Use of Carboxylates for Carbon Sequestration, Improved Oil Recovery, and Hydrogen Storage and Regeneration

Abstract

Described herein are compositions, techniques, methods and systems for sequestering carbon, producing oil, improving oil recovery and storing hydrogen by injecting an aqueous mixture into an underground reservoir. The aqueous mixture includes one or more carboxylates, which may represent a form of carbon dioxide and / or a form of hydrogen. The aqueous mixture including carboxylates may also be useful to alternatively increase the viscosity of fluids in the reservoir or modify the wettability of rocks in the reservoir to improve the availability and production of hydrocarbons contained within the pores of the rocks.

Description

[Technical field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims the benefit of and priority to U.S. Provisional Application No. 63 / 182,299, filed April 30, 2021, which is incorporated by reference herein in its entirety.

[0002] Field The present invention is in the field of carbon capture and sequestration, enhanced and improved oil recovery, and hydrogen storage. The present invention generally relates to compositions, methods, techniques, and systems for sequestering carbon in underground reservoirs, producing hydrocarbons, enhancing hydrocarbon production from underground reservoirs, and using underground reservoirs to store and / or regenerate hydrogen. [Background technology]

[0003] background As atmospheric carbon dioxide (CO2) levels continue to rise, carbon capture and sequestration is becoming more important. Sequestration of CO2 in underground reservoirs as gaseous CO2 or liquid CO2 is being considered, but additional technologies are needed to safely and effectively sequester carbon.

[0004] Waterflooding is useful to assist the rate of oil production from underground reservoirs and may be used to increase oil production rates and oil recovery as the reservoir is depleted. The injected water may be previously produced water or brine from the reservoir or another reservoir, and seawater, freshwater or aquifers may alternatively be used. Water may be injected at a distance from the production well to provide a driving force to displace the oil in the reservoir toward the production well and may be useful to maintain pressure in the reservoir as the oil is produced. In some cases, some oil in the reservoir may not be readily available for extraction, such as when the oil is trapped within the pores of rocks in the reservoir. Techniques exist for producing oil from porous rocks, but they may require the use of surfactants, solvents or other expensive additives that may be complex or not environmentally friendly.

[0005] Hydrogen gas (H2) is useful as a fuel for power generation using hydrogen fuel cells. However, because the H2 used to generate electricity must be available when electricity is needed, H2 is typically stored in the form of compressed gas or as a hydrogen carrier (e.g., ammonia or methylcyclohexane), which can present a challenge in storing sufficient quantities of H2 to meet demand. In some cases, H2 can be generated on demand as needed, but H2 generation is often an energy-intensive process, and on-demand generation to meet real-time needs can have significant energy requirements. Summary of the Invention [Means for solving the problem]

[0006] overview Various techniques are described herein for sequestering carbon, for oil production and production enhancement, and for storing and / or regenerating hydrogen by injecting aqueous mixtures into subterranean reservoirs. The aqueous mixture includes one or more carboxylates, which may represent a form of carbon dioxide and / or a form of hydrogen. Optionally, the aqueous mixture including the carboxylates may be useful for modifying the wettability of rocks in the reservoir to improve the availability and production of hydrocarbons contained within the pores of the rocks. Carboxylates may also be used as viscosity modifiers (e.g., to increase the viscosity of fluids in the reservoir). Furthermore, since carboxylates tend not to occur naturally in subterranean reservoirs in high concentrations, they may also alternatively be used as tracers to track the movement of fluids in the reservoir and identify well connectivity. Advantageously, carboxylates can be easily characterized and quantified using spectroscopic techniques such as nuclear magnetic resonance or liquid or gas chromatography mass spectrometry. Furthermore, carboxylates tend to be environmentally friendly, easily produced, available at low cost, and useful for both carbon and hydrogen storage as well as hydrogen regeneration. In some instances, hydrogen reclamation can occur in situ within the reservoir from injected carboxylates or at the surface from produced carboxylates.

[0007] The present technology overcomes challenges associated with sequestration of gaseous carbon dioxide in subsurface reservoirs, such as having to compress the carbon dioxide to high pressures or the possibility that the carbon dioxide may leak from the reservoir and escape to the surface, because the carbon can be securely stored in the form of a carboxylate, such as formate, acetate, or propionate. Carbon dioxide or related ions, such as carbonate or bicarbonate, can be converted to carboxylates, for example, via electrochemical reduction with water. Carboxylates can be highly miscible with water or brine, so aqueous mixtures of carboxylates can be directly injected as liquids into subsurface reservoirs without needing to be highly pressurized like carbon dioxide gas, making current liquid injection systems practical for carbon sequestration using carboxylates.

[0008] The present technology also overcomes challenges in recovering oil or hydrocarbons from subsurface reservoirs, as the presence of carboxylates in the injected aqueous mixture may modify the wettability of rock surfaces in the reservoir, changing the rock surfaces to more water-wet conditions (less oil-wet conditions), allowing for easier release and production of hydrocarbons contained within the pores of the rock. Carboxylates may also be optionally used as thickeners, alone or with one or more polymers (e.g., hydrolyzed or partially hydrolyzed polyacrylamide), to increase the viscosity of fluids in the subsurface reservoir and improve the front stability of fluid displacement in the reservoir. Advantageously, including carboxylates in the injected aqueous mixture may also help reduce the net carbon emissions associated with the production of hydrocarbons from the reservoir. In some instances, the net carbon emissions associated with the production of hydrocarbons from the reservoir may be improved using carboxylate injection, even beyond the emissions achieved by injecting CO2.

[0009] The disclosed techniques may alter the wettability of rock to advantageously enable hydrocarbon release from the reservoir, and in many cases without the use of surfactants present in the aqueous mixture, or in the absence of surfactants. However, in some cases, it may still be advantageous to include surfactants in the injected aqueous mixture. Eliminating or reducing the use of surfactants may have an additional beneficial effect, as it reduces the complexity and cost of the aqueous mixture, since stabilizers typically used to maintain surfactant stability also do not need to be used, or need to be used less. Furthermore, using surfactants as wettability modifiers may not be feasible in certain reservoirs, such as those with high salinity or high temperature conditions. The aqueous mixture may also include other components, such as solvents, that can favorably interact with the hydrocarbons in the reservoir, for example, to reduce the viscosity of the hydrocarbons, enabling easier and / or more efficient production. In some instances, carboxylates may be used with oxygenated solvents, such as ketones, to modify the wettability of rock to enable advantageous hydrocarbon release.

[0010] The present technology also provides an advantageous method for storing hydrogen gas (H2) by storing it in the form of carboxylates rather than in gas form, making it suitable for storage in underground reservoirs. For example, formic acid can act as a liquid organic hydrogen carrier, allowing reversible H2 generation / storage by catalytic (de)hydrogenation with carbon dioxide (CO2). By storing large amounts of carboxylates in underground reservoirs, these carboxylates can be produced and used for on-demand H2 generation, or catalysts (e.g., nanocatalysts and / or pH modifiers) can be added to the underground reservoir to facilitate in-situ H2 generation, such that H2 can be produced directly from the underground reservoir. Advantageously, the carboxylates injected into the underground reservoir can be produced using renewable energy resources (e.g., solar, wind, etc.), which often may be intermittent or overproduce during certain times of the day. The produced carboxylates or hydrogen produced therefrom can be produced later during periods of low renewable energy generation and used as a power generation source. In this way, the carboxylates can be useful for grid load balancing purposes.

[0011] In a first aspect, a method is disclosed herein. In one example, the method of this aspect includes obtaining an aqueous mixture including water and a carboxylate, e.g., a carboxylate having a concentration of 1% to 45% by weight, and injecting the aqueous mixture into an underground reservoir. In some cases, the underground reservoir contains water or a brine, and the carboxylate can be distributed in or throughout the water or brine in the underground reservoir. For example, the underground reservoir can be an oil or gas reservoir, a saline aquifer, a freshwater aquifer, a geothermal reservoir, or a cavity (e.g., a salt cavity). Optionally, the method of this aspect may further include determining a pH of the water or brine in the underground reservoir, and amending the pH of the aqueous mixture to be the same as or close to (e.g., within 1 pH unit) the pH of the water or brine in the underground reservoir. In examples, the pH of the aqueous mixture can be modified by adding an acid (e.g., hydrochloric acid) or a base (e.g., sodium hydroxide) to the mixture, depending on the source of the carboxylate (e.g., carboxylic acid or carboxylate salt).

[0012] To sequester carbon from, for example, carbon dioxide using the disclosed methods, carboxylates can be prepared from atmospheric CO2 or CO2 captured from industrial processes, such as directly captured CO2 or other forms of CO2, such as carbonate or bicarbonate ions in an aqueous medium. For example, carboxylates can be prepared from CO2, carbonate or bicarbonate ions using an electrochemical reduction process involving water. Advantageously, such electrochemical reduction processes can be powered using renewable energy (e.g., solar, wind, geothermal, etc.), such that the injection process functions as a net carbon negative process, since the electrochemical reduction process is carbon neutral. Additionally, as discussed above, such electrochemical reduction processes can be useful for load balancing purposes.

[0013] A variety of different carboxylates are useful in the systems, methods and aqueous mixtures described herein. For example, the carboxylates may be: [ka] where R is an alkyl group and X is H or a metal, such as an alkali metal. The carboxylate can be present in the aqueous mixture at any suitable concentration. Exemplary concentrations of the carboxylate can be from about 1% to about 45% by weight. For example, useful total concentrations of one or more carboxylates in the aqueous mixture can be from 1% to 2% by weight, 2% to 3% by weight, 3% to 4% by weight, 4% to 5% by weight, 5% to 6% by weight, 6% to 7% by weight, 7% to 8% by weight, 8% to 9% by weight, 9% to 10% by weight, 10% to 11% by weight, 11% to 12% by weight, 12% to 13% by weight, 13% to 14% by weight, 14% to 15% by weight, 15% to 16% by weight, 16% to 17% by weight, 17% to 18% by weight, 18% to 19% by weight, 19% to 20% by weight, 20% to 21% by weight, 21% to 22% by weight, 22% to 23% by weight, 23% to 24% by weight, 24% to 25% by weight, 25% to 26% by weight, 26% to 27% by weight, 27% to 28% by weight, 28% to 29% by weight, 29% to 30% by weight, 30% to 31% by weight, 31% to 32% by weight, 32% to 33% by weight, 33% to 34% by weight, 34% to 35% by weight, 35% to 36% by weight, 36% to 37% by weight, 37% to 38% by weight, 38% to 39% by weight, 39% to 40% by weight, 40% to 41% by weight, 42% to 43% by weight, 43% to 44% by weight, 44 It may be 3% by weight, 23% to 24% by weight, 24% to 25% by weight, 25% to 26% by weight, 26% to 27% by weight, 27% to 28% by weight, 28% to 29% by weight, 29% to 30% by weight, 30% to 31% by weight, 31% to 32% by weight, 32% to 33% by weight, 33% to 34% by weight, 34% to 35% by weight, 35% to 36% by weight, 36% to 37% by weight, 37% to 38% by weight, 38% to 39% by weight, 39% to 40% by weight, 40% to 41% by weight, 41% to 42% by weight, 42% to 43% by weight, 43% to 44% by weight, or 44% to 45% by weight. In embodiments, the concentration of the carboxylate is within (i.e., below or about) the solubility limit of the carboxylate in the aqueous mixture at the temperature and pressure of the subsurface reservoir. Optionally, the amount of carboxylate in the aqueous mixture is above or at the solubility limit of the carboxylate, such as in the form of a saturated or supersaturated aqueous mixture. In some embodiments, multiple carboxylates are used in the aqueous mixture.

[0014] The aqueous mixture may optionally include several different components other than water and carboxylates. For example, the aqueous mixture may optionally include fresh water, sea water, reservoir connected water, produced water, river water, pond water, or brine. In some methods, obtaining the aqueous mixture includes obtaining an aqueous solution and augmenting the aqueous solution with one or more additives including carboxylates. Optionally, the aqueous mixture includes one or more of a surfactant, a solvent, an acid, a base, a salt, a chelating agent, an inorganic compound, a polymer, a nanomaterial, a hydrocarbon, an amino acid, a biocide, nitrogen, or carbon dioxide. Examples of surfactants may include anionic surfactants, cationic surfactants, nonionic surfactants, amphoteric or zwitterionic surfactants, or any combination thereof. Examples of solvents may include hydrocarbons, hydrocarbon solvents, amines, ethers, alcohols, ketones, esters, or any combination thereof. Examples of acids may include hydrochloric acid or acetic acid. Examples of bases may include sodium hydroxide, potassium hydroxide, lithium hydroxide, ammonium hydroxide (ammonia solution / ammonia water), and / or amines. Examples of salts may include those containing sodium ions, potassium ions, magnesium ions, calcium ions, strontium ions, chloride ions, bromide ions, iodide ions, sulfate ions, bicarbonate ions, carbonate ions, or any combination thereof.

[0015] The aqueous mixture may have any suitable salinity. Optionally, the salinity of the aqueous mixture is equal to or greater than the salinity of the brine or water in the underground reservoir. Optionally, the salinity of the aqueous mixture is equal to or less than the salinity of the brine or water in the underground reservoir. A specific salinity of the aqueous mixture may be from about 0 ppm to about 250,000 ppm. For example, the salinity of the aqueous mixture can be 0 ppm to 500 ppm, 500 ppm to 1000 ppm, 1000 ppm to 5000 ppm, 5000 ppm to 10000 ppm, 10000 ppm to 50000 ppm, 10000 ppm to 15000 ppm, 15000 ppm to 20000 ppm, 20000 ppm to 50000 ppm, 50000 ppm to 100000 ppm, 100000 ppm to 150000 ppm, 150000 ppm to 200000 ppm, or 200000 ppm to 250000 ppm. Optionally, the salinity of the aqueous mixture is about 100% or less of the salinity of the brine or water in the underground reservoir. In some cases, the salinity of the aqueous mixture can affect the solubility of the carboxylate in the aqueous mixture.

[0016] In some cases, it may be desirable for the pH of the aqueous mixture to be approximately equal, e.g., within about 1 pH unit, to the pH of the brine or water in the underground reservoir. Optionally, the pH of the aqueous mixture is equal to or less than the pH of the brine or water in the underground reservoir. Optionally, the pH of the aqueous mixture is 0.1 pH units to 5.0 pH units lower than the pH of the brine or water in the underground reservoir, 0.1 pH units to 0.5 pH units lower than the pH of the brine or water in the underground reservoir, 0.5 pH units to 1.0 pH units lower than the pH of the brine or water in the underground reservoir, 1.0 pH units to 1.5 pH units lower than the pH of the brine or water in the underground reservoir, 1.5 pH units to 2.0 pH units lower than the pH of the brine or water in the underground reservoir, or 0.5 pH units to 1.0 pH units lower than the pH of the brine or water in the underground reservoir. may be 2.0 pH units to 2.5 pH units lower than the pH of the water, 2.5 pH units to 3.0 pH units lower than the pH of the brine or water in the underground reservoir, 3.0 pH units to 3.5 pH units lower than the pH of the brine or water in the underground reservoir, 3.5 pH units to 4.0 pH units lower than the pH of the brine or water in the underground reservoir, 4.0 pH units to 4.5 pH units lower than the pH of the brine or water in the underground reservoir, or 4.5 pH units to 5.0 pH units lower than the pH of the brine or water in the underground reservoir. Optionally, the pH of the aqueous mixture is equal to or greater than the pH of the brine or water in the underground reservoir.Optionally, the pH of the aqueous mixture is between 0.1 pH units and 5.0 pH units higher than the pH of the brine or water in the underground reservoir, between 0.1 pH units and 0.5 pH units higher than the pH of the brine or water in the underground reservoir, between 0.5 pH units and 1.0 pH units higher than the pH of the brine or water in the underground reservoir, between 1.0 pH units and 1.5 pH units higher than the pH of the brine or water in the underground reservoir, between 1.5 pH units and 2.0 ... may be 2.0 pH units to 2.5 pH units higher than the pH of the water, 2.5 pH units to 3.0 pH units higher than the pH of the brine or water in the underground reservoir, 3.0 pH units to 3.5 pH units higher than the pH of the brine or water in the underground reservoir, 3.5 pH units to 4.0 pH units higher than the pH of the brine or water in the underground reservoir, 4.0 pH units to 4.5 pH units higher than the pH of the brine or water in the underground reservoir, or 4.5 pH units to 5.0 pH units higher than the pH of the brine or water in the underground reservoir. In some examples, the pH of the aqueous mixture does not substantially modify the overall pH of the brine or water in the underground reservoir. However, the pH of the aqueous mixture may be used to modify, at least temporarily, the pH of the brine or water in the underground reservoir in the area surrounding the injection well. Optionally, the pH of the aqueous mixture is adjusted prior to injection. In some examples, the pH of the aqueous mixture can be from about 5 to about 9, such as 5-6, 6-7, 7-8, or 8-9.

[0017] The methods and systems described herein may be useful in a variety of different underground reservoirs. For example, the underground reservoir may be an oil or gas reservoir, a saline aquifer, a freshwater aquifer, or a geothermal reservoir. Optionally, the underground reservoir includes one or more rock types, including, but not limited to, sandstone, carbonate, or volcanic rock. Optionally, the underground reservoir includes one or more minerals, including, but not limited to, quartz, calcite, dolomite, anhydrite, gypsum, feldspar, siderite, zeolite, kaolinite, illite, chlorite, or smectite. Optionally, the underground reservoir includes organic matter, such as kerogen or bitumen. Rocks in the underground reservoir may have a porosity of less than 10% (e.g., a tight shale formation) or may have a greater porosity (e.g., up to 20% or 30%). Rocks in an underground reservoir may have a permeability of less than 5nD or 10nD, or may have a greater permeability, such as up to 5D or 10D.

[0018] For example, in the case of enhanced oil recovery and / or hydrocarbon production, the aqueous mixture or its components may contact a rock surface in an underground reservoir and, optionally, increase the water-wetting properties of the rock surface. The use of carboxylates in aqueous mixtures used to produce hydrocarbons may provide several distinct advantages. For example, carboxylates may be used as tracers to enable identification of fluid connectivity between wells in a reservoir, particularly since carboxylates do not naturally occur in underground oil or gas reservoirs and are easily identifiable and quantifiable using spectroscopic techniques.

[0019] Hydrocarbons in an underground reservoir that may be produced according to the methods described herein may include, but are not limited to, crude oil, talc, bitumen, heavy oil, tight oil, shale oil, gas condensate, or any combination thereof. In some examples, the recovery of hydrocarbons from an underground reservoir may be greater by injecting an aqueous mixture (containing one or more carboxylates) compared to the recovery of hydrocarbons from an underground reservoir without injecting the aqueous mixture. For example, by modifying the wettability conditions of rock surfaces in the reservoir, the reservoir may become more amenable to releasing hydrocarbons.

[0020] Optionally, the method of this aspect further includes disposing one or more wells in the underground reservoir. In an embodiment, injecting the aqueous mixture into the underground reservoir includes injecting the aqueous mixture into one or more wells. Optionally, the method of this aspect may further include producing a fluid from the underground reservoir, for example from one or more wells. Optionally, the fluid includes a hydrocarbon, for example in the case of enhanced oil recovery. In some embodiments, producing the hydrocarbon from the underground reservoir includes recovering at least a portion of the aqueous mixture injected into the underground reservoir. Optionally, a brine may be produced from the underground reservoir, for example during or separate from the production of hydrocarbons from the underground reservoir. Optionally, the carboxylate is present, identified, or observed as a tracer in the brine produced from the underground reservoir. For example, in the case of hydrogen storage, the fluid optionally includes a carboxylate, or the fluid optionally includes hydrogen.

[0021] Systems, such as systems for sequestering carbon in an underground reservoir, producing hydrocarbons from an underground reservoir, or storing hydrogen in an underground reservoir, are also provided herein. An exemplary system includes a source of an aqueous mixture, e.g., an aqueous mixture including water and a carboxylate, e.g., a carboxylate having a concentration of 1% to 45% by weight in the aqueous mixture; and an injection system in fluid communication with the source and the underground reservoir for injecting the aqueous mixture into the underground reservoir. Further exemplary details are described below.

[0022] Without wishing to be bound by any particular theory, the present specification may discuss a belief or understanding of underlying principles related to the present invention. It is recognized that regardless of whether any mechanistic explanation or hypothesis is ultimately correct, embodiments of the present invention may nevertheless be operable and useful. [Brief description of the drawings]

[0023] [Figure 1] 1 is a schematic diagram of an underground reservoir and a system for injecting an aqueous mixture into the underground reservoir.

[0024] [Diagram 2] FIG. 1 illustrates an overview of an exemplary carbon sequestration method.

[0025] [Diagram 3] FIG. 1 shows an overview of an exemplary hydrocarbon production process.

[0026] [Figure 4] FIG. 1 illustrates an overview of an exemplary hydrogen storage method.

[0027] [Diagram 5] 1 is a photograph showing the change in contact angle over time for Wolfcamp shale immersed in reservoir brine.

[0028] [Figure 6]1 is a photograph showing the change in contact angle over time for Wolfcamp shale immersed in 1 wt % sodium formate in reservoir brine.

[0029] [Figure 7] 1 is a photograph showing the change in contact angle over time for Eagle Ford Shale immersed in reservoir brine.

[0030] [Figure 8] 1 is a photograph showing the change in contact angle over time for Eagle Ford shale immersed in 1 wt % sodium formate in reservoir brine.

[0031] [Figure 9] 1 is a photograph showing the change in contact angle over time for Wolfcamp shale immersed in reservoir brine.

[0032] [Figure 10] 1 is a photograph showing the change in contact angle over time for Wolfcamp shale immersed in 1 wt % sodium acetate in reservoir brine.

[0033] [Figure 11] 1 is a photograph showing the change in contact angle over time for Eagle Ford Shale immersed in reservoir brine.

[0034] [Figure 12] Photographs showing the change in contact angle over time for Eagle Ford shale immersed in 1 wt % sodium acetate in reservoir brine.

[0035] [Figure 13] 1 is a photograph of a solution of sodium formate in deionized water.

[0036] [Figure 14] 1 is a plot showing the viscosity of formate solutions in brine at 25, 50 and 75° C.

[0037] [Figure 15]FIG. 1 is a diagram of a 3D aquifer model with two facies, sand and shale.

[0038] [Figure 16A] 1 is a plot showing water-oil permeability curves.

[0039] [Figure 16B] 1 is a plot showing liquid-gas specific permeability curves.

[0040] [Figure 17A] 13A-13D are profiles showing CO2 and formate distribution in the aquifer over the simulation period. [Figure 17B] 13A-13D are profiles showing CO2 and formate distribution in the aquifer over the simulation period. [Figure 17C] 13A-13D are profiles showing CO2 and formate distribution in the aquifer over the simulation period. [Figure 17D] 13A-13D are profiles showing CO2 and formate distribution in the aquifer over the simulation period.

[0041] [Figure 18] 1 is a plot showing cumulative CO2 and formate production from an aquifer.

[0042] [Figure 19] 1 is a plot showing the cumulative amount of water produced from an aquifer.

[0043] [Figure 20] 1 is a plot showing cumulative moles of injectant stored in an aquiver.

[0044] [Figure 21] 3D diagram of reservoir porosity distribution.

[0045] [Figure 22A] FIG. 1 shows CO2 and formate profiles at different times. [Figure 22B] FIG. 1 shows CO2 and formate profiles at different times. [Figure 22C] FIG. 1 shows CO2 and formate profiles at different times. [Figure 22D] FIG. 1 shows CO2 and formate profiles at different times.

[0046] [Figure 23] 1 is a plot showing cumulative water production.

[0047] [Figure 24] 1 is a plot showing oil recovery from CO2 and formate solution injection.

[0048] [Diagram 25] 1 is a plot showing the history of moles of injectant stored in a reservoir.

[0049] [Figure 26] 1 is a plot showing the reduction in carbon intensity using the format versus CO2.

[0050] [Figure 27A] FIG. 1 shows CO2 and formate profiles in an oil reservoir using adjusted kv / kh values. [Figure 27B] FIG. 1 shows CO2 and formate profiles in an oil reservoir using adjusted kv / kh values. [Figure 27C] FIG. 1 shows CO2 and formate profiles in an oil reservoir using adjusted kv / kh values.

[0051] [Figure 28] 1 is a plot showing oil production results of CO2 and formate injection.

[0052] [Figure 29] 1 is a plot showing injectant storage for CO2 and formate injection in a reservoir.

[0053] [Diagram 30] FIG. 1 shows the molecular structures of different forms of glycine.

[0054] [Diagram 31] FIG. 1 shows the molecular structures of formate, acetate and glycine.

[0055] [Diagram 32] 1 is a photograph showing an apparatus for measuring contact angles.

[0056] [Diagram 33] 1 is a photograph showing an Amot cell.

[0057] [Diagram 34] FIG. 1 is a schematic diagram of the experimental setup used for forced absorption measurements.

[0058] [Diagram 35] 1 is a plot showing the results of a reservoir contact angle experiment with calcite.

[0059] [Figure 36A] 1 is a plot showing the results of glycine contact angle experiments with calcite at different glycine solution concentrations. [Figure 36B] 1 is a plot showing the results of glycine contact angle experiments with calcite at different glycine solution concentrations. [Figure 36C] 1 is a plot showing the results of glycine contact angle experiments with calcite at different glycine solution concentrations. [Figure 36D] 1 is a plot showing the results of glycine contact angle experiments with calcite at different glycine solution concentrations.

[0060] [Figure 37A] 1 is a plot showing the results of acetate contact angle experiments with calcite at different acetate solution concentrations. [Figure 37B] 1 is a plot showing the results of acetate contact angle experiments with calcite at different acetate solution concentrations. [Figure 37C] 1 is a plot showing the results of acetate contact angle experiments with calcite at different acetate solution concentrations. [Figure 37D] 1 is a plot showing the results of acetate contact angle experiments with calcite at different acetate solution concentrations.

[0061] [Figure 38A] 1 is a plot showing the results of acetate contact angle experiments with calcite at different formate solution concentrations. [Figure 38B] 1 is a plot showing the results of acetate contact angle experiments with calcite at different formate solution concentrations. [Figure 38C] 1 is a plot showing the results of acetate contact angle experiments with calcite at different formate solution concentrations. [Figure 38D] 1 is a plot showing the results of acetate contact angle experiments with calcite at different formate solution concentrations.

[0062] [Figure 39] 1 is a plot showing the results of contact angle experiments with Eagle Ford shale slabs.

[0063] [Figure 40A] 1 is a plot showing the results of a series of spontaneous water imbibition experiments with Texas Cream limestone cores. [Figure 40B] 1 is a plot showing the results of a series of spontaneous water imbibition experiments with Texas Cream limestone cores.

[0064] [Figure 41A] 1 is a plot showing the results of a series of forced imbibition experiments with a Texas Cream limestone core. [Figure 41B] 1 is a plot showing the results of a series of forced imbibition experiments with a Texas Cream limestone core.

[0065] [Figure 42A] 1 is a plot showing the results of a series of spontaneous imbibition experiments with Texas Cream limestone cores. [Figure 42B]1 is a plot showing the results of a series of spontaneous imbibition experiments with Texas Cream limestone cores.

[0066] [Figure 43A] 1 is a plot showing the results of a series of forced imbibition experiments with a Texas Cream limestone core. [Figure 43B] 1 is a plot showing the results of a series of forced imbibition experiments with a Texas Cream limestone core.

[0067] [Figure 44A] FIG. 1 shows a configuration illustrating two possible mechanisms of calcium binding to glycine. [Figure 44B] FIG. 1 shows a configuration illustrating two possible mechanisms of calcium binding to glycine.

[0068] [Diagram 45] FIG. 1 shows the role of the amino group in the chelating effect of glycine (left) over carboxylate anions (right).

[0069] [Diagram 46] 1 is a plot showing the viscosity of formate solutions in deionized water.

[0070] [Figure 47] 1 is a plot showing the viscosity of formate solutions in 15000 ppm NaCl.

[0071] [Figure 48] 1 is a plot showing the viscosity of formate solutions in 49000 ppm NaCl.

[0072] [Figure 49] 1 is a plot showing the viscosity of formate solutions in 102,646 ppm brine (97,897 ppm NaCl and 4,749 ppm CaCl2).

[0073] [Figure 50]1 is a plot showing the in situ and bulk viscosity of a 20 wt % formate solution at room temperature.

[0074] [Figure 51] 1 is a plot showing the results of a core flooding experiment (brine case).

[0075] [Figure 52] 1 is a plot showing the results of a core flooding experiment (20 wt % formate case).

[0076] [Figure 53] 1 is a plot showing the results of a core flooding experiment (30 wt % formate case). DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0077] Detailed Description Described herein are methods, systems, and techniques for the injection of an aqueous mixture containing one or more carboxylates into a subsurface reservoir, such as for carbon sequestration, enhanced oil recovery, or hydrogen storage. To sequester carbon, the carboxylates can be present in the aqueous mixture at any suitable concentration, such as 1% to 45% by weight or more. In this manner, large amounts of carbon can be injected into a subsurface reservoir where it can remain sequestered. In some cases, the carboxylates can be produced by capturing carbon dioxide from the atmosphere or at the point of production, converting it to the carboxylates by chemical reactions such as hydrogenation reactions or electrochemical reduction of CO2 in other forms (e.g., carbonate or bicarbonate) in an aqueous medium, and optionally using renewable energy (e.g., solar, wind, geothermal) as a power source to provide a carbon negative process. For enhanced oil recovery, the aqueous mixture containing the carboxylates can be useful for modifying the wettability of rocks in the reservoir to improve the availability and production of hydrocarbons contained within the pores of the rocks. Carboxylates may also optionally be used as thickeners, alone or with one or more polymers, to help increase the viscosity of fluids in the underground reservoir, which in turn may be a more effective fluid displacement component in the reservoir and help drive fluids more efficiently through portions of the reservoir. To store hydrogen, the carboxylates can be present in an aqueous mixture at any suitable concentration, such as 1% to 45% by weight, and can be injected into the underground reservoir for later recovery for hydrogen production. For example, the carboxylates can be produced from the reservoir and used in a chemical reaction where hydrogen gas is generated, such as a dehydrogenation reactor. In some cases, catalysts, pH adjusters and / or nanocatalysts can be injected into the underground reservoir to catalyze hydrogen generation from the oxidation of the carboxylates in-situ, so that hydrogen can then be produced directly from the underground reservoir.

[0078] As used herein, "carboxylate" refers to a molecule that contains a carboxyl functional group, which is in the anionic form (-COO -), a protonated form as a carboxylic acid (-COOH), or in the form of a carboxylate salt (-COOM), such as an alkali metal carboxylate salt (e.g., sodium carboxylate). In aqueous mixtures, the carboxylate may be in a solvated form, and it will be understood that the pH of the mixture, the salt concentration of the mixture, and / or the concentration of the carboxylate may affect the extent to which the carboxylate is in the form of a carboxylic acid, a carboxylate ion, or a carboxylate salt. In general, carboxylates useful in the technology described herein have the formula [ka] where X is H or an alkali metal and R is H or an alkyl group, e.g., a C1-C3 alkyl group, which may be substituted or unsubstituted. It will be understood that the carboxylates useful in the technology described herein may be different from amino acids, which may correspond to the carboxylates of the above formula, where R contains an amine functionality. For example, stated in other ways, the carboxylate is not an amino acid or R does not contain an amine.

[0079] The use of carboxylates can be beneficial for several reasons. First, many carboxylates are naturally occurring and environmentally friendly. For example, acetic acid, formic acid, and propionic acid have been approved as food additives by the U.S. Food and Drug Administration. Although carboxylates can be naturally occurring, they are typically absent or present at low concentrations in aqueous fluids within subterranean reservoirs, so that when added by injection according to the methods described herein, they can be used as tracers to track the movement of fluids within a subterranean reservoir, such as to identify which wells within the reservoir are in fluid communication with each other, or to track the flow of aqueous fluids within a subterranean reservoir. Carboxylates can also advantageously modify conditions within a subterranean reservoir to allow increased or easier production of hydrocarbons from the reservoir, such as by modifying the wettability of rock surfaces within the reservoir.

[0080] Carboxylates may be advantageously used in combination with other additives to the aqueous mixture injected into the underground reservoir, such as surfactants, acids, bases, polymers, chelating agents, nanomaterials, amino acids, biocides, solvents, hydrocarbons or dissolved gases. For the production of hydrocarbons, the use of carboxylates may allow for less of the other components, such as less of the surfactants, to be used for the same effect, i.e., allowing the hydrocarbons to be more easily released from the pores within the rock in the underground reservoir, as the carboxylates may provide a similar effect as the surfactants.

[0081] In particular, the wettability of rock surfaces in the reservoir may change from more oil-wet (less water-wet) to more water-wet (less oil-wet) in the presence of carboxylates. Such effects may be quantified as a change in contact angle between the rock surface and the aqueous and oleic phases. In an embodiment, the rock may have a more oil-wet property (oil contact angle less than 90°, water contact angle greater than 90°) before contacting the carboxylate-containing aqueous mixture and change to a more water-wet property (water contact angle less than 90°, oil contact angle greater than 90°) after contacting the carboxylate-containing mixture.

[0082] FIG. 1 provides a schematic diagram of an exemplary underground reservoir 100 in which several wells 105 are disposed. The underground reservoir 100 may be, for example, an oil or gas reservoir or may be an aquifer. In some cases, the wells 105 may be vertical wells. In some cases, the wells 105 may be horizontal wells. Combinations of vertical and horizontal wells are also contemplated herein. The wells 105 may be used to inject and store aqueous mixtures including carboxylates in the underground reservoir 100, as described above, for purposes such as carbon sequestration or hydrogen storage.

[0083] In some cases, well 105 may be used for a cyclic injection process (e.g., a huff and puff or huff-n-puff process) in which a fluid, such as an aqueous mixture described herein containing a carboxylate, is injected and a production process occurs after an optional soaking period. In some cases, well 105 may be used for a flooding process (e.g., a waterflood process) in which a fluid, such as an aqueous mixture described herein containing a carboxylate, is injected into a first well and a second well is used to produce a fluid, such as a hydrocarbon-containing fluid or an aqueous or gaseous fluid. Depending on the particular configuration, the same or different wells 105 may be used for both injection and production.

[0084] The well 105 may optionally be used to inject a slug of the aqueous mixture described herein containing carboxylates in brine or water, followed by a tracer fluid. The tracer fluid may include brine or water and other components, such as chelating agents, amines, or inorganic bases. In some cases, the tracer fluid may include the same brine or water that is the base of the aqueous mixture containing carboxylates, or may be a different brine or water (e.g., containing different ions and / or concentrations of ions). Other exemplary components for the tracer fluid include one or more of a surfactant, a solvent, an acid, a base, a salt, an inorganic compound, a polymer, a chelating agent, a nanomaterial, an amino acid, a biocide, a hydrocarbon, nitrogen, or carbon dioxide. The tracer fluid may be useful and may include one or more components for reducing retention of sorbed carboxylates at rock surfaces in the subterranean reservoir and / or for desorbing at least a portion of the carboxylates from the aqueous mixture. Exemplary tracer fluids may include water or brine and one or more of a chelating agent, an amine, or inorganic base.

[0085] The injection system may be in fluid communication with the well 105. As shown in FIG. 1, the injection system may include, for example, conduits and pumping equipment 110. A fluid source 115 may be in fluid communication with the injection system or the injection system may include the fluid source 115. The fluid source 115 may comprise or include, for example, a storage tank, a mixing tank, a fluid conduit, etc., and may be used to provide an aqueous mixture for injection into the reservoir 100 via the well 105.

[0086] The production system may be in fluid communication with the well 105. As shown in FIG. 1, the production system may include, for example, conduits and pumping equipment 120. Tank 125 may be in fluid communication with and / or may be a component of the production system. Tank 125 may comprise a storage tank or may be, for example, a reaction vessel. In the case of hydrogen storage, the fluid produced using pumping equipment 120 may include carboxylates that are provided to tank 125, which may function as a reaction vessel for a dehydrogenation reaction in which hydrogen gas is produced from the produced carboxylates.

[0087] 2 provides an overview of an exemplary method 200 for producing sequestered carbon by injecting carboxylates into a subsurface reservoir. In block 205, one or more wells are disposed in the subsurface reservoir. The wells may have any suitable dimensions, orientation, direction, etc. The one or more wells may comprise, for example, vertical wells, horizontal wells, or combinations thereof. The subsurface reservoir may be an aquifer, such as a freshwater aquifer or a saline aquifer, or an oil or gas reservoir, which may optionally correspond to a depleted oil or gas reservoir.

[0088] In block 210, a carboxylate is prepared. In some examples, a formate may be prepared by electrochemical reduction reaction with CO2, carbonate ion, or bicarbonate ion. In some cases, the carboxylate may be commercially available or produced using other methods. In some examples, an acetate or acetic acid may be prepared by bacterial fermentation, methanol carbonylation, acetaldehyde oxidation, or ethylene oxidation. For carbon sequestration purposes, it may be desirable to perform the preparation of the carboxylate in block 210 using only carbon-neutral power, such as solar, wind, geothermal, or nuclear power. In some cases, the preparation of the carboxylate in block 210 is an optional process and may be replaced by a process that obtains the carboxylate.

[0089] With the available carboxylates, an aqueous mixture may be prepared in block 215 by mixing the carboxylates with water or another aqueous solution (e.g., brine). Without limitation, the water or aqueous solution may be from any suitable source, such as, for example, previously produced brine or water from an underground reservoir or another reservoir, or seawater, freshwater, river water, pond water, aquifer water, etc. Optionally, additives may be included in the mixture, such as surfactants, solvents, acids, bases, salts, inorganic compounds, polymers, chelating agents, amino acids, biocides, nanomaterials, hydrocarbons, nitrogen, or carbon dioxide. In some examples, additives may be used to increase the solubility of the carboxylates or provide a suspension of solid particles including the carboxylates in the solution, allowing the concentration of the carboxylates to be higher than the natural solubility limit of the carboxylates in water.

[0090] In block 220, the aqueous mixture including one or more carboxylates is injected into the subterranean reservoir, such as through one or more wells. The aqueous mixture may be injected continuously, or semi-continuously or in one or more separate injection processes. The injection of the aqueous mixture may optionally be allowed to proceed or may be followed by the injection of other fluids, which may or may not include carboxylates. Any of blocks 210, 215, or 220 may optionally be repeated one or more times.

[0091] In some examples, a sample of fluid from the subsurface reservoir may optionally be produced, such as using the injection well or a separate well. The sampled fluid may be tested to identify the concentration of carboxylates in the subsurface reservoir, such as to identify or estimate the amount of sequestered carbon in the subsurface reservoir. In some cases, the concentration of carboxylates in the injected aqueous mixture may be amended based on the identification or estimated amount of sequestered carbon in the subsurface reservoir or the concentration of carboxylates in the produced fluid.

[0092] FIG. 3 provides an overview of an exemplary method 300 for producing hydrocarbons from an underground reservoir. In block 305, one or more wells are disposed in the underground reservoir. As discussed above, the one or more wells may be independently used to inject fluids into the underground reservoir and / or produce fluids from the underground reservoir. The wells may have any suitable dimensions, orientation, direction, etc. The one or more wells may comprise, for example, vertical wells, horizontal wells, or combinations thereof. The wells may optionally be used to directly produce fluids, such as gas or liquids, from the underground reservoir, such as hydrocarbons, and optionally aqueous fluids including carboxylates, etc.

[0093] At block 310, an aqueous mixture containing carboxylates is obtained, such as by augmenting an aqueous fluid (e.g., seawater, freshwater, aquifer water, or brine previously produced from the reservoir or another reservoir, etc.) with carboxylates and any other additives, including (solvents, surfactants, etc.). Without limitation, the aqueous mixture may include freshwater, seawater, reservoir-connected water, produced water, river water, pond water, or brine, in addition to the carboxylates. The aqueous mixture may include surfactants, solvents, acids, bases, salts, inorganic compounds, polymers, chelating agents, amino acids, biocides, nanomaterials, hydrocarbons, nitrogen, or carbon dioxide, in addition to the carboxylates.

[0094] At block 315, the aqueous mixture including one or more carboxylates is injected into the subterranean reservoir, such as through one or more wells. The aqueous mixture may be injected continuously, or semi-continuously or in one or more separate injection processes. The injection of the aqueous mixture may optionally proceed, as shown in block 320, or may be followed by the injection of other fluids, which may or may not include carboxylates, such as tracer fluids. The injection of the aqueous mixture and tracer fluids may optionally be repeated one or more times.

[0095] In block 325, hydrocarbons are produced from the underground reservoir. Depending on the underground reservoir and / or configuration, the pressure within the underground reservoir may be sufficient to produce hydrocarbons directly from the underground reservoir without the need for artificial lift to draw the hydrocarbons to the surface, although in some cases an artificial lift system may be used. Depending on the production process used, the injection of the aqueous mixture and production of hydrocarbon steps in blocks 315 and 325 may be repeated one or more times, such as in a cyclic injection process, with optional repeating of the follow-up fluid injection process in block 320.

[0096] At block 325, non-hydrocarbon fluids may optionally be recovered from the subterranean reservoir. In some cases, it may be desirable to recover at least a portion of the injected aqueous mixture to recover some of the carboxylates or other additives in the aqueous mixture injected into the subterranean reservoir. However, depending on the formation, recovery of these components may or may not be feasible. It will be understood that fluid production may occur, for example, during, after, or in lieu of production of hydrocarbons.

[0097] At block 330, the aqueous mixture may optionally be modified such that different aqueous mixtures can be injected in repeated injection steps corresponding to block 315. For example, production of hydrocarbons and / or fluids from the subterranean reservoir may provide information used to vary the aqueous mixture, such as using different carboxylates, varying carboxylate concentrations, providing other or more or less additives (e.g., surfactants, acids, bases, etc.) in the aqueous mixture, etc. In this manner, injection and production can be adjusted based on real-time feedback obtained during the production process.

[0098] 4 provides an overview of an exemplary method 400 for storing hydrogen in an underground reservoir. In block 405, one or more wells are disposed in the underground reservoir. As described above, the one or more wells may be independently used for injecting fluids into the underground reservoir and / or producing fluids from the underground reservoir. The wells may have any suitable dimensions, orientation, direction, etc. The one or more wells may comprise, for example, vertical wells, horizontal wells, or combinations thereof. The wells may optionally be used to produce fluids, such as gas or liquids, directly from the underground reservoir, such as hydrocarbons, aqueous fluids optionally including carboxylates, etc.

[0099] At block 410, a carboxylate is prepared as a carrier of hydrogen and then mixed with an aqueous fluid to prepare an aqueous mixture. As described above, the carboxylate can be prepared using any desired technique. In some cases, a hydrogenation reaction of CO2 can be used to prepare formic acid, which can be mixed with, for example, water or brine. Optionally, other additives can be included in the aqueous mixture, such as components that help increase the solubility of the carboxylate in the mixture. Without being limited thereto, the aqueous mixture can include, in addition to the carboxylate, fresh water, sea water, reservoir connected water, produced water, river water, pond water, or brine. The aqueous mixture can include, for example, in addition to the carboxylate, a surfactant, a solvent, an acid, a base, a salt, an inorganic compound, a polymer, a chelating agent, an amino acid, a biocide, a nanomaterial, a hydrocarbon, nitrogen, or carbon dioxide.

[0100] At block 415, the aqueous mixture including the one or more carboxylates is injected into the subterranean reservoir, such as through one or more wells. The aqueous mixture may be injected continuously, or may be injected semi-continuously or in one or more separate injection processes.

[0101] At block 420, a catalyst can optionally be injected into the subsurface reservoir, such as through one or more wells. The catalyst can be or include, for example, a metal catalyst useful for assisting in the dehydrogenation of carboxylates to produce hydrogen gas in-situ in the subsurface reservoir. Optionally, the catalyst can include a nanocatalyst. In some examples, the catalyst can be a pH modifier that can help drive the reaction for the generation of hydrogen.

[0102] In block 425, fluids are produced from the underground reservoir. In the case of in-situ hydrogen gas generation, the fluids may include hydrogen gas. Additionally or alternatively, the produced fluids may include carboxylates. In some cases, it may be desirable to recover at least a portion of the injected aqueous mixture to recover a portion of the catalyst injected into the underground reservoir, although this aspect is optional. However, depending on the formation, recovery of these components may or may not be feasible. Depending on the process used, the injection of the aqueous mixture and production of fluids in blocks 415 and 425, and optionally the catalyst injection step in block 420, may be repeated one or more times.

[0103] Hydrogen gas may optionally be produced from carboxylates in the fluid produced from the subterranean reservoir at block 430. As described above, the carboxylates may be subjected to a dehydrogenation reaction to produce hydrogen gas, such as in a reactor at the surface above the subterranean formation or another location to which the produced fluid is transported.

[0104] At various points in the process, the aqueous mixture may optionally be modified so that a different aqueous mixture can be injected in a step corresponding to block 415. For example, production of fluids from an underground reservoir may provide information used to vary the aqueous mixture, such as using different carboxylates, varying carboxylate concentrations, providing other or more or less additives (e.g., surfactants, acids, bases, catalysts, etc.), etc. In this manner, the hydrogen storage process can be adjusted based on real-time feedback obtained during the process.

[0105] The present invention can be further understood by the following non-limiting examples.

[0106] Example 1: Changes in contact angle on oil-wet shale surface versus formate anion (HCOO - ) effect Experiments were performed to evaluate the ability of solutions containing formate anions to modify the wettability properties of shale formations. These experiments used shale disk samples from the Wolfcamp and Eagle Ford outcrops.

[0107] Disks of the Wolfcamp and Eagle Ford shale outcrops were oil-aged to produce strongly oil-wet surfaces. The oil used to mature the shale surfaces was crude oil (molecular weight 210 g / mol, 71.6 wt.% saturates, 24.8 wt.% aromatics, 3.4 wt.% resins, and 0.1 wt.% asphaltenes (n-pentane insoluble).

[0108] Oil-aged disks were immersed in reservoir brine (RB) or 1 wt% sodium formate in reservoir brine at 74°C. The reservoir brine had a salinity of 68,722 ppm. Oil droplets were placed on the shale surface in reservoir brine (RB) or 1 wt% sodium formate in reservoir brine, and the contact angle of the oil droplet was measured on day 0 (initial) and day 3 (final). The oil used for the droplets was crude oil (molecular weight 186 g / mol, density 822.5 kg / m at 288.71 K). 3 , 76.7 wt% saturated, 20.1 wt% aromatics, 3.2 wt% resins, and less than 0.1 wt% asphaltenes (n-pentane insoluble).

[0109] Table 1 shows that 1 wt% formate in the formation brine was effective at only slightly decreasing the contact angle of the Wolfcamp shale. The reservoir brine itself did not significantly change the contact angle of the oil droplet on the Wolfcamp shale (Figure 5). However, the formate solution changed the contact angle from 134.27° to 121.15° within 3 days (Figure 6). [Table 1]

[0110] Formate salts showed superior wettability changes on the Eagle Ford Shale surface compared to the Wolfcamp surface, making the surface strongly water-wet within 3 days; see Table 2. Formation brine also reduced the contact angle of the oil droplet on the Eagle Ford Shale surface but did not significantly modify the wettability properties (Figure 7). However, the formate salt solution made the Eagle Ford Shale surface strongly water-wet; the contact angle changed from 148.02° to 45.57° within 3 days (Figure 8). [Table 2]

[0111] From the above data, it is clear that 1 wt% sodium formate in reservoir brine at 74°C can change the Eagle Ford rock surface to be significantly water-wet in 3 days. However, 1 wt% sodium formate in reservoir brine did not change the contact angle of the Wolfcamp rock surface under the same conditions. This may be due to the difference in mineralogy of the two reservoir rocks (Table 3). [Table 3]

[0112] The Eagle Ford rocks, which are mostly calcite, show rapid contact angle changes to formate solutions; on the other hand, the Wolfcamp rocks are mostly quartz (silicate) and inert. Thus, favorable electrostatic interactions between formate anions and the positively charged Eagle Ford rock surface may play a significant role in the wettability changes.

[0113] Example 2: Effect of acetate anion (CHCOO) on the change in contact angle on oil-wet shale surface - ) effect Experiments were performed to evaluate the ability of solutions containing acetate anions to modify the wettability properties of shale formations. These experiments used shale disk samples from the Wolfcamp and Eagle Ford outcrops.

[0114] Disks of the Wolfcamp and Eagle Ford shale outcrops were oil-aged to produce strongly oil-wet surfaces. The oil used to mature the shale surfaces was crude oil (molecular weight 210 g / mol, 71.6 wt.% saturates, 24.8 wt.% aromatics, 3.4 wt.% resins, and 0.1 wt.% asphaltenes (n-pentane insoluble).

[0115] The oil-aged disks were immersed in reservoir brine (RB) or 1 wt% sodium acetate in reservoir brine at 74°C. The reservoir brine had a salinity of 68,722 ppm. Oil droplets were placed on the shale surface in reservoir brine (RB) or 1 wt% sodium acetate in reservoir brine, and the contact angle of the oil droplet was measured on day 0 (initial) and day 3 (final). The oil used for the droplets was crude oil (molecular weight 186 g / mol, density 822.5 kg / m at 288.71 K). 3 , 76.7 wt% saturated, 20.1 wt% aromatics, 3.2 wt% resins, and less than 0.1 wt% asphaltenes (n-pentane insoluble).

[0116] Table 4 shows that 1 wt% acetate in the formation brine was effective in significantly reducing the contact angle of the Wolfcamp shale and changing the surface to strongly water-wet. The reservoir brine itself reduced the contact angle of the oil droplet on the Wolfcamp shale but did not change the wettability nature of the surface (Figure 9). However, the acetate solution significantly changed the contact angle from 134.08° to 45.06° within 3 days (Figure 10). [Table 4]

[0117] The acetate also showed excellent wettability changes to the Eagle Ford Shale surface, making the surface strongly water-wet within 3 days; see Table 5. The formation brine only slightly changed the contact angle of the oil droplet on the Eagle Ford Shale surface (Figure 11). However, the acetate solution made the Eagle Ford Shale surface strongly water-wet; the contact angle changed from 148.02° to 45.57° within 3 days (Figure 12). [Table 5]

[0118] From the above data, it is clear that 1 wt% sodium acetate in reservoir brine at 74°C is capable of transforming the Wolfcamp and Eagle Ford rock surfaces to water-wet in 3 days. Unlike the formate experiments, the acetate wettability transformation characteristics were found to be independent of the mineral composition of the shale rock samples.

[0119] Example 3: Simulation case study of aqueous formic acid for geological carbon storage Carbon storage in geological formations has been considered as an important technology to reduce the carbon intensity of fossil fuel-based industrial processes. Carbon capture and storage (CCS) traditionally uses high-pressure carbon dioxide (CO2) as a carbon carrier. However, various drawbacks of traditional CCS are related to the physical properties of CO2, such as low carbon density at low to moderate pressures, low mass density, low viscosity, immiscibility with water, and corrosivity. In particular, CO2 injection often results in inefficient use of pore space in formations under geophysical heterogeneity.

[0120] This example presents a case study of using formic acid brine solutions as carbon-bearing water for geological carbon storage. The properties of formate solutions in brine were measured, such as solubility, density, and viscosity. Experimental results showed that formate solubility in 102,600 ppm NaCl+CaCl2 brine ranged from 30 wt% to 35 wt% at 25-75°C. The viscosity of a 30 wt% formate solution in brine was approximately 12 cp at 25°C, 5 cp at 50°C, and 3 cp at 75°C with Newtonian behavior.

[0121] Numerical reservoir simulations were performed for two cases: aquifer case study 1 and oil reservoir case study 2. Simulation results consistently showed that the formate injection case consistently resulted in more stable oil and water displacement fronts. The more stable fronts resulted in oil recovery and carbon storage that was insensitive to injectant breakthrough. This is a substantial advantage of using formate as a carbon carrier to control the risks of CCS associated with permeability heterogeneities and their impact on subsurface flow regimes.

[0122] Introduction. The Intergovernmental Panel on Climate Change's Sixth Assessment Report states that the global warming threshold of 2°C will be exceeded by the end of the 21st century without significant reductions in carbon dioxide (CO2) emissions (IPCC, 2021). Carbon storage in geological formations has been identified as a key technology to preserve the country's sustainable growth. Oil reservoirs and deep saline aquifers are the most attractive formations, as large storage capacities are estimated for these formations based on available data from previous injection projects.

[0123] Current carbon storage processes involve compressing captured CO2 into supercritical CO2, which has a liquid-like density rather than a gas-like viscosity. Challenges associated with carbon storage include: a) substantial costs associated with capturing, compressing, transporting and recycling anthropogenic CO2 after CO2 breakthrough in production wells; b) subsurface fluid flow issues resulting in inefficient use of pore space (volumetric sweep and local displacement efficiency) due to low mass density and viscosity in multiphase displacement of oil and water by CO2 in heterogeneous media; c) the corrosive nature of CO2; d) the potential for CO2 leakage to the surface through unexpected hydraulic paths. These issues are closely related to the physical properties of CO2.

[0124] This example concerns the novel idea of ​​using formate solutions as aqueous carbon carriers for geological carbon storage. Formate (HCOO-) is the simplest member of the carboxylate group and the conjugate base of formic acid. Formate can be formed from the electrochemical reduction (ECR) of CO2. Electrochemical conversion of CO2 to other useful products has attracted attention due to the need to reduce carbon emissions. Formate / formic acid is a high-value product from CO2ECR. Upscaling of the formate production process has been limited by the mass transport of CO2 in aqueous electrolytes at ambient pressure and temperature. However, studies on CO2ECR to formate have shown that the mass transfer process is significantly improved when gas diffusion electrodes are used, presenting the possibility of industrial scale-up of CO2ECR to formate.

[0125] Research has shown that formate solutions can improve oil recovery by changing the wettability of carbonate rocks from oil-wet to water-wet with minor pH adjustments. Research on formic acid brines as a base fluid for mud drilling shows that formates have a favorable health, safety and environmental (HSE) profile and good compatibility with oilfield equipment. This example presents the use of aqueous formic acid solutions as carbon carriers through two case studies: one for carbon storage in aquifers and the other for enhanced oil recovery (EOR) and carbon storage in oil reservoirs. This example also reports new experimental data on the solubility, density and viscosity of sodium formate solutions in brines, which sets the foundation for numerical flow simulations in this research.

[0126] Measurement of Formate Solution Properties. Because formation solution properties are relatively scarce in the literature, this example measured new data on the solubility of formate species in brine, as well as the viscosity and density of formate solutions as part of this research. The results were used to set up numerical flow simulations for the case studies presented below.

[0127] Materials and Methods. Sodium formate, sodium chloride and calcium chloride dihydrate salts (all with a purity of >99%) were used to prepare the brine and formate solutions used in this research. The accuracy of the weighing balance used for mass measurements was ±0.0001 g. All experiments were performed under atmospheric pressure.

[0128] Solubility of sodium formate in deionized water (DIW). The solubility of sodium formate in DIW was determined by preparing aqueous solutions of formic acid with different molarities, equilibrating them, and observing the maximum molar concentration at which there was no undissolved salt. Figure 13 shows the prepared sodium formate solutions with different molarities at 25°C. Formic acid was added to the solutions to adjust the pH to 7. The solubility experiments were performed at 25, 50, and 75°C.

[0129] The concentration of formic acid added to the solution is given by the Henderson-Hasselbalch equation:

number

[0130] Solubility of sodium formate in NaCl+CaCl2 brine. To determine the solubility of sodium formate in brine, sodium formate was dissolved in NaCl+CaCl2 brine (97,897 ppm NaCl and 4,749 ppm CaCl2). Several solutions of sodium formate in brine were made, each with a different weight fraction of sodium formate. After an initial refinement screening, the solutions were equilibrated and the solution with the highest weight fraction of sodium formate added without undissolved salt was recorded. The experiment was performed at 25, 50 and 75°C. The pH value of the solution was adjusted by adding formic acid as described above.

[0131] This particular brine containing NaCl and CaCl2 was used because it is common to have divalent cations in formation brines. The addition of CaCl2 was to include the effect of divalent cations without exploring the many possible brine compositions for formation brines. A separate research project is required to develop a database of formate solution properties in brines.

[0132] Viscosity Measurements. The viscosity of solutions of different concentrations of sodium formate in brine (97,897 ppm NaCl and 4,749 ppm CaCl2) was measured using a TA Ares LS-1 rheometer coupled with a circulating bath for temperature control. A double-walled Couette geometry was used for the measurements. Viscosity measurements were taken at 25, 50 and 75°C. The sodium formate solutions were prepared and equilibrated in an oven set at the target temperature.

[0133] For viscosity measurements at 50 and 75° C., the temperature of the sample holding cup was raised to the target temperature using a circulating bath before the solution was placed in the rheometer's sample holding cup. This was done to avoid precipitation of dissolved salts in samples with high concentrations of formate (e.g., >30 wt %), which could occur due to the reduced solubility of sodium formate at lower temperatures.

[0134] Experimental Results. This section reports the formate ion (HCOO-) concentrations in solution measured in this example. Note that the formate weight fraction / percentage is different from the sodium formate (HCOONa) weight fraction in solution. Also, HCOO - Each mole of HCOOH contains one mole of carbon. - Note that the molar masses of are similar to that of CO (45.018 and 44.01 g / mol, respectively); therefore, the solubility value of the formate salt is close to the mass fraction of CO retained in aqueous form.

[0135] Table 6 shows the solubility values ​​of sodium formate in DIW; the solubility of formate in DIW increased with increasing temperature from 31.5 wt % at 25° C. to 36.77 wt % at 75° C. The formate solubility measured at 25° C. was close to the reported result of 32.2 wt %.

[0136] Brines found in geological formations are often highly saline waters. Sodium formate was dissolved in brine (salt composition: 97,897 ppm NaCl and 4,749 ppm CaCl2) at 25, 50 and 75°C to determine its solubility at these temperatures and to see if the solution remained single phase without any precipitation. Table 7 shows the solubility of sodium formate in brine at 25, 50 and 75°C. The solubility of formate in brine ranged from 29.6 wt% at 25°C to 34.8 wt% at 75°C.

[0137] Newtonian behavior was consistently observed by viscosity measurements of different solutions of sodium formate in brine at 25, 50 and 75°C over a wide range of shear rates. The viscosity of the formate solutions increased with increasing formate concentration, and a linear trend was observed when the viscosity was plotted against the molar concentration of formate on a semi-log scale as shown in Figure 14 at 25, 50 and 75°C. The density and viscosity of sodium formate in NaCl+CaCl2 brine at 25, 50 and 75°C are shown in Tables 8, 9 and 10. For reference, the reported viscosity of nearly saturated 45% (% w / w) sodium formate in water was 9.5 cp at 20°C, indicating that the solution viscosity increased with the addition of formate to water.

[0138] Numerical Simulation Case Study: Injection of high pressure CO2 into hydrocarbon reservoirs and saline aquifers has been investigated and commercially implemented to reduce the carbon intensity of fossil fuel-based industrial processes. The central question in this research is whether aqueous formate injection could be a viable option for geological carbon storage to ameliorate the various problems associated with CO2 injection.

[0139] The cost of CO2 capture and storage is one of the barriers to the global deployment of large-scale carbon capture and storage operations. In a formate injection scenario, the cost of CO2 ECR to formate can be significant. Therefore, the objective of the simulation case study is to calculate the cost of the ECR process, which is not considered in this example.

[0140] The case study is based on numerical flow simulations of CO2 injection and 30 wt% formate solution injection for two scenarios of geological carbon storage in a saline aquifer and an oil reservoir. The simulations are performed using CMG GEM (Computer Modelling Group 2018), a multiphase compositional flow simulator. The experimental data mentioned above were used as part of the simulation input.

[0141] Case study 1: Saline aquifer. Numerical flow simulation. Simulation of carbon storage in the aquifer was based on a 3D heterogeneous reservoir model. The model used was one of a stochastic realization using sequential indicator simulation to represent two lithofacies (85% by volume clean sand and 15% by volume shale barrier), each facies being homogeneous and isotropic. The model was 183 x 183 x 27 m 3 (600×600×90ft 3 ) and has dimensions of 9 x 9 x 0.5m 3 (30×30×1.5ft 3 ) uniform grid block size, giving a total of 24,000 grid blocks. Figure 15 shows the facies distribution in the 3D aquifer model.

[0142] Table 11 shows the aquifer model properties. Both cases (CO2 and formic acid solution) assumed a constant carbon injection rate of 114 kmol carbon per day (equivalent to 5 tons of CO2). Reservoir pressure was controlled using a production well set at 8963 kPa (1300 psia) pressure. Figure 16A shows the relative permeability curves (only one for water and one for gas was used in the simulations in this section).

[0143] The main difference between the CO2 and formate cases is in the flow regime: in the CO2 case, the injected CO2 displaced the formation brine under the two-phase flow of gas and water with an unstable displacement front and strong buoyancy.

[0144] The stability of a displacement front is typically measured by the end-point mobility ratio (M 0 ) and

number

number

[0145] The gravitational force in displacement is expressed by the density number (N d ) can be measured by

number

[0146] Numerical simulations were performed for the CO2 and formate injection cases over a simulation period of 34 years. Figures 17A, 17B, 17C, and 17D show the profiles of gas saturation for the CO2 case and the profiles of formate mole fraction in the water phase for the formate case. The CO2 case resulted in a gravity-dominated flow regime where the injected CO2 accumulated from the top of the formation and displaced the formation water along with the immiscible gaseous CO2 phase in a gravity-stable direction. The gravity-dominated flow regime was very strong and the displacement of water by CO2, although immiscible, was not affected by the geological heterogeneity in the reservoir model used. The accumulation of CO2 near the top of the formation indicates any disturbance to the surface and potential leakage of gaseous CO2 through the hydraulic pathway along the well.

[0147] Formate concentration profiles in Figures 17A-17D show the positive N d and the influence of geological heterogeneity. However, miscible displacement with favorable viscosity ratio stabilized the displacement front in the case of formate injection.

[0148] Figures 18, 19, and 20 show the injectant (CO2 or formate) production, cumulative water production, and cumulative carbon storage, respectively, from the simulations. CO2 and formate each contain one mole of carbon; therefore, they are comparable on a carbon mole basis. The CO2 injection case showed CO2 breakthrough at 18 years (Figure 18). Figures 19 and 20 show that upon CO2 breakthrough, water production and carbon storage leveled off and carbon storage efficiency dropped off rapidly.

[0149] The favorable viscosity ratio in the miscible displacement for the formate injection case resulted in water production that was not affected by formate breakthrough in the production well (Figure 19). Carbon storage continued after breakthrough in the formate case (Figure 20). After 34 years of injection, the formate case resulted in 42% more carbon storage (in moles) than the CO2 case. The main difference between the two cases is due to the carbon storage efficiency after injectant breakthrough.

[0150] This simulation case did not include the solubility of CO2 in the formation water and the subsequent geochemical reactions and diffusion of carbon species in the aqueous phase. These factors may affect carbon storage on longer time scales. Also, optimization of carbon storage in this case is possible by uplifting the perforation areas of the injection and production wells. However, a useful point to be made in this case study was the continued carbon storage even after breakthrough in the formate injection case. The insensitivity of carbon storage to breakthrough is expected to make the design of geological carbon storage more robust under various uncertainties of the geological formations.

[0151] Case study 2: Oil reservoir (EOR and carbon storage). The IEA reported that injection of CO2 for enhanced oil recovery (CO2EOR) is the second largest use of CO2. This subsection compares the cases of CO2 injection and formate injection in oil reservoirs.

[0152] Numerical flow simulation. The reservoir model was based on a heterogeneous sandstone reservoir model from the 10th SPE Comparative Solutions Project. The original model had dimensions of 366 x 671 x 52 m. 3 (1200×2200×170ft 3 ) and 6×3×0.6m 3 (20×10×2ft 3 ), resulting in a grid block size of 1.122 × 106. In this study, a 122 × 122 × 21 m 3 (400×400×70ft 3) cross section was used, which is shallow marine sandstone with thin layers of fine to medium grained sandstone and some silicite and shale. The simulation used a quarter of a 5-spot pattern (an injection pattern in which 4 injection wells are located at the corners of a square and the production well enters the center). 6 x 3 x 0.6 m 3 (20×10×2ft 3 ), resulting in 20 × 40 × 35 (28,000) grid blocks. Figure 21 shows a 3D view of the reservoir porosity distribution.

[0153] Table 12 shows the properties of selected reservoir sections. The models were originally generated for use in the PUNQ (Production Prediction with Uncertainty Quantification) project, a history matching and uncertainty quantification study. The original PUNQ model used a uniform value of the ratio of vertical to horizontal permeability (kv / kh) throughout the model, as did the simulations in this section; however, kv / kh was set to 0.3 for the fractures and 0.0001 for the matrix in the 10th SPE Comparative Solutions Project, to be used as a susceptibility test. Table 13 shows the oil composition and fluid properties used for this simulation example.

[0154] For both cases (CO2 and aqueous formic acid), oil production was initiated by a five-year waterflood at 11,376 kPa (1,650 psia). Both injections were then set at a constant rate of 114 kmol carbon / day (equivalent to 5 tons CO2 / day). Production pressure was maintained at 10,342 kPa (1,500 psia). Phase behavior was modeled by the Peng-Robinson equation of state. The thermodynamic minimum miscibility pressure of CO2 with oil (oil composition shown in Table 2) was calculated to be 10,053 kPa (1,458 psia) at a reservoir temperature of 41 °C (106 °F) using the equation of state model. Figure 16B shows the two-phase relative permeability curves used for the simulations. Three-phase relative permeabilities were generated using Stone's Model II. Simulations of the two cases were run over a 40-year simulation period, including five years of initial waterflooding.

[0155] Unlike case study 1, injection into the oil reservoir is accompanied by multiphase displacement of oil and formation water by the injected fluid. Important differences between the CO2 and formate injection cases arose from the flow regime, which is strongly influenced by the displacement process and buoyancy stability; however, these two factors manifested differently from the previous case study due to the strong tendency to channelize the flow through the fracture network.

[0156] M of injection and oil 0 was calculated to be 13 for the CO2 case and 0.16 for the formate case. The M0 of the injectant and formation water was calculated to be 3.1 for the CO2 case. The displacement of the water by the formate solution was a miscible process with a favorable viscosity ratio of 0.13.

[0157] Figures 22A, 22B, 22C and 22D show profiles of overall CO mole fraction at different times for the CO injection case and formate mole fraction in the water phase for the formation injection case. Figures 23, 24 and 25 show the water production, oil production and injectant storage results from the simulation. The CO case shows gravity override and the injected CO is at the M mentioned above. 0 Formate injection displaced oil preferentially over formation water due to its high saturation value. The formate injection case showed stable propagation of the displacement front without gravity-driven flow, even after breakthrough, and efficient displacement of water and oil phases. Formate injection resulted in 15% more oil recovery and 37% more carbon storage than the CO2 injection case.

[0158] With increased oil recovery, there may be concerns about formate resulting in more carbon emissions. We calculated the moles of produced hydrocarbon components in the oil, summed the number of produced carbon molecules, and compared these to the number of stored carbon molecules to see how much carbon intensity reduction was achieved by each injectant. After 15 years of CO2 / formate injection, the formate case had a 20% reduction in carbon intensity and the CO2 case had a 16% reduction in carbon intensity, as shown in Figure 26. That is, the greater injectant storage compensates for the higher oil recovery obtained from the formate case. The results suggest that carbon storage in oil reservoirs requires deliberate design for efficient displacement of not only oil but also water (water from waterflooding and residual water).

[0159] Sensitivity analysis to kv / kh. The matrix kv / kh value was adjusted from 0.3 to 0.0001 while the fracture volume kv / kh value was kept at 0.3. As mentioned before, this corresponds to the settings in the 10th SPE Comparative Solutions Project. The effect of the changes in kv / kh on the flow patterns, carbon storage and oil recovery for the CO2 and formate injection cases was investigated.

[0160] The change in kv / kh affected the observed injectant distribution profile, as shown in Figures 27A, 27B, and 27C. The reduction in kv / kh resulted in increased levels of channeling flow and therefore suppression of gravity-driven fluxes, especially as seen in the CO2 case. Figures 28 and 29 show the oil production and carbon storage for both reservoir configurations (kv / kh=0.3 and 0.0001). Both cases saw a reduction in oil and carbon storage with a significant reduction in kv / kh; however, the CO2 case was much more affected by this adjustment. In the CO2 injection case, oil recovery was reduced by 50% and carbon storage was reduced by 52%, while in the formate injection case, oil recovery was reduced by 25% and carbon storage was reduced by 19%.

[0161] This sensitivity analysis shows the benefits of using formate as a carbon carrier to control the risk of CCS associated with permeability heterogeneity and its impact on the subsurface flow regime. Previous studies on the use of formic acid brine as a base fluid in drilling muds have shown that aqueous formic acid is compatible with polymers and retained stability at temperatures as high as 150°C; therefore, it is indeed possible to control the in-situ flow regime of formate (carbon carrier) by adjusting the density and viscosity of the injected formate solution.

[0162] Conclusions. In this example, a case study of aqueous formic acid as a carbon carrier for geological carbon storage is presented in comparison to CO2 as a conventional carbon carrier. New experimental data is reported on the properties of formate solutions in brines and used to set up numerical flow simulations for the case study. Some conclusions are as follows:

[0163] Experimental data showed that formate is stable in NaCl+CaCl2 brine (102,600 ppm) and the formate solubility ranges from 30% to 35% by weight at temperatures between 25 and 75°C.

[0164] Newtonian behavior was consistently observed for formate solutions in brine at different formate concentrations and temperatures. The measured viscosities correlated well as a logarithmic function of the molar concentration of formate. The viscosity of a 30 wt. % formate solution in 102,600 ppm brine was approximately 12 cp at 25°C, 5 cp at 50°C, and 3 cp at 75°C.

[0165] Two simulation case studies of carbon storage were performed; aquifer case study 1 and oil reservoir case study 2. For each case study, CO2 and formate injection were compared in terms of flow regime and displacement of reservoir fluids (formation water in case study 1 and formation water and formation oil in case study 2). Although the flow regime depended on the reservoir properties, the formate injection case showed a much more stable front of oil and water displacement. The more stable front resulted in oil recovery and carbon storage that was insensitive to injectant breakthrough. In all studied scenarios, the formate solution injection case resulted in approximately 40% greater carbon (molar valley) storage compared to the CO2 injection case.

[0166] [Table 6]

[0167] [Table 7]

[0168] [Table 8]

[0169] [Table 9]

[0170] [Table 10]

[0171] [Table 11]

[0172] [Table 12]

[0173] [Table 13]

[0174] Figure captions for Example 3. Figure 13. Sodium formate solution in DIW at 25° C. The undissolved salts settled to the bottom. The solution with the highest molar concentration of sodium formate with undissolved salts was chosen as the solubility limit and the weight fraction of formate in the solution was recorded.

[0175] Figure 14. Viscosity of formate solutions in brine at 25, 50, and 75° C. The data show a clear correlation as a logarithmic function of formate molarity.

[0176] Figure 15. 3D aquifer model with two facies. The sand facies is red and the shale facies is blue. The injection well is in the lower right corner and the production well is in the upper left corner.

[0177] Figure 16A. Water-oil relative permeability curves used in the case study. Figure 16B. Liquid-gas relative permeability curves used in the case study.

[0178] Figures 17A, 17B, 17C, and 17D. Distribution of CO2 and formate in the aquifer over the simulation period. CO2 injection showed a clear gravity override profile, unlike the formate case. Because the miscible displacement had a favorable viscosity ratio, the profile evolved into a uniform distribution of formate in the aquifer.

[0179] Figure 18. Cumulative production of CO2 and formate from the aquifer in Case Study 1. Each molecule of formate and CO2 contains one mole of carbon; therefore, their production is comparable on a molar basis. CO2 production rose rapidly as soon as CO2 breakthrough began, which is typical for high mobility gases.

[0180] Figure 19. Cumulative water production from the aquifer in Case Study 1. Once CO2 breakthrough occurred, water production leveled off. Almost all of the injected CO2 was produced after breakthrough.

[0181] Figure 20. Cumulative moles of injectate stored in Case Study 1. The moles of formate stored steadily increased after breakthrough as the formate solution miscibly displaced formation water at a favorable viscosity ratio.

[0182] Figure 21. 3D diagram of reservoir porosity distribution; taken from the 10th SPE Comparative Solutions Project (Christie and Blunt, 2001). The color scale indicates porosity.

[0183] 22A, 22B, 22C, 22. CO2 and formate profiles at different times in case study 2. The time frame in the first column refers to the time after the start of CO2 / formate injection. Oil production was initiated by waterflooding for 5 years. The formate injection case shows a stable displacement front and more efficient oil and water displacement than CO2.

[0184] Figure 23. Cumulative water production simulated in case study 2.

[0185] Figure 24. Oil recovery from CO2 and formate solution injection in case study 2. The formate injection case resulted in approximately 20% more oil recovery than the CO2 injection case.

[0186] Figure 25. History of moles of injectate stored in Case Study 2. One mole of CO2 / formate contains one mole of carbon; therefore, moles of CO2 / formate stored are equivalent to moles of carbon stored.

[0187] Figure 26. Carbon intensity drop. This is the ratio of moles of carbon in the stored injectant to the moles of carbon in the oil produced by the injectant. Although formate injection produced more hydrocarbons (oil) than CO2 injection, formate still has a higher carbon intensity drop compared to CO2.

[0188] Figures 27A, 27B, 27C. CO2 and formate profiles in the oil reservoir using an adjusted kv / kh value of 0.0001 relative to the matrix volume. The time frame in the first column refers to the time after the start of CO2 / formate injection.

[0189] Figure 28. Oil production results for CO2 and formate injection cases in case study 2 using kv / kh values ​​of 0.3 and 0.0001.

[0190] Figure 29. Injectate storage for the CO2 and formate injection cases of Case Study 2 using kv / kh values ​​of 0.3 and 0.0001.

[0191] Example 4: Comparative experimental investigation of formate, acetate and glycine as wettability modifiers in carbonate and shale formats Studies have shown the effectiveness of glycine, the simplest amino acid, as a wettability modifier to enhance water imbibition in carbonate reservoirs. The objective of this example was to compare the performance of formate, acetate, and glycine as wettability modifiers for carbonate formations. Formate and acetate are introduced for the first time as novel chemicals for this purpose. It is noted that the aminomethyl group and amino group are the only structural differences between formate and glycine, and between acetate and glycine, respectively.

[0192] The experiments consisted of contact angle measurements on oil-aged calcite and shale plates, as well as imbibition displacements (spontaneous and forced). Comparisons between these additives were realised with and without the addition of hydrogen chloride (HCl) to adjust the pH of the solution. The Amott Index of the glycine and formate + HCl solutions was significantly higher than the remaining cases of the imbibition experiments. It was found that formate can be very effective in changing the wettability of carbonate rocks to a water-wet state when the pH of the solution was reduced. This indicates a successful synergistic effect of pH adjustment and formate adsorption onto the rock surface, resulting in improved oil recovery.

[0193] Glycine performed better compared to the formate and acetate wettability modifiers for all experimental conditions in this example. This indicated that in the presence of carboxyl groups, the amino group plays an important role in altering the wettability of the rock. The ability of glycine to alter wettability comes from two factors: one is the chelating effect caused by the amino group as an electron donor in the presence of carboxyl groups. The chelating effect makes glycine more entropically favorable to bind calcium cations in the brine, induce calcite dissolution, and / or attach directly to the calcite surface. The other factor is the calcite dissolution induced by the pH drop followed by the attraction of glycine to the rock surface.

[0194] Introduction. Waterflooding in carbonate oil reservoirs is generally inefficient because the large permeability contrast between the matrix and fractures results in channeling flow. Also, carbonate rocks tend to be oil-wet, so spontaneous imbibition of water from fractures into the matrix is ​​not effective for oil recovery. A shift in wettability to a more water-wet state is expected to improve oil recovery in oil-wet carbonate reservoirs.

[0195] Interactions between rock minerals, brines, and oil affect the wettability of rocks, among other factors. Formation water (or brine) is the initial wetting phase in conventional oil reservoirs before oil migration. After oil migration, the brine is still the wetting phase as long as the brine film is stable. When the stability of the brine starts to change, a connection is formed between the rock surface and the oil. Following this process, the surface active components of the oil are adsorbed, resulting in a decrease in water-wettability or even a switch of the surface to oil-wet. By improving the stability of the thin brine or / and detaching the adsorbed oil components from the rock surface, it is possible to change the wettability back from oil-wet to water-wet.

[0196] A widely studied method to alter the wettability of rocks is surfactant injection. However, surfactant-induced wettability changes are usually expected to occur together with a reduction in the interfacial tension between the oleic and aqueous phases. However, the IFT can reach ultra-low values ​​(10 -3 Oil recovery may be limited by a very low IFT because the surfactant absorption rate is reduced.

[0197] Another wettability alteration method that has gained popularity is low salinity waterflooding (LSW) of both sandstone and carbonate reservoirs. In this process, low salinity water can modify the wettability of carbonate rocks by changing the total charge of the carbonate rocks and increasing the electrical double layer at the brine-rock and oil-brine interfaces. CO3 2- , SO4 2- , Ca 2+ and Mg 2+ Multiply charged ions such as these have been reported as potential determining ions that control the charge on rock surfaces.

[0198] The effect of seawater on oil recovery, especially in carbonate reservoirs, was investigated. Based on spontaneous water imbibition experiments using seawater, a change in rock wettability was observed in the presence of sulfate ions, which displaced naphthenic acid from the carbonate rock surface. Sulfate ions could be assisted by calcium and magnesium ions in the wettability change process.

[0199] LSW has been evaluated by core flooding experiments. Continuous injection of seawater and its dilute solutions showed an incremental oil recovery of 0.18. The influence of ions was studied separately using surface potential experiments. The main ions that changed the wettability of R10 carbonate were sulfate and calcium. Surface potential did not fully explain the oil-improving calcite dissolution, so calcite dissolution has been proposed as one of the potential mechanisms of wettability change.

[0200] Chemicals other than surfactants have also been investigated as wettability modifiers for carbonate reservoirs. Aqueous solutions of 3-pentanone were investigated to enhance oil recovery through wettability modification. Comprehensive analysis was performed by contact angle, imbibition and core flooding experiments. The results showed a significant improvement in oil recovery from limestone cores after adding 3-pentanone to the brine.

[0201] Amino acids have also been studied as another type of wettability modifier. The simplest amino acids and introduced glycine have been studied as effective wettability modifiers. Surfactants synthesized from amino acids have also been studied as oil recovery agents and for several other applications. These amino acids contain a carboxylic acid (-COOH) group and an amine (-NH2) group in the same molecule. An important property of glycine is that its overall charge depends on the pH of the solution, as shown in Figure 30. If the pH of the solution is higher than its isoelectric point (pI), which is 5.97 at room temperature, glycine is negatively charged. Otherwise, glycine is positively charged. Glycine is effective when the solution pH is between its pI and the point of zero charge (pzc) of calcite.

[0202] The objective of this example is to investigate the ability of carboxylate anions, specifically formate and acetate, to change the wettability of carbonate mineral surfaces from oil-wet to water-wet. This was done by comparing formate and acetate with glycine, a proven wettability modifier, through contact angle and absorption experiments. The aminomethyl and amino groups are the only structural differences between formate and glycine, and between acetate and glycine, respectively (Figure 31). This example also analyzes how these carboxylate anions can be more effective at wettability modification under slightly reduced pH. The negative charge of formate and acetate ions can result in wettability modification due to the interaction between the positively charged calcite surface and the carboxyl groups.

[0203] Inspired by the results of the comparative study, we investigated the importance of the amino groups of glycine for rock wettability modification and effective enhancement of water absorption into carbonate rocks. The comparison among glycine, formate, and acetate was useful to study two possible mechanisms of wettability modification by glycine. One is the chelating effect, which may occur only in glycine. The other is the synergistic effect between calcite dissolution and carboxyl groups, which is expected to occur in formate and acetate as well.

[0204] Materials and Methods. Experiments in this example include contact angle measurements with calcite surfaces and Eagle Ford shale plates, as well as spontaneous and forced imbibition tests with Texas Cream limestone core plugs.

[0205] Materials. Table 14 shows the properties of the dead crude oil sample used in the contact angle experiments with calcite chips and limestone cores. This oil is called Oil 1 and its reservoir temperature is 347 K. Table 15 shows the oil used in the contact angle experiments in the Eagle Ford Shale. This oil is called Oil 2 and its reservoir temperature is 337 K. The reservoir brine (RB) was the same for all experiments as shown in Table 16, and its salinity was 68,722 mg / L. X-ray powder diffraction showed that the Eagle Ford Shale sample consisted of 75% calcite, 14% quartz, 4% dolomite, 2% kaolinite, 1% K-spar, 1% pyrite, etc. The Texas Cream limestone core consisted of 98% calcite, 1% pyrite, and negligible amounts of other minerals.

[0206] Glycine, acetate and formate samples (Sigma-Aldrich) have a purity of greater than 99%. Glycine has a pI of 5.97 at room temperature. Figure 31 shows the molecular structures of glycine, acetate and formate. The aqueous stability of all three chemicals was confirmed using RB in the reservoir and at room temperature.

[0207] Contact angle experiments. Contact angle experiments were performed on calcite surfaces and Eagle Ford shale plates. While the contact angle experiments with calcite focus on determining the optimal concentrations of glycine, formate and acetate, experiments were performed on shale plates to verify the effectiveness of the solutions with another carbonate-rich rock. After cutting the plates to the appropriate size, they were polished with a diamond grinder to obtain a smooth surface. These calcite and shale plates were then first aged in RB for 1 day and then placed in heavy crude oil at 347 K for at least 3 weeks until they reached an oil-wet state.

[0208] The pH values ​​of the chemical solutions were measured before and after the experiments. To test the effect of solution pH, contact angle experiments were performed with calcite surfaces doped with different concentrations of formate and acetate, as well as HCl to reach the pH level of glycine.

[0209] Chemical solutions were prepared in a glasshouse and placed in an oven at 363 K to degas them for at least one day. RB was first prepared by adding salts and adjusting the total mass of the solution to 1 kg with deionized water. Then, appropriate amounts of either glycine, formate or acetate were added to reach the desired concentration. For solutions containing HCl, HCl was added to the formate and acetate solutions at room temperature with slow stirring. The final pH level was adjusted to correspond to a glycine solution of the same concentration. After the aqueous solutions were prepared and degassed, they were placed in an oven at the desired reservoir temperature (347 K for calcite and 337 for Eagle Ford shale). Table 17 summarizes the aqueous solutions tested.

[0210] After at least three weeks of aging in heavy oil, the calcite or shale pieces were collected and excess oil was carefully removed from the surface. Then, to start the experiment, the rock pieces were immersed in the solution and then an oil drop was placed at the bottom of the rock pieces. The solution chamber was placed in an oven for equilibration. Images of the oil drop were then taken. After a certain number of days, a new oil drop was placed and images were taken after equilibration. The contact angles reported in the figures are equilibrium contact angles. For example, if data is reported from the 7th day, the data is the final equilibrium contact angle of the drop placed on the 7th day. A photograph of the setup for the contact angle experiment is shown in Figure 32. Contact angles were measured from the photographs using on-screen protractor software.

[0211] A similar procedure was followed for another set of experiments with Eagle Ford shale plates. Five cases (5 wt% glycine, 5 wt% acetate, 5 wt% acetate + HCl, 5 wt% formate and 5 wt% formate + HCl) were used to test the effect of HCl (pH adjustment) on the wettability change mechanism of formate and acetate. Oil droplets were placed on the bottom of the shale plates on days 0 and 3 because the contact angle change was faster than in the calcite experiments.

[0212] Spontaneous Absorption. Spontaneous absorption studies were performed with glycine, formate and acetate. The effect of solution pH was also tested for formate and acetate. The Amott Cell used was approximately 15 cm in height and 5 cm in diameter, as shown in Figure 33. The neck of the Amott Cell was calibrated and the scale was calibrated to the actual volume before starting the experiment.

[0213] The Texas Cream limestone core plugs used were 38 mm in diameter and 92 mm in length. The cores were evacuated with a vacuum pump for 30 minutes and then brine was injected at a constant pressure of 689 kPa (100 psig) to completely saturate the cores with brine. This was done at room temperature. The porosity and permeability of the core plugs were then measured using RB. The experimental setup consisted of two accumulators (RB and Oil1), one vacuum pump, one pump, one manual hydraulic pump to maintain overload, one Hassler type core holder, one differential pressure gauge and one oven.

[0214] Next, add 60 cm of Oil 1. 3 The oil was injected into the core at a constant rate of 100 cm / hr. This was done at room temperature and without any back pressure, i.e. the outlet side was open to the atmosphere. After the oil break, the rate was reduced to 100 cm / hr. 3 These values ​​minimized capillary end effects and were approximately 2 × 10 -5 The capillary number was chosen to give a value of 0.01 for the effluent, using equations (3) and (4). Oil injection was continued until no more brine was produced in the effluent, at which point the residual water saturation S wr Tables 18 and 19 summarize the rock properties of each core used in the spontaneous and forced imbibition experiments.

[0215] Four cores shown in Table 18 were used in imbibition experiments with the following solutions: reservoir brine (RB), 5 wt% glycine in RB, 5 wt% acetate in RB and 5 wt% formate in RB. To test the effect of solution pH, six cores shown in Table 19 were used with the following solutions: RB, RB+HCl, 2.5 wt% glycine, 5 wt% formate+HCl and 5 wt% acetate+HCl. The first trial resulted in unexpectedly low oil recovery, so acetate+HCl was repeated in two experiments.

[0216] After saturation with Oil 1, four cores shown in Table 18 and six cores shown in Table 19 were placed in a glass chamber filled with Oil 1 for 30 days. However, the first set of cores was aged at room temperature for 10 days and at 347 K for 30 days. The latter set of cores was aged at 347 K for the entire 30 days. The difference in aging temperature affects the initial oil wettability of the two sets, as shown below. Therefore, the RB case was used as a control experiment for the two sets of cores shown in Tables 18 and 19.

[0217] The solutions were placed in an oven at 363 K for one day for degassing, and then they were placed in an oven at 347 K (experimental temperature). The oil-saturated cores were then introduced into the Amott cell. Immediately afterwards, the aqueous solution was carefully poured in so as to avoid the formation of air bubbles. It is noted that this Amott test started with all materials heated at 347 K to avoid thermal expansion / contraction of the oil. Atmospheric pressure was maintained inside the cell throughout the experiment. Finally, oil recovery was monitored daily.

[0218] Forced imbibition. The Amott cell was cooled after the spontaneous imbibition experiment, and then the oil and brine (or other solution) were withdrawn from the cell using a glass pipette and their volumes were measured. The core was withdrawn from the Amott cell and immediately placed in a core holder for forced imbibition.

[0219] Figure 34 shows the experimental setup for forced absorption. The experiment was carried out at 347 K. There was no back pressure, in other words, the outlet side was open to the atmosphere during the experiment. 100 cm of the corresponding solution for each case was added. 3 The oil was injected at a constant flow rate of 1000 ml / hr. To minimize capillary end effects, the flow rate was reduced to 300 cm after oil production ceased. 3 / hr. The produced fluid was collected in a vial and the oil recovery was calculated.

[0220] Using the results, we calculate the water I w The Amott index was estimated as:

number

[0221] The rate of the forced imbibition experiment was chosen similarly to the core saturation procedure. This rate was 2 × 10 -5 The capillary number N used in this example was set to give vc The formula for is:

number

number

number

[0222] Increased injection rate to minimize capillary end effects is 2.5 cp-cm 2 / min or more Rapoport and Lease count (N RL ) based on N RL in([cp cm 2 ) / min] is given by:

number

[0223] Results and Discussion. In this section, experimental results from the contact angle and imbibition experiments are discussed. The contact angle experiments consisted of two sets of calcite and Eagle Ford shale pieces. The imbibition experiments consisted of spontaneous and forced imbibition.

[0224] Contact angle experiments. The overall charge of glycine depends on the pH of the solution (Figure 30). When the pH is greater than the pI of glycine, i.e., 5.97, an overall negative charge results. The pzc of calcite is reported to be 8.8. Therefore, glycine is expected to change wettability when the solution pH is between 5.97 and 8.8. Table 20 summarizes the solution pH measured before and after the contact angle experiments for all cases. The table shows that the pH values ​​for all glycine cases were within the pH window of wettability change. The acetate and formate solutions were basic, unlike the glycine solution.

[0225] Figures 35, 36A, 36B, 36C, 36D, 37A, 37B, 37C, 37D, 38A, 38B, 38C and 38D show the contact angle values ​​of calcite surfaces in RB and different concentrations of glycine, acetate and formate with and without HCl. In most glycine cases, a significant decrease in contact angle was observed over time. For example, it reached almost 40° at 2.5 and 5 wt% glycine concentrations (Figures 38C and 38D). From these experiments, it is clear that 2.5 wt% glycine concentration is more optimal from an economical point of view. However, the RB and acetate cases without HCl did not significantly decrease the contact angle. The formate case without HCl resulted in a slightly water-wet state with a contact angle of about 80° (Figures 38A, 38B, 38C and 38D).

[0226] Table 20 shows that the initial solution pH of glycine was less than that of formate and acetate. This may have happened in the case of glycine, since a lower pH can result in a calcite dissolution reaction. Calcite dissolution may release absorbed polar components from the rock surface. A wettability change is then possible when negatively charged ions are attracted to the positively charged calcite surface, as in the case of glycine at a pH between the pI and the surface pzc.

[0227] The wettability change to water-wet state is believed to be enhanced when formate or acetate anions are present in the solution after calcite dissolution has occurred. This is because the formate and acetate anions can bind to the positively charged calcite surface once the calcite dissolves and releases the oil molecules from the calcite surface. Table 20 shows that the acetate and formate cases with HCl had pH values ​​close to that of the glycine solution at the same concentration. Reducing the solution pH for the formate and acetate cases enhanced the wettability change as shown in Figures 35, 36A, 36B, 36C, 36D, 37A, 37B, 37C, 37D, 38A, 38B, 38C, and 38D. Notably, a significant improvement was observed for formate; in the formate case with HCl, the contact angle decreased to 50-60°. Decreasing the pH also improved the RB case, but the contact angle was still around 80°. This observation confirms that having negatively charged ions (e.g., glycine and carboxylate anions with pH values ​​above their pI) along with calcite dissolution is essential for larger wettability changes.

[0228] As mentioned above, five cases (5 wt% glycine, 5 wt% acetate, 5 wt% acetate + HCl, 5 wt% formate and 5 wt% formate + HCl) were tested on the Eagle Ford Shale rock surface. This was to reaffirm that the addition of HCl improves the wettability alteration ability of formate and acetate. Figure 39 shows that the final contact angles of formate and acetate were reduced to about 60° with HCl and to about 80° without HCl. Reducing the pH of the carboxylate solutions (formate and acetate) resulted in a wettability alteration intensity similar to glycine, which also resulted in a reduction in the contact angle to 60°.

[0229] Spontaneous and forced water imbibition experiments. Contact angle experiments showed wettability changes; however, further testing of the additives was performed at the core scale to verify the observed wettability changes. As mentioned above, in the first series of experiments, RB, 5 wt% glycine, 5 wt% acetate and 5 wt% formate without HCl were used for the four cores shown in Table 18. In the second series of experiments, RB, RB+HCl, 2.5 wt% glycine, 5 wt% formate+HCl and 5 wt% acetate+HCl were used for the six cores shown in Table 19. These concentrations were chosen because they worked best for glycine and formate. In the case of acetate, 5 wt% was also chosen because this concentration reduced the contact angle on the shale plate similar to the remaining chemicals.

[0230] The IFT between Oil 1 and the four solutions was also measured and is shown in Table 21 to verify that the oil recovery was improved by wettability changes and not IFT reduction. Even though the IFT of the carboxylate solution / Oil 1 was slightly lower than that of both the RB and glycine solutions, this small difference is not expected to significantly change the capillary pressure.

[0231] In addition to rock properties, it is important to consider the units used to calculate oil recovery. Thus, Figures 40A, 41A, 42A and 43A show oil recovery in units of original oil reserves in place (OOIP), while Figures 40B, 41B, 42B and 43B show oil recovery in terms of pore volume (PV).

[0232] Figures 40A and 40B show the oil recovery from spontaneous imbibition experiments. Due to differences between core properties, the oil recovery graphs were corrected with the Leverett coefficient, √(k / φ), for better comparison. Each experiment was terminated when a plateau was reached. Glycine outperformed the other cases, reaching a recovery of 0.32 in spontaneous imbibition. The oil recovery of acetate and formate was 0.20 and 0.23, respectively, which is very close to the RB recovery of 0.22 (Figure 40A).

[0233] The forced imbibition experiment was conducted immediately after spontaneous imbibition. Figures 41A and 41B show the oil recovery during the forced imbibition experiment in terms of pore volume of injection. The final oil recovery is similar between the cases, but it is important to note that at the field scale, the typical injection is about 1 PV, and glycine clearly outperforms the remaining chemicals with PV injected at 1 or less. Table 22 shows the water Amott Index for the first series of cores, as well as the water saturation at the start of the experiment, after spontaneous imbibition, and after forced imbibition (see Table 18). The Amott Index for water for glycine was significantly higher than those for RB, formate, and acetate, indicating that the glycine case was more water wet. These results are consistent with the contact angle results presented in the previous section.

[0234] Figures 42A and 42B show the oil recovery from spontaneous imbibition for the second series of experiments. As expected from the contact angle experiments, the wettability change due to formate was enhanced by decreasing pH. The formate solution with HCl was comparable to 2.5 wt% glycine, which recovered more than twice as much as RB or RB+HCl. This observation reaffirms the synergistic effect of the solution pH effect and the negatively charged carboxyl groups. However, this synergistic effect was not observed in the two duplicate experiments for the acetate case. The first trial of 5 wt% acetate+HCl yielded a similar amount of oil as RB, and the second trial yielded slightly less oil recovery. The lower oil recovery from core #6 in the second trial could be attributed to the longer maturation time, which resulted in stronger oil wetting conditions. Based on these two experiments, it can be concluded that acetate cannot be used advantageously as an enhanced oil recovery technique.

[0235] Figures 43A and 43B show the oil recovery from forced imbibition for the second series of experiments. The cores used for the first trial of 5 wt% acetate were discarded before reaching a plateau in the spontaneous imbibition test, so the forced imbibition experiment could not be continued. Thus, Figures 43A and 43B show the results of only the second trial of acetate. Table 23 shows the water Amott Index for the second series of cores, as well as the water saturation at the start of the experiment, after spontaneous imbibition, and after forced imbibition (see Table 19). The 2.5 wt% glycine case has the highest Amott Index, slightly higher than the 5 wt% formate + HCl case. The comparison of "RB + HCl" to "5% formate + HCl" demonstrates the importance of carboxyl groups in the wettability change (in other words, calcite dissolution alone had no effect). Furthermore, the comparison of "5 wt% formate" to "5 wt% formate + HCl" shows the importance of the addition of HCl (i.e., the presence of carboxylate anions alone was not effective). Carboxyl groups were hypothesized to have interacted with the rock surface after calcite dissolution due to reduced solution pH, as explained above; however, the addition of HCl did not enhance the acetate case. Further investigations could be useful to understand the details of the binding of ions on rock surfaces at different scales, e.g., from scratch, molecular dynamics and surface complexation modeling.

[0236] Nevertheless, the results show that glycine was more effective than formate and acetate with / without pH control. It is reasonable to attribute this to the amino group of glycine, a structural difference between glycine and acetate in the presence of carboxyl groups. That is, other than the negatively charged carboxylate side, the electron-donating amino group of glycine plays an important role in improving oil recovery by wettability change. This electron-donating group of glycine makes it a chelating ligand, or more specifically, a bidentate ligand that can interact with calcium cations in solution and / or the calcite surface with two functional groups in the molecule. Chelating ligands have a higher affinity for metal ions than similar monodentate ligands that can only interact with one functional group. The chelating property of glycine that allows it to bind to calcite is due to two mechanisms. Figure 44A and Figure 44B present two ways in which calcium cations bind to glycine. It was hypothesized that glycine binds to calcium and magnesium cations in the brine, and then the rock surface attempts to compensate for these sequestered cations to restore equilibrium. This process causes calcite dissolution, which enhances wettability to a more water-wet state, as the release of cations releases oil molecules from the calcite surface. This hypothesis was first demonstrated for chelating agents such as ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA) and diethylenetriaminepentaacetic acid (DTPA), which can enhance oil recovery better than low salinity brines. Furthermore, it was hypothesized that glycine is more entropically favored to attach to the calcite surface than the oil-derived naphthenic acids, which can only interact with the calcite surface through their carboxyl groups in a similar manner. This mechanism is illustrated in Figure 45. This higher affinity of the calcite surface for glycine due to the chelating effect compared to carboxylate ions may be one of the reasons why glycine alters wettability more significantly.

[0237] In summary, the results of this example show the effectiveness of formate in wettability change under slightly reduced pH due to the possible synergistic effect between calcite dissolution and the attraction of carboxyl groups to the calcite surface. The results also show the value of amino groups on wettability change with glycine, which may be more effective than acetate with / without pH adjustment. This may be due to the presence of amino groups along with carboxyl groups that make glycine a chelating ligand.

[0238] Conclusions. The objectives of this example included investigating formate and acetate anions as wettability modifiers for carbonate rocks and clarifying the utility of the amino group of glycine. This was accomplished by comparing the contact angle and sorption experimental results of these three chemicals. The main conclusions are as follows:

[0239] Contact angle experiments with oil-aged calcite surfaces and Eagle Ford shale plates showed a significant preference for glycine over acetate and a slight preference for formate, which was reconfirmed by subsequent Amott tests with Texas Cream limestone cores, revealing the importance of the amino group in glycine.

[0240] The important role of the amino group in altering wettability was hypothesized to be due to the chelating effect that occurs in glycine but not in formate and acetate. In addition to the carboxyl group, the amino group acts as a binding functional group (electron donor group) for the chelating effect to occur. This makes glycine a bidentate ligand, which is entropically more favorable to bind calcium cations, induce further calcite dissolution, and / or directly bind to the calcite surface, which has both amino and carboxyl groups. This property of glycine results in a greater wettability change than that of acetate or formate, which can only interact via the carboxyl group.

[0241] Acetate and formate became more effective in reducing the contact angle of the oil droplet on the shale plate when the pH of the solution was reduced to the same level as glycine. RB with reduced pH was not effective in reducing the contact angle of the oil droplet on the calcite surface. This indicates the importance of the synergistic effect between the carboxyl group and the solution pH. Compared to acetate, formate was better in its ability to alter wettability.

[0242] The water absorption tests showed a successful synergy between calcite dissolution and attraction to the rock surface by glycine (through a chelating effect) and formate (through the carboxyl group). The Amott Indexes of the glycine and formate + HCl solutions were significantly higher than the remaining cases. It is not clear why the acetate case was not enhanced by the addition of HCl in the absorption tests, suggesting that further investigation is needed.

[0243] The above points allow the introduction of the use of formate salts with reduced pH for wettability modification of oil-wet carbonate rocks and therefore for enhancing oil recovery due to its ability to improve water uptake.

[0244] nomenclature [Table 39]

[0245] [Table 14]

[0246] [Table 15]

[0247] [Table 16]

[0248] [Table 17]

[0249] [Table 18]

[0250] [Table 19]

[0251] [Table 20]

[0252] [Table 21]

[0253] [Table 22]

[0254] [Table 23]

[0255] Captions for figures in Example 4. Figure 30. Molecular structures of different forms of glycine.

[0256] Figure 31. Molecular structures of the chemicals used in this example: (a) formate anion, (b) acetate anion, and (c) glycine.

[0257] Figure 32. Contact angle apparatus used in this example.

[0258] Figure 33. The Amott cell used in this example. The oil-aged core is placed in the Amott cell, and then the solution to be tested is slowly poured into the Amott cell. All components were at reservoir temperature (347 K) during the experimental setup to avoid fluid expansion. The produced oil accumulates at the top, and its volume can be measured from the grid available in the Amott cell.

[0259] Figure 34. Diagram of the experimental setup used for forced absorption.

[0260] Figure 35. Results of RB contact angle experiments with calcite.

[0261] Figures 36A, 36B, 36C, and 36D. Results of glycine contact angle experiments with calcite: (Figure 36A) 0.5 wt% glycine solution, (Figure 36B) 1 wt% glycine solution, (Figure 36C) 2.5 wt% glycine solution, and (Figure 36D) 5 wt% glycine solution.

[0262] FIG. 37A, FIG. 37B, FIG. 37C, FIG. 37D. Results of acetate contact angle experiments with calcite: (FIG. 37A) 0.5 wt. % acetate solution, (FIG. 37B) 1 wt. % acetate solution, (FIG. 37C) 2.5 wt. % acetate solution, and (FIG. 37D) 5 wt. % acetate solution.

[0263] FIG. 38A, FIG. 38B, FIG. 38C, FIG. 38D. Results of formate contact angle experiments with calcite: (FIG. 38A) 0.5 wt. % formate solution, (FIG. 38B) 1 wt. % formate solution, (FIG. 38C) 2.5 wt. % formate solution, and (FIG. 38D) 5 wt. % formate solution.

[0264] Figure 39. Results of contact angle experiments with Eagle Ford shale plates.

[0265] 40A and 40B. Results of the first series of spontaneous imbibition experiments with a Texas Cream limestone core: (FIG. 40A) oil recovery in terms of OOIP, (FIG. 40B) oil recovery in terms of pore volume (PV).

[0266] 41A and 41B. Results of the first series of forced imbibition experiments with a Texas Cream limestone core: (FIG. 41A) oil recovery for OOIP, (FIG. 41B) oil recovery for PV.

[0267] Figures 42A and 42B. Results of a second series of spontaneous imbibition experiments with Texas Cream limestone cores: (Figure 42A) oil recovery for OOIP, (Figure 42B) oil recovery for PV.

[0268] 43A and 43B. Results of a second series of forced imbibition experiments with a Texas Cream limestone core: (FIG. 43A) oil recovery for OOIP, (FIG. 43B) oil recovery for PV.

[0269] Figure 44A and Figure 44B. Two possible mechanisms of calcium binding to glycine: (Figure 44A) calcium binding to the carboxyl group, (Figure 44B) calcium binding to the carboxyl and amino groups. Calcium is yellow, carbon is grey, nitrogen is blue, hydrogen is white, and oxygen is red. Schematic taken from Tang et al.

[0270] Figure 45. Illustration of the role of the amino group in the dominance of glycine (left) over carboxylate anions (right) due to the chelating effect. Glycine is attracted to the calcite surface through both the amino and carboxyl groups, making it more entropically favored compared to carboxylate anions such as formate or acetate, which interact only through the carboxyl group. This attraction is necessary if oil molecules are to be released from the surface for calcite dissolution.

[0271] Example 5: Experimentally determined properties of formate solutions Solutions of formate salt in deionized water and different brines were prepared. The solubility of formate salt in the solutions was measured, as summarized in Table 24.

[0272] [Table 24]

[0273] The viscosity of formate solutions at three salinities (0, 15000 and 49000 ppm NaCl), three temperatures (25, 50 and 75°C) and five concentrations (0, 10, 20, 25 and 30 wt%) was measured and the results are summarized in Tables 25-28, Figure 46, Figure 47, Figure 48 and Figure 49. The viscosity of several formate and HPAM (hydrolyzed acrylic acid polymer) solutions was also measured, as summarized in Table 29.

[0274] [Table 25]

[0275] [Table 26]

[0276] [Table 27]

[0277] [Table 28]

[0278] [Table 29]

[0279] Interfacial tension measurements were performed between the formate solutions and the oil and the results are summarized in Table 30.

[0280] [Table 30]

[0281] In-situ viscosity and adsorption measurements were obtained as summarized in Tables 31 and 32. In-situ viscosity measurements of 20 wt. % formate solutions with Indiana limestone were obtained at room temperature. The in-situ viscosity exhibits Newtonian fluid behavior. The average in-situ viscosity is 4 cp and the average bulk viscosity is 3.3 cp.

[0282] [Table 31]

[0283] [Table 32]

[0284] Core flooding experiments were performed on three Indiana limestone cores. The first case, summarized in Tables 33 and 34 and Figure 51, was for flooding with brine, and the ultimate oil recovery was 53.3% and the breakthrough time was 0.298 HCPV (hydrocarbon pore volume).

[0285] [Table 33]

[0286] [Table 34]

[0287] The second case summarized in Tables 35 and 36 and FIG. 52 is for flooding with 20 wt% formate, the ultimate oil recovery was 53.2% and the breakthrough time was 0.425 HCPV.

[0288] [Table 35]

[0289] [Table 36]

[0290] The third case summarized in Tables 37 and 38 and FIG. 53 was for flooding with 30 wt% formate, the ultimate oil recovery was 52.6% and the breakthrough time was 0.489 HCPV.

[0291] [Table 37]

[0292] [Table 38]

[0293] Figure captions for Example 5. Figure 46. Viscosity of formate solutions in DI water.

[0294] Figure 47. Viscosity of formate solutions in 15000 ppm NaCl.

[0295] Figure 48. Viscosity of formate solutions in 49000 ppm NaCl.

[0296] Figure 49. Viscosity of formate solution in 102646 ppm brine (97897 ppm NaCl and 4749 ppm CaCl2).

[0297] Figure 50. In situ and bulk viscosity of 20 wt % formate solution at room temperature.

[0298] Figure 51. Results of core flooding #1 (brine case).

[0299] Figure 52. Core flooding #2 results (20 wt% formate case).

[0300] Figure 53. Core flooding #3 results (30 wt% formate case).

[0301] References U.S. Patent Nos. 4,637,466, 6,248,792, 8,822,391 and 9,783,729.

[0302] U.S. Patent Application Publication No. 2015 / 0105301.

[0303] PCT International Application Publication Nos. WO2019 / 180503, WO2020 / 191319 and WO2020 / 263829.

[0304] Abe, M., Schechter, RS, Selliah, RD, Sheikh, B. and Wade, WH1987. "Phase Behavior of Branched Tail Ethoxylated Carboxylate Surfactants / Electrolyte / Alkane Systems," Journal of Dispersion Science and Technology, Vol 8(2), 157-172. DOI: 10.1080 / 01932698708943599

[0305] Ahmed,T.,&Meehan,DN2012.Introduction to Enhanced Oil Recovery.In Advanced Reservoir Management and Engineering(Second Edition,pp.541-585).Gulf Professional Publishing.DOI:10.1016 / B978-0-12-385548-0.00006-3.

[0306] Al Mahrouqi,Dawoud,Jan Vinogradov,and Matthew D.Jackson.2017 a.「Zeta Potential of Artificial and Natural Calcite in Aqueous Solution.」Advances in Colloid and Interface Science 240:60-76.DOI:10.1016 / j.cis.2016.12.006

[0307] Al-Mamoori,A.,Krishnamurthy,A.,Rownaghi,A.A.,&Rezaei,F.,2017.Carbon Capture and Utilization Update.Energy Technology,5(6),834-849.DOI:10.1002 / ente.201600747

[0308] Alotaibi,Mohammed B,Hisham A Nasr-El-Din,and James J Fletcher.2011.「Electrokinetics of Limestone and Dolomite Rock Particles.」SPE Reservoir Evaluation&Engineering 14(05):594-603.DOI:10.2118 / 148701-PA

[0309] M.B.Alotaibi,A.A.Yousef,The Role of Individual and Combined Ions in Waterflooding Carbonate Reservoirs:Electrokinetic Study,SPE Res Eval&Eng.20(2017)77-86.SPE-177983-PA.DOI:10.2118 / 177983-PA

[0310] Alotaibi,Mohammed B,and Ali Al-Yousef.2017.「The Role of Individual and Combined Ions in Waterflooding Carbonate Reservoirs:Electrokinetic Study.」SPE Reservoir Evaluation&Engineering 20(01):77-86.

[0311] J.O.Alvarez,D.S.Schechter.2017.Wettability Alteration and Spontaneous Imbibition in Unconventional Liquid Reservoirs by Surfactant Additives,SPE Reservoir Eval.Eng.20(2017)107-117.DOI:10.2118 / 177057-PA

[0312] J.O.Alvarez,F.D.Tovar,D.S Schechter,Improving Oil Recovery in the Wolfcamp Reservoir by Soaking / Flowback Production Schedule with Surfactant Additives,SPE Reservoir Eval.Eng.21(2018)1083-1096.DOI:10.2118 / 187483-PA

[0313] J.O.Alvarez,I.W.R.Saputra,D.S.Schechter,The Impact of Surfactant Imbibition and Adsorption for Improving Oil Recovery in the Wolfcamp and Eagle Ford Reservoirs.SPE Journal 23(2018)2103-2117.DOI:10.2118 / 187176-PA

[0314] E.Amott,Observations relating to the wettability of porous rock,Trans.AIME 219(1959)156-162.DOI:10.2118 / 1167-G

[0315] Anderson,J.J.,Rode,D.,Zhai,H.,&Fischbeck,P.2021.A techno-economic assessment of-carbon-sequestration tax incentives in the US power sector.International Journal of Greenhouse Gas Control,111,103450.DOI:10.1016 / j.ijggc.2021.103450

[0316] S.C.Ayirala,M.E.Saleh,S.M.Enezi,A.A.Al-Yousef,Effect of Salinity and Water Ions on Electrokinetic Interactions in Carbonate Reservoirs Cores at Elevated Temperatures,SPE Res Eval&Eng.21(2018)733-746.DOI:10.2118 / 189444-PA

[0317] F.J.Argueelles-Vivas,M.Wang,G.A.Abeykoon,R.Okuno,2020.Oil recovery from fractured porous media with / without initial water saturation by using 3-pentanone and its aqueous solution.Fuel.276,118031.DOI:10.1016 / j.fuel.2020.118031

[0318] F.J.Argueelles-Vivas,G.A.Abeykoon,R.Okuno,Wettability modifiers for enhanced oil recovery from tight and shale reservoirs,in:R.G.Moghanloo(Eds.),Unconventional Shale Gas Development,Elsevier Inc.,Cambridge,2022,pp.345-392.

[0319] Austad,Tor,Skule Strand,Merete V.Madland,Tina Puntervold,and Reidar I.Korsnes.2008.「Seawater in Chalk:An EOR and Compaction Fluid.」SPE Reservoir Evaluation&Engineering 11(04):648-54.DOI:10.2118 / 118431-PA

[0320] Ayirala,Subhash C,Salah Hamad Saleh,Sultan M Enezi,and Ali A Al-Yousef.2018.「Effect of Salinity and Water Ions on Electrokinetic Interactions in Carbonate Reservoir Cores at Elevated Temperatures.」SPE Reservoir Evaluation&Engineering 21(03):733-46.

[0321] Baghishov,I.,Abeykoon,G.A.,Wang,M.,Argueelles-Vivas,F.J.,and Okuno,R.,Glycine for Enhanced Water Imbibition in Tight Reservoirs-What is the Role of Amino Group?SPE Annual Technical Conference and Exhibition,September 21-23,2021,Dubai,UAE(virtual presentation).DOI:10.2118 / 206294-MS

[0322] Bartels,W.B.,Mahani,H.,Berg,S.and Hassanizadeh,S.M.2019.Literature Review of Low Salinity Waterflooding from a Length and Time Scale Perspective.Fuel 236:338-353.DOI:10.1016 / j.fuel.2018.09.018

[0323] Bjerre and Soerensen,1992,「Thermal decomposition of dilute aqueous formic acid solutions.」Ind.Eng.Chem.Res.,31,6,1574-1577.DOI:10.1021 / ie00006a022

[0324] Bruant,R.,Guswa,A.,Celia,M.,&Peters,C.2002.Safe storage of CO2 in deep saline aquifers.Environmental Science and Technology-Washington DC-,36(11),240A-245A.

[0325] Buckley,J S,K Takamura,and N R Morrow.1989.「Influence of Electrical Surface Charges on the Wetting Properties of Crude Oils.」SPE Reservoir Engineering 4(03):332-40.DOI:10.2118 / 16964-PA

[0326] Budinis,S.,Krevor,S.,Dowell,N.M.,Brandon,N.,&Hawkes,A.2018.An assessment of CCS costs,barriers,and potential.Energy Strategy Reviews,22,61-81.DOI:10.1016 / j.esr.2018.08.003

[0327] Celia,M.A.,Bachu,S.,Nordbotten,J.M.,&Bandilla,K.W.2015.Status Of CO2 Storage in Deep Saline Aquifers with Emphasis on Modeling Approaches and Practical Simulations.Water Resources Research,51(9),6846-6892.DOI:10.1002 / 2015wr017609

[0328] Chen,Szu-ying,Kai Kristiansen,Dongjin Seo,Nicholas A Cadirov,Howard A Dobbs,Yair Kaufman,Alex M Schrader,et al.2018.「Time-Dependent Physicochemical Changes of Carbonate Surfaces from SmartWater(Diluted Seawater)Flooding Processes for Improved Oil Recovery.」Research-article.Langmuir 35:41-50.DOI:10.1021 / acs.langmuir.8b02711

[0329] Chen,Y.,Vise,A.,Klein,W.E.,Cetinbas,F.C.,Myers,D.J.,Smith,W.A.,&Neyerlin,K.C.2020.A robust,scalable platform for the electrochemical conversion of CO2 to formate:identifying pathways to higher energy efficiencies.ACS Energy Letters,5(6),1825-1833.

[0330] Christie,M.A.,Blunt,M.J.,2001.Tenth SPE comparative solution project:a comparison of upscaling techniques.SPE Reservoir Evaluation and Engineering 4(4),308-317.DOI:10.2118 / 72469-PA

[0331] Downs,J.D.1992.High-temperature stabilisation of xanthan in drilling fluids by the use of formate salts.Physical chemistry of colloids and interfaces in oil production,50,197-202.

[0332] Downs,J.D.,Formate Brines:Novel Drilling and Completion Fluids for Demanding Environments.SPE International Symposium on Oilfield Chemistry,New Orleans,Louisiana,March 1993.DOI:10.2118 / 25177-MS

[0333] Eppinger and Huang.2016.「Formic acid as a Hydrogen Energy Carrier.」ACS Energy Letters 2017,2:188-195.

[0334] Farvardini,M.2017.The Sedimentological Distribution of Upper Brent,Oseberg field,North Sea(Dissertation).Retrieved from urn.kb.se / resolve?urn=urn:nbn:se:uu:diva-312874

[0335] Ghosh,Pinaki,Himanshu Sharma,and Kishore K Mohanty.2018.「Development of Surfactant-Polymer SP Processes for High Temperature and High Salinity Carbonate Reservoirs.」In SPE Annual Technical Conference and Exhibition.Society of Petroleum Engineers.DOI:10.2118 / 191733-MS

[0336] Godec,M.,2014.Acquisition and Development of Selected Cost Data for Saline Storage and Enhanced Oil Recovery(EOR).United States.DOI:10.2172 / 1557133

[0337] Godinez-Alvarez,J.M.,Mora-Mendoza,J.L.,Rodriguez-Betancourt,E.,Zavala-Olivares,G.,and Gonzalez-Nunez,M.2018.「Inhibition of Ferrous Metal Corrosion by Carboxylates,」Paper Presented at the Corrosion,New Orleans,Louisiana,USA.March.NACE-04412.

[0338] Grigoni,Sagar,Li,Lee,Yan,Bertens,Miao,Wang,Abed,Won,Arquer,Ip,Sinton,and Sargent.2020.「CO2Electroreduction to Format at a Partial Current Density of 930mAcm -2with InP Colloidal Quantum Dot Derived Catalysts.」ACS Energy Letters 2021,6:79-84.

[0339] Grubel,Jeong,Yoon,and Autrey.2020.「Challenges and opportunities for using formate to store,transport,and use hydrogen.」Journal of Energy Chemistry 41:216-224.

[0340] Hailu,Tamijani,Mason,and Shaw,2020,「Efficient Conversion of CO2 to Formate Using Inexpensive and Easily Prepared Post-Transition Metal Catalysts,」Energy Fuels,34,3,3467-3476.DOI:10.1021 / acs.energyfuels.9b03783.

[0341] F.Heberling,T.P.Trainor,J.Luetzenkirchen,P.Eng,M.A.Denecke,D.Bosbach,Structure and reactivity of the calcite-water interface,Journal of Colloid and Interface Science.354(2011)843-857.DOI:10.1016 / j.jcis.2010.10.047

[0342] Hiorth,A,L M Cathles,and M V Madland.2010.「The Impact of Pore Water Chemistry on Carbonate Surface Charge and Oil Wettability.」Transport in Porous Media 85(1):1-21.

[0343] Hirasaki,G.J.1991.「Wettability:Fundamentals and Surface Forces.」SPE Formation Evaluation 6(02):217-26.DOI:10.2118 / 17367-PA.

[0344] G.J.Hirasaki,D.L.Zhang.2004.Surface Chemistry of Oil Recovery from Fractured,Oil-Wet,Carbonate Formations,SPE Journal 9,151-162.DOI:10.2118 / 88365-PA

[0345] A.Hiorth,L.M.Cathles,M.V.Madland,The Impact of Pore Water Chemistry on Carbonate Surface Charge and Oil Wettability,Transport in Porous Media.85(2010)1-21.DOI:10.1007 / s11242-010-9543-6

[0346] Hφgnesen,E J,S Strand,T Austad,and U Stavanger.2005.「Waterflooding of Preferential Oil-Wet Carbonates:Oil Recovery Related to Reservoir Temperature and Brine Composition.」SPE Europe / EAGE Conference.DOI:10.2118 / 94166-MS

[0347] Howard,Siv K.,Formate Brines for Drilling and Completion:State of the Art.SPE Annual Technical Conference and Exhibition,Dallas,Texas,October 1995.DOI:10.2118 / 30498-MS

[0348] IEA.2019.Putting CO2to Use,IEA,Paris www.iea.org / reports / putting-co2-to-use

[0349] Jouny,M.,Luc,W.,&Jiao,F.2018.General techno-economic analysis of CO2 electrolysis systems.Industrial&Engineering Chemistry Research,57(6),2165-2177.

[0350] Jun,L.,Britton,C.,Solairaj,S.,Liyanage,P.J.,Kim,D.H.,Adkins,S.,Arachchilage,G.W.,Weerasooriya,U.P.,and Pope,G.A.2014.「Novel Large-Hydrophobe Alkoxy Carboxylate Surfactants for Enhanced Oil Recovery,」SPE Journal.Vol 19(6):1024-1034.SPE-154261-PA.DOI:10.2118 / 154261-PA.

[0351] Juergenson,G.A.,Bittner,C.,Kurkal-Siebert,V.,Oetter,G.and Tinsley,J.2015.「Alkyl Ether Carboxylates Surfactants for Chemically Enhanced Oil Recovery in Harsh Field Conditions,」Paper presented at the SPE Asia Pacific Enhanced Oil Recovery Conference,11-15 August.SPE-174589-MS.DOI:10.2118 / 174589-MS.

[0352] Kelemen,P.,Benson,S.,Pilorge,H.,Psarras,P.&Wilcox,J.2019.An Overview of the Status and Challenges of CO2 Storage in Minerals and Geological Formations.Frontiers in Climate,vol.1.DOI:10.3389 / fclim.2019.00009

[0353] Kim,M.,Kim,C.,Lee,H.&Kim,K.1996.Temperature dependence of dissociation constants for formic acid and 2,6-dinitrophenol in aqueous solutions up to 175°C.Journal of the Chemical Society,Faraday Transactions,92(24),4951-4956.DOI:10.1039 / FT9969204951

[0354] Kumar,A.2016.Characterization of Reservoir Fluids based on Perturbation from n-Alkanes.Doctoral dissertation,University of Alberta.Education and Research Archive.DOI:10.7939 / R3PR7N024

[0355] Kelemen,P.,Benson,S.,Pilorge,H.,Psarras,P.and Wilcox,J.,2019.An Overview of the Status and Challenges of CO2 Storage in Minerals and Geological Formations.Frontiers in Climate,vol.1.DOI:10.3389 / fclim.2019.00009

[0356] Kim,M.,Kim,C.,Lee,H.and Kim,K.,1996.Temperature dependence of dissociation constants for formic acid and 2,6-dinitrophenol in aqueous solutions up to 175°C.Journal of the Chemical Society,Faraday Transactions,92(24),pp.4951-4956.DOI:10.1039 / FT9969204951

[0357] R.A.Lara Orozco,G.A.Abeykoon,M.Wang,F.J.Argueelles-Vivas,R.Okuno,L.W.Lake,S.C.Ayirala,A.M.AlSofi,Amino acid as a novel wettability modifier for enhanced waterflooding in carbonate reservoirs,SPE Reservoir Evaluation and Engineering.23(2020)741-757.DOI:10.2118 / 195907-PA

[0358] M.C.Leverett,Capillary Behavior in Porous Solids,Trans.Soc.Pet.Eng.,142(1941)152-169.DOI:10.2118 / 941152-G

[0359] Li,G.-Z.,Xu,J.,Mu,J.-H.,Zhai,L.-M.,Shui,L.-L.,Chen,W.-J.,Jiang,J.-L.,Chen,F.,Guo,D.-F.,and Lin,W.-M.2005.「Design and Application of an Alkaline-Surfactant-Polymer Flooding Systems in Filed Pilot Test,」Journal of Dispersion Science and Technology,Vol 26(6),709-717.DOI:10.1081 / DIS-200063021.

[0360] Li,J.,Kuang,Y.,Meng,Y.,Tian,X.,Hung,W.,Zhang,X.,Li,A.,Xu,M.,Zhou,W.,Ku,C.,Chiang,C.,Zhu,G.,Guo,J.,Sun,X.and Dai,H.,2020.Electroreduction of CO2 to Formate on a Copper-Based Electrocatalyst at High Pressures with High Energy Conversion Efficiency.Journal of the American Chemical Society,142(16),pp.7276-7282.DOI:10.1021 / jacs.0c00122

[0361] K.Li,K.Chow,RN.Horne,Influence of initial water saturation on recovery by spontaneous imbibition in gas / water / rock systems and the calculation of relative permeability,SPE Reservoir Eval Eng,9(2006)295-301.DOI:10.2118 / 99329-PA

[0362] Li,M.,Idros,M.N.,Wu,Y.,Garg,S.,Gao,S.,Lin,R.,Rabiee,H.,Li,Z.,Ge,L.,Rufford,T.E.,Zhu,Z.,Li,L.,&Wang,G.2021.Unveiling the effects of dimensionality of tin oxide-derived catalysts on CO2reduction by using gas-diffusion electrodes.Reaction Chemistry&Engineering,6(2),345-352.DOI:10.1039 / d0re00396d

[0363] Liu,Z.,Zhang,L.,Cao,X.,Song,X.,Jin,Z.,Zhang,L.,and Zhao,S.2013.「Effect of Electrolyte on Interfacial Tension of Alkyl Ether Carboxylate Solutions,」Energy and Fuels.Vol.27(6),3122-3129.DOI:10.1021 / ef400458q.

[0364] Ma,Xie,Zhang,Sun,Kang,Jiang,Zhang,Wu,and Wang,2019,「Promoting electrocatalytic CO2 reduction to formate via sulfur-boosting water activation on indium surfaces.」Nature Communications 10,892.DOI:10.1038 / s41467-019-08805-x

[0365] M.Madani,G.Zargar,M.A.Takassi,A.Daryasafar,D.A.Wood,Z.Zhang,Fundamental Investigation of an Environmentally-Friendly Surfactant Agent for Chemical Enhanced Oil Recovery,Fuel.238(2019)186-197.DOI:10.1016 / j.fuel.2018.10.105

[0366] Mahani,Hassan,Arsene Levy Keya,Steffen Berg,and Ramez Nasralla.2016.「Electrokinetics of Carbonate / Brine Interface in Low-Salinity Waterflooding:Effect of Brine Salinity,Composition,Rock Type,and pH on zeta-Potential and a Surface-Complexation Model.」SPE Journal 22(01):053-068.DOI:10.2118 / 181745-pa

[0367] M.A.Mahmoud,K.Z.Abdelgawad,Chelating-Agent Enhanced Oil Recovery for Sandstone and Carbonate Reservoirs,SPE J.20(2015)483-495.DOI:10.2118 / 172183-PA

[0368] Mason,G.and Morrow,N.R.2013.Developments in Spontaneous Imbibition and Possibilities for Future Work.Journal of Petroleum Science and Engineering 110:268-293.DOI:10.1016 / j.petrol.2013.08.018

[0369] Meng,Q.,Liu,H.and Wang,J.2017.A Critical Review on Fundamental Mechanisms of Spontaneous Imbibition and the Impact of Boundary Condition,Fluid Viscosity and Wettability.Advances in Geo-energy Research 1(1):1-17.

[0370] Morrow,N.R.and Mason,G.2001.Recovery of Oil by Spontaneous Imbibition.Current Opinion in Colloid&Interface Science 6(4):321-337.DOI:10.1016 / S1359-0294(01)00100-5

[0371] Myint,Philip C.,and Abbas Firoozabadi.2015.「Thin Liquid Films in Improved Oil Recovery from Low-Salinity Brine.」Current Opinion in Colloid and Interface Science 20(2):105-14.DOI:10.1016 / j.cocis.2015.03.002

[0372] Newell,D.L.,Carey,J.W.,Backhaus,S.N.,and Lichtner,P.2018.Experimental study of gravitational mixing of Supercritical CO2.International Journal of Greenhouse Gas Control,71,62-73.DOI:10.1016 / j.ijggc.2018.02.013

[0373] Ofei T.N.,Al Bendary R.M.,Habte A.D.2017.Rheological Performance of Potassium Formate Water-Based Muds for High-Temperature Wells.In:Awang M.,Negash B.,Md Akhir N.,Lubis L.,Md.Rafek A.(eds)ICIPEG 2016.Springer,Singapore.DOI:10.1007 / 978-981-10-3650-7_63

[0374] P.Kathel,K.K.Mohanty,Wettability Alteration in a Tight Oil Reservoir,Energy Fuels 27(2013)6460-6468.DOI:10.1021 / ef4012752

[0375] Perez-Fortes,Schoneberger,Boulamanti,Harrison,and Tzimas.2016.「Formic acid synthesis using CO2as raw material:Techno-economic and environmental evaluation and market potential.」International Journal of Hydrogen Energy 41:16444-16462.

[0376] Philips,M.,Gruter,G.,Koper,M.and Schouten,K.,2020.Optimizing the Electrochemical Reduction of CO2 to Formate:A State-of-the-Art Analysis.ACS Sustainable Chemistry&Engineering,8(41),pp.15430-15444.DOI:10.1021 / acssuschemeng.0c05215

[0377] Plummer,L N,T M L Wigley,and D L Parkhurst.1978.「The Kinetics of Calcite Dissolution in CO2-Water Systems at 5 Degrees to 60 Degrees C and 0.0 to 1.0 Atm CO2.」American Journal of Science 278(2):179-216.

[0378] Rapoport,L.A.and Leas,W.J.1953.Properties of Linear Waterfloods.Journal of Petroleum Technology 5(05):139-148.DOI:10.2118 / 213-G

[0379] A.Seethepalli,B.Adibhatla,K.K.Mohanty.2004.Wettability Alteration During Surfactant Flooding of Carbonate Reservoirs,Paper presented at the SPE / DOE Symposium on Improved Oil Recovery,Tulsa,Oklahoma.DOI:10.2118 / 89423-MS

[0380] Shaffer,G.,2010.Long-term effectiveness and consequences of carbon dioxide sequestration.Nature Geoscience 3,464-467.DOI:10.1038 / ngeo896

[0381] Shaw.,J.E.1984.「Carboxylate Surfactants Systems Exhibiting Phase Behavior Suitable for Enhanced Oil Recovery,」Journal of American Oil Chemists’ Society.Vol 61,1395-1399.DOI:10.1007 / BF02542250.

[0382] Sharma,H.,Panthi,K.,Ghosh,P.,Weerasooriya,U.,and Mohanty,K.2018.「Novel Surfactants without Hydrocarbon Chains for Chemical EOR,」Paper Presented at SPE Improved Oil Recovery Conference,14-18 April.SPE-190232-MS.DOI:10.2118 / 190232-MS

[0383] Sheng,K.,Okuno,R.,Imran,M.,Nakutnyy,P.&Nakagawa,K.2021.An Experimental Study of Steam-solvent Coinjection for Bitumen Recovery Using a Large-scale Physical Model.In IOR 2021(Vol.2021,No.1,pp.1-37).European Association of Geoscientists&Engineers.www.earthdoc.org / content / papers / 10.3997 / 2214-4609.202133152

[0384] Sjoeberg,E Lennart,and David T Rickard.1984.「Temperature Dependence of Calcite Dissolution Kinetics between 1 and 62 C at PH2.7 to 8.4 in Aqueous Solutions.」Geochimica et Cosmochimica Acta 48(3):485-93.

[0385] Somoza-Tornos,A.,Guerra,O.J.,Crow,A.M.,Smith,W.A.,&Hodge,B.M.2021.Process modeling,techno-economic assessment,and life cycle assessment of the electrochemical reduction of CO2:a review.Iscience,24(7).DOI:10.1016 / j.isci.2021.102813

[0386] Strand,Skule,Eli J Hφgnesen,and Tor Austad.2006.「Wettability Alteration of Carbonates-Effects of Potential Determining Ions and Temperature」275:1-10.DOI:10.1016 / j.colsurfa.2005.10.061

[0387] N.Tang,L.H.Skibsted,Calcium Binding to Amino Acids and Small Glycine Peptides in Aqueous Solution:Toward Peptide Design for Better Calcium Bioavailability,Journal of Agricultural and Food Chemistry.64(2016)4376-4389.DOI:10.1021 / acs.jafc.6b01534

[0388] Tagavifar,Mohsen,Himanshu Sharma,Denning Wang,Sung Hyun Jang,and Gary Pope.2018.「Alkaline / Surfactant / Polymer Flooding With Sodium Hydroxide in Indiana Limestone:Analysis of Water / Rock Interactions and Surfactant Adsorption.」SPE Journal 23(06):2279-2301.DOI:10.2118 / 191146-pa

[0389] D.B.Tripathy,A.Mishra,J.Clark,T.Farmer,Synthesis,Chemistry,Physicochemical Properties and Industrial Applications of Amino Acid Surfactants:A review,Comptes Rendus Chimie.21(2018)112-130.DOI:10.1016 / j.crci.2017.11.005

[0390] Upadhyay and Srivastava.2016.「Carbon Sequestration:Hydrogenation of CO2to Formic Acid.」Present Environment and Sustainable Development.10,2:13-31.

[0391] van Putten,Wissink,Swinkels,and Pidko.2019.「Fuelling the hydrogen economy:Scale-up of an integrated formic acid-to-power system.」International Journal of Hydrogen Energy 44:28533-28541.

[0392] Wang,D.,Maubert,M.,Pope,G.A.,Liyanage,P.J.,Jang,S.H.,Upamali,K.A.,Chang,L.,Tagavifar,M.,Sharma,H.,Ren,G.and Mateen,K.2018.Reduction of Surfactant Retention in Limestones Using Sodium Hydroxide.SPE Journal.SPE-194009-PA.DOI:10.2118 / 194009-PA

[0393] M.Wang,G.A.Abeykoon,F.J.Arguelles-Vivas,R.Okuno,2019.Ketone Solvent as a Wettability Modifier for Improved Oil Recovery from Oil-Wet Porous Media.Fuel.258,116195.DOI:10.1016 / j.fuel.2019.116195

[0394] A.A.Yousef,S.H.Al-Saleh,A.Al-Kaabi,M.S.Al-Jawfi,Laboratory Investigation of the Impact of Injection-Water Salinity and Ionic Content on Oil Recovery from Carbonate Reservoirs,SPE Reservoir Evaluation&Engineering.14(2011)578-593;DOI:10.2118 / 137634-PA

[0395] Yu and Savage,1998,「Decomposition of Formic Acid under Hydrothermal Conditions,」Ind.Eng.Chem.Res.,37:2-10.DOI:10.1021 / ie970182e

[0396] D.L.Zhang,S.Liu,M.Puerto,C.A.Miller,G.J.Hirasaki.2006.Wettability alteration and spontaneous imbibition in oil-wet carbonate formations,Journal of Petroleum Science and Engineering,52(2006)213-226,DOI:10.1016 / j.petrol.2006.03.009

[0397] Zhang,Peimao,Medad T.Tweheyo,and Tor Austad.2007.「Wettability Alteration and Improved Oil Recovery by Spontaneous Imbibition of Seawater into Chalk:Impact of the Potential Determining Ions Ca2+,Mg2+,and SO42-.」Colloids and Surfaces A:Physicochemical and Engineering Aspects 301(1-3):199-208.DOI:10.1016 / j.colsurfa.2006.12.058

[0398] Zhou,D.,Jia,L.,Kamath,J.and Kovscek,A.R.2002.Scaling of Counter-Current Imbibition Processes in Low-Permeability Porous Media.Journal of Petroleum Science and Engineering 33(1-3):61-74.DOI:10.1016 / S0920-4105(01)00176-0

[0399] Zukfli,NN,Mahmood,SM,Akbari,S.,Manap,AAA,Kechut,NI,and Elrais,KA2020. "Evaluation of New Surfactants for Enhanced Oil Recovery Applications in High-Temperature Reservoirs, Journal of Petroleum Exploration and Production Technology." Vol. 10,283-296.DOI:10.1007 / s13202-019-0713-y

[0400] ChelateEffect (and MacrocycleEffect): Available at chem.libertexts.org / @go / page / 200888 (accessed December 13, 2021).

[0401] INCORPORATION BY REFERENCE AND MODIFICATION STATEMENT All references throughout this application, e.g., patent documents, including issued or granted patents or equivalents; published patent applications; non-patent literature or other source documents, are incorporated by reference in their entirety herein, as if each reference were individually incorporated by reference, unless each reference is at least partially inconsistent with the disclosure of this application (e.g., a non-corresponding reference is incorporated by reference except for the non-corresponding portion of the reference).

[0402] All patents and publications mentioned herein are indicative of the level of skill of those skilled in the art to which the present invention pertains. References cited herein are, in some cases, incorporated herein by reference in their entirety to indicate the state of the art as of the filing date, and it is intended that this information may be adopted herein to exclude (e.g., disclaim) certain embodiments that are in the prior art, if necessary. For example, when a compound is claimed, it is understood that compounds known in the prior art, including specific compounds disclosed in the references disclosed herein (particularly patent documents referenced), are not intended to be included in the scope of the claim.

[0403] When a group of substituents is disclosed herein, it is understood that all individual members of the group are disclosed separately, as well as all subgroups and classes that can be formed with the substituents. When a Markush group or other cluster is used herein, all individual members of the group, as well as all possible combinations and subcombinations of the group, are intended to be individually included in the disclosure. As used herein, "and / or" means that one, all, or any combination of the items in the list separated by "and / or" is included in the list, e.g., "1, 2, and / or 3" is equivalent to "'1' or '2' or '3', or '1 and 2' or '1 and 3' or '2 and 3', or '1, 2, and 3'.

[0404] Any combination or permutation of the components described or illustrated can be used to practice the present invention unless otherwise specified. The specific names of the materials are intended as examples, since one skilled in the art will know that the same materials can be named differently. One skilled in the art will understand that methods, device elements, starting materials, and synthetic methods other than those specifically illustrated can be used in the practice of the present invention without resorting to undue experimentation. All art-known functional equivalents of any such methods, device elements, starting materials, and synthetic methods are intended to be included in the present invention. Whenever a range is given herein, e.g., a temperature range, a time range, a composition range, all intermediate and subranges, as well as all individual values ​​included in the given range, are intended to be included in the present disclosure.

[0405] As used herein, "comprising" is synonymous with "including," "containing," or "characterized by," is inclusive or open-ended, and does not exclude additional, unrecited elements or method steps. As used herein, "consisting of" excludes any element, step, or ingredient not specified in the claim element. As used herein, "consisting essentially of" does not exclude materials or steps that do not materially affect the basic and novel characteristics of the claim. Any reference herein to the term "comprising," particularly in a description of a component of a composition or in a description of an element of a device, is to be understood to include those compositions and methods that consist essentially of the recited components or elements. The invention illustratively described herein may suitably be practiced in the absence of any element or elements, limitation or limitations not specifically disclosed herein.

[0406] The terms and expressions employed are used as terms of description and not of limitation, and there is no intention in the use of such terms and expressions to exclude any equivalents of the features shown and described or portions thereof, but it is recognized that various modifications are possible within the scope of the invention as claimed. Thus, while the invention has been specifically disclosed by preferred embodiments and optional features, it is to be understood that modifications and variations of the concepts disclosed herein may be resorted to by those skilled in the art, and that such modifications and variations are considered to be within the scope of the invention as defined by the appended claims.

Claims

1. Obtaining an aqueous mixture comprising water and a carboxylate, wherein the concentration of the carboxylate in the aqueous mixture is between 1% and 45% by weight; injecting the aqueous mixture into an underground reservoir; A method comprising:

2. 10. The method of claim 1 , wherein the aqueous mixture has a pH within 1 pH unit of the aqueous fluid in the subterranean reservoir.

3. 10. The method of claim 1, wherein injecting the aqueous mixture comprises sequestering the carboxylate form of carbon or carbon dioxide in the subterranean reservoir.

4. Obtaining the aqueous mixture comprises ２ preparing the carboxylate from a gas, carbonate ion or bicarbonate ion; or obtaining the aqueous mixture comprises preparing the carboxylate from CO2 and H2O, from carbonate ions and H2O, or from bicarbonate ions and H2O using an electrochemical reduction process; The method of claim 1.

5. The method of claim 1 , wherein obtaining the aqueous mixture comprises adjusting the pH of the aqueous mixture by adding an acid or a base to the aqueous mixture.

6. 2. The method of claim 1, wherein the concentration of the carboxylate is within the solubility limits of the carboxylate in the aqueous mixture at the temperature and pressure of the subsurface reservoir.

7. 2. The method of claim 1 , wherein the concentration of the carboxylate exceeds the solubility limit of the carboxylate in the aqueous mixture at the temperature and pressure of the subsurface reservoir, or the aqueous mixture is a saturated or supersaturated solution of the carboxylate.

8. 2. The method of claim 1, wherein the aqueous mixture comprises a plurality of different carboxylates, and the concentration of each of the plurality of different carboxylates in the aqueous mixture is from 0.5% to 44.5% by weight.

9. 10. The method of claim 1, wherein the underground reservoir comprises an oil or gas reservoir, a saline aquifer, a freshwater aquifer, a geothermal reservoir or cavity, the underground reservoir comprises sandstone, carbonate, volcanic rock, or any combination thereof, or the underground reservoir comprises one or more minerals including quartz, calcite, carbonate, dolomite, anhydrite, gypsum, feldspar, siderite, zeolite, kaolinite, illite, chlorite, or smectite.

10. 2. The method of claim 1, wherein the aqueous mixture comprises fresh water, seawater, reservoir relict water, produced freshwater, river water, pond water, or brine, the salinity of the aqueous mixture is greater than or approximately equal to the salinity of the brine in the underground reservoir, or the salinity of the aqueous mixture is less than or approximately equal to the salinity of the brine in the underground reservoir.

11. 13. The method of claim 1, wherein the aqueous mixture or a component thereof contacts a rock surface in the underground reservoir and increases the water-wetting properties of the rock surface, or the aqueous mixture or a component thereof increases the viscosity of a fluid in the underground reservoir.

12. producing hydrocarbons from the underground reservoir, wherein: the rate at which the hydrocarbons are produced from the underground reservoir is greater after injecting the aqueous mixture compared to the rate at which the hydrocarbons are produced from the underground reservoir prior to injecting the aqueous mixture; or The hydrocarbons include crude oil, talc, bitumen, kerogen, heavy oil, tight oil, shale oil, gas condensate, wet gas, dry gas, or any combination thereof; The method of claim 1.

13. 10. The method of claim 1, wherein the aqueous mixture further comprises one or more of a surfactant, a solvent, an acid, a base, a salt, an inorganic compound, a polymer, a chelating agent, a nanomaterial, an amino acid, a biocide, a hydrocarbon, nitrogen, or carbon dioxide.

14. producing the hydrocarbons from the underground reservoir includes producing the hydrocarbons from one or more wells in the underground reservoir; producing the hydrocarbons from the underground reservoir includes recovering at least a portion of the aqueous mixture injected into the underground reservoir; or The method of claim 12 , wherein the method further comprises producing brine from the underground reservoir.

15. producing the hydrocarbons from the underground reservoir includes producing the brine from the underground reservoir; the carboxylate is present as a tracer in brine produced from the underground reservoir; or 15. The method of claim 14, wherein the method further comprises identifying the carboxylate as a tracer in the brine produced from the subterranean reservoir.

16. injecting the aqueous mixture and producing the hydrocarbons comprises a flooding process or a huff-n-puff process; or The method of claim 12 , wherein injecting the aqueous mixture and producing the hydrocarbons comprises a continuous injection process, a periodic injection process, or a slug injection process.

17. injecting the aqueous mixture includes storing hydrogen in the form of the carboxylate in the subterranean reservoir; the method further comprising producing fluid from the subterranean reservoir; the fluid comprises H2, or the fluid comprises the carboxylate; 2. The method of claim 1, wherein the method further comprises using the carboxylate to produce H2 from the fluid, and wherein using the carboxylate to produce H2 comprises dehydrogenating the carboxylate from the fluid.

18. The carboxylate in the underground reservoir is used to generate H in the underground reservoir. ２ 20. The method of claim 17, further comprising generating H2 in the subterranean reservoir, wherein generating H2 in the subterranean reservoir comprises injecting a catalyst comprising a nanocatalyst or a pH adjuster into the subterranean reservoir.

19. a source of an aqueous mixture comprising water and a carboxylate, the concentration of the carboxylate in the aqueous mixture being between 1% and 45% by weight; an injection system in fluid communication with the source and with subsurface reservoir fluid for injecting the aqueous mixture into the subsurface reservoir; A system comprising:

20. the carboxylate comprises a carboxylic acid, a carboxylate salt, a carboxylate ion, or any combination thereof; or the salinity of the aqueous mixture is from about 0 ppm to about 243,000 ppm; or the aqueous mixture has a pH of 5 to 9 or within 1 pH unit of the aqueous fluid in the subterranean reservoir; or The aqueous mixture comprises fresh water, seawater, reservoir water, raw water, river water, pond water or brine; or the carboxylate is not an amino acid, or The carboxylate is 【Chemistry 4】 wherein R is H or a C1-C3 alkyl group and X is H or an alkali metal. or the carboxylate is a formate, formic acid, acetate, acetic acid, propionate or propionic acid; or the underground reservoir comprises an oil or gas reservoir, a saline aquifer, a freshwater aquifer, or a geothermal reservoir; or the source of the aqueous mixture comprises an electrochemical reduction reactor for producing the carboxylate from CO2 and H2O; or the fluid comprises H2, or The system further comprises a fluid production system in fluid communication with the subterranean reservoir for producing fluid from the subterranean reservoir, wherein: the fluid comprises a hydrocarbon; or the fluid comprises the carboxylate, and the system further comprises a dehydrogenation reactor in fluid communication with the fluid production system for producing H2 from the carboxylate in the fluid.

20. The system of claim 19.

Images