents with a small head group.

[0079] In some examples, suitable synergists may include one or more of 2-mercaptoethanol, thioglycolic acid, sodium thiosulfate. In some examples, the corrosion inhibitor includes at least one synergist. In some examples, the corrosion inhibitor includes only one synergist.

[0080] In some examples, an additive may be at least about 0.1 wt% of the corrosion inhibitor composition, such as about 0.1 wt% to about 10 wt%, about 0.1 wt% to about 1.0 wt%, about 1.0 wt% to about 3.0 wt%, about 3.0 wt% to about 6.0 wt%, about 6.0 wt% to about 10.0 wt%, less than about 10.0 wt%, less than about 6.0 wt%, or less than about 4.0 wt% of the corrosion inhibitor composition. A plurality of additives may each independently be present in any of the amounts disclosed above.

[0081] In examples with additives, the amount of corrosion inhibitor (e.g., functionalized phytic acid) in the corrosion inhibitor composition may be unchanged, but the amount of solvent may be reduced by the amount of additive(s).

[0082] The corrosion inhibitor compositions disclosed herein are composed to provide corrosion resistance for more than 15 hours, such as about 15 hours to about 48 hours, about 20 hours to about 36 hours, more than about 20 hours, more than about 24 hours, or less than about 72 hours.

[0083] The amino acid functionalized phytic acid corrosion inhibitors disclosed herein have been shown to exhibit corrosion inhibition properties, through their ability to adsorb at the metal interface and form a film. Phytic acid has ion-chelating capabilities. Without being bound by any specific theory, by synthesizing a phytic acid substituted with amino acids, the inventors currently believe the amino acid groups are able to adsorb and form a film on metal surfaces that prevents corrosion of the metal surfaces, and any unsubstituted groups on the phytic acid core are able to chelate any metals in solution, thus also delaying corrosion.

[0084] The corrosion inhibitor composition (e.g., 10-25% activity) maybe dosed into a wellbore fluid to inhibit corrosion and scaling on drilling, downhole, production, pumping, separating, or other oil and gas equipment. As explained in more detail below, various tests were carried out to the determine properties of amino acid functionalized phytic acid, such as corrosion potential and corrosion inhibition.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0085] Notwithstanding the techniques and components for forming corrosion inhibitor compositions disclosed above, various methods of forming may be performed using phytic acid and amino acid functional groups disclosed herein.

[0086] FIG. 4 is a flow diagram of a method 400 of forming a corrosion inhibitor composition, according to one or more embodiments of the present disclosure. The method 400 includes an act 410 of providing an amino acid functionalized phytic acid, and act 420 of adding the amino acid functionalized phytic acid to a solvent composed to retain the amino acid functionalized phytic acid therein effective to form the corrosion inhibitor composition. The method 400 may include more or fewer acts than the acts 410-420. For example, any of the acts 410 or 420 may be combined, split into separate acts, or omitted. Additional acts may be included in the method 400.

[0087] The act 410 of providing an amino acid functionalized phytic acid may include providing one or more of any of the amino acid functionalized phytic acids disclosed herein. For example, the amino acid functionalized phytic acid may include a phytic acid core having one or more of glycine, cysteine, methionine, lysine, homocysteine, arginine, cystine, histidine, phenylalanine, tyrosine, glutathione, or the like bound thereto at one or more locations.

[0088] In some examples, providing the amino acid functionalized phytic acid may include forming the amino acid functionalized phytic acid. In such examples, amino acid functionalized phytic acid may include any of the techniques for forming amino acid functionalized phytic acid disclosed herein. For example, providing an amino acid functionalized phytic acid may include providing a phytic acid, and reacting the phytic acid with one or more amino acids to form the amino acid functionalized phytic acid. The one or more amino acids may include any of the amino acids disclosed herein, such as one or more of glycine, cysteine, methionine, lysine, homocysteine, arginine, cystine, histidine, phenylalanine, tyrosine, glutathione, or the like.

[0089] Providing a phytic acid may include providing pure phytic acid, such as any of the phytic acids (e.g., stereo isomers, such as the myo isomer) disclosed herein. Providing phytic acid may include forming phytic acid. Forming phytic acid may include providing inositol and bonding phosphate groups to each of the oxygen atoms bonded to the hexane ring in inositol.

[0090] Reacting the phytic acid with one or more amino acids to form the amino acid functionalized phytic acid may include using any of the amino acids disclosed herein as a reactant. The phytic acid may be disposed in a reactor vessel. The phytic acid may be provided as a selected percent solution in water, such as at least 5% solution in water (e g., 60% solution in a waterFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT solvent). In some examples, the phytic acid may be provided as a powder and dissolved in the water and later heated as disclosed below. The solution may be heated for a time at a temperature of at least 25 °C (e.g., 45 °C) to dehydrate the phytic acid solution. The dehydration time may be at least 10 minutes, such as 10 minutes to 4 hours, 30 minutes to 1.5 hours, 1 hour to 2 hours, less than 3 hours, less than 2 hours, or less than 1 hour. A vacuum may be applied during dehydration. Put another way, the dehydration may be carried out under negative pressure.

[0091] Reacting the phytic acid with one or more amino acids to form the amino acid functionalized phytic acid may include adding an acid catalyst to the mixture. The acid catalyst may include an inorganic acid, such as one or more of hydrochloric acid, sulfuric acid, nitric acid, or the like. The acid catalyst may be provided in a relatively small amount, such as at least one drop of concentrated acid. For example, the acid may be provided in a volume of at least about 0.05 milliliters (mL), such as about 0.05 mL to about 1.0 mL, about 0.05 mL to about 0.5 mL, about 0.1 mL to about 0.4 mL, about 0.3 mL to about 0.7 mL, about 0.6 mL to about 1.0 mL, more than about 0.25 mL, more than about 0.5 mL, or less than 1.0 mL. The molarity (M) of the acid catalyst in the resulting mixture may be at least about 0.03 M, such as about 0.03 M to about 0.3 M, about 0.05 M to about 0.1 M, about 0.1 M to about 0.2 M, about 0.2 M to about 0.3 M, less than 1 M, or less than 0.3 M, less than 0.1 M.

[0092] The amino acid(s) may be added to the reaction mixture, such as the mixture having the phytic acid and catalyst therein. The amino acid may be provided in a liquid form or a salt form. For example, the amino acid may be provided as a hydrochloride salt such as glycine hydrochloride, cysteine hydrochloride, or the like. The amino acid may be provided in an amount sufficient to functionalize the phytic acid to a selected degree (e.g., functionalize a selected number of R1-R12). For example, the amino acid may be provided in a molecular ratio of amino acid to phytic acid that is greater than about 0.5, such as about 0.5 to about 10, about 0.5 to about 1, about 1 to about 3, about 2 to about 4, about 3 to about 6, about 6 to about 10, less than about 8, less than about 6.0, less than about 4.0, less than about 3.0, or less than about 2.0. Any of the amino acids disclosed herein may be present on the phytic acid core in any of the amounts disclosed herein. The degree of substitution or functionalization may be controlled at least in part by one or more of the polarity or size of the amino acid(s).

[0093] In some examples, cysteine may be substituted onto the phytic acid core to provide 4 to 10 or 4 to 6 cysteine functional groups (e.g., degree of substitution) on the resulting cysteineFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT functionalized phytic acid. In some examples, lysine may be substituted onto the phytic acid core to provide 3 to 5 lysine functional groups on the resulting lysine functionalized phytic acid. In some examples, homocysteine may be substituted onto the phytic acid core to provide 1 to 5 or 2 to 4 homocysteine functional groups on the resulting homocysteine functionalized phytic acid. In some examples, arginine may be substituted onto the phytic acid core to provide 2 to 6 or 2 to 4 arginine functional groups on the resulting arginine functionalized phytic acid. In some examples, cystine may be substituted onto the phytic acid core to provide 1 to 6 or 1 to 3 cystine functional groups on the resulting cystine functionalized phytic acid. In some examples, phenylalanine may be substituted onto the phytic acid core to provide 1 to 6 or 3 to 5 phenylalanine functional groups on the resulting phenylalanine functionalized phytic acid. In some examples, glutamic acid may be substituted onto the phytic acid core to provide 2 to 8 or 4 to 6 glutamic acid functional groups on the resulting glutamic acid functionalized phytic acid.

[0094] After addition of the amino acid(s), the mixture may be heated for a selected duration. The heating may include any of the temperatures disclosed above. In some examples, the heating may be at least about 35 °C, such as about 35 °C to about 95°C, about 35 °C to about 55 °C, about 50 °C to about 70°C, about 70 °C to about 95°C, about 80 °C to about 90°C, less than about 95 °C, or less than about 85 °C. The (elevated or second) heating may be carried out for at least about 30 minutes, such as about 30 minutes to about 24 hours, about 1 hour to about 5 hours, about 2 hours to about 4 hours, about 5 hours to about 10 hours, less than about 24 hours, less than about 10 hours, less than about 5 hours, or less than about 3 hours. During the second heating period, hydroxyl groups are lysed from the phosphate groups of the phytic acid and the amino acids bond to the phosphorous atoms of the phytic acid to form the functionalized phytic acid. During the second heating period, the mixture may be subjected to negative pressure, such as being heated under vacuum. Under such conditions, the amino acid functionalized phytic acid mixture is at least partially dewatered. In such examples, the resulting amino acid functionalized phytic acid is substantially isolated without an additional purification step. In some examples, some water may be present in the product(s) amino acid functionalized phytic acid.

[0095] FIG. 5 is an image illustrating synthesis of phytic acid functionalized with cysteine, according to one or more embodiments of the present disclosure. As shown in FIG. 5, phytic acid (36.5 g) is used as a reactant along with cysteine (19.32 g). The phytic acid is provided as a 60% solution in water. In a first step, the phytic acid is heated under vacuum at 45 °C for an hour toFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT dehydrate the phytic acid. After the first step, five drops (approximately 0.25 mL) of concentrated hydrochloric acid are added to the phytic acid and stirred. Subsequently, the cysteine (cysteine hydrochloride monohydrate) is added to the mixture slowly. The mixture is then heated at 85 °C under vacuum for three hours. The product cysteine functionalized phytic acid was then isolated without further purification.

[0096] While the preceding example utilizes cysteine and above reaction conditions, any of the amino acids and reaction conditions / steps disclosed herein may be used to form a corrosion and scaling inhibitor.

[0097] Returning to FIG. 4, the act 420 of adding the amino acid functionalized phytic acid to a solvent composed to retain the amino acid functionalized phytic acid therein effective to form the corrosion inhibitor composition. Adding the amino acid functionalized phytic acid to a solvent may include diluting the amino acid functionalized phytic acid with the solvent(s). For example, after the second heating period, the substantially pure amino acid functionalized phytic acid may be diluted with a selected solvent to a selected concentration (e.g., activity level). The amino acid functionalized phytic acid may be diluted with water, a base oil, monoethylene glycol, or the like. The selected concentration may be any of the concentrations disclosed herein for a corrosion inhibitor composition, such as at least about 1 wt% (e.g., 1% activity), about 1 wt% to about 15 wt%, about 15 wt% to about 30 wt%, about 20 wt% to about 30 wt%, less than about 30 wt%, or about 25 wt% or less. For example, the amino acid functionalized phytic acid may form less than 35 wt% of the corrosion inhibitor composition.

[0098] In some examples, the method 400 may include storing the corrosion inhibitor composition, such as in a barrel, drum, tank, bucket, or the like. During such storage, the amino acid functionalized phytic acid may remain stable in the solvent(s) of the corrosion inhibitor composition.

[0099] In some examples, the method 400 includes adding one or more additives to the corrosion inhibitor composition, such as any of the additives disclosed herein (e.g., viscosifier, fluid loss additive, emulsifier).

[0100] The corrosion inhibitor composition may be added to wellbore fluid (e.g., production fluid or drilling fluid) to prevent corrosion and scaling on production, drilling, and downhole equipment (e.g., pipe).FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0101] FIG. 6 is a flow diagram of a method 600 of forming a borehole extending through an earth formation, according to one or more embodiments of the present disclosure. The method 600 includes an act 610 of mixing a corrosion inhibitor composition with a wellbore fluid, and an act 620 of pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation. The method 600 may include more or fewer acts than the acts 610-620. For example, any of the acts 610 or 620 may be combined, split into separate acts, or omitted. Additional acts may be included in the method 600, such as forming the borehole via drilling, or collecting production fluid from the borehole.

[0102] The act 610 of mixing a corrosion inhibitor composition with a wellbore fluid may include using any of the corrosion inhibitor compositions — corrosion inhibitors and solvents — disclosed herein. For example, the corrosion inhibitor composition may include at least one amino acid functionalized phytic acid of formulas 1 and 2 above. The amino acid(s) bound to the phytic acid core may include one or more of glycine, cysteine, methionine, lysine, homocysteine, arginine, cystine, histidine, phenylalanine, tyrosine, or glutathione. In some examples, the amino acid functional groups include one or more heteroatoms such as sulfur, nitrogen, or oxygen. The amino acid(s) are bonded to the phosphorous atom of one or more of the phosphate groups of the phytic acid core to form one or more amino acid functional groups thereon.

[0103] The corrosion inhibitor composition may include any of the solvents disclosed herein, such as water, base oil, monoethylene glycol, or the like. For example, the corrosion inhibitor composition may include a composition having about 25 wt% of cysteine functionalized phytic acid in water. The solvent is composed to retain the corrosion inhibitor therein, such as without reacting with other components of the composition.

[0104] The corrosion inhibitor may be present in the corrosion inhibitor composition in any of the amounts (wt%) disclosed herein with at least some of the remainder including the solvent(s). For example, mixing a corrosion inhibitor composition with a wellbore fluid includes mixing the corrosion inhibitor composition including less than about 35 wt% (e.g., 20 wt% to 30 wt%) of the corrosion inhibitor with the wellbore fluid.

[0105] The wellbore fluid may include any of the wellbore fluids disclosed herein, such as an aqueous-based wellbore fluid or a non-aqueous-based wellbore fluid. The wellbore fluid may be a production fluid including water (e.g., sea water, brine, fresh water, produced water, municipal water, grey water). The wellbore fluid may be a drilling mud. Mixing a corrosion inhibitorFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT composition with a wellbore fluid includes feeding the corrosion inhibitor composition into the wellbore fluid, such as in a drilling fluid (mud) pond. Mixing a corrosion inhibitor composition with a wellbore fluid may include flowing the corrosion inhibitor composition from a drum, a barrel, or other container, into the wellbore fluid.

[0106] The corrosion inhibitor composition may be fed at a selected rate to achieve and maintain a selected concentration of the corrosion inhibitor in the wellbore fluid. For example, mixing a corrosion inhibitor composition with a wellbore fluid includes adding the corrosion inhibitor composition into the wellbore fluid effective to form a wellbore fluid having 500 ppm or less of the corrosion inhibitor therein. After mixing, the corrosion inhibitor may be present in a concentration of about 1 ppm to about 500 ppm in the wellbore fluid, such as about 1 ppm to about 100 ppm, about 100 ppm to about 200 ppm, about 200 ppm to about 300 ppm, about 1 ppm to about 50 ppm, about 10 ppm to about 40 ppm, about 50 ppm to about 100 ppm, more than about 1 ppm, more than about 10 ppm, less than about 250 ppm, less than about 100 ppm, or less than about 50 ppm.

[0107] While intended to be continuously introduced into a production fluid, drilling fluid, or other wellbore fluid, the corrosion inhibitors and corrosion inhibitor compositions disclosed herein may provide corrosion resistance for at least 15 hours, such as at least 20 hours or at least 22 hours.

[0108] The act 620 of pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation may include pumping any of the wellbore fluids disclosed herein. The act 620 of pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation may include pumping any of the corrosion inhibitor compositions disclosed herein into the earth formation in the wellbore fluid. The act 620 of pumping the wellbore fluid may include pumping the wellbore fluid into or through the wellbore, a production pipe, a drill pipe, or other portion of a borehole, such as from the surface.

[0109] The act 620 of pumping the wellbore fluid may include pumping the wellbore fluid into the earth formation at a selected pressure, such as to force the wellbore fluid into the earth formation to carry or force one or more hydrocarbons out of the earth formation via the well bore fluid (e.g., production fluid).

[0110] The act 620 of pumping the wellbore fluid may include forming a borehole in the earth formation while pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation. Forming the borehole may include drilling the borehole in the earth formationFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT using any of the drilling techniques and equipment disclosed herein, while pumping the wellbore fluid into the earth formation, such as into the borehole.

[0111] The act 620 of pumping the wellbore fluid may include discharging the wellbore fluid from one or more selected-size nozzles, jets, or other orifices in a drill bit, such as for the purposes of cooling the drill bit, for cutting structures thereon, or for lifting cuttings out of the borehole or wellbore as it is being drilled.

[0112] The method 600 may include adjusting the amount of the corrosion inhibitor composition pumped from a first amount to a second amount. For example, the adjustment may be from a lower concentration to a higher concentration or vice versa. Such adjustments may be based on one or earth formation fluid composition, wellbore fluid composition, or the like over time, such as when changes in the foregoing are detected over time.

[0113] The method 600 may include collecting at least a portion of the wellbore fluid from the well. In such examples, the wellbore fluid may be a production fluid and collecting the wellbore fluid includes collecting one or more hydrocarbons in the production fluid. In such embodiments, the method 600 may be a method of collecting fluid (e.g., hydrocarbon(s)) from an earth formation. For example, the method 600 may include mixing the corrosion inhibitor composition with a wellbore fluid (e.g., production fluid), the corrosion inhibitor composition including a corrosion inhibitor including a functionalized phytic acid having one or more amino acid groups a solvent composed to retain the corrosion inhibitor therein. The method may include pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation. In such examples, the method 600 includes collecting the wellbore fluid (e.g., production fluid) from the earth formation via the wellbore. In some examples, the method includes separating one or more hydrocarbons from the production fluid.

[0114] In some examples, the direct functionalization of the central sugar unit (e.g., inositol) of phytic acid with amino acids may also be considered. This can be carried out by dephosphorylation of phytic acid or by use of inositol, best derived from a renewable resource, followed by the functionalization reactions similar or identical to those described above to directly bond the amino acid(s) to the inositol ring. The reaction conditions and reactions may be similar or identical to those disclosed above with respect to phytic acid in one or more aspects. Such an approach may be particularly useful when environmental restrictions prefer a corrosion inhibitor without phosphor-containing moieties.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0115] Examples were made and tested to confirm the corrosion inhibition efficacy of the amino acid functionalized phytic acids disclosed herein.WORKING EXAMPLES

[0116] EXAMPLE 1

[0117] In one example, 50 mL phytic acid, obtained as 50% aqueous solution in water, was charged into a reactor, and placed under vacuum with gentle heating to 45°C to remove excess water. Subsequently, 12.27 g crystalline glycine hydrochloride was charged to the vessel, and the reaction mixture was placed under vacuum again with heating to 30°C for 3 hours to remove any produced water. A viscous paste was collected as the final product to form Example 1 and analyzed by gel permeation chromatography (GPC).

[0118] FIG. 7 is a GPC chromatogram of phytic acid functionalized with glycine, according to one or more embodiments of the disclosure. The analysis revealed that a compound with a molecular weight comparable to the calculated molecular weight of an esterified phytic acid- glycine compound was formed. The GPC showed a compound with a molecular weight around 1,516 g / mol (peak 2). This aligns with the calculated molecular weight of a fully glycine substituted molecule of phytic acid. Peak 3 indicates a molecule with a molecular weight around 660 g / mol, which is the calculated molecular weight of unaltered phytic acid. The non-integrated three peaks of higher intensity (and low molecular weight) were attributed to flowrate markers and unreacted amino acid.

[0119] Corrosion inhibition properties of various examples were tested. Corrosion inhibition potential was measured by an electrochemical technique called linear polarization resistance (LPR). LPR evaluates the performance of corrosion inhibition which allows for direct measurement of corrosion rate. Fortesting, LPR probes with two C1018 electrodes were immersed in 3% NaCl solution and sparged with CO2 for 24 hours at 65°C. The Ohm’s Law polarization resistance values (Rp (ohms cm2)) were obtained by applying a voltage sweep of 20 mV / min from -10 to +10 mV which were converted to corrosion rate in millimeter per year (mpy) using the Stem Gary equation. Exemplary corrosion inhibition results would be the lowest values for mpy possible, such as in the single digits (e.g., 4 mpy or less).

[0120] Example 1 was dosed into a monoethylene glycol solvent at a concentration of 200 ppm and analyzed by LPR to assess its effectiveness as a corrosion inhibitor. Corrosion inhibition dataFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT was collected via LPR for each starting material — phytic acid and glycine — at a concentration of 200 ppm for comparison with Example 1 (glycine functionalized phytic acid).

[0121] FIG. 8 is an LPR graph of phytic acid, according to one or more embodiments of the disclosure. FIG. 8 shows an initially high corrosion rate, slowing to below 100 mpy for a time before increasing FIG. 8 shows that phytic acid alone initially has corrosion inhibition potential, however the compound does not seem to stay attached to the metal surface well enough to provide long-term protection, as the corrosion rate increases again after about 15 hours.

[0122] FIG. 9 is an LPR graph of glycine, according to one or more embodiments of the disclosure. FIG. 9 shows that glycine alone has a steadily increasing corrosion rate initially above 200 mpy and apparently leveling off at about 450 mpy after about 20 hours of testing. Based on the test results, glycine alone has no corrosion inhibition potential.

[0123] FIG. 10 is an LPR graph of Example 1 (phytic acid functionalized with glycine), according to one or more embodiments of the disclosure. As shown in FIG. 6, Example 1 — glycine functionalized phytic acid — provides uninterrupted corrosion inhibition, steadily decreasing and maintaining below 100 mpy up to the end of the measurement time of 22 hours.

[0124] Without being bound to a particular theory, the inventors currently believe the beneficial effect of corrosion resistance demonstrated by Example 1 is that the amino acid (glycine functional group) anchors to the metal which allows the phytic acid to stay attached to the metal surface and prevents corrosion at least as a coating thereon. Any unsubstituted groups on the phytic acid are able to chelate any metals in solution, thus also delaying corrosion.

[0125] EXAMPLE 2

[0126] In a second example, 42 mL phytic acid, obtained as 60% aqueous solution in water, was charged into a reactor, and placed under vacuum with gentle heating to 45°C to remove excess water. Subsequently, five drops of concentrated hydrochloric acid and 19.32 g crystalline cysteine hydrochloride monohydrate was charged to the vessel, and the reaction mixture was placed under vacuum again with heating to 85°C for 3 hours to form Example 2 and remove any produced water. Example 2 was analyzed via GPC as disclosed above with respect to Example 1. The product contained a compound with a molecular weight of 1,319 g / mol. This aligns with the calculated molecule weight of a phytic acid-cysteine product where 6 of the available 12 hydroxyl groups have been replaced by cysteine as shown in FIG. 5.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0127] Further variations of the synthesis of the amino acid functionalized phytic acid to yield higher activity of the desired amino acid functionalized phytic acid product(s) and investigation of other amino acids that may provide a synergistic effect indicate evidence of even higher corrosion inhibition (e.g., lower corrosion rates) possibilities than Examples 1 and 2.

[0128] Further LPR testing was carried out on various amino acid functionalized phytic acids to determine the corrosion resistance of each. The LPR testing was carried out and analyzed as described above with respect to Example 1. The testing revealed average corrosion rates for the various amino acid functionalized phytic acids including phytic acid functionalized with glycine, cysteine, methionine, lysine, homocysteine, arginine, and cystine, respectively. The results are shown below in Table 1.

[0129] Table t:

[0130] As shown, the amino acids with sulfur heteroatoms, cysteine, homocysteine, and cystine, showed the highest corrosion resistance (e.g., lowest corrosion rates), followed by glycine. Methionine had relatively poor corrosion resistance, with arginine and lysine showing average corrosion resistance.

[0131] LPR testing was also carried out on various amino acids (alone, without the phytic acid core). The amino acids and results are shown below in Table 2.

[0132] Table 2:FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0133] As shown in tables 1 and 2, the amino acids with sulfur heteroatoms performed very well when functionalized onto a phytic acid core.

[0134] Testing was carried out on a corrosion inhibitor composition including 6-cysteine substituted phytic acid and having the formulation set forth in Table 3 below.

[0135] Table 3:

[0136] The formulation of Table 3 was underwent LPR testing and resulted in a performance of 3.6 mpy at 50 ppm.

[0137] The embodiments of wellbore (e.g., production or drilling) fluids including the corrosion inhibitor composition including the corrosion inhibitors have been primarily described with reference to wellbore operations, the wellbore fluids described herein may be used in applications other than the well production or drilling of a wellbore. In other embodiments, wellbore fluids including the corrosion inhibition composition according to the present disclosure may be used outside a wellbore, borehole, or other downhole environment used for the exploration or production of natural resources. Accordingly, the terms “wellbore,” “borehole,” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment. In addition, the wellbore fluids may be used in cased completion wellbores and in open hole completion wellbores, such as in production fluids.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0138] In some embodiments, the wellbore fluids may be used during formation of a borehole and / or wellbore to be used for carbon capture, utilization, and storage (CCUS) and / or for recovery and use of geothermal energy. For example, the wellbore fluids may be used to form boreholes and / or wellbores without introducing materials to the earth formation that may impede subsequent storage of carbon in the earth formation.

[0139] Geothermal energy is a promising source of renewable energy that captures energy from heat generated within the earth. For example, geothermal energy may be used to heat structures (e.g., buildings) and / or to generate electricity (e.g., by heating water to generate steam and drive a turbine with the steam). The wellbore fluids described herein may be used to form boreholes and / or wellbores used to circulate a fluid that is heated within the earth formation through which the borehole and / or wellbore extends. The heated fluid may be circulated to the surface where the captured heat may be recovered to heat a structure and / or generate electricity, followed by recirculation of the fluid to the earth formation to continue the cycle.

[0140] CCUS facilitates the capture, use, and / or storage of carbon (e.g., carbon dioxide), which has a goal of achieving carbon neutrality and / or net zero carbon emissions (NZE). CCUS may facilitate the capture of carbon dioxide from large point sources (e.g., power plants, refineries, cement plants, other industrial processing plants, or other industrial facilities that use fossil fuels, biomass fuels, or other fuels that generate carbon dioxide). The captured carbon dioxide may be converted into valuable products such as, for example, ethanol, sustainable aviation fuel, chemicals, and mineral aggregates. Alternatively, the carbon dioxide may be stored in geologic formations, such as in depleted hydrocarbon reservoirs. The carbon dioxide may be introduced into the earth formation through a borehole and / or wellbore formed using the wellbore fluids described herein. In the earth formation, the carbon dioxide may be dispersed in an aqueous phase and stored as carbon dioxide, in mineral form (e.g., as a carbonate, such as calcium carbonate, magnesium carbonate, iron (II) carbonate), or as another form of carbon.

[0141] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodimentspecific decisions will be made to achieve the developers’ specific goals, such as compliance withFILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0142] The articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements in the preceding descriptions. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

[0143] A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT

[0144] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

[0145] The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCTCLAIMSWhat is claimed is:

1. A corrosion inhibitor composition for a wellbore fluid, the corrosion inhibitor composition comprising: a corrosion inhibitor including a functionalized phytic acid having one or more amino acid groups; and a solvent composed to retain the corrosion inhibitor therein.

2. The corrosion inhibitor composition of claim 1, wherein the one or more amino acid groups includes one or more proteinogenic amino acids.

3. The corrosion inhibitor composition of claim 1, wherein the functionalized phytic acid has a chemical structure of:wherein R1-R12 independently include a hydroxyl group or an amino acid group having a structure of:, and wherein Ro includes one or more heteroatoms.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT4. The corrosion inhibitor composition of claim 3, wherein at least five of R1-R12 independently include the amino acid group.

5. The corrosion inhibitor composition of claim 3, wherein Ro includes on or more sulfur heteroatoms.

6. The corrosion inhibitor composition of claim 1, wherein the one or more amino acid groups include at least one of cysteine, methionine, lysine, arginine, tryptophan, or histidine.

7. The corrosion inhibitor composition of claim 1, wherein one or more amino acid groups include amino acids other than proteinogenic amino acids.

8. The corrosion inhibitor composition of claim 1, wherein the corrosion inhibitor is 35 weight percent or less of the corrosion inhibitor composition.

9. The corrosion inhibitor composition of claim 1, wherein the corrosion inhibitor is 5 weight percent to 25 weight percent of the corrosion inhibitor composition.

10. The corrosion inhibitor composition of claim 1, wherein the solvent includes water.

11. The corrosion inhibitor composition of claim 1, wherein the solvent includes a base oil.

12. The corrosion inhibitor composition of claim 1, wherein the corrosion inhibitor composition is composed to provide corrosion resistance for more than 15 hours.

13. A method of forming a corrosion inhibitor composition, the method comprising: providing an amino acid functionalized phytic acid; and adding the amino acid functionalized phytic acid to a solvent composed to retain the amino acid functionalized phytic acid therein effective to form the corrosion inhibitor composition.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT14. The method of claim 13, wherein providing an amino acid functionalized phytic acid includes: providing a phytic acid; and reacting the phytic acid with one or more amino acids to form the amino acid functionalized phytic acid.

15. The method of claim 13, wherein one or more amino acids of the amino acid functionalized phytic acid include at least one of cysteine, cystine, methionine, homocysteine, glycine, lysine, arginine, tryptophan, tyrosine, or histidine.

16. The method of claim 13, wherein the amino acid functionalized phytic acid forms less than 35 weight percent of the corrosion inhibitor composition.

17. A method of forming a borehole extending through an earth formation, the method comprising: mixing a corrosion inhibitor composition with a wellbore fluid, the corrosion inhibitor composition including: a corrosion inhibitor including a functionalized phytic acid having one or more amino acid groups; and a solvent composed to retain the corrosion inhibitor therein; and pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation.

18. The method of claim 17, wherein mixing a corrosion inhibitor composition with a wellbore fluid includes mixing the corrosion inhibitor composition including less than about 35 weight percent of the corrosion inhibitor with the wellbore fluid.

19. The method of claim 17, wherein mixing a corrosion inhibitor composition with a wellbore fluid includes adding the corrosion inhibitor composition into the wellbore fluid effective to form a wellbore fluid mixture having 50 ppm or less of the corrosion inhibitor composition therein.FILED ELECTRONICALLY Docket No. IS24 1049-WO-PCT20. The method of claim 17, wherein mixing a corrosion inhibitor composition with a wellbore fluid includes flowing the corrosion inhibitor composition from a drum or barrel into the wellbore fluid.

21. The method of claim 17, further comprising forming a borehole in the earth formation while pumping the wellbore fluid including the corrosion inhibitor composition into the earth formation.

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